Last updated on March 11th, 2024 at 07:41 pm
Title 18—Conservation of Power and Water Resources–Volume 1
M.c.f. = Thousand cubic feet. B.t.u. = British thermal units. ICC = Interstate Commerce Commission.
CHAPTER I—FEDERAL ENERGY REGULATORY COMMISSION, DEPARTMENT OF ENERGY
SUBCHAPTER A—GENERAL RULES
PART 1—RULES OF GENERAL APPLICABILITY
Subpart A—Definitions and Rules of Construction
§ 1.101 Definitions.
The definitions set forth in this section apply for purposes of this chapter, except as otherwise provided in this chapter:
(a) Commission means the Federal Energy Regulatory Commission.
(b) Chairman means the Chairman of the Commission.
(c) Commissioner and Member mean a member of the Commission.
(d) Secretary means the Secretary of the Commission.
(e) Executive Director means the Executive Director of the Commission.
(f) General Counsel means the General Counsel of the Commission.
(g) DOE Act means the Department of Energy Organization Act.
(h) DOE means the Department of Energy.
(i) Administrative law judge means an officer appointed under section 3105 of title 5 of the United States Code.
(j) Attorney means an attorney admitted to practice before the Supreme Court of the United States or the highest court of any State, territory of the United States, or the District of Columbia, or any other person with the requisite qualifications to represent others, who acts in a representative capacity for any participant before the Commission.
(k) State Commission means the regulatory body of any State or municipality having jurisdiction to regulate rates or charges for the sale of electric energy or natural gas to consumers or for the transportation of oil by pipeline within the State or municipality.
(l) Oath includes affirmation and sworn includes affirmed.
§ 1.102 Words denoting number, gender and so forth.
In determining the meaning of any provision of this chapter, unless the context indicates otherwise:
(a) The singular includes the plural;
(b) The plural includes the singular;
(c) The present tense includes the future tense; and
(d) Words of one gender include the other gender.
PART 1b—RULES RELATING TO INVESTIGATIONS
§ 1b.1 Definitions.
For purposes of this part—
(a) Formal investigation means an investigation instituted by a Commission Order of Investigation.
(b) Preliminary Investigation means an inquiry conducted by the Commission or its staff, other than a formal investigation.
(c) Investigating officer means the individual(s) designated by the Commission in an Order of Investigation as Officer(s) of the Commission.
(d) Enforcement Hotline is a forum in which to address quickly and informally any matter within the Commission’s jurisdiction concerning natural gas pipelines, oil pipelines, electric utilities and hydroelectric projects.
§ 1b.2 Scope.
This part applies to investigations conducted by the Commission but does not apply to adjudicative proceedings.
§ 1b.3 Scope of investigations.
The Commission may conduct investigations relating to any matter subject to its jurisdiction.
§ 1b.4 Types of investigations.
Investigations may be formal or preliminary, and public or private.
§ 1b.5 Formal investigations.
The Commission may, in its discretion, initiate a formal investigation by issuing an Order of Investigation. Orders of Investigation will outline the basis for the investigation, the matters to be investigated, the officer(s) designated to conduct the investigation and their authority. The director of the office responsible for the investigation may add or delete Investigating Officers in the Order of Investigation.
§ 1b.6 Preliminary investigations.
The Commission or its staff may, in its discretion, initiate a preliminary investigation. In such investigations, no process is issued or testimony compelled. Where it appears from the preliminary investigation that a formal investigation is appropriate, the staff will so recommend to the Commission.
§ 1b.7 Procedure after investigation.
Where it appears that there has been or may be a violation of any of the provisions of the acts administered by the Commission or the rules, opinions or orders thereunder, the Commission may institute administrative proceedings, initiate injunctive proceedings in the courts, refer matters, where appropriate, to the other governmental authorities, or take other appropriate action.
§ 1b.8 Requests for Commission investigations.
(a) Any individual, partnership, corporation, association, organization, or other Federal or State governmental entity, may request the Commission to institute an investigation.
(b) Requests for investigations should set forth the alleged violation of law with supporting documentation and information as completely as possible. No particular forms or formal procedures are requested.
(c) It is the Commission’s policy not to disclose the name of the person or entity requesting an investigation except as required by law, or where such disclosure will aid the investigation.
§ 1b.9 Confidentiality of investigations.
All information and documents obtained during the course of an investigation, whether or not obtained pursuant to subpoena, and all investigative proceedings shall be treated as nonpublic by the Commission and its staff except to the extent that (a) the Commission directs or authorizes the public disclosure of the investigation; (b) the information or documents are made a matter of public record during the course of an adjudicatory proceeding; or (c) disclosure is required by the Freedom of Information Act, 5 U.S.C. 552. Procedures by which persons submitting information to the Commission during the course of an investigation may specifically seek confidential treatment of information for purposes of Freedom of Information Act disclosure are set forth in 18 CFR part 3b and § 1b.20. A request for confidential treatment of information for purposes of Freedom of Information Act disclosure shall not, however, prevent disclosure for law enforcement purposes or when disclosure is otherwise found appropriate in the public interest and permitted by law.
§ 1b.10 By whom conducted.
Formal Commission investigations are conducted by the Commission or by an individual(s) designated and authorized in the Order of Investigation. Investigating Officers are officers within the meaning of the statutes administered by the Commission and are authorized to perform the duties of their office in accordance with the laws of the United States and the regulations of the Commission. Investigating Officers shall have such duties as the Commission may specify in an Order of Investigation.
§ 1b.11 Limitation on participation.
There are no parties, as that term is used in adjudicative proceedings, in an investigation under this part and no person may intervene or participate as a matter of right in any investigation under this part.
§ 1b.12 Transcripts.
Transcripts, if any, of investigative testimony shall be recorded solely by the official reporter, or by any other person or means designated by the investigating officer. A witness who has given testimony in an investigation shall be entitled, upon written request, to procure a transcript of the witness’ own testimony on payment of the appropriate fees, except that in a non-public formal investigation, the office responsible for the investigation may for good cause deny such request. In any event, any witness or his counsel, upon proper identification, shall have the right to inspect the official transcript of the witness’ own testimony.
§ 1b.13 Powers of persons conducting formal investigations.
Any member of the Commission or the Investigating Officer, in connection with any formal investigation ordered by the Commission, may administer oaths and affirmations, subpoena witnesses, compel their attendance, take evidence, and require the production of any books, papers, correspondence, memoranda, contracts, agreements or other records relevant or material to the investigation.
§ 1b.14 Subpoenas.
(a) Service of a subpoena upon a person named therein shall be made by the investigating officer (1) by personal delivery, (2) by certified mail, (3) by leaving a copy thereof at the principle office or place of business of the person to be served, (4) or by delivery to any person designated as agent for service or the person’s attorney.
(b) At the time for producing documents subpoenaed in an investigation, the subpoenaed party shall submit a statement stating that, if true, such person has made a diligent search for the subpoenaed documents and is producing all the documents called for by the subpoena. If any subpoenaed document(s) are not produced for any reason, the subpoenaed party shall state the reason therefor.
(c) If any subpoenaed documents in an investigation are withheld because of a claim of the attorney-client privilege, the subpoenaed party shall submit a list of such documents which shall, for each document, identify the attorney involved, the client involved, the date of the document, the person(s) shown on the document to have prepared and/or sent the document, and the person(s) shown on the document to have received copies of the document.
§ 1b.15 Non-compliance with compulsory processes.
In cases of failure to comply with Commission compulsory processes, appropriate action may be initiated by the Commission or the Attorney General, including but not limited to actions for enforcement or the imposition of penalties.
§ 1b.16 Rights of witnesses.
(a) Any person who is compelled or requested to furnish documentary evidence or testimony in a formal investigation shall, upon request, be shown the Commission’s Order of Investigation. Copies of Orders of Investigation shall not be furnished, for their retention, to such persons requesting the same except with the express approval of the director of the office responsible for the investigation. Such approval shall not be given unless the director of the office responsible for the investigation, in the director’s discretion is satisfied that there exist reasons consistent with the protection of privacy of persons involved in the investigation and with the unimpeded conduct of the investigation.
(b) Any person compelled to appear, or who appears in person at a formal investigation by request or permission of the Investigating Officer may be accompanied, represented and advised by counsel, as provided by § 385.2101 of this chapter and these rules, except that all witnesses shall be sequestered and, unless permitted in the discretion of the Investigating Officer, no witness or the counsel accompanying any such witness shall be permitted to be present during the examination of any other witness called in such proceeding. When counsel does represent more than one person in an investigation, for example, where the counsel is counsel to the witness and his employer, said counsel shall inform the Investigating Officer and each client of said counsel’s possible conflict of interest in representing that client and, if said counsel appears with a witness giving testimony on the record in an investigation, counsel shall state on the record all persons said counsel represents in the investigation.
(c) Any witness may be accompanied, represented, and advised by counsel as follows:
(1) Counsel for a witness may advise the witness, in confidence, upon his initiative or the witness’ with respect to any question, and if the witness refuses to answer a question, then the witness or counsel may briefly state on the record the legal grounds for such refusal.
(2) Where it is claimed that the witness has a privilege to refuse to answer a question on the grounds of self-incrimination, the witness must assert the privilege personally.
(3) Following completion of the examination of a witness, such witness may make a statement on the record and his counsel may on the record question the witness to enable the witness to clarify any of the witness’ answers or to offer other evidence.
(4) The Investigating Officer shall take all necessary action to regulate the course of the proceeding to avoid delay and prevent or restrain obstructionist or contumacious conduct or contemptuous language. Such officer may report to the Commission any instances where an attorney or representative has refused to comply with his directions, or has engaged in obstructionist or contumacious conduct or has used contemptuous language in the course of the proceeding. The Commission may thereupon take such further action as the circumstances may warrant, including suspension or disbarment of counsel from further appearance or practice before it, in accordance with § 385.2101 of this chapter, or exclusion from further participation in the particular investigation.
(d) Unless otherwise ordered by the Commission, in any public formal investigation, if the record shall contain implications of wrongdoing by any person, such person shall have the right to appear on the record; and in addition to the rights afforded other witnesses hereby, he shall have a reasonable opportunity of cross-examination and production of rebuttal testimony or documentary evidence. Reasonable shall mean permitting persons as full an opportunity to assert their position as may be granted consistent with administrative efficiency and with avoidance of undue delay. The determinations of reasonableness in each instance shall be made in the discretion of the investigating officer.
§ 1b.17 Appearance and practice before the Commission.
The provisions of subpart U of part 385 of this chapters are specifically applicable to all investigations.
§ 1b.18 Right to submit statements.
Any person may, at any time during the course of an investigation, submit documents, statements of facts or memoranda of law for the purpose of explaining said person’s position or furnishing evidence which said person considers relevant regarding the matters under investigation.
§ 1b.19 Submissions.
In the event the Investigating Officer determines to recommend to the Commission that an entity be made the subject of a proceeding governed by part 385 of this chapter, or that an entity be made a defendant in a civil action to be brought by the Commission, the Investigating Officer shall, unless extraordinary circumstances make prompt Commission review necessary in order to prevent detriment to the public interest or irreparable harm, notify the entity that the Investigating Officer intends to make such a recommendation. Such notice shall provide sufficient information and facts to enable the entity to provide a response. Within 30 days of such notice, the entity may submit to the Investigating Officer a non-public response, which may consist of a statement of fact, argument, and/or memorandum of law, with such supporting documentation as the entity chooses, showing why a proceeding governed by part 385 of this chapter should not be instituted against said entity, or why said entity should not be made a defendant in a civil action brought by the Commission. If the response is submitted by the due date, the Investigating Officer shall present it to the Commission together with the Investigating Officer’s recommendation. The Commission will consider both the Investigating Officer’s recommendation and the entity’s timely response in deciding whether to take further action.
§ 1b.20 Request for confidential treatment.
Any person compelled to produce documents in an investigation may claim that some or all of the information contained in a particular document(s) is exempt from the mandatory public disclosure requirements of the Freedom of Information Act (5 U.S.C. 552), is information referred to in 18 U.S.C. 1905, or is otherwise exempt by law from public disclosure. In such case, the person making such claim shall, at the time said person produces the document to the officer conducting the investigation shall also produce a second copy of the document from which has been deleted the information for which the person wishes to claim confidential treatment. The person shall indicate on the original document that a request for confidential treatment is being made for some or all of the information in the document and shall file a statement specifying the specific statutory justification for non-disclosure of the information for which confidential treatment is claimed. General claims of confidentiality are not sufficient. Sufficient information must be furnished for the officer conducting the investigation, or other appropriate official, to make an informed decision on the request for confidential treatment. If the person states that the information comes within the exception in 5 U.S.C. 552(b)(4) for trade secrets and commercial or financial information, the person shall include a statement specifying why the information is privileged or confidential. If the person filing a document does not submit a second copy of the document with the confidential information deleted, the Officer conducting the investigation may assume that there is no objection to public disclosure of the document in its entirety. The Commission retains the right to make the determination with regard to any claim of confidentiality. Notice of the decision by the investigating Officer or other appropriate official to deny a claim, in whole or in part, and an opportunity to respond shall be given to a person claiming confidentiality no less than 5 days before its public disclosure.
§ 1b.21 Enforcement hotline.
(a) The Hotline Staff may provide information to the public and give informal staff opinions. The opinions given are not binding on the General Counsel or the Commission.
(b) Except as provided for in paragraph (g) of this section, any person may seek information or the informal resolution of a dispute by calling or writing to the Hotline at the telephone number and address in paragraph (f) of this section. The Hotline Staff will informally seek information from the caller and any respondent, as appropriate. The Hotline Staff will attempt to resolve disputes without litigation or other formal proceedings. The Hotline Staff may not resolve matters that are before the Commission in docketed proceedings.
(c) All information and documents obtained through the Hotline Staff shall be treated as non-public by the Commission and its staff, consistent with the provisions of section 1b.9 of this part.
(d) Calls to the Hotline may be made anonymously.
(e) Any person who contacts the Hotline is not precluded from filing a formal action with the Commission if discussions assisted by Hotline Staff are unsuccessful at resolving the matter. A caller may terminate use of the Hotline procedure at any time.
(f) The Hotline may be reached by calling (202) 502–8390 or 1–888–889–8030 (toll free), by e-mail at [email protected], or writing to: Enforcement Hotline, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426.
§ 1b.22 Landowner Helpline.
(a) Any person affected by either the construction or operation of a certificated or authorized natural gas project under the Natural Gas Act or by the construction or operation of a project under the Federal Power Act may seek the informal resolution of a dispute by contacting the Commission’s Landowner Helpline. The Commission’s Landowner Helpline may be reached by calling toll-free at 1–877–337–2237, or by email at [email protected], or writing to: Commission’s Landowner Helpline, Federal Energy Regulatory Commission, 888 First Street NE., Washington, DC 20426.
(b) Any person who contacts the Landowner Helpline is not precluded from filing a formal action with the Commission if discussions assisted by the Landowner Helpline staff are unsuccessful at resolving the matter. A caller may terminate the use of alternative dispute resolution procedures at any time.
PART 1c—PROHIBITION OF ENERGY MARKET MANIPULATION
§ 1c.1 Prohibition of natural gas market manipulation.
(a) It shall be unlawful for any entity, directly or indirectly, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of the Commission,
(1) To use or employ any device, scheme, or artifice to defraud,
(2) To make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or
(3) To engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any entity.
(b) Nothing in this section shall be construed to create a private right of action.
§ 1c.2 Prohibition of electric energy market manipulation.
(a) It shall be unlawful for any entity, directly or indirectly, in connection with the purchase or sale of electric energy or the purchase or sale of transmission services subject to the jurisdiction of the Commission,
(1) To use or employ any device, scheme, or artifice to defraud,
(2) To make any untrue statement of a material fact or to omit to state a material fact necessary in order to make the statements made, in the light of the circumstances under which they were made, not misleading, or
(3) To engage in any act, practice, or course of business that operates or would operate as a fraud or deceit upon any entity.
(b) Nothing in this section shall be construed to create a private right of action.
PART 2—GENERAL POLICY AND INTERPRETATIONS
Statements of General Policy and Interpretations of the Commission
§ 2.1 Initial notice; service; and information copies of formal documents.
(a) Whenever appropriate, publication of an initial notice or order in the
(1) It is the policy of the Commission to publish notice in the
(i) Natural gas pipeline companies and public utility rate schedules and tariffs. (A) Initial rate schedule filings and changes in rates schedules proposed by public utilities and changes in rate schedules or tariffs proposed by natural gas pipeline companies, including purchased gas adjustment clauses.
(B) Changes in rates proposed by natural gas pipeline companies for field sales.
(C)–(D) [Reserved]
(E) Tracking rate schedule or tariff filings made pursuant to settlement agreements.
(F) Rate schedule or tariff filings made by natural gas pipeline companies or public utilities in compliance with Commission orders.
(G) Reports of refunds by natural gas pipeline companies and public utilities.
(H) [Reserved]
(I) Complaints against natural gas pipeline companies and public utilities, unless otherwise directed.
(ii) Interconnections, service and exportation pursuant to the Federal Power Act. (A) Applications for interconnection and service under section 202(b).
(B)–(C) [Reserved]
(D) Applications pursuant to section 207.
(E) [Reserved]
(iii) Hydroelectric, Federal Power Act. (A) Applications for preliminary permits pursuant to section 4(f).
(B) Applications for licenses for constructed or unconstructed projects, or notice of declaration of intention, sections 4(e), 23(a)(b).
(C) Applications for amendment of license, unless otherwise directed.
(D) Application for relicenses or nonpower licenses, or a recommendation for takeover, sections 14 and 15.
(E) Applications for transfer of license, section 8.
(F) Applications for surrender of license, section 6.
(G) Proceeding for revocation or termination of license, sections 6, 13, 26.
(H) Issuance of annual licenses, section 15.
(I) Lands withdrawn pursuant to an application for preliminary permit or license, and the vacation of such land withdrawals, section 24.
(J) Complaints against licensees, unless otherwise directed.
(iv) Corporate electric. (A) Applications pursuant to sections 203, 204, of the Federal Power Act, and applications or complaints pursuant to section 305 of the Federal Power Act.
(v) Accounting, gas and electric. (A) Applications pursuant to sections 4, 23, 301, and 302 of the Federal Power Act.
(B) Applications pursuant to sections 8 and 9 of the Natural Gas Act.
(vi) Federal rates. (A) Application for confirmation and approval of rate schedules for Federal hydroelectric projects.
(vii) Natural gas pipeline certificates, exportations, and importations, Natural Gas Act. (A) Applications for exemption under section 1(c).
(B) Applications for authorization to import and export gas under section 3.
(C) Applications for orders directing physical connection of facilities and sale of natural gas under section 7(a).
(D) Applications for permission and approval to abandon under section 7(b).
(E) Applications for permanent certificates under section 7(c).
(F) [Reserved]
(G) Complaints against natural gas pipeline companies, filed by individuals and companies, unless otherwise directed.
(viii)–(ix) [Reserved]
(x) Environmental statements. (A) Notice to be published pursuant to Order series 415.
(xi) Miscellaneous, gas and electric. (A) Order instituting an investigation in which hearings are fixed or in which an opportunity is given for filing comments or petitions to intervene.
(B) Show cause order, in which hearings are fixed or in which an opportunity is given for filing comments or petitions to intervene.
(C) Order or notice consolidating proceedings for hearing purposes or severing a proceeding formerly consolidated for hearing purposes.
(D) Applications for declaratory order, disclaimers of jurisdiction, or waiver of Commission regulations, unless otherwise directed.
(E) Requests for redesignation, unless otherwise directed.
(F) Requests for extension of time pursuant to § 385.2008 of this chapter, unless otherwise directed.
(G) Consolidations and severance pursuant to § 375.302(f) of this chapter, unless otherwise directed.
(H) Notice of correction of a document in any of the above categories.
(I) Notice of meetings of advisory committees established by the Commission.
(J) Notices of conferences in docketed rulemaking proceedings.
(K) Proposed penalties under section 31 of the Federal Power Act.
(L) Such other notices or orders as may be submitted by the Secretary for publication.
(2) Otherwise directed, as referred to above, shall be interpreted to mean notice given by the discretion of the Secretary.
(b) After notice has been given, the service of formal documents issued in a proceeding shall be confined to the parties of record or their attorneys, and the mailing or e-mailing of information copies shall be confined to that which is required by the Commission’s rules and regulations, by courtesy in response to written requests for copies, or by other considerations deemed valid by the Secretary in specific instances.
§ 2.1a Public suggestions, comments, proposals on substantial prospective regulatory issues and problems.
(a) The Commission by this policy statement explicitly encourages the public, including those persons subject to regulation by the Commission, to submit suggestions, comments, or proposals concerning substantial prospective regulatory policy issues and problems, the resolution of which will have a substantial impact upon those regulated by the Commission or others affected by the Commission’s activities. This policy is intended to serve as a means of advising the Commission on a timely basis of potential significant issues and problems which may come before it in the course of its activities and to permit the Commission an early opportunity to consider argument regarding policy questions and administrative reforms in a general context rather than in the course of individual proceedings.
(b) Upon receipt of suggestions, comments, or proposals pursuant to paragraph (a) of this section, the Commission shall review the matters raised and take whatever action is deemed necessary with respect to the filing, including, but not limited to, requesting further information from the filing party, the public, or the staff, or prescribing an informal public conference for initial discussion and consultation with the Commission, a Commissioner, or the Staff, concerning the matter(s) raised. In the absence of a notice of proposed rulemaking, any conferences or procedures undertaken pursuant to this section shall not be deemed by the Commission as meeting the requirements of the Administrative Procedure Act with respect to notice of rulemakings, but are to be utilized by the Commission as initial discussions for advice as a means of determining the need for Commission action, investigation or study prior to the issuance of a notice of proposed rulemaking to the extent required by the Administrative Procedure Act, 5 U.S.C. 553.
(c) [Reserved]
(d) A person may not invoke this policy as a means of advocating ex parte before the Commission a position in a proceeding pending at the Commission and any such filing will be rejected. Comments must relate to general conditions in industry or the public or policies or practices of the Commission which may need reform, review, or initial consideration by the Commission.
§ 2.1b Availability in contested cases of information acquired by staff investigation.
Pursuant to the Commission’s authority under the Natural Gas Act, particularly subsection (b) of section 8 thereof, and under the Federal Power Act, particularly subsection (b) of section 301 thereof, upon request by a party to the proceedings, or as required in conjunction with the presentation of a Commission staff case of staff’s cross-examination of any other presentation therein, all relevant information acquired by Commission staff, including workpapers pursuant to any staff investigation conducted under sections 8, 10, or 14 of the Natural Gas Act, and sections 301, 304 or 307 of the Federal Power Act, shall, without further order of the Commission, be free from the restraints of said subsection (b) of section 8 of the Natural Gas Act, and subsection (b) of section 301 of the Federal Power Act, regarding the divulgence of information, with respect to any matter hereafter set for formal hearing.
§ 2.1c Policy statement on consultation with Indian tribes in Commission proceedings.
(a) The Commission recognizes the unique relationship between the United States and Indian tribes and Alaska Native Claims Settlement Act (ANCSA) Corporations as defined by treaties, statutes, and judicial decisions. Indian tribes have various sovereign authorities, including the power to make and enforce laws, administer justice, and manage and control their lands and resources. Through several Executive Orders and a Presidential Memorandum, departments and agencies of the Executive Branch have been urged to consult with federally-recognized Indian tribes in a manner that recognizes the government-to-government relationship between these agencies and tribes. In essence, this means that consultation should involve direct contact between agencies and tribes and should recognize the status of the tribes as governmental sovereigns.
(b) The Commission acknowledges that, as an independent agency of the federal government, it has a trust responsibility to Indian tribes and this historic relationship requires it to adhere to certain fiduciary standards in its dealings with Indian tribes.
(c) The Commission will endeavor to work with Indian tribes on a government-to-government basis, and with ANCSA Corporations in a similar manner, and will seek to address the effects of proposed projects on tribal rights and resources through consultation pursuant to the Commission’s trust responsibility, the Federal Power Act, the Natural Gas Act, the Public Utility Regulatory Policies Act, section 32 of the Public Utility Holding Company Act, the Interstate Commerce Act, the Outer Continental Shelf Lands Act, section 106 of the National Historic Preservation Act, and in the Commission’s environmental and decisional documents.
(d) As an independent regulatory agency, the Commission functions as a neutral, quasi-judicial body, rendering decisions on applications filed with it, and resolving issues among parties appearing before it, including Indian tribes. Therefore, the provisions of the Administrative Procedure Act and the Commission’s rules concerning off-the-record communications, as well as the nature of the Commission’s licensing and certificating processes and of the Commission’s review of jurisdictional rates, terms and conditions, place some limitations on the nature and type of consultation that the Commission may engage in with any party in a contested case. Nevertheless, the Commission will endeavor, to the extent authorized by law, to reduce procedural impediments to working directly and effectively with tribal governments.
(e) The Commission, in keeping with its trust responsibility, will assure that tribal concerns and interests are considered whenever the Commission’s actions or decisions have the potential to adversely affect Indian tribes, Indian trust resources, or treaty rights. The Commission will use the agency’s environmental and decisional documents to communicate how tribal input has been considered.
(f) The Commission will seek to engage tribes in high-level meetings to discuss general matters of importance, such as those that uniquely affect the tribes. Where appropriate, these meetings may be arranged for particular tribes, by region, or in some proceedings involving hydroelectric projects, by river basins.
(g) The Commission will strive to develop working relationships with tribes and will seek to establish procedures to educate Commission staff about tribal governments and cultures and to educate tribes about the Commission’s various statutory functions and programs. To assist in this effort, the Commission is establishing the position of tribal liaison. The tribal liaison will provide a point of contact and a resource for tribes for any proceeding at the Commission.
(h) Concurrently with this policy statement, the Commission is issuing certain new regulations regarding the licensing of hydroelectric projects. In this connection, the Commission sets forth the following additional policies for the hydroelectric licensing process.
(i) The Commission believes that the hydroelectric licensing process will benefit by more direct and substantial consultation between the Commission staff and Indian tribes. Because of the unique status of Indian tribes in relation to the Federal government, the Commission will endeavor to increase direct communications with tribal representatives in appropriate circumstances, recognizing that different issues and stages of a proceeding may call for different approaches, and there are some limitations that must be observed.
(j) The Commission will seek to notify potentially-affected tribes about upcoming hydroelectric licensing processes, to discuss the consultation process and the importance of tribal participation, to learn more about each tribe’s culture, and to establish case-by-case consultation procedures consistent with our ex parte rules.
(k) In evaluating a proposed hydroelectric project, the Commission will consider any comprehensive plans prepared by Indian tribes or inter-tribal organizations for improving, developing, or conserving a waterway or waterways affected by a proposed project. The Commission will treat as a comprehensive plan, a plan that:
(1) Is a comprehensive study of one or more of the beneficial uses of a waterway or waterways;
(2) Includes a description of the standards applied, the data relied upon, and the methodology used in preparing the plan; and
(3) Is filed with the Secretary of the Commission. See generally 18 CFR 2.19.
Statements of General Policy and Interpretations Under the Federal Power Act
§ 2.2 Transmission lines.
In a public statement dated March 7, 1941, the Commission announced its determination that transmission lines which are not primary lines transmitting power from the power house or appurtenant works of a project to the point of junction with the distribution system or with the interconnected primary transmission system as set forth in section 3(11) of the Act are not within the licensing authority of the Commission, and directed that future applications filed with it for such licenses be referred for appropriate action to the Federal department having supervision over the lands or waterways involved.
§ 2.4 Suspension of rate schedules.
The Commission approved and adopted on May 29, 1945, the following conclusions as to its powers of suspension of rate schedules under section 205 of the act:
(a) The Commission cannot suspend a rate schedule after its effective date.
(b) The Commission can suspend any new schedule making any change in an existing filed rate schedule, including any rate, charge, classification, or service, or in any rule, regulation, or contract relating thereto, contained in the filed schedule.
(c) Included in such changes which may be suspended are:
(1) Increases.
(2) Reductions.
(3) Discriminatory changes.
(4) Cancellation or notice of termination.
(5) Changes in classification, service, rule, regulation or contract.
(d) Immaterial, unimportant or routine changes will not be suspended.
(e) During suspension, the prior existing rate schedule continues in effect and should not be changed during suspension.
(f) Changes under escalator clauses may be suspended as changes in existing filed schedules.
(g) Suspension of a rate schedule, within the ambit of the Commission’s statutory authority is a matter within the discretion of the Commission.
§ 2.7 Recreational development at licensed projects.
The Commission will evaluate the recreational resources of all projects under Federal license or applications therefor and seek, within its authority, the ultimate development of these resources, consistent with the needs of the area to the extent that such development is not inconsistent with the primary purpose of the project. Reasonable expenditures by a licensee for public recreational development pursuant to an approved plan, including the purchase of land, will be included as part of the project cost. The Commission will not object to licensees and operators of recreational facilities within the boundaries of a project charging reasonable fees to users of such facilities in order to help defray the cost of constructing, operating, and maintaining such facilities. The Commission expects the licensee to assume the following responsibilities:
(a) To acquire in fee and include within the project boundary enough land to assure optimum development of the recreational resources afforded by the project. To the extent consistent with the other objectives of the license, such lands to be acquired in fee for recreational purposes shall include the lands adjacent to the exterior margin of any project reservoir plus all other project lands specified in any approved recreational use plan for the project.
(b) To develop suitable public recreational facilities upon project lands and waters and to make provisions for adequate public access to such project facilities and waters and to include therein consideration of the needs of persons with disabilities in the design and construction of such project facilities and access.
(c) To encourage and cooperate with appropriate local, State, and Federal agencies and other interested entities in the determination of public recreation needs and to cooperate in the preparation of plans to meet these needs, including those for sport fishing and hunting.
(d) To encourage governmental agencies and private interests, such as operators of user-fee facilities, to assist in carrying out plans for recreation, including operation and adequate maintenance of recreational areas and facilities.
(e) To cooperate with local, State, and Federal Government agencies in planning, providing, operating, and maintaining facilities for recreational use of public lands administered by those agencies adjacent to the project area.
(f)(1) To comply with Federal, State and local regulations for health, sanitation, and public safety, and to cooperate with law enforcement authorities in the development of additional necessary regulations for such purposes.
(2) To provide either by itself or through arrangement with others for facilities to process adequately sewage, litter, and other wastes from recreation facilities including wastes from watercraft, at recreation facilities maintained and operated by the licensee or its concessionaires.
(g) To ensure public access and recreational use of project lands and waters without regard to race, color, sex, religious creed or national origin.
(h) To inform the public of the opportunities for recreation at licensed projects, as well as of rules governing the accessibility and use of recreational facilities.
§ 2.8 [Reserved]
§ 2.9 Conditions in preliminary permits and licenses—list of and citations to “P—” and “L—” forms.
(a) The Commission has approved several sets of standard conditions for normal inclusion in preliminary permits or licenses for hydroelectric developments. In a special situation, of course, the Commission in issuing a permit or license for a project will modify or eliminate a particular article (condition). For reference purposes the sets of conditions are designated as “Forms”—those for preliminary permits are published in Form P–1, and those for licenses are published in Form L’s. There are different Form L’s for different types of licenses, and the forms have been revised from time to time. Thus at any given time there will be several series of standard forms applicable to the various vintages of different types of licenses. The forms and their revisions are published on the Commission’s Web site (www.ferc.gov/industries/hydropower/gen-info/comp-admin/l-forms.asp).
(b) Forms currently in use may be obtained on the Commission’s Web site or from Federal Energy Regulatory Commission, Washington, DC 20426.
§ 2.12 Calculation of taxes for property of public utilities and licensees constructed or acquired after January 1, 1970.
Pursuant to the provisions of section 441(a)(4)(A) of the Tax Reform Act of 1969, 83 Stat. 487, 625, public utilities and licensees regulated by the Commission under the Federal Power Act which have exercised the option provided by that section to change from flow through accounting will be permitted by the Commission, with respect to liberalized depreciation, to employ a normalization method for computing federal income taxes in their accounts and annual reports with respect to property constructed or acquired after January 1, 1970, to the extent with which such property increases the productive or operational capacity of the utility and is not a replacement of existing capacity. Such normalization will also be permitted for ratemaking purposes to the extent such rates are subject to the Commission’s ratemaking authority. As to balances in Account 282 of the Uniform System of Accounts, “Accumulated deferred income taxes—Other property,” it will remain the Commission’s policy to deduct such balances from rate base in rate proceedings.
§ 2.13 Design and construction.
(a) The Commission recognizes the importance of protecting and enhancing natural, historic, scenic, and recreational values at projects licensed or proposed to be licensed under the Federal Power Act.
(b) In furtherance of these policies, the Commission will not (1) permit the amendment of any license for the purpose of construction of additional facilities or (2) authorize the disposition of any interest in project lands for construction of any type, unless a showing is made that the construction will be designed to avoid or minimize conflict with the natural, historic, and scenic values and resources of the project area.
§ 2.15 Specified reasonable rate of return.
(a) Pursuant to section 10(d) of the Federal Power Act, the Commission has determined that the specified reasonable rate of return used in computing amortization reserves for hydroelectric project licenses shall be calculated annually based on current capital ratios developed from an average of 13 monthly balances of amounts properly includible in the licensee’s long-term debt and proprietary capital accounts, as listed in the Commission’s Uniform System of Accounts. The cost rate for such ratios shall be the weighted average cost of long-term debt and preferred stock for the year, and the cost of common equity shall be the interest rate on 10-year government bonds (reported as the Treasury Department’s 10-year constant maturity series) computed on the monthly average for the year in question, plus four percentage points (400 basis points).
(b) The Statement of Policy adopted herein shall be effective upon issuance of this order.
(c) The Secretary shall cause prompt publication of this order to be made in the
(d) All requests and suggestions not specifically dealt with herein are hereby denied.
(e) The Secretary is hereby authorized to change the appropriate license article upon application by the licensees to reflect the specified reasonable rate of return as adopted herein.
§ 2.17 Price discrimination and anticompetitive effect (price squeeze issue).
To implement compliance with the Supreme Court decision in F.P.C. v. Con-Way Corp., 426 U.S. 271 (1976), aff’g 510 F. 2d 1264 (D.C. Cir. 1975) and to expedite the consideration of price squeeze issues in wholesale electric rate proceedings, the Commission adopts the following procedures for raising price squeeze issues which are to be followed unless they are demonstrated in an individual case to be inadequate:
(a) Any wholesale customer, state commission or other interested person may file petitions to intervene alleging price discrimination and anticompetitive effects of the wholesale rates. In order to have the issue of price discrimination considered in the rate proceeding, the intervening customer or other interested person must support its allegation by a prima facie case. The elements of the prima facie case shall include at a minimum:
(1) Specification of the filing utility’s retail rate schedules with which the intervening wholesale customer is unable to compete due to purchased power costs;
(2) A showing that a competitive situation exists in that the wholesale customer competes in the same market as the filing utility;
(3) A showing that the retail rates are lower than the proposed wholesale rates for comparable service;
(4) The wholesale customer’s prospective rate for comparable retail service, i.e. the rate necessary to recover bulk power costs (at the proposed wholesale rate) and distribution costs;
(5) An indication of the reduction in the wholesale rate necessary to eliminate the price squeeze alleged.
(b) Where price squeeze is alleged, the Commission shall, in the order granting intervention, direct the Administrative Law Judge to convene a prehearing conference within 15 days from the date of the order for the purpose of hearing intervenors’ request for data required to present their case, including prima facie showing, on price squeeze issues.
(c) Within 30 days from the date of the conference the filing utility shall respond to the data requests authorized by the Administrative Law Judge.
(d) Within 30 days from the filing utility’s response, the intervenors shall file their case-in-chief on price squeeze issues, which shall include their prima facie case, unless filed previously.
(e) The burden of proof (i.e. the risk of nonpersuasion) to rebut the allegations of price squeeze and to justify the proposed rates are on the utility proposing the rates under section 205(e) of the Federal Power Act.
(f) In proceedings where price squeeze is an issue, the Secretary shall include the state commission, agency or body which is responsible for regulation of retail rates in the state affected in the service list maintained under § 385.2010(c) of this chapter.
§ 2.18 Phased electric rate increase filings.
(a) In general, when a public utility files a phased rate increase, the Commission will determine the appropriate suspension period based on the total increase requested in all phases. If a utility files a rate increase within sixty days after filing another rate increase, the Commission will consider the filings together to be a phased rate increase request.
(b) This policy will not be applied if the increase is phased:
(1) To coordinate with new facilities coming on line;
(2) To implement a rate moderation plan;
(3) To avoid price squeeze;
(4) To comply with a settlement approved by the Commission; or
(5) If the utility makes a convincing showing that application of the policy would be harsh and inequitable and that, therefore, good cause has been shown not to apply the policy in the case.
§ 2.19 State and Federal comprehensive plans.
(a) In determining whether the proposed hydroelectric project is best adapted to a comprehensive plan under section (10)(a)(1) of the Federal Power Act for improving or developing a waterway, the Commission will consider the extent to which the project is consistent with a comprehensive plan (where one exists) for improving, developing, or conserving a waterway or waterways affected by the project that is prepared by:
(1) An agency established pursuant to Federal law that has the authority to prepare such a plan, or
(2) A state agency, of the state in which the facility is or will be located, authorized to conduct such planning pursuant to state law.
(b) The Commission will treat as a state or Federal comprehensive plan a plan that:
(1) Is a comprehensive study of one or more of the beneficial uses of a waterway or waterways;
(2) Includes a description of the standards applied, the data relied upon, and the methodology used in preparing the plan; and
(3) Is filed with the Secretary of the Commission.
§ 2.20 Good faith requests for transmission services and good faith responses by transmitting utilities.
(a) General Policy. (1) This Statement of Policy is adopted in furtherance of the goals of sections 211(a) and 213(a) of the Federal Power Act, as amended and added by the Energy Policy Act of 1992.
(2) Under section 211(a), the Commission may issue an order requiring a transmitting utility to provide transmission services (including any enlargement of transmission capacity necessary to provide such services) only if an applicant has made a request for transmission services to the transmitting utility that would be the subject of such order at least 60 days prior to its filing of an application for such order. The requirement in section 211(a) that an applicant make such a request will be met if such an applicant has, pursuant to section 213(a) of the FPA, made a good faith request to a transmitting utility to provide wholesale transmission services and requests specific rates and charges, and other terms and conditions.
(3) It is the Commission’s intention to apply the standards of this Statement of Policy when determining whether and when a valid “good faith” request for service was made.
(4) It is the Commission’s intention to encourage an open exchange of information that exhibits a reasonable degree of specificity and completeness between the party requesting transmission services and the transmitting utility.
(5) The Commission intends to apply this Statement of Policy so as to carry out Congress’ objective that, subject to appropriate terms and conditions and just and reasonable rates, in conformance with section 212 of the FPA, access to the electric transmission system for the purposes of wholesale transactions be more widely available.
(b) The Components of a good faith request. The Commission generally considers the following to constitute the minimum components of a good faith request for transmission services:
(1) The identity, address, telephone number, and facsimile number of the party requesting transmission services, and the same information, if different, for the party’s contact person or persons.
(2) A statement that the party requesting transmission services is, or will be upon commencement of service, an entity eligible to request transmission under sections 211(a) and 213(a) of the FPA.
(3) A statement that the request for transmission services is intended to satisfy the “request for transmission services” requirement under sections 211(a) and 213(a) of the FPA, and that the request is not a request for mandatory retail wheeling prohibited under section 212(h) of the FPA.
(4) The party requesting transmission services should specify the character and nature of the services requested. Some types of service may require more detailed information than others. Where point-to-point service is requested, the party requesting transmission services should specify the anticipated point(s) of receipt to the transmitting utility’s grid and the anticipated point(s) of delivery from the transmitting utility’s grid. Where a party requesting transmission services requests additional flexibility to schedule multiple resources to meet its needs (e.g., network service), the request for services should contain a description of the requested services in sufficient detail to permit the transmitting utility to model the additional services on its transmission system.
(5) The names of any other parties likely to provide transmission service to deliver electric energy to, and receive electric energy from, the transmitting utility’s grid in connection with the requested transmission services.
(6) The proposed dates for initiating and terminating the requested transmission services.
(7) The total amount of transmission capacity being requested.
(8) To the extent it is known or can be estimated, a description of the “expected transaction profile” including load factor data describing the hourly quantities of power and energy the party requesting transmission services would expect to deliver to the transmitting utility’s grid at relevant points of interconnection. In the event delivery is to multiple points within the transmitting utility’s electric control area, the requestor should describe, to the extent it is known or can be estimated, the expected load (over a given duration of time) at each such delivery point.
(9) Whether firm or non-firm service is being requested. Where a party requests non-firm service, it should specify the priority of service it is willing to accept, or the conditions under which it is willing to accept interruption or curtailment, if known.
(10) A statement as to whether the request is being made in response to a solicitation and a copy of the solicitation if publicly available. This will help the transmitting utility determine whether requests for transmission service are duplicative or mutually exclusive of requests filed by other parties.
(11) The proposed rates, terms and conditions for the requested transmission services as required by section 213(a). It is not necessary for the requestor to propose a specific numerical rate. Rather, a party requesting transmission services can fulfill the rates, terms and conditions requirement by specifying a rate methodology (e.g., embedded or incremental cost) or by referencing an existing formula rate, transmission tariff, or transmission contract. The validity of the good faith request will not depend on the rates proposed by the party requesting transmission services. This requirement is not intended to allow utilities to delay responses to requests for transmission services, or to deny requests for transmission services on the basis of an overly rigid or technical approach to the “rates, terms and conditions” element of the request.
(12) Any other information to facilitate the expeditious processing of its request. Such information will improve the negotiation process, reduce costs, and will improve chances to arrange the requested transmission without resorting to section 211 application procedures before the Commission.
(c) Components of a Reply to a Good Faith Request. The Commission generally considers the following to constitute the minimum components of a reply to a good faith request for transmission services under section 213(a):
(1) Unless the parties agree to a different time frame, the transmitting utility must acknowledge the request within 10 days of receipt. The acknowledgement must include a date by which a response will be sent to the party requesting transmission services and a statement of any fees associated with responding to the request (e.g., initial studies).
(2) The transmitting utility may ask the applicant to provide clarification of only the information needed to evaluate and process a “good faith” request. If the person requesting transmission services believes the transmitting utility is attempting to frustrate the process by making excessive requests for clarification, it may raise this issue if, and when, it files a request for a section 211 order with the Commission.
(3) The transmitting utility must respond to a request within 60 days of receipt or some other mutually agreed upon response date. If both parties agree to an alternative schedule, the agreement must be in writing and signed by both parties.
(4) If the transmitting utility determines that it can provide all the requested services from existing capacity, it should respond by offering the party requesting transmission services an executable service agreement that at a minimum contains the following information:
(i) A description of the proposed transmission rate and any other costs. It is not necessary for the proposed service agreement to contain a fully developed cost-of-service. However, the agreement should explain the basis for the charges for each component of service, including the unbundled components of any transmission rate as well as any other charges.
(ii) The proposed service agreement should explicitly describe all of the applicable terms and conditions of the transmission services provided under the agreement.
(iii) The transmitting utility should accompany the proposed service agreement with a clear statement of the time during which the offer to provide the transmission services will remain open. An open agreement offer may obligate the seller while imposing no countervailing obligation on the purchaser, and an unexecuted contract potentially ties up transmission facilities, thus jeopardizing the availability and price for subsequent requests that would use the same facilities. However, at a minimum, a transmitting utility should permit the party requesting transmission services sufficient time to review service agreements and coordinate multiple stages of joint transactions.
(5) If the transmitting utility determines that it must construct additional facilities or modify existing facilities to provide all or part of the requested services, it must:
(i) Identify the specific constraints and their duration that prevent it from providing all the requested services and explain how these constraints prevent it from providing all the requested services or the desired level of firmness.
(ii) Provide to the applicant all studies, computer input and output data, planning, operating and other documents, work papers, assumptions and any other material that forms the basis for determining the constraints.
(iii) Offer to the applicant an executable agreement under which the applicant agrees to reimburse the transmitting utility for all costs of performing any studies necessary to determine what changes to the transmitting utility’s grid are needed to overcome the constraint and provide the requested services, their cost, and the estimated time to complete them. At a minimum, the proposed agreement should contain the following:
(A) An estimate of the cost of the study and the time required to complete it, and
(B) A commitment to supply to the party requesting transmission services all computer input and output data, planning, operating and other documents, work papers, assumptions and any other material used to perform the study.
(iv) If a transmitting utility determines that it can provide part but not all of the requested services without building new facilities, it should inform the applicant of any portion of the requested services that can be performed without constructing additional facilities or modifying existing facilities. In effect, the transmitting utility may be able to treat such a request as two separate transactions—one for service on existing facilities and the other as a request involving expansion decisions. Furthermore, where there are alternative, less expensive means of satisfying all or a portion of a transmission request, the Commission expects the transmitting utility to explore such alternatives (e.g., redispatching certain generating units to alleviate a constraint).
§ 2.21 Regional Transmission Groups.
(a) General policy. The Commission encourages Regional Transmission Groups (RTGs) as a means of enabling the market for electric power to operate in a more competitive and efficient way. The Commission believes that RTGs can provide a means of coordinating regional planning of the transmission system and assuring that system capabilities are always adequate to meet system demands. RTG agreements that contain components that satisfy paragraphs (b) and (c) of this section generally will be considered to be just, reasonable, and not unduly discriminatory or preferential under the Federal Power Act (FPA). The Commission encourages RTG agreements that contain as much detail as possible in all of the components listed, particularly if the RTG participants will be seeking Commission deference to decisions reached under an RTG agreement.
(b) Organizational components. (1) An RTG agreement should provide for broad membership and, at a minimum, allow any entity that is subject to, or eligible to apply for, an order under section 211 of the FPA to be a member. An RTG agreement should encompass an area of sufficient size and contiguity to enable members to provide transmission services in a reliable, efficient, and competitive manner.
(2) An RTG agreement should provide a means of adequate consultation and coordination with relevant state regulatory, siting, and other authorities.
(3) An RTG agreement should include fair and nondiscriminatory governance and decision making procedures, including voting procedures.
(c) Other components. (1) An RTG agreement should impose on member transmitting utilities an obligation to provide transmission services for other members, including the obligation to enlarge facilities, on a basis that is consistent with sections 205, 206, 211, 212 and 213 of the FPA. To the extent practicable and known, the RTG agreement should specify the terms and conditions under which transmission services will be offered.
(2) An RTG agreement should require, at a minimum, the development of a coordinated transmission plan on a regional basis and the sharing of transmission planning information, with the goal of efficient use, expansion, and coordination of the interconnected electric system on a grid-wide basis. An RTG agreement should provide mechanisms to incorporate the transmission needs of non-members into regional plans. An RTG agreement should include as much detail as possible with regard to operational and planning procedures.
(3) An RTG agreement should include voluntary dispute resolution procedures that provide a fair alternative to resorting in the first instance to section 206 complaints or section 211 proceedings.
(4) An RTG agreement should include an exit provision for RTG members that leave the RTG, specifying the obligations of a departing member.
(d) Filing procedures. Any proposed RTG agreement that in any manner affects or relates to the transmission of electric energy in interstate commerce by a public utility, or rates or charges for such transmission, must be filed with the Commission. Any public utility member of a proposed RTG may file the RTG agreement with the Commission on behalf of the other public utility members under section 205 of the FPA.
§ 2.22 Pricing policy for transmission services provided under the Federal Power Act.
(a) The Commission has adopted a Policy Statement on its pricing policy for transmission services provided under the Federal Power Act. That Policy Statement can be found at 69 FERC 61,086. The Policy Statement constitutes a complete description of the Commission’s guidelines for assessing the pricing proposals. Paragraph (b) of this section is only a brief summary of the Policy Statement.
(b) The Commission endorses transmission pricing flexibility, consistent with the principles and procedures set forth in the Policy Statement. It will entertain transmission pricing proposals that do not conform to the traditional revenue requirement as well as proposals that conform to the traditional revenue requirement. The Commission will evaluate “conforming” transmission pricing proposals using the following five principles, described more fully in the Policy Statement.
(1) Transmission pricing must meet the traditional revenue requirement.
(2) Transmission pricing must reflect comparability.
(3) Transmission pricing should promote economic efficiency.
(4) Transmission pricing should promote fairness.
(5) Transmission pricing should be practical.
(c) Under these principles, the Commission will also evaluate “non-conforming” proposals which do not meet the traditional revenue requirement, and will require such proposals to conform to the comparability principle. Non-conforming proposals must include an open access comparability tariff and will not be allowed to go into effect prior to review and approval by the Commission under procedures described in the Policy Statement.
The Commission will address and consider cumulative impact issues at original licensing and relicensing to the fullest extent possible consistent with the Commission’s statutory responsibility to avoid undue delay in the relicensing process and to avoid undue delay in the amelioration of individual project impacts at relicensing. To the extent, if any, that it is not possible to explore and address all cumulative impacts at relicensing, the Commission will reserve authority to examine and address such impacts after the new license has been issued, but will define that reserved authority as narrowly and with as much specificity as possible, particularly with respect to the purpose of reserving that authority. The Commission intends that such articles will describe, to the maximum extent possible, reasonably foreseeable future resource concerns that may warrant modifications of the licensed project. Before taking any action pursuant to such reserved authority, the Commission will publish notice of its proposed action and will provide an opportunity for hearing by the licensee and all interested parties. Hydropower licenses also contain standard “reopener” articles (see § 2.9 of this part) which reserve authority to the Commission to require, among other things, licensees of projects located in the same river basin to mitigate the cumulative impacts of those projects on the river basin. In light of the policy described above, the Commission will use the standard “reopener” articles to explore and address cumulative impacts only (except in extraordinary circumstances) where such impacts were not known at the time of licensing or are the result of changed circumstances. The Commission has authority under the Federal Power Act to require licensees, during the term of the license, to develop and provide data to the Commission on the cumulative impacts of licensed projects located in the same river basin. In issuing both new and original licenses, the Commission will coordinate the expiration dates of the licenses to the maximum extent possible, to maximize future consideration of cumulative impacts at the same time in contemporaneous proceedings at relicensing. The Commission’s intention is to consider to the extent practicable cumulative impacts at the time of licensing and relicensing, and to eliminate the need to resort to the use of reserved authority.
§ 2.24 Project decommissioning at relicensing.
The Commission issued a statement of policy on project decommissioning at relicensing in Docket No. RM93–23–000 on December 14, 1994.
§ 2.25 Ratemaking treatment of the cost of emissions allowances in coordination transactions.
(a) General Policy. This Statement of Policy is adopted in furtherance of the goals of Title IV of the Clean Air Act Amendments of 1990, Pub. L. 101–549, Title IV, 104 Stat. 2399, 2584 (1990).
(b) Costing Emissions Allowances in Coordination Sales. If a public utility’s coordination rate on file with the Commission provides for recovery of variable costs on an incremental basis, the Commission will allow recovery of the incremental costs of emissions allowances associated with a coordination sale. If a coordination rate does not reflect incremental costs, the public utility should propose alternative allowance costing methods or demonstrate that the coordination rate does not produce unreasonable results. The Commission finds that the cost to replace an allowance is an appropriate basis to establish the incremental cost.
(c) Use of Indices. The Commission will allow public utilities to determine emissions allowance costs on the basis of an index or combination of indices of the current price of emissions allowances, provided that the public utility affords purchasing utilities the option of providing emissions allowances. Public utilities should explain and justify any use of different incremental cost indices for pricing coordination sales and making dispatch decisions.
(d) Calculation of Amount of Emissions Allowances Associated With Coordination Transactions. Public utilities should explain the methods used to compute the amount of emissions allowances included in coordination transactions.
(e) Timing. (1) Public utilities should provide information to purchasing utilities regarding the timing of opportunities for purchasers to stipulate whether they will purchase or return emissions allowances. A public utility may require a purchasing utility to declare, no later than the beginning of the coordination transaction:
(i) Whether it will purchase or return emissions allowances; and
(ii) If it will return emissions allowances, the date on which those allowances will be returned.
(2) Public utilities may include in agreements with purchasing utilities non-discriminatory provisions for indemnification if the purchasing utility fails to provide emissions allowances by the date on which it declares that the allowances will be returned.
(f) Other Costing Methods Not Precluded. The ratemaking treatment of emissions allowance costs endorsed in this Policy Statement does not preclude other approaches proposed by individual utilities on a case-by-case basis.
§ 2.26 Policies concerning review of applications under section 203.
(a) The Commission has adopted a Policy Statement on its policies for reviewing transactions subject to section 203. That Policy Statement can be found at 77 FERC ¶ 61,263 (1996). The Policy Statement is a complete description of the relevant guidelines. Paragraphs (b)–(e) of this section are only a brief summary of the Policy Statement.
(b) Factors Commission will generally consider. In determining whether a proposed transaction subject to section 203 is consistent with the public interest, the Commission will generally consider the following factors; it may also consider other factors:
(1) The effect on competition;
(2) The effect on rates; and
(3) The effect on regulation.
(c) Effect on competition. Applicants should provide data adequate to allow analysis under the Department of Justice/Federal Trade Commission Merger Guidelines, as described in the Policy Statement and Appendix A to the Policy Statement.
(d) Effect on rates. Applicants should propose mechanisms to protect customers from costs due to the merger. If the proposal raises substantial issues of relevant fact, the Commission may set this issue for hearing.
(e) Effect on regulation. (1) Where the affected state commissions have authority to act on the transaction, the Commission will not set for hearing whether the transaction would impair effective regulation by the state commissions. The application should state whether the state commissions have this authority.
(2) Where the affected state commissions do not have authority to act on the transaction, the Commission may set for hearing the issue of whether the transaction would impair effective state regulation.
(f) Under section 203(a)(4) of the Federal Power Act (16 U.S.C. 824b), in reviewing a proposed transaction subject to section 203, the Commission will also consider whether the proposed transaction will result in cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company, unless that cross-subsidization, pledge, or encumbrance will be consistent with the public interest.
Non-Mandatory Guidance on Smart Grid Standards
§ 2.27 Availability of North American Energy Standards Board (NAESB) Smart Grid Standards as non-mandatory guidance.
The Commission informationally lists the following NAESB Business Practices Standards as non-mandatory guidance:
(a) WEQ–016, Specifications for Common Electricity Product and Pricing Definition, WEQ Version 003, July 31, 2012;
(b) WEQ–017, Specifications for Common Schedule Communication Mechanism for Energy Transactions, WEQ Version 003, July 31, 2012;
(c) WEQ–018, Specifications for Wholesale Standard Demand Response Signals (WEQ Version 003.2, Dec. 8, 2017);
(d) WEQ–019, Customer Energy Usage Information Communication (WEQ Version 003.1, Sep. 30, 2015); and
(e) WEQ–020, Smart Grid Standards Data Element Table, WEQ Version 003, July 31, 2012.
(f) Copies of these standards may be obtained from the North American Energy Standards Board, 801 Travis Street, Suite 1675, Houston, TX 77002, Tel: (713) 356–0060. NAESB’s website is at https://www.naesb.org/. Copies may also be obtained from the Federal Energy Regulatory Commission’s website, https://www.ferc.gov.
Statements of General Policy and Interpretations Under the Natural Gas Act
§ 2.51 [Reserved]
§ 2.52 Suspension of rate schedules.
The interpretation stated in § 2.4 applies as well to the suspension of rate schedules under section 4 of the Natural Gas Act.
§ 2.55 Auxiliary installations and replacement facilities.
For the purposes of section 7(c) of the Natural Gas Act, as amended, the word facilities as used therein shall be interpreted to exclude:
(a) Auxiliary installations. (1) Installations (excluding gas compressors) which are merely auxiliary or appurtenant to an authorized or proposed transmission pipeline system and which are installations only for the purpose of obtaining more efficient or more economical operation of the authorized or proposed transmission facilities, such as: Valves; drips; pig launchers/receivers; yard and station piping; cathodic protection equipment; gas cleaning, cooling and dehydration equipment; residual refining equipment; water pumping, treatment and cooling equipment; electrical and communication equipment; and buildings. The auxiliary installations must be located within the existing or proposed certificated permanent right-of-way or authorized facility site and must be constructed using the temporary work space used to construct the existing or proposed facility (see Appendix A to this Part 2 for guidelines on what is considered to be the appropriate work area in this context).
(2) Advance notification. One of the following requirements will apply to any specified auxiliary installation. If auxiliary facilities are to be installed:
(i) On existing transmission facilities, then no notification is required;
(ii) On, or at the same time as, certificated facilities which are not yet in service (except those authorized under the automatic procedures of part 157 of subpart F of this chapter), then a description of the auxiliary facilities and their locations must be provided to the Commission at least 30 days in advance of their installation; or
(iii) On, or at the same time as facilities that are proposed, then the auxiliary facilities must be described in the environmental report specified in § 380.12 or in a supplemental filing while the application is pending.
(3) Abandonment or replacement of auxiliary installations. Authorization to abandon or replace auxiliary facilities that were or could be installed under paragraph (a)(1) of this section is pre-granted under section 7(b) of the Natural Gas Act, and no reporting is required, provided that:
(i) All activities will be confined to areas, including temporary work space, previously authorized by the Commission for the construction and operation of facilities at that location;
(ii) All activities will comply with applicable conditions on certificate authorizations for the construction and operation of facilities at that location; and
(iii) The abandonment or replacement will have no adverse impact on customers’ certificated services.
(b) Replacement of facilities. (1) Facilities which constitute the replacement of existing facilities that have or will soon become physically deteriorated or obsolete, to the extent that replacement is deemed advisable, if:
(i) The replacement will not result in a reduction or abandonment of service through the facilities;
(ii) The replacement facilities will have a substantially equivalent designed delivery capacity, will be located in the same right-of-way or on the same site as the facilities being replaced, and will be constructed using the temporary work space used to construct the existing facility (see Appendix A to Part 2 for guidelines on what is considered to be the appropriate work area in this context);
(iii) Except as described in paragraph (b)(2) of this section, the company files notification of such activity with the Commission at least 30 days prior to commencing construction.
(2) Advance notification not required. The advance notification described in paragraph (b)(1)(iii) of this section is not required if:
(i) The cost of the replacement project does not exceed the cost limit specified in Column 1 of Table I of § 157.208(d) of this chapter; or
(ii) U.S. Department of Transportation safety regulations require that the replacement activity be performed immediately;
(3) Contents of the advance notification. The advance notification described in paragraph (b)(1)(iii) of this section must include the following information:
(i) A brief description of the facilities to be replaced (including pipeline size and length, compression horsepower, design capacity, and cost of construction);
(ii) Current U.S. Geological Survey 7.5-minute series topographic maps showing the location of the facilities to be replaced; and
(iii) A description of the procedures to be used for erosion control, revegetation and maintenance, and stream and wetland crossings.
(4) Annual report. On or before May 1 of each year, a company must file (in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov.) an annual report that lists for the previous calendar year each replacement project that was completed pursuant to paragraph (b)(1) of this section and that was exempt from the advance notification requirement pursuant to paragraph (b)(2) of this section. For each such replacement project, the company must include all of the information described in paragraph (b)(3) of this section. Exception. A company does not have to include in this annual report any above-ground replacement project that did not involve compression facilities or the use of earthmoving equipment.
(c) Landowner notification. (1)(i) No activity described in paragraphs (a) and (b) of this section that involves ground disturbance is authorized unless a company makes a good faith effort to notify in writing each affected landowner, as noted in the most recent county/city tax records as receiving the tax notice, whose property will be used and subject to ground disturbance as a result of the proposed activity, at least five days prior to commencing any activity under this section. A landowner may waive the five-day prior notice requirement in writing, so long as the notice has been provided. No landowner notice under this section is required:
(A) If all ground disturbance will be confined entirely to areas within the fence line of an existing above-ground site of facilities operated by the company; or
(B) For activities done for safety, DOT compliance, or environmental or unplanned maintenance reasons that are not foreseen and that require immediate attention by the company.
(ii) The notification shall include at least:
(A) A brief description of the facilities to be constructed or replaced and the effect the activity may have on the landowner’s property;
(B) The name and phone number of a company representative who is knowledgeable about the project; and
(C) A description of the Commission’s Landowner Helpline, which an affected person may contact to seek an informal resolution of a dispute as explained in § 1b.22(a) of this chapter and the Landowner Helpline number.
(2) “Affected landowners” include owners of interests, as noted in the most recent county/city tax records as receiving tax notice, in properties (including properties subject to rights-of-way and easements for facility sites, compressor stations, well sites, and all above-ground facilities, and access roads, pipe and contractor yards, and temporary work space) that will be directly affected by (i.e., used) and subject to ground disturbance as a result of activity under this section.
(d) [Reserved]
§ 2.57 Temporary certificates—pipeline companies.
The Federal Energy Regulatory Commission will exercise the emergency powers set forth in the second proviso of section 7(c) of the Natural Gas Act to authorize in appropriate cases, by issuance of temporary certificates, comparatively minor enlargements or extensions of an existing pipeline system. It will not be the policy of the Commission, however, to proceed summarily, i.e., without notice or hearing, in cases where the proposed construction is of major proportions. Pipeline companies are accordingly urged to conduct their planning and to submit their applications for authority sufficiently early so that compliance with the requirements relating to issuance of permanent certificates of public convenience and necessity (when those requirements are deemed applicable by the Commission) will not cause undue delay in the commencement of necessary construction.
The Commission, cognizant of the need of the natural gas industry for advice with respect to the applicability of the Natural Gas Act and the Commission’s regulations thereunder regarding activities and operations of natural gas companies taking security measures in preparation for a possible national emergency, sets forth the following interpretation and statement of policy:
(a) Facilities. The definition of auxiliary installations in § 2.55(a) for which no certificate authority is necessary includes such defense-related facilities as (1) fallout shelters at compressor stations and other operating and maintenance camps; (2) emergency company headquarters or other similar installations; and (3) emergency communication equipment.
(b) The Commission will consider reasonable investment in defense-related facilities, such as those described in paragraph (a) of this section, to be prudent investment for ratemaking purposes.
(c) When a person, not otherwise subject to the jurisdiction of the Commission, files an application for a certificate of public convenience and necessity authorizing the construction of facilities to be used solely for operation in a national emergency for the delivery of gas to, or receipt of gas from, a person subject to the Commission’s jurisdiction, the Commission will consider a request by such applicant for waiver of the requirement to keep and maintain its accounts in accordance with the Uniform System of Accounts for Natural Gas Companies (parts 201 and 204 of this chapter) or to file the annual reports to the Commission required by §§ 260.1 and 260.2 of this chapter.
§ 2.67 Calculation of taxes for property of pipeline companies constructed or acquired after January 1, 1970.
Pursuant to the provisions of section 441(a)(4)(A) of the Tax Reform Act of 1969, 83 Stat. 487, 625, natural gas pipeline companies which have exercised the option provided by that section to change from flow through accounting will be permitted by the Commission, with respect to liberalized depreciation, to employ a normalization method for computing Federal income taxes in their accounts and annual reports with respect to property constructed or acquired after January 1, 1970, to the extent to which such property increases the productive or operational capacity of the utility and is not a replacement of existing capacity. Such normalization will also be permitted for ratemaking purposes. As to balances in Account No. 282 of the Uniform System of Accounts, “Accumulated deferred income taxes—Other property,” it will remain the Commission’s policy to deduct such balances from the rate base of natural gas pipeline companies in rate proceedings.
§ 2.69 [Reserved]
§ 2.76 Regulatory treatment of payments made in lieu of take-or-pay obligations.
With respect to payments made to a first seller of natural gas as consideration for waiving or revising any agreement for the first sale of natural gas, as defined by section (2)(21) of the Natural Gas Policy Act (NGPA), the Commission sets forth the following statement of general policy and interpretation of law.
(a) Payments in consideration. A first seller of natural gas that receives payments as consideration for amending or waiving the take-or-pay or similar minimum payment provisions of a contract for the first sale of natural gas is not in violation of section 504(a) of the NGPA.
(b) Recovery in rates. A pipeline that makes any payments referred to under paragraph (a) of this section, to first sellers may file to recover such costs in any section 4(e) rate filing other than a filing to recover purchased gas costs.
(c) Case-specific review. A pipeline’s method of recovering these costs and how it should apportion them among customers will be addressed on a case-by-case basis in the context of individual rate case filings.
(d) Customers’ rights. When a pipeline seeks to recover payments referred to under paragraph (a) of this section, its customers will have the full opportunity contemplated by section 4 of the Natural Gas Act to raise questions as to the prudence of such payments, the apportionment of costs among customers proposed by the filing pipeline, and any other reasonably related matters.
(e) Certificate amendments and abandonment. With regard to natural gas the sale of which is subject to the Commission’s jurisdiction under the Natural Gas Act, if any payments referred to under paragraph (a) of this section are accompanied by a change in or a termination of, the first seller’s contractual obligation to provide natural gas service, the Commission will, as a general policy under sections 7(c) and 7(b) of the Natural Gas Act, expeditiously grant any certificate amendments or abandonment authorizations, required to effectuate such contractual or service modifications.
In cases where a producer abandonment application is based on payments made pursuant to this policy statement, the interstate pipeline making the payments will be deemed to have waived any right to oppose the abandonment.
§ 2.78 Utilization and conservation of natural resources—natural gas.
(a)(1) The national interests in the development and utilization of natural gas resources throughout the United States will be served by recognition and implementation of the following priority-of-service categories for use during periods of curtailed deliveries by jurisdictional pipeline companies:
(i) Residential, small commercial (less than 50 Mcf on a peak day).
(ii) Large commercial requirements (50 Mcf or more on a peak day), firm industrial requirements for plant protection, feedstock and process needs, and pipeline customer storage injection requirements.
(iii) All industrial requirements not specified in paragraph (a)(1)(ii), (iv), (v), (vi), (vii), (viii), or (ix) of this section.
(iv) Firm industrial requirements for boiler fuel use at less than 3,000 Mcf per day, but more than 1,500 Mcf per day, where alternate fuel capabilities can meet such requirements.
(v) Firm industrial requirements for large volume (3,000 Mcf or more per day) boiler fuel use where alternate fuel capabilities can meet such requirements.
(vi) Interruptible requirements of more than 300 Mcf per day, but less than 1,500 Mcf per day, where alternate fuel capabilities can meet such requirements.
(vii) Interruptible requirements of intermediate volumes (from 1,500 Mcf per day through 3,000 Mcf per day), where alternate fuel capabilities can meet such requirements.
(viii) Interruptible requirements of more than 3,000 Mcf per day, but less than 10,000 Mcf per day, where alternate fuel capabilities can meet such requirements.
(ix) Interruptible requirements of more than 10,000 Mcf per day, where alternate fuel capabilities can meet such requirements.
(2) The priorities-of-deliveries set forth above will be applied to the deliveries of all jurisdictional pipeline companies during periods of curtailment on each company’s system; except, however, that, upon a finding of extraordinary circumstances after hearing initiated by a petition filed under § 385.207 of this chapter, exceptions to those priorities may be permitted.
(3) The above list of priorities requires the full curtailment of the lower priority category volumes to be accomplished before curtailment of any higher priority volumes is commenced. Additionally, the above list requires both the direct and indirect customers of the pipeline that use gas for similar purposes to be placed in the same category of priority.
(4) The tariffs filed with this Commission should contain provisions that will reflect sufficient flexibility to permit pipeline companies to respond to emergency situations (including environmental emergencies) during periods of curtailment where supplemental deliveries are required to forestall irreparable injury to life or property.
(b) Request for relief from curtailment shall be filed under § 385.1501 of this chapter. Those petitions shall use the priorities set forth in (paragraph (a)(1) of this section) above, the definitions contained in paragraph (b)(3) of this section and shall contain the following minimal information:
(1) The specific amount of natural gas deliveries requested on peak day and monthly basis, and the type of contract under which the deliveries would be made.
(2) The estimated duration of the relief requested.
(3) A breakdown of all natural gas requirements on peak day and monthly bases at the plant site by specific end-uses.
(4) The specific end-uses to which the natural gas requested will be utilized and should also reflect the scheduling within each particular end-use with and without the relief requested.
(5) The estimated peak day and monthly volumes of natural gas which would be available with and without the relief requested from all sources of supply for the period specified in the request.
(6) A description of existing alternate fuel capabilities on peak day and monthly bases broken down by end-uses as shown in paragraph (b)(3) of this section.
(7) For the alternate fuels shown in paragraph (b)(5) of this section, provide a description of the existing storage facilities and the amount of present fuel inventory, names and addresses of existing alternate fuel suppliers, and anticipated delivery schedules for the period for which relief is sought.
(8) The current price per million Btu for natural gas supplies and alternate fuels supplies.
(9) A description of efforts to secure natural gas and alternate fuels, including documentation of contacts with the Federal Energy Office and any state or local fuel allocation agencies or public utility commission.
(10) A description of all fuel conservation activities undertaken in the facility for which relief is sought.
(11) If petitioner is a local natural gas distributor, a description of the currently effective curtailment program and details regarding any flexibility which may be available by effectuating additional curtailment to its existing industrial customers. The distributor should also provide a breakdown of the estimated disposition of its natural gas estimated to be available by end-use priorities established in paragraph (a)(1) of this section for the period for which relief is sought.
(c) When used in paragraphs (a) and (b) of this section, the following terms will be defined as follows:
(1) Residential. Service to customers which consists of direct natural gas usage in a residential dwelling for space heating, air conditioning, cooking, water heating, and other residential uses.
(2) Commercial. Service to customers engaged primarily in the sale of goods or services including institutions and local, state, and federal government agencies for uses other than those involving manufacturing or electric power generation.
(3) Industrial. Service to customers engaged primarily in a process which creates or changes raw or unfinished materials into another form or product including the generation of electric power.
(4) Firm service. Service from schedules or contracts under which seller is expressly obligated to deliver specific volumes within a given time period and which anticipates no interruptions, but which may permit unexpected interruption in case the supply to higher priority customers is threatened.
(5) Interruptible service. Service from schedules or contracts under which seller is not expressly obligated to deliver specific volumes within a given time period, and which anticipates and permits interruption on short notice, or service under schedules or contracts which expressly or impliedly require installation of alternate fuel capability.
(6) Plant protection gas. Is defined as minimum volumes required to prevent physical harm to the plant facilities or danger to plant personnel when such protection cannot be afforded through the use of an alternate fuel. This includes the protection of such material in process as would otherwise be destroyed, but shall not include deliveries required to maintain plant production. For the purposes of this definition propane and other gaseous fuels shall not be considered alternate fuels.
(7) Feedstock gas. Is defined as natural gas used as raw material for its chemical properties in creating an end product.
(8) Process gas. Is defined as gas use for which alternate fuels are not technically feasible such as in applications requiring precise temperature controls and precise flame characteristics. For the purposes of this definition propane and other gaseous fuels shall not be considered alternate fuels.
(9) Boiler fuel. Is considered to be natural gas used as a fuel for the generation of steam or electricity, including the utilization of gas turbines for the generation of electricity.
(10) Alternate fuel capabilities. Is defined as a situation where an alternate fuel could have been utilized whether or not the facilities for such use have actually been installed; Provided, however, Where the use of natural gas is for plant protection, feedstock, or process uses and the only alternate fuel is propane or other gaseous fuel then the consumer will be treated as if he had no alternate fuel capability.
Statement of General Policy To Implement Procedures for Compliance With the National Environmental Policy Act of 1969
§ 2.80 Detailed environmental statement.
(a) It will be the general policy of the Federal Energy Regulatory Commission to adopt and to adhere to the objectives and aims of the National Environmental Policy Act of 1969 (NEPA) in its regulations promulgated for statutes under the jurisdiction of the Commission, including the Federal Power Act, the Natural Gas Act and the Natural Gas Policy Act. The National Environmental Policy Act of 1969 requires, among other things, all Federal agencies to include a detailed environmental statement in every recommendation or report on proposals for legislation and other major Federal actions significantly affecting the quality of the human environment.
(b) Therefore, in compliance with the National Environmental Policy Act of 1969, the Commission staff will make a detailed environmental statement when the regulatory action taken by the Commission under the statutes under the jurisdiction of the Commission will have a significant environmental impact. The specific regulations implementing NEPA are contained in part 380 of the Commission’s regulations.
Statement of General Policy To Implement the Economic Stabilization Act of 1970, as Amended, and Executive Orders 11615 and 11627
§§ 2.100-2.102 [Reserved]
§ 2.103 Statement of policy respecting take or pay provisions in gas purchase contracts.
(a) Recognizing that take or pay contract obligations may be shielding the prices of deregulated and other higher cost gas from market constraints, the Commission sets forth its general policy regarding prepayments for natural gas pursuant to take or pay provisions in gas contracts and amendments thereto between producers and interstate pipelines which become effective December 23, 1982. The provisions of this policy statement do not establish a binding norm but instead provide general guidance. In particular cases, both the underlying validity of the policy and its application to particular facts may be challenged and are subject to further consideration.
(b) With respect to gas purchase contracts entered into on or after December 23, 1982, the Commission intends to apply a rebuttable presumption in general rate cases that prepayments to producers will not be given rate base treatment if the prepayments are made pursuant to take or pay requirements in such gas purchase contracts or amendments which exceed 75 percent of annual deliverability.
§ 2.104 Mechanisms for passthrough of pipeline take-or-pay buyout and buydown costs.
(a) General Policy. The Commission as a matter of policy will provide two distinct mechanisms for passthrough of take-or-pay buyout and buydown costs of interstate natural gas pipelines. The first is pursuant to existing Commission policy and practice. Under this method, pipelines may pass through prudently incurred take-or-pay buyout and buydown costs in their sales commodity rates. The second method is available to pipelines which agree to an equitable sharing of take-or-pay costs and which transport under part 284 of this chapter. Qualifying pipelines may utilize the alternative passthrough mechanisms described in this section. Where a pipeline agrees to absorb from 25 to 50 percent of take-or-pay buyout and buydown costs, the Commission will permit the pipeline to recover through a fixed charge an amount equal to (but not greater than) the amount absorbed. Any remaining costs up to 50 percent of total buyout and buydown costs may be recovered either through a commodity rate surcharge or a volumetric surcharge on total throughput.
(b) Cost allocation procedures. A pipeline’s volume-based surcharges must be based on the volumes which underlie its most recent Commission-approved rates. Fixed charges must be based on each customer’s cumulative deficiency in purchases in recent years (during which the current take-or-pay liabilities of the pipelines were incurred) measured in relation to that customer’s purchases during a representative period during which take-or-pay liabilities were not incurred. The allocation formula employed must incorporate the following guidelines:
(1) A representative base period must be selected. The base period must reflect a representative level of purchases by the pipeline’s firm customers during a period preceding the onset of changed conditions which resulted in reduced purchases and growth of the take-or-pay problem.
(2) Firm purchases by each customer during the base year under firm rate schedules or contracts for firm service must be determined.
(3) Firm sales purchase deficiency volumes for each subsequent year must be determined.
(4) A fixed charge based on each customer’s cumulative deficiencies as compared to total cumulative deficiencies must be derived. The filing pipeline will be free to select for rate calculation and filing purposes a reasonable amortization period for buyout and buydown costs being recovered through fixed charges or volumetric surcharges. The pipeline will be entitled to interest at the rate set forth in part 154 of this chapter on unamortized amounts.
(c) Implementing procedures. (1) Pipelines acting pursuant to this section may submit on or before December 31, 1990, a non-PGA rate filing under section 4(e) of the Natural Gas Act. Pipelines may include in their filings a fixed charge and a volumetric surcharge to recover buyout and buydown costs actually paid as of the date of filing plus similar costs which are known and measurable within the following nine months. Detailed support for the amounts claimed and for the calculation of customer surcharges must be provided. In addition, the pipeline must disclose and describe all consideration, both cash and noncash, given to producers in exchange for take-or-pay relief.
(2) In any filings made under this section, pipelines must include proposals for periodic (preferably annual) adjustments to customer surcharges, together with any necessary accounting procedures, designed to assure that revenues recovered by the pipeline remain in balance with buyout and buydown costs covered by the filing and actually incurred by the pipeline.
(d) Prudence. (1) The Commission will examine the issue of prudence if it is raised by a party in an individual proceeding. If it is raised, the pipeline will be required to demonstrate the prudence of take-or-pay buyout and buydown costs which it seeks to recover from its customers through both fixed and volume-based charges.
(2) The Commission intends to exercise its authority to the full extent permitted by the Natural Gas Act to approve take-or-pay settlements. The Commission intends to approve uncontested take-or-pay settlements which are consistent with this section and found to be in the public interest. The Commission will also, if it appears reasonable and permissible to do so, approve contested settlements as to all consenting parties and initiate separate hearings to establish the rates for opposing parties. Alternatively, the Commission will approve contested settlements on the merits if supported by substantial evidence in the record. In any case where hearings are held as to the prudence of take-or-pay buyout and buydown costs, the Commission will permit the pipeline the opportunity to recover all take-or-pay costs found to be prudent from the contesting parties on a proportional basis, even if the amount allowed is greater than the amounts initially sought to be recovered by the pipeline.
(e) Flowthrough by downstream pipelines. Downstream pipelines must flow through approved take-or-pay fixed charges based on the cumulative purchase deficiencies of their customers. Volumetrically-based surcharges must be flowed through on a volumetric basis. Customers of downstream pipelines have the right in connection with either PGA or general rate filings to challenge the purchasing practices of such pipelines. Remedies for purchasing practices found by the Commission to be imprudent will be determined on a case-by-case basis.
(f) Ongoing proceedings. Pipeline rate proceedings pending September 15, 1987 may be utilized as a forum for implementing the approved cost recovery mechanisms set forth in this section. Permission will be granted in cases where implementation of this policy in pending proceedings appears feasible, will not result in inordinate delay, or can be expected to result in unnecessary or cumulative rate filings with the Commission. In the event permission is granted, the presiding judge(s) will allow pipelines to supplement their filings to the extent necessary to assure compliance with the filing and data requirements set forth herein. The presiding judges shall also establish any procedures necessary to protect the rights of all parties. Any rates established pursuant to this section will be permitted to become effective only prospectively upon Commission approval.
(g) Scope. This section does not go beyond the Commission’s determination in the April 10, 1985, policy statement (Docket No. PL85–1–000) that take-or-pay buyout and buydown costs do not violate the pricing provision of the Natural Gas Policy Act of 1978 (NGPA). It is not intended to affect take-or-pay prepayments made by pipelines and included in account 165 and in their rate bases. Nor does it address the issue of whether take-or-pay prepayments to a producer for gas not taken and which cannot be made up violate the Title I pricing provisions of the NGPA. This policy statement applies only to buyout and buydown costs paid by pipelines that are transporting under part 284 of this chapter, under existing contracts, and is not intended to disturb in any way take-or-pay settlements previously entered into between pipelines and their producer suppliers.
§ 2.105 Gas supply charges.
An interstate natural gas pipeline that transports under part 284 of this chapter may include in its tariff a charge, not related to facilities, for standing ready to supply gas to sales customers in accordance with the following principles:
(a) The pipeline may not recover take-or-pay or similar charges from suppliers by any other means.
(b) The pipeline must allow its sales customers to nominate levels of service freely within their firm sales entitlements or otherwise employ a mechanism for the renegotiation of levels of service at regular intervals.
(c) The pipeline must announce prior to nominations by the customers a firm price or pricing formula for the service, and hold that price or pricing formula firm during the interval arranged in paragraph (b) of this section.
(d) By nominating a new level of service lower than its current level, a customer has consented to any abandonment sought by the pipeline commensurate with the difference between the current level of service and the nominated level.
Rules of General Applicability
§ 2.201 [Reserved]
Statement of General Policy and Interpretations Under the Natural Gas Policy Act of 1978
§ 2.300 Statement of policy concerning allegations of fraud, abuse, or similar grounds under section 601(c) of the NGPA.
Recognizing the potential for an increasing number of intervenor complaints predicated on the fraud, abuse, or similar grounds exception to guaranteed passthrough, the Commission sets forth the elements of a cognizable claim under section 601(c)(2) which it expects to apply in cases in which fraud, abuse, or similar grounds is raised. The provisions of this policy statement do not establish a binding norm but instead provide general guidance. In particular cases, both the underlying validity of the policy and its application to particular facts may be challenged and are subject to further consideration. The procedure prescribed conforms with the NGPA’s general guarantee of passthrough by placing the burden of pleading the elements and proving the elements of a case on intervenors who would allege fraud, abuse, or similar grounds as a basis for denying passthrough of gas prices incurred by an interstate pipeline.
(a) In order for the issue of fraud, as that term is used in section 601(c) of the NGPA, to be considered in a proceeding, an intervenor or intervenors must file a complaint alleging that:
(1) The interstate pipeline, any first seller who sells natural gas to the interstate pipeline, or both acting together, have made a fraudulent misrepresentation or concealment; and
(2) Because of that fraudulent misrepresentation or concealment, the amount paid by the interstate pipeline to any first seller of natural gas was higher than it would have been absent the fraudulent conduct.
(b) In order for the issue of abuse, as that term is used in section 601(c) of the NGPA, to be considered in a proceeding, an intervenor or intervenors must file a complaint alleging that:
(1) The interstate pipeline, a first seller who sells to the interstate pipeline, or both acting together, have made a negligent misrepresentation or concealment, or other misrepresentation or concealment in disregard of a duty; and
(2) Because of that negligent misrepresentation or concealment, or other misrepresentation or concealment in disregard of a duty, the amount paid by the interstate pipeline to any first seller of natural gas was higher than it would have been absent the negligent misrepresentation or concealment, or other misrepresentation or concealment made in disregard of a duty.
(c) In order for the issue of similar grounds, as that term is used in section 601(c) of the NGPA, to be considered in a proceeding, an intervenor or intervenors must file a complaint alleging that:
(1) The interstate pipeline, any first seller who sells natural gas to the interstate pipeline, or both acting together, have made an innocent misrepresentation of fact; and
(2) Because of that innocent misrepresentation of facts, the amount paid by the interstate pipeline to any first seller of natural gas was higher than it would have been absent the innocent misrepresentation of fact.
Statement of Interpretation Under the Public Utility Regulatory Policies Act of 1978
§ 2.400 Statement of interpretation of waste concerning natural gas as the primary energy source for qualifying small power production facilities.
For purposes of deciding whether natural gas may be considered as waste as the primary energy source pursuant to § 292.204(b)(1)(i) of this chapter, the Commission will use the criteria described in paragraphs (a), (b) and (c) of this section.
(a) Category 1. Except as provided in paragraph (b) of this section, natural gas with a heating value of 300 Btu per standard cubic foot (scf) or below will be considered unmarketable.
(b) Category 2. In determining whether natural gas with a heating value above 300 Btu but not more than 800 Btu per scf and natural gas produced in the Moxa Arch area is unmarketable, the Commission will consider the following information:
(1) The percentages of the chemical components of the gas, the wellhead pressure, and the flow rate;
(2) Whether the applicant offered the gas to all potential buyers located within 20 miles of the wellhead under terms and conditions commensurate with those prevailing in the region and that such potential buyers refused to buy the gas; and
(3) A study, which may be submitted by an applicant, that evaluates the economics of upgrading the gas for sale and transporting the gas to a pipeline. The study should include estimates of the revenues which could be derived from the sale of the gas and the fixed and variable costs of upgrading.
(c) Category 3. In determining whether natural gas with a heating value above 800 Btu per scf is marketable, the Commission will consider the information included in paragraph (b) of this section and whether:
(1) The gas has actually been flared, vented to the atmosphere, or continuously injected into a non-producing zone for a period of one year, pursuant to legal authority; or
(2) The gas has been certified as waste, i.e., suitable for disposal, by an appropriate state authority.
Statement of Penalty Reduction/Waiver Policy To Comply With the Small Business Regulatory Enforcement Fairness Act of 1996
§ 2.500 Penalty reduction/waiver policy for small entities.
(a) It is the policy of the Commission that any small entity is eligible to be considered for a reduction or waiver of a civil penalty if it has no history of previous violations, and the violations at issue are not the product of willful or criminal conduct, have not caused loss of life or injury to persons, damage to property or the environment or endangered persons, property or the environment. An eligible small entity will be granted a waiver if it can also demonstrate that it performed timely remedial efforts, made a good faith effort to comply with the law and did not obtain an economic benefit from the violations. An eligible small entity that cannot meet the criteria for waiver of a civil penalty may be eligible for consideration of a reduced penalty. Upon the request of a small entity, the Commission will consider the entity’s ability to pay before assessing a civil penalty.
(b) Notwithstanding paragraph (a) of this section, the Commission reserves the right to waive or reduce civil penalties in appropriate individual circumstances where it determines that a waiver or reduction is warranted by the public interest.
Appendix A to Part 2—Guidance for Determining the Acceptable Construction Area for Auxiliary and Replacement Facilities
These guidelines shall be followed to determine what area may be used to construct the auxiliary or replacement facility. Specifically, they address what areas, in addition to the permanent right-of-way, may be used.
An auxiliary or replacement facility must be within the existing right-of-way or facility site as specified by § 2.55(a)(1) or § 2.55(b)(1)(ii). Construction activities for the auxiliary or replacement facility can extend outside the current permanent right-of-way if they are within the temporary and permanent right-of-way and associated work spaces authorized for the construction of the existing installation.
If documentation is not available on the location and width of the temporary and permanent rights-of-way and associated work spaces that were used to construct the existing facility, the company may use the following guidance for the auxiliary installation or replacement, provided the appropriate easements have been obtained:
a. Construction should be limited to no more than a 75-foot-wide right-of-way including the existing permanent right-of-way for large diameter pipeline (pipe greater than 12 inches in diameter) to carry out routine construction. Pipeline 12 inches in diameter and smaller should use no more than a 50-foot-wide right-of-way.
b. The temporary right-of-way (working side) should be on the same side that was used in constructing the existing pipeline.
c. A reasonable amount of additional temporary work space on both sides of roads and interstate highways, railroads, and significant stream crossings and in side-slope areas is allowed. The size should be dependent upon site-specific conditions. Typical work spaces are:
| Item | Typical extra area (width/length) |
|---|---|
| Two lane road (bored) | 25–50 by 100 feet. |
| Four lane road (bored) | 50 by 100 feet. |
| Major river (wet cut) | 100 by 200 feet. |
| Intermediate stream (wet cut) | 50 by 100 feet. |
| Single railroad track | 25–50 by 100 feet. |
d. The auxiliary or replacement facility must be located within the permanent right-of-way or, in the case of nonlinear facilities, the cleared building site. In the case of pipelines this is assumed to be 50 feet wide and centered over the pipeline unless otherwise legally specified.
However, use of the above guidelines for work space size is constrained by the physical evidence in the area. Areas obviously not cleared during the existing construction, as evidenced by stands of mature trees, structures, or other features that exceed the age of the facility being replaced, should not be used for construction of the auxiliary or replacement facility.
If these guidelines cannot be met, the company should consult with the Commission’s staff to determine if the exemption afforded by § 2.55 may be used. If the exemption may not be used, construction authorization must be obtained pursuant to another regulation under the Natural Gas Act.
Appendix B to Part 2 [Reserved]
Appendix C to Part 2—Nationwide Proceeding Computation of Federal Income Tax Allowance Independent Producers, Pipeline Affiliates and Pipeline Producers Continental U.S.—1972 Data (Docket No. R–478)
| Line No. | Particulars | Schedule No. | Line No. | (1)—Total 1 | (2)—Total excluding production taxes 2 | (3)—Gas only 3 | (4)—Lease separation 3 | (5)—No lease separation 3 | (6)—Total 4 | (7)—Percentage lease separation gas 5 | (8)—Allocated amount gas 6 |
|---|---|---|---|---|---|---|---|---|---|---|---|
| 2 | Direct and indirect lease costs and expenses | 1–A | 01 | 1,694,893,558 | 1,694,893,558 | 57,287,938 | $144,679,567 | $19,763,791 | $221,731,296 | 90.33 | 207,740,782 |
| 2 | Taxes (except income and production) | A–1 | 02 | 210,335,720 | 210,335,720 | 16,507,630 | 20,431,444 | 4,360,024 | 41,299,098 | 9.33 | 39,323,337 |
| 4 | Production taxes | 1–A | 03 | 479,424,297 | 27,124,210 | 96,699,673 | 10,005,599 | 133,829,482 | 90.33 | 124,478,624 | |
| 5 | Other lease expenses | 1–A | 04 | 61,102,433 | 61,102,433 | 17,527,077 | 24,988,900 | 336,427 | 42,852,404 | 90.33 | 40,435,977 |
| 6 | Depletion, depreciation and amortization | 1–A | 05 | 1,716,823,070 | 1,716,823,070 | 105,999,777 | 297,881,312 | 25,502,048 | 429,383,137 | 90.33 | 400,578,014 |
| 7 | Corporate general expense | 1–A | 06 | 278,845,909 | 278,845,909 | 13,611,337 | 25,077,796 | 3,579,728 | 42,268,861 | 90.33 | 39,843,838 |
| 8 | Area, district, division and field expense | 1–A | 07 | 261,718,417 | 26,178,417 | 7,207,320 | 21,758,604 | 2,778,944 | 31,744,868 | 90.33 | 29,640,811 |
| 9 | Miscellaneous lease revenues | 1–A | 09 | (12,203,136) | (12,203,136) | (1,348,729) | (2,768,788) | (314,067) | (4,431,584) | 90.33 | (4,163,842) |
| 10 | Return on production rate base at 15 percent | 1–A | 13 | 2,505,272,672 | 2,505,272,672 | 186,055,524 | 427,939,601 | 69,857,212 | 663,852,337 | 90.33 | 622,470,578 |
| 11 | Exploration and development costs and expenses | 1–A | 15 | 1,673,945,853 | 1,673,945,853 | 594,971,262 | |||||
| 12 | Return on exploration rate base at 15 percent | 1–A | 16 | 588,558,894 | 588,558,894 | 234,604,103 | |||||
| 13 | Regulatory commission expense including return | 1–A | 17 | 6,514,279 | 6,514,279 | 6,514,852 | |||||
| 14 | |||||||||||
| 15 | Total computed revenue | 9,465,231,966 | 8,985,807,669 | 2,336,439,376 | |||||||
| 16 (gross income) | |||||||||||
| 17 | |||||||||||
| 18 revenue deductions | |||||||||||
| 19 | Direct and indirect lease costs and expenses | 1–A | 01 | 1,694,893,558 | 1,694,893,558 | 207,740,872 | |||||
| 20 | Taxes (except income and production) | 1–A | 02 | 210,335,720 | 210,335,720 | 39,323,377 | |||||
| 21 | Production taxes | 1–A | 03 | 479,424,297 | 124,478,624 | ||||||
| 22 | Other lease expenses | 1–A | 04 | 61,102,433 | 61,102,433 | 40,435,977 | |||||
| 23 | Book depletion | 7 (283,121,142) | 283,121,242 | 24,287,986 | 61,675,828 | 6,177,596 | 92,141,410 | 90.33 | 86,177,357 | ||
| 24 | Depreciation expense | 1–A | 05 | 7 (654,604,447) | 654,604,447 | 30,223,586 | 94,010,520 | 7,007,662 | 131,241,768 | 90.33 | 122,150,951 |
| 25 | Amortization of capitalized IDC | 7 (779,097,382) | 779,097,382 | 51,488,205 | 142,194,964 | 12,316,790 | 205,999,959 | 90.33 | 192,249,706 | ||
| 26 | Corporate general expense | 1–A | 06 | 278,845,909 | 278,845,909 | 39,843,838 | |||||
| 27 | Area, district, division and field expense | 1–A | 07 | 261,718,417 | 261,718,417 | 29,640,811 | |||||
| 28 | Miscellaneous lease revenues | 1–A | 09 | (12,203,136) | (12,203,136) | (4,163,842) | |||||
| 29 | Exploration and development costs and expenses | 1,673,945,853 | 1,673,945,853 | 594,971,262 | |||||||
| 30 | Regulatory commission expense | 4–A | 01 | 6,384,384 | 6,394,384 | 6,394,384 | |||||
| 31 | |||||||||||
| 32 | Total book expenses | 6,371,380,505 | 5,891,856,209 | 1,479,243,227 | |||||||
| 33 | |||||||||||
| 34 | Production net income (line 15 less line 32) | 3,093,951,461 | 3,093,951,460 | 857,190,149 | |||||||
| 35 | |||||||||||
| 36 tax adjustment—add ( | |||||||||||
| 37 | Amortization of capitalized IDC | 779,097,282 | 779,097,382 | 192,249,706 | |||||||
| 38 | Estimated IDC capitalized in 1972 | 8 (1,470,935,857) | (1,470,935,857) | (362,967,445) | |||||||
| 39 | Interest expense (calculated) | 9 (243,846,540) | (243,846,540) | (60,587,136) | |||||||
| 40 | |||||||||||
| 41 | Taxable income | 2,158,266,445 | 2,158,266,445 | 625,891,274 | |||||||
| 42 | |||||||||||
| 43 | Federal income tax at 48 percent | 1,992,245,949 | 1,992,245,949 | 10 577,745,791 | |||||||
1 Lines 1 thru 15, col. (1). From Notice issued Sept. 12, 1974, app. A, p. 12, col. (d).
2 Production taxes have been deleted from col. (1).
3 From notice issued Sept. 12, 1974, app. A, p. 12, cols. (g), (h), and (i).
4 Col. (3) plus col. (4) plus col. (5).
5 Calculated on a modified British thermal unit basis (1.5 to 1).
6 Col. (7) times col. (4), plus cols. (3) and (5).
7 See composites mailed to all parties on Feb. 13, 1974.
8 Calculated, 188.8 percent (A R64–1–2) times $779,097,382 equals $1,470,935,857.
9 Calculated 0.0146 (interest rate) times $16,701,817,818 (app. A, schedule 2–A, (d), line 11, p. 13) equals $243,846,540.
10 $577,745,791 divided by 9,508,369,001 equals 6.08 cents per thousand cubic feet.
PART 3 [RESERVED]
PART 3a—NATIONAL SECURITY INFORMATION
General
§ 3a.1 Purpose.
This part 3a describes the Federal Energy Regulatory Commission program to govern the classification, downgrading, declassification, and safeguarding of national security information. The provisions and requirements cited herein are applicable to the entire agency except that material pertaining to personnel security shall be safeguarded by the Personnel Security Officer and shall not be considered classified material for the purpose of this part.
§ 3a.2 Authority.
Official information or material referred to as classified in this part is expressly exempted from public disclosure by 5 U.S.C. 552(b)(1). Wrongful disclosure thereof is recognized in the Federal Criminal Code as providing a basis for prosecution. E.O. 11652, March 8, 1972 (37 FR 5209, March 10, 1972), identifies the information to be protected, prescribes classification, downgrading, declassification, and safeguarding procedures to be followed and establishes a monitoring system to insure its effectiveness. National Security Council Directive Governing the Classification, Downgrading, Declassification and Safeguarding of National Security Information, May 17, 1972 (37 FR 10053, May 19, 1972), implements E.O. 11652.
Classification
§ 3a.11 Classification of official information.
(a) Security Classification Categories. Information or material which requires protection against unauthorized disclosure in the interest of the national defense or foreign relations of the United States (hereinafter collectively termed national security) is classified Top Secret, Secret or Confidential, depending upon the degree of its significance to national security. No other categories are to be used to identify official information or material requiring protection in the interest of national security, except as otherwise expressly provided by statute. These classification categories are defined as follows:
(1) Top Secret. Top Secret refers to national security information or material which requires the highest degree of protection. The test for assigning Top Secret classification is whether its unauthorized disclosure could reasonably be expected to cause exceptionally grave damage to the national security. Examples of exceptionally grave damage include armed hostilities against the United States or its allies; disruption of foreign relations vitally affecting the national security; the compromise of vital national defense plans or complex cryptologic and communications intelligence systems; the revelation of sensitive intelligence operations; and the disclosure of scientific or technological developments vital to national security. This classification is to be used with the utmost restraint.
(2) Secret. Secret refers to national security information or material which requires a substantial degree of protection. The test for assigning Secret classification shall be whether its unauthorized disclosure could reasonably be expected to cause serious damage to the national security. Examples of serious damage include disruption of foreign relations significantly affecting the national security; significant impairment of a program or policy directly related to the national security; revelation of significant military plans or intelligence operations; and compromise of significant scientific or technological developments relating to national security. The classification Secret shall be sparingly used.
(3) Confidential. Confidential refers to national security information or material which requires protection, but not to the degree described in paragraphs (a) (1) and (2) of this section. The test for assigning Confidential classification shall be whether its unauthorized disclosure could reasonably be expected to cause damage to the national security.
(b) Classified information will be assigned the lowest classification consistent with its proper protection. Documents will be classified according to their own content and not necessarily according to their relationship to other documents.
(c) The overall classification of a file or group of physically connected documents will be at least as high as that of the most highly classified document therein. When put together as a unit or complete file, the classification of the highest classified document contained therein will be marked on a cover sheet, file folder (front and back), or other similar covering, and on any transmittal letters, comments, or endorsements.
(d) Administrative Control Designations. These designations are not security classification designations, but are used to indicate a requirement to protect material from unauthorized disclosure. Material identified under the provisions of this subparagraph will be handled and protected in the same manner as material classified Confidential except that it will not be subject to the central control system described in § 3a.71. Administrative Control designations are:
(1) For Official Use Only. This designation is used to identify information which does not require protection in the interest of national security, but requires protection in accordance with statutory requirements or in the public interest and which is exempt from public disclosure under 5 U.S.C. 552(b) and § 388.105(n) of this chapter.
(2) Limited Official Use. This administrative control designation is used by the Department of State to identify nondefense information requiring protection from unauthorized access. Material identified with this notation must be limited to persons having a definite need to know in order to fulfill their official responsibilities.
(e) A letter or other correspondence which transmits classified material will be classified at a level at least as high as that of the highest classified attachment or enclosure. This is necessary to indicate immediately to persons who receive or handle a group of documents the highest classification involved. If the transmittal document does not contain classified information, or if the information in it is classified lower than in an enclosure, the originator will include a notation to that effect. (See § 3a.31(e).)
§ 3a.12 Authority to classify official information.
(a) The authority to classify information or material originally under E.O. 11652 is restricted to those offices within the executive branch which are concerned with matters of national security, and is limited to the minimum number absolutely required for efficient administration.
(b) The authority to classify information or material originally as Top Secret is to be exercised only by such officials as the President may designate in writing and by the heads of the following departments and agencies and such of their principal staff officials as the heads of these departments and agencies may designate in writing;
(c) The authority to classify information or material originally as Secret is exercised only by:
(1) Officials who have Top Secret classification authority under § 3a.11(b); and
(2) The heads of the following departments and agencies and such principal staff officials as they may designate in writing:
(d) The authority to classify information or material originally as Confidential is exercised by officials who have Top Secret or Secret classification authority.
(e) Pursuant to E.O. 11652, the authority to classify information or material originally as Secret or Confidential in the FERC shall be exercised only by the Chairman, the Vice Chairman, and the Executive Director. When an incumbent change occurs in these positions, the name of the new incumbent will be reported to the Interagency Classification Review Committee NSC.
§ 3a.13 Classification responsibility and procedure.
(a) Each FERC official who has classifying authority (§ 3a.12) shall be held accountable for the propriety of the classifications attributed to him. Unnecessary classification and overclassification shall be avoided. Classification shall be solely on the basis of national security considerations. In no case shall information be classified in order to conceal inefficiency or administrative error, to prevent embarrassment to the FERC or any of its officials or employees, or to prevent for any other reason the release of information which does not require protection in the interest of national security.
(b) Each classified document shall show on its face its classification and whether it is subject to or exempt from the General Declassification Schedule (§ 3a.22(b)). It also shall show the office of origin, the date of preparation and classification and, to the extent practicable, be so marked as to indicate which portions are classified, at what level, and which portions are not classified in order to facilitate excerpting and other use. Material which merely contains references to classified materials, which references do not reveal classified information, shall not be classified.
(c) Material classified under this part shall indicate on its face the identity of the highest authority authorizing the classification. Where the individual who signs or otherwise authenticates a document or item has also authorized the classification, no further annotation as to his identity is required.
(d) Classified information or material furnished to the United States by a foreign government or international organization shall either retain its original classification or be assigned a U.S. classification. In either case, the classification shall assure a degree of protection equivalent to that required by the government or international organization which furnished the information or material.
(e) Whenever information or material classified by an authorized official is incorporated in another document or other material by any person other than the classifier, the previously assigned security classification category shall be reflected thereon together with the identity of the classifier.
(f) As a holder of classified information or material, the FERC shall observe and respect the classification assigned by the originator. If it is believed that there is unnecessary classification; that the assigned classification is improper, or that the document is subject to declassification under E.O. 11652, the FERC will so inform the originator who is then required by the Executive order to reexamine the classification.
Declassification and Downgrading
§ 3a.21 Authority to downgrade and declassify.
(a) The authority to downgrade and declassify information or material shall be exercised as follows:
(1) Information or material may be downgraded or declassified by the official authorizing the original classification, by a successor or by a supervisory official of either.
(2) Downgrading and declassification authority may also be exercised by an official specifically authorized under regulations issued by the head of the Department listed in sections 2 A and B of E.O. 11652, March 10, 1972.
(3) In the case of classified information or material transferred pursuant to statute or Executive order in conjunction with a transfer of function and not merely for storage purposes, the receiving department or agency shall be deemed to be the originating department or agency for all purposes under E.O. 11652, including downgrading and declassification.
(4) In the case of classified information or material not officially transferred under paragraph (a)(3) of this section, but originated in a department or agency which has since ceased to exist, each department or agency in possession shall be deemed to be the originating department or agency for all purposes. Such information or material may be downgraded and declassified after consulting with any other departments or agencies having an interest in the subject matter.
(5) Classified information or material transferred to the General Services Administration for accession to the Archives of the United States shall be downgraded and declassified by the Archivist of the United States in accordance with E.O. 11652, directives of the President issued through the National Security Council, and pertinent regulations of the departments and agencies.
§ 3a.22 Declassification and downgrading.
(a) When classified information of material no longer requires the level of protection assigned to it, it shall be downgraded or declassified in order to preserve the effectiveness and integrity of the classification system. The Chairman, Vice Chairman, and Executive Director exercise downgrading and declassification authority in the FERC.
(b) Information and material classified prior to June 1, 1972, and assigned to Group 4 under E.O. 10501, as amended by E.O. 10964, unless declassified earlier by the original classifying authority, shall be declassified and downgraded in accordance with the following General Declassification Schedule.
(1) Top Secret. Information or material originally classified TOP SECRET becomes automatically downgraded to Secret at the end of the second full calendar year following the year in which it was originated, downgraded to Confidential at the end of the fourth full calendar year following the year in which it was originated, and declassified at the end of the 10th full calendar year following the year in which it was originated.
(2) Secret. Information and material originally classified Secret becomes automatically downgraded to Confidential at the end of the second full calendar year following the year in which it was originated, and declassified at the end of the eighth full calendar year following the year in which it was originated.
(3) Confidential. Information and material originally classified Confidential becomes automatically declassified at the end of the sixth full calendar year following the year in which it was originated.
(c) To the fullest extent applicable, there shall be indicated on each such FERC originated classified document whether it can be downgraded or declassified at a date earlier than under the above schedule, or after a specified event, or upon the removal of classified attachments or enclosures. Classified information in the possession of the Federal Power Commission, but not bearing a marking for automatic downgrading or declassification, will be marked or designated by the Chairman or the Security Officer designated by § 3a.51 hereof for automatic downgrading or declassification in accordance with the rules and regulations of the department or agency which originally classified the information or material.
(d) When the FERC official having classification authority downgrades or cancels the classification of a document before its classification status changes automatically, each addressee to whom the document was transmitted shall be notified of the change unless the addressee has previously advised that the document was destroyed. Addressees must be notified similarly when it has been determined that a document must be upgraded.
(e) When classified information from more than one source is incorporated into a new document or other material, the document or other material shall be classified, downgraded, or declassified in accordance with the provisions of E.O. 11652 and NSC directives thereunder applicable to the information requiring the greatest protection.
(f) All information or material classified prior to June 1, 1972, other than that described in paragraph (b) of this section, is excluded from the General Classification Schedule. However, at any time after the expiration of 10 years from the date of origin it shall be subject to classification review and disposition by FERC provided:
(1) A department or agency or member of the public requests review;
(2) The request describes the record with sufficient particularity to enable FERC to identify it; and
(3) The record can be obtained with a reasonable amount of effort.
(g) All classified information or material which is 30 years old or more will be declassified under the following conditions:
(1) All information and material classified after June 1, 1972, will, whether or not declassification has been requested, become automatically declassified at the end of 30 full calendar years after the date of its original classification except for such specifically identified information or material which the Chairman personally determines in writing to require continued protection because such continued protection is essential to the national security, or disclosure would place a person in immediate jeopardy. In such case, the Chairman also will specify the period of continued classification.
(2) All information and material classified before June 1, 1972 and more than 30 years old will be systematically reviewed for declassification by the Archivist of the United States by the end of the 30th full calendar year following the year in which it was originated. In his review, the Archivist will separate and keep protected only such information or material as is specifically identified by the Chairman in accordance with paragraph (g) (1) of this section. In such case, the Chairman also will specify the period of continued classification.
(3) The Executive Director, acting for the Chairman, is assigned to assist the Archivist of the United States in the exercise of his responsibilities indicated in paragraph (g)(2) of this section. He will:
(i) Provide guidance and assistance to archival employees in identifying and separating those materials originated in FERC which are deemed to require continued classification; and
(ii) Develop a list for submission to the Chairman which identifies the materials so separated, with recommendations concerning continued classification. The Chairman will then make the determination required under paragraphs (g) (1) and (2) of this section and cause a list to be created which identifies the documents included in the determination, indicates the reason for continued classification, and specifies the date on which such material shall be declassified.
§ 3a.23 Review of classified material for declassification purposes.
(a) All information and material classified after June 1, 1972, and determined in accordance with Chapter 21, title 44, United States Code, to be of sufficient historical or other value to warrant preservation shall be systematically reviewed on a timely basis for the purpose of making such information and material publicly available according to the declassification determination at the time of classification. During each calendar year the FPC shall segregate to the maximum extent possible all such information and material warranting preservation and becoming declassified at or prior to the end of such year. Promptly after the end of such year the FERC, or the Archives of the United States if transferred thereto, shall make the declassified information and material available to the public to the extent permitted by law.
(b) Departments and agencies and members of the public may direct requests for review for declassification, as described in § 3a.22(f), to:
(c) The FERC Review Committee will establish procedures to review and act within 30 days upon all applications and appeals regarding requests for declassification. The chairman, acting through the committee, is authorized to overrule previous determinations in whole or in part when, in its judgment, continued protection is no longer required. If the committee determines that continued classification is required under the criteria of section 5(B) of E.O. 11652, it will promptly so notify the requester and advise him that he may appeal the denial to the Interagency Classification Review Committee.
(d) A request by a department or agency or a member of the public to review for declassification documents more than 30 years old shall be referred directly to the Archivist of the United States, and he shall have the requested documents reviewed for declassification. If the information or material requested has been transferred to the General Services Administration for accession into the Archives, the Archivist shall, together with the chairman, have the requested documents reviewed for declassification. Classification shall be continued in either case only when the chairman makes the personal determination indicated in § 3a.22(g)(1). The Archivist shall notify the requester promptly of such determination and of his right to appeal the denial to the Interagency Classification Review Committee.
(e) For purposes of administrative determinations under paragraph (b), (c), or (d) of this section, the burden is on the FERC to show that continued classification is warranted. Upon a determination that the classified material no longer warrants classification, it will be declassified and made available to the requester if not otherwise exempt from disclosure under section 552(b) of Title 5, U.S.C. (Freedom of Information Act) or other provisions of law.
(f) A request for classification review must describe the document with sufficient particularity to enable the FERC to identify it and obtain it with a reasonable amount of effort. Whenever a request is deficient in its description of the record sought, the requester will be asked to provide additional identifying information whenever possible. Before denying a request on the ground that it is unduly burdensome, the requester will be asked to limit his request to records that are reasonably obtainable. If the requester then does not describe the records sought with sufficient particularity, or the record requested cannot be obtained with a reasonable amount of effort, the requester will be notified of the reasons why no action will be taken and of his right to appeal such decision.
(g) The FERC Review Committee will consist of the Executive Director, as Committee Chairman, the Secretary, and the Director, Office of Public Information, as members. In addition to the activities described in this paragraph, the Review Committee has authority to act on all suggestions and complaints with respect to administration of E.O. 11652 and this part 3a.
(h) The FERC Review Committee is also responsible for recommending to the chairman appropriate administrative action to correct abuse or violation of any provision of E.O. 11652 or NSC directives thereunder, including notifications by warning letter, formal reprimand, and to the extent permitted by law, suspension without pay and removal.
(i) The Chairman of the Review Committee will submit through the chairman, FERC, a report quarterly to the Interagency Classification Review Committee, NSC, of actions on classification review requests, classification abuses, and unauthorized disclosures.
Classification Markings and Special Notations
§ 3a.31 Classification markings and special notations.
(a) After the chairman, the vice chairman, or the executive director determines that classified information is contained in an original document or other item, the appropriate marking, i.e., Secret or Confidential, will be applied as indicated herein. In addition, each classified document will reflect its date of origin and the Bureau, Office, or Regional Office responsible for its preparation and issuance, and the identity of the highest authority authorizing the classification. Where the individual who signs or otherwise authenticates the document or other item has also authorized the classification, no further annotation as to his identity is required. Each classified document will also show on its face whether it is subject to or exempt from the General Declassification Schedule described in § 3a.22(b).
(1) For marking documents which are subject to the General Declassification Schedule, the following stamp will be used:
(Top Secret, Secret, or Confidential) Classified by ____________. Subject to General Declassification Schedule of E.O. 11652, automatically downgraded at 2-year intervals and declassified on December 31, ____________ (insert year).
(2) For marking documents which are to be automatically declassified on a given event or date earlier than the General Declassification Schedule the following stamp will be used:
(Top Secret, Secret, or Confidential) Classified by ____________. Automatically declassified on ____________________ (effective date or event).
(3) For marking documents which are exempt from the General Declassification Schedule the following stamp will be used:
(Top Secret, Secret, or Confidential) Classified by ____________. Exempt from General Declassification Schedule of E.O. 11652, Exemption Category (section 5B (1), (2), (3), or (4). Automatically declassified on ____________________ (effective date or event, if any).
(b) Should the classifier fail to mark such document with one of the foregoing stamps, the document shall be deemed to be subject to the General Declassification Schedule. The person who signs or finally approves a document or other material containing classified information shall be deemed to be the classifier. If the classifier is other than such person he shall be identified on the stamp as indicated.
(c) On documents, the classification markings Secret and Confidential will be stamped in red ink, printed, or written in letters considerably larger than those used in the text of the document. On documents which are typewritten in elite, pica or executive size type, the above markings should be in letters not less than three-sixteenths inch in height. No markings, other than those indicated above, are authorized to designate that a document or material requires protection in the interests of national security. The overall classification assigned to a document will be conspicuously marked on the top and bottom of each page and on the outside of the front and back covers, if any. Letters of transmittal, endorsements, routing slips, or any other papers of any size which conceal or partially conceal the cover, the title page, or first page, will bear the marking of the overall classification.
(d) Whenever a classified document contains either more than one security classification category or unclassified information, each section, part or paragraph should be marked to the extent practicable to show its classification category or that it is unclassified.
(e) Letters of transmittal or other covering documents which are classified solely because of classified enclosures or attachments, or which are classified in a lower category than such enclosures or attachments, will bear either of the following markings, as appropriate.
(1) If the covering document is classified on its own, but has enclosures or attachments of a higher classification, or is a component (i.e., an endorsement or comment) or a file in which other components bear a higher classification:
(2) If unclassified when separated from its classified enclosures or attachments:
(f) In addition to the classification category markings prescribed above, the first or title page of each classified document will contain instructions as appropriate, in accordance with the following:
(1) Regarding instructions. The declassification and downgrading notation, as described in § 3a.31(g) will be applied to classified documents only. The notation will not be carried forward to unclassified letters of transmittals or other cover documents. When such cover documents are classified by their own content, they will be annotated with the notwithstanding instructions which pertain to the enclosures.
(2) “Special Handling” notation. Classified information will not be released or disclosed to any foreign national without proper specific authorization. This applies even when the classified material does not bear the special handling notice described below. The special handling notice indicated only that the material has been reviewed and a specific determination made that the information is not releasable to foreign nationals. If it is anticipated that the handling or distribution of a classified document will make it liable to inadvertent disclosure to foreign nationals it will be marked with a separate special handling notation, which will be carried forward to letters of transmittals or other cover documents. The notation reads:
(g) Whenever classified material is upgraded, downgraded, or declassified, the material will be marked to reflect:
(1) The change in classification.
(2) The authority for the action.
(3) The effective date.
(4) The person or unit taking the action.
(h) In addition to the foregoing marking requirements, warning notices shall be displayed prominently on classified documents or materials as prescribed below. When display of these warning notices on the documents or other materials is not feasible, the warnings shall be included in the written notification of the assigned classification.
(1) Restricted data. For classified information or material containing restricted data as defined in the Atomic Energy Act of 1954, as amended:
This document contains restricted data as defined in the Atomic Energy Act of 1954. Its dissemination or disclosure to any unauthorized person is prohibited.
(2) Formerly restricted data. For classified information or material containing solely Formerly Restricted Data, as defined in section 142.d, Atomic Energy Act of 1954, as amended:
Unauthorized disclosure subject to administrative and criminal sanctions. Handle as restricted data in foreign dissemination, section 114.b., Atomic Energy Act, 1954.
(3) Information other than restricted data or formerly restricted data. For classified information or material furnished to persons outside the Executive Branch of Government other than as described in paragraphs (h)(1) and (2) of this section.
Unauthorized disclosure subject to criminal sanctions.
(4) Sensitive intelligence information. For classified information or material relating to sensitive intelligence sources and methods, the following warning notice shall be used, in addition to and in conjunction with those prescribed in paragraph (h)(1), (2), or (3), of this section, as appropriate:
Access to Classified Materials
§ 3a.41 Access requirements.
(a) The Personnel Security Officer, on a continuing current basis, will certify to the Security Officer, the head of each bureau and office and each regional engineer, the names of officers and employees who have been granted a security clearance for access to classified material and the level of such clearance (Top Secret, Secret, Confidential). The Personnel Security Officer will maintain accurate and current listings of personnel who have been granted security clearances in accordance with the standards and criteria of Executive Orders 10450 and 10865 and as prescribed by this part.
(b) In addition to a security clearance, staff members must have a need for access to classified information or material in connection with the performance of duties. The determination for the need-to-know will be made by the official having responsibility for the classified information or material.
(c) When a staff member no longer requires access to classified information or material in connection with performance of official duties, the Personnel Security Officer will administratively withdraw the security clearance. Additionally, when a staff member no longer needs access to a particular security classification category, the security clearance will be adjusted to the classification category required. In both cases, this action will be without prejudice to the staff member’s eligibility for a security clearance or upgrading of category should the need again arise.
(d) Access to classified information or material originated by the FERC may be authorized to persons outside the Executive Branch of the Government engaged in historical research and to former Presidential appointees as provided in paragraphs VI B and C of the NSC directive dated May 17, 1972. The determination of access authorization will be made by the Chairman.
(e) Except as otherwise provided in section 102 of the National Security Act of 1947, 61 Stat. 495, 50 U.S.C. 403, classified information or material originating in one department or agency shall not be disseminated outside any other department or agency to which it has been made available without the consent of the originating organization.
Security Officers
§ 3a.51 Designation of security officers.
(a) The Director, Office of Administrative Operations (OAO) is designated as Top Secret Control Officer and Security Officer for classified material for the Federal Energy Regulatory Commission. The Director, OAO, will designate alternate Top Secret Control Officers and alternated Security Officers, who will be authorized, subject to such limitations as may be imposed by the Director, to perform the duties for which the Top Secret Control Officer and Security Officer is responsible. As used hereinafter, the terms Top Secret Control Officer and Security Officer shall be interpreted as including the alternate Top Secret Control Officers and Security Officers. The FERC Security Officer is authorized and directed to insure the proper application of the provisions of Executive Order 11652 and of this part.
(b) Regional Engineers are designated as Regional Security Officers for the purpose of carrying out the functions assigned herein.
(c) The Director, OAO, will appoint in writing appropriately cleared staff members to act as couriers for transmittal, as necessary, for classified information or material.
Storage and Custody of Classified Information
§ 3a.61 Storage and custody of classified information.
(a) Unless specifically authorized by the Chairman or Executive Director, classified information and materials within the Washington office will be stored only in GSA-approved security containers in the Office of Administrative Operations. Such containers will be of steel construction with built-in, three-position, dial-type, manipulation-proof, changeable combination locks.
(b) A custodian and one or more alternate custodians will be assigned responsibility for the security of each container under his jurisdiction in which classified information is stored. Such assignment will be made a matter of record by executing GSA Optional Form 63, Classified Container Registration, and affixing it to the container concerned. Custodians will be responsible for assuring that combinations are changed as required and that locking and checking functions are accomplished daily in compliance with paragraphs (g) and (h) of this section.
(c) GSA Optional Form 63 is a 3-sheet form, each sheet having a specific purpose and disposition, as follows:
(1) Sheet 1 records the names, addresses, and home telephone numbers of the custodian and alternate custodians. Sheet 1 is affixed to the outside of the container.
(2) Sheet 2 records the combination of the container and is placed inside Sheet 3, which is an envelope.
(3) Sheet 3, an envelope, is a carbon copy of Sheet 1. When the container combination is recorded on Sheet 2, it is sealed inside Sheet 3 which is then forwarded to the FERC Top Secret Control Officer.
(d) GSA Optional Form 62, Safe or Cabinet Security Record, will be attached conspicuously to the outside of each container used to store classified information. The form is used to certify the opening and locking of a container, and the checking of a container at the end of each working day or whenever it is opened and locked during the day.
(e) Combinations of containers used to store classified materials will be assigned classifications equal to the highest category of classified information stored therein. Active combinations are subject to the safeguarding and receipting requirements of this instruction. Superseded combinations become declassified automatically and certificates of destruction therefore are unnecessary.
(f) Knowledge of or access to the combination of a container used for the storage of classified material will be given only to those appropriately cleared individuals who are authorized access to the information stored therein.
(g) Combinations of containers used to store classified material will be changed at least once a year. A combination will be changed also whenever anyone knowing or having access to it is transferred; when the combination has been subjected to compromise; when the security classification of the container is upgraded; and at any other time as may be deemed necessary. Combinations to locks on security containers will be changed only by individuals having a security clearance equal to the highest category of classified material stored therein. Changing lock combinations is a responsibility of OAO. (See FPC Special Instruction No. AM 2162.2, Periodic Change of Combination on Locks.)
(h) The individual who unlocks a container will indicate the date and time and initial entry on GSA Optional Form 62. At the close of each workday, or when the container is locked at earlier time, the individual locking the container will make the appropriate entry on GSA Optional Form 62. An individual other than the one who locked the container will check to insure that it is properly closed and locked and will make the appropriate entry on GSA Optional Form 62. When a container has not been opened during the day, the checker will enter the date and the notation “Not Opened” and make appropriate entry in the “Checked By” column.
(i) The red and white reversible “Closed-Open” cardboard sign will be used on all classified containers to indicate whether the container is open or locked.
(j) Typewriter ribbons used in the preparation of classified information will be safeguarded in the manner appropriate for the degree of classification involved. Cloth ribbons are considered insecure until both upper and lower lines have been cycled through the typewriter at least twice. Carbon paper or film ribbons are insecure at all times since the imprint thereon cannot be obliterated and such ribbon must be destroyed as classified waste. Insecure ribbons will not be left in typewriters overnight but will be stored in appropriate classified container.
Accountability For Classified Material
§ 3a.71 Accountability for classified material.
(a) The Office of Administrative Operations is the central control registry for the receipt and dispatch of classified material in the Washington office and maintains the accountability register of all classified material. In addition, each Regional Engineer will maintain an accountability register for classified material of which he has custody.
(b) With the exception of the Chairman, Vice Chairman, and Executive Director, no individual, bureau, or office is authorized to receive, open, or dispatch classified material other than the authorized personnel in OAO or the Regional Engineers. Classified material received by other than the OAO or Regional Engineers will be delivered promptly and unopened to the Security Officer or Regional Engineer in order that it may be brought under accountable control.
(c) Each classified document received by or originating in the FERC will be assigned an individual control number by the central control registry, OAO. Control numbers will be assigned serially within a calendar year. The first digit of the four-digit control number will indicate the calendar year in which the document was originated or received in the FERC. Control numbers assigned to top secret material will be separate from the sequence for other classified material and will be prefixed by the letters “TS”. Examples:
(d) The accounting system for control of classified documents will be effected through the use of FERC Form 55, Classified Document Control Record and Receipt. This form will be used to:
(1) Register an accurate, unclassified description of the document; its assigned control number; and the date it is placed under accountability.
(2) Serve as the accountability register for classified material.
(3) Record all changes in status or custody of the document during its classification life or the period it is retained under accountability in the FERC.
(4) Serve as the principal basis for all classified document inventory and tracer actions.
(5) Serve as a receipt for the central control registry when the document is transferred.
(e) For Top Secret documents only, an access register, FPC Form 1286, Top Secret Access Record, for recording the names of all individuals having access to the document, will be prepared in addition to FPC Form 55. In addition, a physical inventory of all Top Secret documents will be conducted during June of each year by the Top Secret Control Officer and witnessed by a staff member holding a Top Secret clearance.
(f) When classified documents are regraded, declassified, or destroyed, the change in status will be recorded in the file copy of FPC Form 55 in the central control registry.
(g) Classified documents will not be reproduced by any means except on the specific written authority of the FPC Security Officer.
(h) In the Washington Office, classified material will be destroyed by OAO and will be accomplished by burning in the presence of a destroying official and a witnessing official. Destroying and witnessing officials will be alternate Security Officers from OAO. A record of destruction of each classified document will be maintained on FPC Form 1285. Classified Document Destruction Certificate. In addition, the date of destruction and the destruction certificate number will be recorded on the file copy of FPC Form 55 in the central control registry. The original signed copy of the destruction certificate will be retained in the central control registry. The duplicate copy will be retained by the destroying official. Regional Engineers will follow these instructions for destruction of classified material in their possession, except that the destroying official shall be the Regional Engineer and the witnessing official shall be any other individual having appropriate security clearance.
(i) It is the responsibility of any staff member who has knowledge of the loss or possible compromise of classified information immediately to report the circumstances to the Director, OAO. The Director, OAO, will notify the originating Department and any other interested Department of the loss or possible compromise in order that a damage assessment can be conducted. An immediate inquiry will be initiated by the Director, OAO, for the purpose of taking corrective action and for recommendations to the chairman, through the Review Committee, for appropriate administrative, disciplinary, or legal action.
Transmittal of Classified Material
§ 3a.81 Transmittal of classified material.
(a) A continuous receipting system, using copies of FERC Form 55, will record all transfers of classified items between elements or officials within the FERC. Receipts for transmittal of classified items from the central registry to the first recipient will be acknowledged on copy number one (original) of FERC Form 55. This copy will be returned to and become part of the central register, where it will remain as an active record until the item is either destroyed or transmitted outside the FERC control registry system. Receipts for subsequent transmittals through the FERC will be recorded on the remaining copies of FERC Form 55.
(b) A recipient will acknowledge receipt and assumption of custody of classified material exactly as it is described on FPC Form 55. If it is determined that parts are missing, it is incorrectly numbered, or otherwise recorded in error on FPC Form 55. The recipient will not sign for the material but will return it promptly to the transmitting element, notifying them accordingly.
(c) Whenever a classified or protected document is being internally transmitted, or is in use, it will be covered by either FERC Label 19, Top Secret Cover Sheet (yellow); FERC Label 20, Secret Cover Sheet (red); FERC Label 21, Confidential Cover Sheet (blue), or FERC Label 22, Official Use Only (Limited Official Use) green. In addition, the red back sheet, FERC Label 23, will be used. With the exception of the FERC Form 55, no transmittal paper or other material will be placed over the label, and no writing will be applied thereon.
(d) The transmission or transfer of custody of classified material outside of the FERC Washington offices or the Regional Offices will be covered by FERC Form 1284, Classified Document Receipt and/or Tracer, prepared in duplicate (one post card and one paper copy). The post card will be enclosed, along with the material being transferred, in the inner envelope, wrapping or container, and the paper copy retained in the central registry pending return of the signed post card.
(e) Classified material transmitted outside of the FERC Washington offices or the Regional Offices will be dispatched in two opaque envelopes or double wrapped in opaque wrapping paper. The outgoing material will be prepared for transmission by:
(1) Preparing and enclosing an appropriate receipt (see paragraph (d) of this section) in the inner envelope or wrapping.
(2) Addressing, return addressing, and sealing or taping the inner envelope or wrapping.
(3) Marking the security classification and other required notations on the front and back of the inner cover. If the nature of the contents deem it necessary or advisable, the inner cover may be marked with the following or a similar notation “To Be Opened By Addressee Only.” When this notation is used, an appropriate “Attention” line must be contained in the address on the outer envelope to insure delivery to the intended recipient.
(4) Enclosing the inner envelope or wrapping in an opaque outer envelope wrapper containing the appropriate address information. These outer covers will not contain any of the markings contained on the inner cover. If the outer cover does not fully conceal the markings on the inner envelope or wrapper, a sheet of plain paper should be folded around the inner wrapper to conceal the markings.
(f) Transmittal of Top Secret information and material shall be effected preferably by oral discussion in person between the officials concerned. Otherwise the transmission of Top Secret information and material shall be by specifically designated personnel, by State Department diplomatic pouch, by a messenger-courier system especially created for that purpose, over authorized communications circuits in encrypted form or by other means authorized by the National Security Council.
(g) Transmittal of material classified Secret or Confidential to any addressee in the 48 contiguous States and the District of Columbia, the State of Hawaii, the State of Alaska, the Commonwealth of Puerto Rico, and Canadian Government installations by the FERC Washington offices or the Regional offices will be by registered mail only. Transmittal outside these specified areas will be as stated in paragraph C(2), Appendix B, of the NSC Directive of May 17, 1972.
Data Index System
§ 3a.91 Data index system.
A data index system shall be established for Top Secret, Secret, and Confidential information in selected categories prescribed by the Interagency Classification Review Committee, in accordance with section VII of the National Security Council Directive Governing the Classification, Downgrading, Declassification, and Safeguarding of National Security Information, May 17, 1972.
PART 3b—COLLECTION, MAINTENANCE, USE, AND DISSEMINATION OF RECORDS OF IDENTIFIABLE PERSONAL INFORMATION
Subpart A—General
§ 3b.1 Purpose.
Part 3b describes the Federal Energy Regulatory Commission’s program to implement the provisions of the Privacy Act of 1974 (Pub. L. No. 93–579, 88 Stat. 1896) to allow individuals to have a say in the collection and use of information which may be used in determinations affecting them. The program is structured to permit an individual to determine what records pertaining to him and filed under his individual name, or some other identifying particular, are collected, maintained, used or disseminated by the Commission, to permit him access to such records, and to correct or amend them, and to provide that the Commission collect, use, maintain and disseminate such information in a lawful manner for a necessary purpose.
§ 3b.2 Definitions.
In this part:
(a) Agency, as defined in 5 U.S.C. 551(1) as “* * * each authority of the Government of the United States, whether or not it is within or subject to review by another agency, * * *”, includes any executive department, military department, Government corporation, Government controlled corporation, or other establishment in the executive branch of the Government (including the Executive Office of the President), or any independent regulatory agency [5 U.S.C. 552(e)];
(b) Individual means a citizen of the United States or an alien lawfully admitted for permanent residence;
(c) Maintain includes, maintain, collect, use, or disseminate;
(d) Record means any item, collection or grouping of information about an individual that is maintained by an agency, including, but not limited to, his education, financial transactions, medical history, and criminal or employment history and that contains his name, or the identifying number, symbol, or other identifying particular assigned to the individual, such as a finger or voice print or a photograph;
(e) System of records means a group of any records under the control of any agency from which information is retrieved by the name of the individual or by some identifying number, symbol, or other identifying particular assigned to the individual;
(f) Statistical record means a record in a system of records maintained for statistical research or reporting purposes only and not used in whole or in part in making any determination about an identifiable individual, except as provided by section 8 of title 13 of the United States Code;
(g) Routine use means, with respect to the disclosure of a record, the use of such record for a purpose which is compatible with the purpose for which it was collected; and
(h) Disclosure means either the transmittal of a copy of a record or the granting of access to a record, by oral, written, electronic or mechanical communication.
§ 3b.3 Notice requirements.
(a) The Commission will publish at least annually in the
(1) The name and location of the system;
(2) The categories of individuals on whom records are maintained in the system;
(3) The categories of records maintained in the system;
(4) The specific statutory provision or executive order, or rule or regulation issued pursuant thereto, authorizing the maintenance of the information contained in the system;
(5) Each routine use of the records contained in the system, including the categories of users and the purposes of such use;
(6) The policies and practices regarding the storage, retrievability, access controls, and retention and disposal of the records;
(7) The title and business address of the Commission official who is responsible for the system of records;
(8) The procedures whereby an individual can be notified at his request if the system of records contains a record pertaining to him;
(9) The procedures whereby an individual can be notified at his request how he can gain access to any record pertaining to him contained in the system of records, and how he can contest its contents; and
(10) The categories of sources of records in the system.
(b) At least thirty days prior to its operation, the Commission will publish in the
(c) The Commission will publish in the
(1) The name of the system of records for which the routine use is to be established;
(2) The authority authorizing the maintenance of the information contained in the system;
(3) The categories of records maintained in the system;
(4) The proposed routine use(s);
(5) The categories of recipients for each proposed routine use; and
(6) Reference to the public notice in the
§ 3b.4 Government contractors.
Systems of records operated by a contractor, pursuant to a contract, on behalf of the Commission, which are designed to accomplish a Commission function, are considered, for the purposes of this part, to be maintained by the Commission. A contract covers any contract, written or oral, subject to the Federal Procurement Regulations. The contractual instrument will specify, to the extent consistent with the Commission’s authority to require it, that the systems of records be maintained in accordance with the requirements of this part.
§ 3b.5 Legal guardians.
For the purposes of this part, the parent of any minor, or the legal guardian of any individual who has been declared to be incompetent due to physical or mental incapacity or age by a court of competent jurisdiction, may act on behalf of the individual.
Subpart B—Standards for Maintenance and Collection of Records
§ 3b.201 Content of records.
(a) All records which are maintained by the Commission in a system of records will contain only such information about an individual that is relevant and necessary to accomplish a purpose of the Commission as required to be accomplished by statute or by executive order of the President. Pursuant to § 3b.3(a)(4) of this part, the Commission will identify in the
(1) Whether each item of information relates to the purposes, in law, for which the system is maintained;
(2) The adverse consequences, if any, of not collecting the information;
(3) Whether the need for the information could be met through the maintenance of the information in a non-individually identifiable form;
(4) Whether the information in the record is required to be collected on every individual who is the subject of a record in the system or whether a sampling procedure would suffice;
(5) The length of time it is necessary to retain the information;
(6) The financial cost of maintaining the record as compared to the adverse consequences of not maintaining it; and
(7) Whether the information, while generally relevant and necessary to accomplish a statutory purpose, is specifically relevant and necessary only in certain cases.
(b) All records which the Commission maintains in a system of records and which are used to make a determination about an individual will be maintained with such accuracy, relevance, timeliness, and completeness as is reasonably necessary to assure fairness to the individual in the determination. Where practicable, in questionable instances, reverification of pertinent information with the individual to whom the record pertains may be appropriate. In pursuit of completeness in the collection of information, the Commission will limit its records to those elements of information which clearly bear on the determination for which the records are intended to be used, assuring that all elements necessary to the determination are present before the determination is made.
(c) Prior to disseminating any records in a system of records, the Commission will make reasonable efforts to assure that such records are as accurate, relevant, timely, and complete as appropriate for the purposes for which they are collected and/or maintained, except when they are disclosed to a member of the public under the Freedom of Information Act, 5 U.S.C. 552, as amended, or to another agency.
(d) No records of the Commission in a system of records shall describe how any individual exercises his First Amendment rights unless expressly authorized by statute or by the individual about whom the record is maintained or unless pertinent to and within the scope of an authorized law enforcement activity. The exercise of these rights includes, but is not limited to, religious and political beliefs, freedom of speech and of the press, and freedom of assembly and petition. In determining whether or not a particular activity constitutes the exercise of a right guaranteed by the First Amendment, the Commission will apply the broadest reasonable interpretation.
§ 3b.202 Collection of information from individuals concerned.
(a) Any information collected by the Commission for inclusion in a system of records which may result in adverse determinations about an individual’s rights, benefits, and privileges under Federal programs, will, to the greatest extent practicable, be collected directly from the subject individual (see paragraph (d) of this section).
(b) The Commission will inform each individual whom it asks to supply information about himself, on the form which it uses to collect the information, or on a separate sheet that can be easily retained by the individual, in language which is explicit, informative, and easily understood, and not so lengthy as to deter an individual from reading it, of:
(1) The specific provision of the statute or executive order of the President, including the brief title or subject of that statute or order which authorizes the solicitation of the information; whether disclosure of such information is mandatory or voluntary; and whether the Commission is authorized or required to impose penalties for failing to respond;
(2) The principal purpose or purposes for which the information is intended to be used;
(3) The routine uses which may be made of the information, as described in the
(4) The effects (beneficial and adverse) on the individual if any, of not providing all or any part of the requested information.
(c) Social security numbers will not be required from individuals whom the Commission asks to supply information unless the disclosure of the number is required by Federal statute or unless disclosure is to the Commission maintaining a system of records in existence and operating before January 1, 1975, if such disclosure was required pursuant to a statute or regulation adopted prior to such date to verify the identity of an individual. When an individual is requested to disclose his social security number to the Commission, he will be informed under what statutory or other authority such number is solicited, what uses will be made of it, whether disclosure is mandatory or voluntary, and if it is mandatory, under what provisions of law or regulation.
(d) The use of third-party sources to collect information about an individual may be appropriate in certain circumstances. In determining when the use of third-party sources would be appropriate, the following considerations will govern:
(1) When the information needed can only be obtained from a third party;
(2) When the cost of collecting the information directly from the individual concerned far exceeds the cost of collecting it from a third party;
(3) When there is little risk that the information proposed to be collected from the third party, if inaccurate, could result in an adverse determination about the individual concerned.
(4) When there is a need to insure the accuracy of information supplied by an individual by verifying it with a third party, or there is a need to obtain a qualitative assessment of the individual’s capabilities or character; or
(5) When there are provisions for verifying any third-party information with the individual concerned before making a determination based on that information.
§ 3b.203 Rules of conduct.
(a) The Executive Director of the Commission has the overall administrative responsibility for implementing the provisions of the Privacy Act of 1974 and overseeing the conduct of all Commission employees with respect to the act.
(b) It is the responsibility of the Comptroller of the Commission, under the guidance of the Executive Director, to prepare the appropriate internal administrative procedures to assure that all persons involved in the design, development, or operation of any system of records, or in collecting, using, or disseminating any individual record, and who have access to any system of records, are informed of all rules and requirements of the Commission to protect the privacy of the individuals who are the subjects of the records, including the applicable provisions of the FERC Standards of Conduct for Employees, Special Government Employees and Commissioners.
(c) The Director, Human Resources Division, is responsible for establishing and conducting an adequate training program for such persons whose official duties require access to and collection, maintenance, use, and dissemination of such records.
(d) The General Counsel of the Commission is responsible for providing legal interpretation of the Privacy Act of 1974, and for preparing all agency rules and notices for official publication in compliance with the act.
(e) Commission employees will be informed of all the implications of their actions in this area, including especially:
(1) That there are criminal penalties for knowing and willful unauthorized disclosure of material within a system of records; for willful failure to publish a public notice of the existence of a system of records; and for knowingly and willfully requesting or obtaining records under false pretenses;
(2) That the Commission may be subject to civil suit due to failure to amend an individual’s record in accordance with his request or failure to review his request in conformity with § 3b.224; refusal to comply with an individual’s request of access to a record under § 3b.221; willful or intentional failure to maintain a record accurately pursuant to § 3b.201(b) and consequently a determination is made which is adverse to the individual; or willful or intentional failure to comply with any other provision of the Privacy Act of 1974, or any rule promulgated thereunder, in such a way as to have an adverse effect upon an individual.
§ 3b.204 Safeguarding information in manual and computer-based record systems.
(a) The administrative and physical controls to protect the information in the manual and computer-based record systems from unauthorized access or disclosure will be specified for each system in the
(b) Whenever records in the manual or computer-based record systems, including input and output documents, punched cards, and magnetic tapes or disks, are not under the personal control of an authorized person, they will be stored in lockable containers and/or in a secured room, or in alternative storage systems which furnish an equivalent or greater degree of physical security. In this regard, the Commission may refer to security guidelines prepared by the General Services Administration, the Department of Commerce (National Bureau of Standards), or other agencies with appropriate knowledge and expertise.
(c) Access to and use of records will only be permitted to persons pursuant to §§ 3b.221, 3b.224, and 3b.225. Access to areas where records are stored will be limited to those persons whose official duties require work in such areas. Proper control of data, in any form, associated with the manual and computer-based record systems will be maintained at all times, including maintenance of an accounting of removal of the records from the storage area.
Subpart C—Rules for Disclosure of Records
§ 3b.220 Notification of maintenance of records to individuals concerned.
(a) Upon written request, either in person or by mail, to the appropriate system manager specified for each system of records, an individual will be notified whether a system of records maintained by the Commission and named by the individual contains a record or records pertaining to him and filed under his individual name, or some other identifying particular.
(b) The system manager may require appropriate identification pursuant to § 3b.222, and if necessary, may request from the individual additional information needed to locate the record which the individual should reasonably be expected to know, such as, but not limited to, date of birth, place of birth, and a parent’s first name.
(c) When practicable, the system manager will provide a written acknowledgement of the inquiry within ten days of receipt of the inquiry (excluding Saturdays, Sundays and legal public holidays) and notification of whether or not a system of records maintained by the Commission and named by the individual contains a record pertaining to him and filed under his individual name or some other identifying particular. If the system manager is unable to provide an answer within the ten-day period, he will so inform the individual in writing, stating the reasons therefor (for good cause shown), and when it is anticipated that notification will be made. Such an extension will not exceed fifteen days from receipt of the inquiry (excluding Saturdays, Sundays, and legal public holidays).
(d) For good cause shown, as used in all sections of this part, includes circumstances such as the following: Where a search for and/or collection of requested records from inactive storage, field offices, or other establishments is required; where a voluminous amount of data is involved; where information on other individuals must be separated or expunged from the record; or where consultations are required with other agencies or with others having a substantial interest in the determination of the request.
§ 3b.221 Access of records to individuals concerned.
(a) Upon written request, either in person or by mail, to the appropriate system manager specified for each system of records, any individual may gain access to records or information in a system of records pertaining to him and filed under his individual name, or some other identifying particular, to review and to have a copy made of all or any portion thereof in a form comprehensible to him.
(b) A person of his own choosing may accompany the individual to whom the record pertains when the record is disclosed [see § 3b.222(e)].
(c) Before disclosure, the following procedure may apply:
Medical or psychological records will be disclosed directly to the individual to whom they pertain unless, in the judgment of the system manager, in consultation with a medical doctor or a psychologist, access to such records could have an adverse effect upon the individual. When the system manager and a doctor determine that the disclosure of such information could have an adverse effect upon the individual to whom it pertains, the system manager may transmit such information to a medical doctor named by the requesting individual.
(d) The system manager will provide a written acknowledgement of the receipt of a request for access within ten days of receipt (excluding Saturdays, Sundays, and legal public holidays). Such acknowledgement may, if necessary, request any additional information needed to locate the record which the individual may reasonably be expected to know, and may require appropriate identification pursuant to § 3b.222 of this part. No acknowledgment is required if access can be granted within the ten-day period.
(1) If access can be granted, the system manager will notify the individual, in writing, as to when, and whether access will be granted in person or by mail, so that access will be provided within twenty days of the receipt of the request (excluding Saturdays, Sundays, and legal public holidays). If the system manager is unable to provide access within twenty days of receipt of the request, he will inform the individual in writing as to the reasons therefor (for good cause shown), and when it is anticipated that access will be granted. If the expected date of access indicated in the written notification to the individual cannot be met, the system manager will advise the individual in writing of the delay, the reasons therefor (for good cause shown), and of a revised date when access will be granted. Such extensions will not exceed thirty days from receipt of the request (excluding Saturdays, Sundays, and legal public holidays).
(2) If access cannot be granted, the system manager will inform the individual, in writing, within twenty days of receipt of the request (excluding Saturdays, Sundays, and legal public holidays) of the refusal of his request; the reasons for the refusal; the right of the individual, within thirty days of receipt of the refusal, to request in writing a review of the refusal by the Chairman of the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, or by an officer designated by the Chairman pursuant to § 3b.224(f); and the right of the individual to seek advice or assistance from the system manager in obtaining such a review.
(e) The Chairman, or officer designated pursuant to § 3b.224(f), not later than thirty days (excluding Saturdays, Sundays, and legal public holidays) from the date of receipt of the individual’s request for review will complete such review, unless, for good cause shown, the Chairman, or designated officer, extends the thirty-day period in writing to the individual with reasons for the delay and the approximate date on which the review is expected to be completed. Such an extension will not exceed thirty-five days from receipt of the request for review (excluding Saturdays, Sundays and legal public holidays). The Chairman, or designated officer, will make one of the following determinations:
(1) Grant the individual access to the requested record and notify the individual, in writing, as to when, and whether access will be granted in person or by mail; or
(2) Inform the individual in writing of the refusal, the reasons therefor, and the right of the individual to seek judicial review of the refusal of his request for access.
(f)(1) The Commission will deny an individual access to the following records pertaining to him:
(i) Information compiled in reasonable anticipation of a civil action or proceeding;
(ii) Records listed in the
(iii) Records which may be required to be withheld under other statutory provisions.
(2) The Commission will not deny an individual access to a record pertaining to him because that record is permitted to be withheld from members of the public under the Freedom of Information Act, 5 U.S.C. 552, as amended.
(g) Disclosure of an original record will take place in the presence of the Commission representative having physical custody of the record.
§ 3b.222 Identification requirements.
The appropriate system manager specified for each system of records will require reasonable identification from individuals to assure that records in a system of records are disclosed to the proper person. Identification requirements will be consistent with the nature of the records being disclosed.
(a) Disclosure of records to the individual to whom the record pertains, or under whose name or some other identifying particular the record is filed, in person, requires that the individual show an identification card. Employee identification, a Medicare card, or a driver’s license are examples of acceptable identification. Documents incorporating a picture and signature of the individual are preferred.
(b) For records disclosed by mail, the system manager will require certain minimum identifying information: name, date of birth, or the system’s personal identifier if known to the individual. A comparison of the signatures of the requester and those in the record will be used to determine identity.
(c) If the system manager determines that the data in the record is so sensitive that unauthorized access could cause harm or embarrassment to the individual involved, a signed notarized statement asserting identity or some other reasonable means to verify identity will be required.
(d) If an individual can provide no suitable information or documents for identification, the system manager will require a signed statement from the individual asserting his identity and stipulating that the individual understands that knowingly or willfully seeking or obtaining access to records about an individual under false pretenses is a misdemeanor punishable by a fine of up to $5,000.
(e) The system manager will require an individual who wishes to be accompanied by another person when reviewing his records to furnish a signed written statement authorizing discussion of his records in the presence of the accompanying person.
(f) The appropriate identification requirements of this section may be required by a system manager from an individual to whom a record does not pertain who seeks access to the record pursuant to § 3b.225 of this part.
(g) No individual will be denied notification of maintenance of a record pursuant to § 3b.220 or access to a record pursuant to §§ 3b.221 and 3b.224 for refusing to disclose a social security number.
(h) No verification of identity will be required of individuals seeking notification of or access to records which are otherwise available to a member of the public under the Freedom of Information Act, 5 U.S.C. 552, as amended.
§ 3b.223 Fees.
(a) Fees will be charged for the direct cost of duplication of records in a system of records when copies are requested by the individual seeking access to the records. Any person may obtain a copy of the Commission’s schedule of fees by telephone, by mail or by coming in person to the office of the appropriate system manager who is responsible for the protection and accountability of the desired record. Requests for copies of requested records and payment therefor must be made to the system manager. Fees will only be charged for costs of $2 or more.
(b) Where practicable, self-service duplication of requested documents may also be made on duplicating machines by the person requesting the records, on a reimbursable basis to the system manager, in the presence of the Commission representative having physical custody of the record. Where data has been extracted from one of the Commission’s systems of records on magnetic tape or disks, or computer files, copies of the records of these files may be secured on a reimbursable basis upon written request to the appropriate system manager. The fee will vary for each requirement, depending on size and complexity.
(c) No fee will be charged in the following instances:
(1) When the system manager determines that he can grant access to records only by providing a copy of the record through the mail because he cannot provide reasonable means for the individual to have access in person;
(2) For search and review of requested records to determine if they fall within the disclosure requirements of this part; and
(3) When the system manager makes a copy of the record as a necessary part of the process of making it available for review.
(d) Except for requests made by Government agencies, certification of copies of any official Commission record shall be accompanied by a fee of $2 per document.
§ 3b.224 Requests to amend records and disputes thereon.
(a) Upon written request, either in person or by mail, to the appropriate system manager specified for each system of records, any individual may amend records in a system of records pertaining to him and filed under his individual name or some other identifying particular. Such requests should contain identifying information needed to locate the record, a brief description of the item or items of information to be amended, and information in support of the request for amendment. The individual may obtain assistance in preparing his request to amend a record from the appropriate system manager.
(b) The system manager will provide a written acknowledgement of the receipt of a request to amend within ten days of receipt (excluding Saturdays, Sundays, and legal public holidays). Such an acknowledgement may, if necessary, request any additional information needed to make a determination which the individual may reasonably be expected to know, and verification of identity consistent with § 3b.222. The acknowledgement will clearly describe the request and advise the individual requesting the amendment when he may expect to be notified of action taken on the request. No acknowledgement is required if the request can be reviewed, processed, and the individual notified of compliance or denial within the ten-day period.
(c) The system manager will complete the review and advise the individual in writing of the results within twenty days of the receipt of the request (excluding Saturdays, Sundays, and legal public holidays). If the system manager is unable to complete the review within twenty days of the receipt of the request, he will inform the individual in writing as to the reasons therefor (for good cause shown) and when it is anticipated that the review will be completed. If the completion date for the review indicated in the acknowledgement cannot be met, the system manager will advise the individual in writing of the delay, the reasons therefor (for good cause shown), and of a revised date when the review may be expected to be completed. Such extensions will not exceed thirty days from receipt of the request (excluding Saturdays, Sundays, and legal public holidays). The system manager will take one of the following actions:
(1) Make the requested correction or amendment; so advise the individual in writing; and, where an accounting of the disclosure of the record was made pursuant to § 3b.226, advise all previous recipients of the record in writing of the fact that the amendment was made and the substance of the amendment [see § 3b.225(d)]; or
(2) Inform the individual in writing of the refusal to amend the record in accordance with the request; the reasons for the refusal including any of the standards which were employed pursuant to paragraph (d) of this section in conducting the review; the right of the individual, within thirty days of receipt of the refusal, to request in writing a review of the refusal by the Chairman of the Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, or by an officer designated by the Chairman pursuant to paragraph (f) of this section; and the right of the individual to seek advice or assistance from the system manager in obtaining such a review.
(d) In reviewing a record in response to a request to amend, the system manager and the Chairman, or the officer he designates pursuant to paragraph (f) of this section, shall assess the accuracy, relevance, timeliness and completeness of the record. They shall consider the record in terms of the criteria established in § 3b.201 of this part.
(e) The Chairman, or officer designated pursuant to paragraph (f) of this section, not later than thirty days (excluding Saturdays, Sundays, and legal public holidays) from the date of receipt of the individual’s request for review, will complete such review, unless, for good cause shown, the Chairman, or designated officer, extends the thirty-day period in a writing to the individual with reasons for the delay and the approximate date on which the review is expected to be completed. Such an extension will not exceed thirty-five days from receipt of the request for review (excluding Saturdays, Sundays, and legal public holidays). The Chairman, or designated officer, will make one of the following determinations:
(1) Make the correction in accordance with the individual’s request and proceed as in paragraph (c)(1) of this section; or
(2) Inform the individual in writing of:
(i) The refusal to amend the record in accordance with the request,
(ii) The reasons therefor, including any of the standards which were employed pursuant to paragraph (d) of this section in conducting the review;
(iii) The right of the individual to file with the Chairman, or designated officer, a concise written statement setting forth the reasons for his disagreement with the decision;
(iv) The fact that the statement of disagreement will be made available to anyone to whom the record is subsequently disclosed, together with the portion of the record which is disputed clearly noted, and, with, at the discretion of the Chairman, or designated officer, a brief statement by the Chairman, or designated officer, summarizing the reasons for refusing to amend the record;
(v) Where an accounting of the disclosure of the record was made pursuant to § 3b.226 of this part, the fact that prior recipients of the disputed record will be provided a copy of the individual’s statement of disagreement, with the portion of the record which is disputed clearly noted, and, at the Chairman’s or designated officer’s discretion, the statement summarizing the refusal to amend [see § 3b.225(d)]; and
(vi) The individual’s right to seek judicial review of the refusal to amend.
(f) The Chairman may designate, in writing, another officer of the Commission to act in his capacity for the purposes of this part. The officer will be organizationally independent of or senior to the system manager who made the initial determination and will conduct a review independent of the initial determination.
§ 3b.225 Written consent for disclosure.
(a) The Commission will not disclose any record which is contained in a system of records by any means of communication to any person, or to any other agency, unless it has the written request by, or the prior written consent of, the individual to whom the record pertains and under whose individual name, or some other identifying particular, the record is filed. The written request or consent should include, at a minimum, the general purposes for or the types of recipients to whom disclosure may be made. The fact that an individual is informed of the purposes for which information will be used when information is collected pursuant to § 3b.202(b)(2) will not constitute consent.
(b) A written request or consent is not required if the disclosure is:
(1) To those officers and employees of the Commission who have a need for the record in the performance of their duties;
(2) Required under the provisions of the Freedom of Information Act, 5 U.S.C. 552, as amended;
(3) For a routine use as defined in § 3b.2(g) of this part and as described in the public notice for each system of records;
(4) To the Bureau of the Census for purposes of planning or carrying out a census or survey or related activity pursuant to the provisions of title 13 of the United States Code;
(5) To a recipient who has provided the appropriate system manager specified for each system of records with advance adequate written assurance that the record will be used solely as a statistical research or reporting record, and the record is to be transferred in a form that is not individually identifiable. The written statement of assurance should include at a minimum:
(i) A statement of the purpose for requesting the record; and
(ii) Certification that the record will only be used for statistical purposes.
(6) To the National Archives of the United States, pursuant to 44 U.S.C. 2103, as a record which has sufficient historical or other value to warrant its continued preservation by the United States Government, or for the evaluation by the Administrator of General Services or his designee to determine whether the record has such value;
(7) To another agency or to an instrumentality of any governmental jurisdiction within or under the control of the United States for a civil or criminal law enforcement activity if the activity is authorized by law, and if the head of the agency or instrumentality, or his delegated official, has made a written request to the appropriate system manager specifying the particular portion of the record desired and the law enforcement activity for which the record is being sought;
(8) To a person pursuant to a showing of compelling circumstances affecting the health or safety of an individual (not necessarily the individual to whom the record pertains), if, upon disclosure, notification of such is sent to the last known address of the individual to whom the record pertains;
(9) To either House of Congress, or to any committee or subcommittee thereof, on a matter within its jurisdiction;
(10) To the Comptroller General, or any of his authorized representatives, in the course of the performance of the duties of the General Accounting Office; or
(11) Pursuant to the order of a court of competent jurisdiction.
(c) When a record is disclosed under compulsory legal process and such process becomes a matter of public record, the system manager will make reasonable efforts to notify the individual to whom the record pertains. A notice will be sent to the individual’s last known address noted in the Commission’s files.
(d) The appropriate system manager shall notify all prior recipients of records, disclosure to whom an accounting was made pursuant to § 3b.226, of any amendments made to the records, including corrections, amendments and notations of dispute made pursuant to §§ 3b.224(c)(1) and 3b.224(e)(1) and (2)(v), within ten days of receipt of the corrected information or notation of dispute (excluding Saturdays, Sundays, and legal public holidays), except under unusual circumstances [see circumstances described in § 3b.220(d)].
(e) The content of the records disclosed under this section shall be maintained pursuant to the standards established in § 3b.201(c).
§ 3b.226 Accounting of disclosures.
(a) The appropriate system manager specified for each system of records will keep an accurate written account of all disclosures of records made to any person or to any other agency with the written consent or at the written request of the individual to whom the record pertains and pursuant to § 3b.225(b)(3) through (11). The account will include the following information:
(1) The date, nature, and purpose of each disclosure;
(2) The name and address of the person or agency to whom the disclosure is made; and
(3) A reference to the justification or basis upon which the release was made, including reference to any written document required as when records are released for statistical or law enforcement purposes pursuant to § 3b.225(b) (5) and (7).
(b) Each system manager will retain the accounting made under paragraph (a) of this section for at least five years from the date of disclosure for which the accounting is made, or the life of the record, which ever is longer.
(c) Except for disclosures made for law enforcement purposes pursuant to § 3b.225(b)(7), and unless the system of records has been exempted from this provision pursuant to subpart D of this part, each system manager will make the accounting made under paragraph (a) of this section available to the individual named in the record at his written request.
(d) The accounting of disclosures is not a system of records under the definition in § 3b.2(e) and no accounting will be maintained for disclosure of the accounting of disclosures.
§ 3b.227 Mailing lists.
An individual’s name and address maintained by the Commission will not be sold or rented for commercial or other solicitation purposes not related to the purposes for which the information was collected, unless such sale or rental is specifically authorized by law. This provision shall not be construed to require the withholding of names or addresses otherwise permitted to be made public, as pursuant to the Freedom of Information Act, 5 U.S.C. 552, as amended.
Subpart D—Rules for Exemptions
§ 3b.250 Specific exemptions.
Any system of records maintained by the Commission may be exempt from certain provisions of the Privacy Act of 1974, and the appropriate sections of this part promulgated pursuant thereto, if the following requirements are met:
(a) The system of records falls within one or more of the following categories:
(1) Records subject to the provisions of 5 U.S.C. 552(b)(1) as classified material;
(2) Investigatory material compiled for law enforcement purposes [except to the extent that the system is more broadly exempt under 5 U.S.C. 552a(j)(2) covering records maintained by an agency whose principal function pertains to the enforcement of criminal laws] provided, however, that is such record is used as a basis for denying an individual any right, privilege, or benefit to which the individual would be entitled in the absence of that record, the individual must be granted access to that record except to the extent that access would reveal the identity of a confidential source who furnished the information to the Government under an express promise that his identity would be held in confidence, or, prior to September 27, 1975, under an implied promise that his identity would be held in confidence;
(3) Records maintained to provide protective services to the President of the United States or other individuals pursuant to 18 U.S.C. 3056;
(4) Records required by statute to be maintained and used solely as statistical records;
(5) Investigatory material compiled solely for determining suitability, eligibility, or qualifications for Federal civilian employment, military service, Federal contracts, or access to classified information, but only to the extent that disclosure of such material would reveal the identity of a source who furnished information to the Government under an express promise that his identity would be held in confidence, or, prior to September 27, 1975, under an implied promise that his identity would be held in confidence;
(6) Testing or examination material used solely to determine individual qualifications for appointment or promotion in the Federal service the disclosure of which would compromise the objectivity or fairness of the testing or examination process; or
(7) Material used to evaluate potential for promotion in the armed services, but only to the extent that the disclosure of such material would reveal the identity of a source who furnished the information to the Government under an express promise that his identity would be held in confidence, or, prior to September 27, 1975, under an implied promise that his identity would be held in confidence;
(b) Publication in the
(1) The name of the system of records;
(2) The specific provision or provisions of the Privacy Act of 1974, and the appropriate sections of this part promulgated pursuant thereto, from which the system is to be exempted; and
(3) The reasons for the exemption; and
(c) The system of records is exempted from one or more of the following provisions of the Privacy Act and the appropriate sections of this part promulgated pursuant thereto:
(1) 5 U.S.C. 552a(c)(3); 18 CFR 3b.226(c)—Making the accounting of disclosures available to the individual named in the record at his request;
(2) 5 U.S.C. 552a(d); 18 CFR 3b.221, 3b.224—Granting an individual the right of access to his records and permitting him to request amendment of such;
(3) 5 U.S.C. 552a(e)(1); 18 CFR 3b.201(a)—Requiring maintenance of relevant and necessary information in a system of records as required by statute or Executive order of the President;
(4) 5 U.S.C. 552a(e)(4)(G); 18 CFR 3b.3(a)(8)—Requiring a description of procedures for determining if a system contains a record on an individual in the public notice of the system of records;
(5) 5 U.S.C. 552a(e)(4)(H); 18 CFR 3b.3(a)(9)—Requiring a description of procedures for gaining access to and contesting the contents of a record in the public notice of the system of records;
(6) 5 U.S.C. 552a(e)(4)(I); 18 CFR 3b.3(a)(10)—Requiring a description of the categories of the sources of records in the public notice of the system of records; and
(7) 5 U.S.C. 552a(f); 18 CFR 3b.220–3b.224—Requiring agency rules for determining if an individual is the subject of a record, for handling requests for access, for granting requests for access, for amending records, and for fees.
PART 3c—STANDARDS OF CONDUCT
§ 3c.1 Cross-reference to employee ethical conduct standards and financial disclosure regulations.
Employees of the Federal Energy Regulatory Commission (Commission) are subject to the executive branch-wide financial disclosure regulations at 5 CFR part 2634, the Standards of Ethical Conduct for Employees of the Executive Branch at 5 CFR part 2635, the Commission regulations at 5 CFR part 3401 which supplement the Standards of Ethical Conduct, and the executive branch-wide employee responsibilities and conduct regulation at 5 CFR part 735.
§ 3c.2 Nonpublic information.
(a) Section 1264(d) (42 U.S.C. 16452(d)) of the Public Utility Holding Company Act of 2005, section 301(b) (16 U.S.C. 825(b)) of the Federal Power Act, and section 8(b) (15 U.S.C. 717g) of the Natural Gas Act prohibit any employee, in the absence of Commission or court direction, from divulging any fact or information which may come to his or her knowledge during the course of examination of books or other accounts.
(b) The nature and time of any proposed action by the Commission are confidential and shall not be divulged to anyone outside the Commission. The Secretary of the Commission has the exclusive responsibility and authority for authorizing the initial public release of information concerning Commission proceedings.
§ 3c.3 Reporting fraud, waste, abuse, and corruption and cooperation with official inquiries.
(a) Employees shall, in fulfilling the obligation of 5 CFR 2635.101(b)(11), report fraud, waste, abuse, and corruption in Commission programs, including on the part of Commission employees, contractors, subcontractors, grantees, or other recipients of Commission financial assistance, to the Office of Inspector General or other appropriate Federal authority.
(b) All alleged violations of the ethical restrictions described in § 3c.1 that are reported in accordance with paragraph (a) of this section to an appropriate authority within the Commission shall in turn be referred by that authority to the Designated Agency Ethics Official or his or her designee, or the Inspector General.
(c) Employees shall cooperate with official inquiries by the Inspector General; they shall respond to questions truthfully under oath when required, whether orally or in writing, and must provide documents and other materials concerning matters of official interest. An employee is not required to respond to such official inquiries if answers or testimony may subject the employee to criminal prosecution.
SUBCHAPTER B—REGULATIONS UNDER THE FEDERAL POWER ACT
PART 4—LICENSES, PERMITS, EXEMPTIONS, AND DETERMINATION OF PROJECT COSTS
Subpart A—Determination of Cost of Projects Constructed Under License
§ 4.1 Initial cost statement.
(a) Notification of Commission. When a project is constructed under a license issued under the Federal Power Act, the licensee shall, within one year after the original project is ready for service, file with the Commission a letter, in quadruplicate, declaring that the original costs have been booked in compliance with the Commission’s Uniform System of Accounts and the books of accounts are ready for audit.
(b) Licensee’s books. The licensee’s books of accounts for each project shall be maintained in such a fashion that each year’s additions, betterments, and deletions to the project may be readily ascertained.
(c) Availability of information to the public. The information made available to the Commission in accordance with this section must be available to the public for inspection and copying when specifically requested.
(d) Compliance with the Act. Compliance with the provisions of this section satisfies the filing requirements of section 4(b) of the Federal Power Act (16 U.S.C. 797(b)).
§ 4.3 Report on project cost.
(a) Scheduling an audit. When the original cost declaration letter, filed in accordance with § 4.1 is received by the Commission, its representative will schedule and conduct an audit of the books, cost records, engineering reports, and other records supporting the project’s original cost. The audit may include an inspection of the project works.
(b) Project records. The cost records shall be supported by memorandum accounts reflecting the indirect and overhead costs prior to their spread to primary accounts as well as all the details of allocations including formulas utilized to spread the indirect and overhead costs to primary accounts.
(c) Report by Commission staff. Upon completion of the audit, a report will be prepared for the Commission setting forth the audit findings and recommendations with respect to the cost as claimed.
§ 4.4 Service of report.
Copies of such report will be served upon said licensees, and copies will also be sent to the State public service commission, or if the State has no regulatory agency, to the Governor of the State where such project is located, and to such other parties as the Commission shall prescribe, and the report will be made available for public inspection at the time of service upon the licensee.
§ 4.5 Time for filing protest.
Thirty days after service thereof will be allowed to such licensee within which to file a protest to such reports. If no protest is filed within the time allowed, the Commission will issue such order as may be appropriate. If a protest is filed, a public hearing will be ordered in accordance with subpart E of part 385 of this chapter.
§ 4.6 Burden of proof.
The burden of proof to sustain each item of claimed cost shall be upon the licensee and only such items as are in the opinion of the Commission supported by satisfactory proof may be entered in the electric plant accounts of the licensee.
§ 4.7 Findings.
(a) Commission determination. Final action by the Commission will be in the form of an order served upon all parties to the proceeding. One copy of the order will be furnished to the Secretary of Treasury by the Commission.
(b) Adjustments to licensee’s books. The licensee’s books of account for the project shall be adjusted to conform to the actual legitimate cost as revised by the order of the Commission. These adjustments and the project may be audited by Commission representatives, as scheduled.
Subpart B—Determination of Fair Value of Constructed Projects, Under Section 23(a) of the Act
§ 4.10 Valuation data.
(a) Notification of Commission. In every case arising under section 23(a) of the Federal Power Act that requires the determination of the fair value of a project already constructed, the licensee shall, within six months after the date of issuance of a license, file with the Commission a letter, in quadruplicate.
(b) Contents of letter. The letter referred to in paragraph (a) shall contain a statement to the effect that an inventory and appraisal in detail, as of the effective date of the license, of all property subject thereto and to be so valued has been completed. The letter shall also include a statement to the effect that the actual legitimate original cost, or if not known, the estimated original cost, and accrued depreciation of the property, classified by prime accounts as prescribed in the Commission’s Uniform System of Accounts, have been established.
(c) Licensee’s books. The licensee’s books of account for each project shall be maintained in such a fashion that each year’s additions, betterments, and deletions to the projects may be readily ascertained.
(d) Availability of information to the public. The information made available to the Commission in accordance with this section must be available for inspection and copying by the public when specifically requested.
§ 4.11 Reports.
Representatives of the Commission will inspect the project works, engineering reports, and other records of the project, check the inventory and make an appraisal of the property and an audit of the books, records, and accounts of the licensee relating to the property to be valued, and will prepare a report of their findings with respect to the inventory, appraisal, original cost, accrued depreciation, and fair value of the property.
§ 4.12 Service of report.
A copy of such report will be served upon said licensee, and copies will also be sent to the State public service commission, or if the State has no regulatory agency, to the Governor of the State where such project is located. The report will be made available for public inspection at the time of service upon the licensee.
§ 4.13 Time for filing protest.
Thirty days after service thereof will be allowed to the licensee within which to file a protest to such report.
§ 4.14 Hearing upon report.
(a) Public hearing. After the expiration of the time within which a protest may be filed, a public hearing will be ordered in accordance with subpart E of part 385 of this chapter.
(b) Commission determination. After the conclusion of the hearing, the Commission will make a finding of fair value, accompanied by an order which will be served upon the licensee and all parties to the proceeding. One copy of the order shall be furnished to the Secretary of the Treasury by the Commission.
(c) Adjustment to licensee’s books. The licensee’s books of account for the project shall be adjusted to conform to the fair value of the project as revised by the order of the Commission. These adjustments and the project may be audited by Commission representatives, as scheduled.
Subpart C—Determination of Cost of Constructed Projects not Subject to Section 23(a) of the Act
§ 4.20 Initial statement.
(a) Notification of Commission. In all cases where licenses are issued for projects already constructed, but which are not subject to the provisions of section 23(a) of the Act (49 Stat. 846; 16 U.S.C. 816), the licensee shall, within 6 months after the date of issuance of license, file with the Commission a letter, in quadruplicate.
(b) Contents of letter. The letter referred to in paragraph (a) of this section shall contain a statement to the effect that an inventory in detail of all property included under the license, as of the effective date of such license, has been completed. The letter shall also include a statement to the effect that actual legitimate original cost, or if not known, the estimated original cost, and accrued depreciation of the property, classified by prime accounts as prescribed in the Commission’s Uniform System of Accounts, have been established.
(c) Licensee’s books. The licensee’s books of account for each project shall be maintained in such a fashion that each year’s additions, betterments, and deletions to the project may be readily ascertained.
(d) Availability of information to the public. The information made available to the Commission in accordance with this section must be available for inspection and copying by the public when specifically requested.
(e) Compliance with the Act. Compliance with the provisions of this section satisfies the filing requirements of section 4(b) of the Federal Power Act (16 U.S.C. 797(b)).
§ 4.21 Reports.
Representatives of the Commission will inspect the project works, engineering reports, and other records of the project, check the inventory and estimated depreciation, make an audit of the books, records, and accounts of the licensee relating to the property under license, and prepare a report of their findings with respect to the inventory, the original cost of the property, and the estimated accrued depreciation thereon.
§ 4.22 Service of report.
Copies of such report will be served upon said licensees, and copies will also be sent to the State public service commission, or if the State has no regulatory agency, to the Governor of the State where such project is located, and to such other parties as the Commission shall prescribe, and the report will be made available for public inspection at the time of service upon the licensee.
§ 4.23 Time for filing protest.
Thirty days after service thereof will be allowed to such licensee within which to file a protest to such reports. If no protest is filed within the time allowed, the Commission will issue such order as may be appropriate. If a protest is filed, a public hearing will be ordered in accordance with subpart E of part 385 of this chapter.
§ 4.24 Determination of cost.
The Commission, after receipt of the reports, or after the conclusion of the hearing if one is held, will determine the amounts to be included in the electric plant accounts of the licensee as the cost of the property and the accrued depreciation thereon.
§ 4.25 Findings.
(a) Commission determination. Final action by the Commission will be in the form of an order served upon all parties to the proceeding. One copy of the order shall be furnished to the Secretary of Treasury by the Commission.
(b) Adjustment to licensee’s books. The licensee’s books of account for the project shall be adjusted to conform to the actual legitimate cost as revised by the order of the Commission. These adjustments and the project may be audited by Commission representatives, as scheduled.
Subpart D—Application for Preliminary Permit, License or Exemption: General Provisions
§ 4.30 Applicability and definitions.
(a) (1) This subpart applies to applications for preliminary permit, license, or exemption from licensing.
(2) Any potential applicant for an original license for which prefiling consultation begins on or after July 23, 2005 and which wishes to develop and file its application pursuant to this part, must seek Commission authorization to do so pursuant to the provisions of part 5 of this chapter.
(b) For the purposes of this part—
(1)(i) Competing development application means any application for a license or exemption from licensing for a proposed water power project that would develop, conserve, and utilize, in whole or in part, the same or mutually exclusive water resources that would be developed, conserved, and utilized by a proposed water power project for which an initial preliminary permit or initial development application has been filed and is pending before the Commission.
(ii) Competing preliminary permit application means any application for a preliminary permit for a proposed water power project that would develop, conserve, and utilize, in whole or in part, the same or mutually exclusive water resources that would be developed, conserved and utilized by a proposed water power project for which an initial preliminary permit or initial development application has been filed and is pending before the Commission.
(2) Conduit means any tunnel, canal, pipeline, aqueduct, flume, ditch, or similar manmade water conveyance that is operated for the distribution of water for agricultural, municipal, or industrial consumption and not primarily for the generation of electricity. The term not primarily for the generation of electricity includes but is not limited to a conduit:
(i) Which was built for the distribution of water for agricultural, municipal, or industrial consumption and is operated for such a purpose; and
(ii) To which a hydroelectric facility has been or is proposed to be added.
(3) Construction of a dam, for the purposes of provisions governing application for exemption of a small conduit hydroelectric facility, means any construction, repair, reconstruction, or modification of a dam that creates a new impoundment or increases the normal maximum surface elevation or the normal maximum surface area of an existing impoundment.
(4)(i) Dam, for the purposes of provisions governing application for license of a major project—existing dam, means any structure for impounding or diverting water.
(ii) Dam, for the purposes of provisions governing an application for exemption of a small conduit hydroelectric facility or a notice of intent to construct a qualifying conduit hydropower facility, means any structure that impounds water.
(iii) Dam, for the purposes of provisions governing application for exemption of a small hydroelectric power project, means any structure for impounding water, including any diversion structure that is designed to obstruct all or substantially all of the flow of a natural body of water.
(5) Development application means any application for either a license or exemption from licensing for a proposed water power project.
(6)(i) Existing dam, for the purposes of provisions governing application for license of a major project—existing dam, means any dam (as defined in paragraph (b)(4)(i) of this section) that has already been constructed and which does not require any construction or enlargement of impoundment structures other than repairs or reconstruction.
(ii) Existing dam, for the purposes of provisions governing application for exemption of a small hydroelectric power project, means any dam, the construction of which was completed on or before July 22, 2005, and which does not require any construction or enlargement of impoundment structures (other than repairs or reconstruction) in connection with the installation of any small hydroelectric power project.
(7) Existing impoundment, for the purposes of provisions governing application for license of a major project—existing dam, means any body of water that an existing dam impounds.
(8) Federal lands, for the purposes of provisions governing an application for exemption of a small conduit hydroelectric facility or a small hydroelectric power project, means any lands to which the United States holds fee title.
(9)(i) Fish and wildlife agencies means the United States Fish and Wildlife Service, the National Marine Fisheries Service, and the state agency in charge of administrative management over fish and wildlife resources of the state in which a proposed hydropower project is located.
(ii) Fish and wildlife recommendation means any recommendation designed to protect, mitigate damages to, or enhance any wild member of the animal kingdom, including any migratory or nonmigratory mammal, fish, bird, amphibian, reptile, mollusk, crustacean, or other invertebrate, whether or not bred, hatched, or born in captivity, and includes any egg or offspring thereof, related breeding or spawning grounds, and habitat. A “fish and wildlife recommendation” includes a request for a study which cannot be completed prior to licensing, but does not include a request that the proposed project not be constructed or operated, a request for additional pre-licensing studies or analysis or, as the term is used in §§ 4.34(e)(1) and 4.34(f)(3), a recommendation for facilities, programs, or other measures to benefit recreation or tourism.
(10) Indian tribe means, in reference to a proposal to apply for a license or exemption for a hydropower project, an Indian tribe which is recognized by treaty with the United States, by federal statute, or by the U.S. Department of the Interior in its periodic listing of tribal governments in the
(11)(i) Initial development application means any acceptable application for either a license or exemption from licensing for a proposed water power project that would develop, conserve, and utilize, in whole or in part, water resources for which no other acceptable application for a license or exemption from licensing has been submitted for filing and is pending before the Commission.
(ii) Initial preliminary permit application means any acceptable application for a preliminary permit for a proposed water power project that would develop, conserve, and utilize, in whole or in part, water resources for which no other acceptable preliminary permit application has been submitted for filing and is pending before the Commission.
(12) Install or increase, for the purposes of provisions governing application for exemption of a small hydroelectric power project, means to add new generating capacity at a site that has no existing generating units, to replace or rehabilitate an abandoned or unused existing generating unit, or to increase the generating capacity of any existing power plant by installing an additional generating unit or by rehabilitating an operable generating unit in a way that increases its rated electric power output.
(13) Licensed water power project means a project, as defined in section 3(11) of the Federal Power Act, that is licensed under Part I of the Federal Power Act.
(14) Major modified project means any major project—existing dam, as defined in paragraph (b)(16) of this section, that would include:
(i) Any repair, modification or reconstruction of an existing dam that would result in a significant change in the normal maximum surface area or the normal maximum surface elevation of an existing impoundment; or
(ii) Any change in existing project works or operations that would result in a significant environmental impact.
(15) Major unconstructed project means any unlicensed water power project that would:
(i) Have a total installed generating capacity of more than 1.5 MW; and
(ii) Use the water power potential of a dam and impoundment which, at the time application is filed, have not been constructed.
(16) Major project—existing dam means a licensed or unlicensed, existing or proposed water power project that would:
(i) Have a total installed generating capacity or more than 2,000 horsepower (1.5 MW); and
(ii) Not use the water power potential provided by any dam except an existing dam.
(17) Minor water power project means any licensed or unlicensed, existing or proposed water power project that would have a total installed generation capacity of 2,000 horsepower (1.5 MW), or less.
(18) New development, for the purposes of provisions governing application for license of a major project—existing dam, means any construction, installation, repair, reconstruction, or other change in the existing state of project works or appurtenant facilities, including any dredging and filling in project waters.
(19) New license means any license, except an annual license issued under section 15 of the Federal Power Act, for a water power project that is issued under the Federal Power Act after the initial license for that project.
(20) Non-Federal lands, for the purposes of provisions governing application for exemption of a small conduit hydroelectric facility or a small hydroelectric power project, means any lands except lands to which the United States holds fee title.
(21) Non-federally owned conduit, for the purposes of provisions governing the notice of intent to construct qualifying conduit hydropower facilities, means any conduit except a conduit to which the United States holds fee title.
(22) Person means any individual and, as defined in section 3 of the Federal Power Act, any corporation, municipality, or state.
(23) Project, for the purposes of provisions governing application for exemption of a small hydroelectric power project, means:
(i) The impoundment and any associated dam, intake, water conveyance facility, power plant, primary transmission line, and other appurtenant facility if a lake or similar natural impoundment or a manmade impoundment is used for power generation; or
(ii) Any diversion structure other than a dam and any associated water conveyance facility, power plant, primary transmission line, and other appurtenant facility if a natural water feature other than a lake or similar natural impoundment is used for power generation.
(24) Qualified exemption applicant, means any person who meets the requirements specified in § 4.31(c)(2) with respect to a small hydroelectric power project for which exemption from licensing is sought.
(25) Qualified license applicant means any person to whom the Commission may issue a license, as specified in section 4(e) of the Federal Power Act.
(26) Qualifying conduit hydropower facility, means a facility, not including any dam or impoundment, that is not required to be licensed under Part I of the FPA because it is determined to meet the following criteria:
(i) Generates electric power using only the hydroelectric potential of a non-federally owned conduit;
(ii) Has an installed capacity that does not exceed 40 megawatts (MW); and,
(iii) Was not licensed or exempted from the licensing requirements of Part I of the FPA on or before August 9, 2013.
(27) Ready for environmental analysis means the point in the processing of an application for an original or new license or exemption from licensing which has been accepted for filing, where substantially all additional information requested by the Commission has been filed and found adequate.
(28) Real property interests, for the purposes of provisions governing application for exemption of a small conduit hydroelectric facility or a small hydroelectric power project, includes ownership in fee, rights-of-way, easements, or leaseholds.
(29) Resource agency means a Federal, state, or interstate agency exercising administration over the areas of flood control, navigation, irrigation, recreation, fish and wildlife, water resource management (including water rights), or cultural or other relevant resources of the state or states in which a project is or will be located.
(30) Small conduit hydroelectric facility, means an existing or proposed hydroelectric facility that is constructed, operated, or maintained for the generation of electric power, and includes all structures, fixtures, equipment, and lands used and useful in the operation or maintenance of the hydroelectric facility, but excludes the conduit on which the hydroelectric facility is located and the transmission lines associated with the hydroelectric facility and which:
(i) Utilizes for electric power generation the hydroelectric potential of a conduit;
(ii) Has an installed generating capacity that does not exceed 40 MW;
(iii) Is not an integral part of a dam;
(iv) Discharges the water it uses for power generation either:
(A) Into a conduit;
(B) Directly to a point of agricultural, municipal, or industrial consumption; or
(C) Into a natural water body if a quantity of water equal to or greater than the quantity discharged from the hydroelectric facility is withdrawn from that water body downstream into a conduit that is part of the same water supply system as the conduit on which the hydroelectric facility is located; and
(v) Does not rely upon construction of a dam, which construction will create any portion of the hydrostatic head that the facility uses for power generation unless that construction would occur for agricultural, municipal, or industrial consumptive purposes even if hydroelectric generating facilities were not installed.
(31) Small hydroelectric power project, means any project in which capacity will be installed or increased after the date of application under subpart K of this chapter, which will have a total installed capacity of not more than 10 MW, and which:
(i) Would utilize for electric power generation the water power potential of an existing dam that is not owned or operated by the United States or by an instrumentality of the Federal Government, including the Tennessee Valley Authority; or
(ii)(A) Would utilize for the generation of electricity a natural water feature, such as a natural lake, waterfall, or the gradient of a natural stream, without the need for a dam or man-made impoundment; and
(B) Would not retain water behind any structure for the purpose of a storage and release operation.
(32) PURPA benefits means benefits under section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA). Section 210(a) of PURPA requires electric utilities to purchase electricity from, and to sell electricity to, qualifying facilities.
§ 4.31 Initial or competing application: who may file.
(a) Application for a preliminary permit or a license. Any citizen, association of citizens, domestic corporation, municipality, or state may submit for filing an initial application or a competing application for a preliminary permit or a license for a water power project under Part I of the Federal Power Act.
(b) Application for exemption of a small conduit hydroelectric facility—(1) Exemption from provisions other than licensing—(i) Only federal lands involved. If only rights to use or occupy federal lands would be necessary to develop and operate the proposed small conduit hydroelectric facility, any citizen, association of citizens, domestic corporation, municipality, or state may apply for exemption of a small conduit hydroelectric facility from provisions of Part I of the Federal Power Act, other than licensing provisions.
(ii) Some non-federal lands involved. If real property interests in any non-federal lands would be necessary to develop and operate the proposed small conduit hydroelectric facility, any citizen, association of citizens, domestic corporation, municipality, or state that has all of the real property interests in the lands necessary to develop and operate that project, or an option to obtain those interests, may apply for exemption of a small conduit hydroelectric facility from provisions of Part I of the Federal Power Act, other than licensing provisions.
(2) Exemption from licensing—(i) Only federal lands involved. If only rights to use or occupy federal lands would be necessary to develop and operate the proposed small conduit hydroelectric facility, any citizen, association of citizens, domestic corporation, municipality, or state may apply for exemption of that facility from licensing under Part I of the Federal Power Act.
(ii) Some non-federal lands involved. If real property interests in any non-federal lands would be necessary to develop and operate the proposed small conduit hydroelectric facility, any citizen, association of citizens, domestic corporation, municipality, or state who has all the real property interests in the lands necessary to develop and operate the small conduit hydroelectric facility, or an option to obtain those interests, may apply for exemption of that facility from licensing under Part I of the Federal Power Act.
(c) Application for case-specific exemption of a small hydroelectric power project—(1) Exemption from provisions other than licensing. Any qualified license applicant or licensee seeking amendment of its license may apply for exemption of the related project from provisions of Part I of the Federal Power Act other than licensing provisions.
(2) Exemption from licensing— (i) Only Federal lands involved. If only rights to use or occupy Federal lands would be necessary to develop and operate the proposed small hydroelectric power project, any citizen, association of citizens, domestic corporation, municipality, or state may apply for exemption of that project from licensing.
(ii) Some non-Federal lands involved. If real property interests in any non-Federal lands would be necessary to develop and operate the proposed small hydroelectric power project, any citizen, association of citizens, domestic corporation, municipality, or state who has all of the real property interests in non-Federal lands necessary to develop and operate that project, or an option to obtain those interests, may apply for exemption of that project from licensing.
§ 4.32 Acceptance for filing or rejection; information to be made available to the public; requests for additional studies.
(a) Each application must:
(1) For a preliminary permit or license, identify every person, citizen, association of citizens, domestic corporation, municipality, or state that has or intends to obtain and will maintain any proprietary right necessary to construct, operate, or maintain the project;
(2) For a preliminary permit or a license, identify (providing names and mailing addresses):
(i) Every county in which any part of the project, and any Federal facilities that would be used by the project, would be located;
(ii) Every city, town, or similar local political subdivision:
(A) In which any part of the project, and any Federal facilities that would be used by the project, would be located; or
(B) That has a population of 5,000 or more people and is located within 15 miles of the project dam;
(iii) Every irrigation district, drainage district, or similar special purpose political subdivision:
(A) In which any part of the project, and any Federal facilities that would be used by the project, would be located; or
(B) That owns, operates, maintains, or uses any project facilities or any Federal facilities that would be used by the project;
(iv) Every other political subdivision in the general area of the project that there is reason to believe would likely be interested in, or affected by, the application; and
(v) All Indian tribes that may be affected by the project.
(3)(i) For a license (other than a license under section 15 of the Federal Power Act) state that the applicant has made, either at the time of or before filing the application, a good faith effort to give notification by certified mail of the filing of the application to:
(A) Every property owner of record of any interest in the property within the bounds of the project, or in the case of the project without a specific boundary, each such owner of property which would underlie or be adjacent to any project works including any impoundments; and
(B) The entities identified in paragraph (a)(2) of this section, as well as any other Federal, state, municipal or other local government agencies that there is reason to believe would likely be interested in or affected by such application.
(ii) Such notification must contain the name, business address, and telephone number of the applicant and a copy of the Exhibit G contained in the application, and must state that a license application is being filed with the Commission.
(4)(i) As to any facts alleged in the application or other materials filed, be subscribed and verified under oath in the form set forth in paragraph (a) (4)(ii) of this section by the person filing, an officer thereof, or other person having knowledge of the matters sent forth. If the subscription and verification is by anyone other than the person filing or an officer thereof, it shall include a statement of the reasons therefor.
(ii) This (application, etc.) is executed in the
Subscribed and sworn to before me, a [Notary Public, or title of other official authorized by the state to notarize documents, as appropriate] of the State of ________________ this day of ______________, 19____.
(5) Contain the information and documents prescribed in the following sections of this chapter, according to the type of application:
(i) Preliminary permit: § 4.81;
(ii) License for a minor water power project and a major water power project 10 MW or less: § 4.61;
(iii) License for a major unconstructed project and a major modified project: § 4.41;
(iv) License for a major project—existing dam: § 4.51;
(v) License for a transmission line only: § 4.71;
(vi) Nonpower license for a licensed project: § 16.11;
(vii) Exemption of a small conduit hydroelectric facility: § 4.92;
(viii) Case-specific exemption of a small hydroelectric power project: § 4.107; or
(ix) License or exemption for a project located at a new dam or diversion where the applicant seeks PURPA benefits: § 292.208.
(b) (1) Each applicant for a preliminary permit, license, and transfer or surrender of license and each petitioner for surrender of an exemption must submit the application or petition to the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov. The applicant or petitioner must serve one copy of the application or petition on the Director of the Commission’s Regional Office for the appropriate region and on each resource agency, Indian tribe, and member of the public consulted pursuant to § 4.38 or § 16.8 of this chapter or part 5 of this chapter. In the case of an application for a preliminary permit, the applicant must, if the Commission so directs, serve copies of the application on the U.S. Department of the Interior and the U.S. Army Corps of Engineers. The application may include reduced prints of maps and drawings conforming to § 4.39(d). The Commission may also ask for the filing of full-sized prints in appropriate cases.
(2) Each applicant for exemption must submit the application to the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov. An applicant must serve one copy of the application on the Director of the Commission’s Regional Office for the appropriate region and on each resource agency consulted pursuant to § 4.38. For each application filed following October 23, 2003, maps and drawings must conform to the requirements of § 4.39.
(3)(i) An applicant must make information regarding its proposed project reasonably available to the public for inspection and reproduction, from the date on which the applicant files its application for a license or exemption until the licensing or exemption proceeding for the project is terminated by the Commission. This information includes a copy of the complete application for license or exemption, together with all exhibits, appendices and any amendments, and any comments, pleadings, supplementary or additional information, or correspondence filed by the applicant with the Commission in connection with the application.
(ii) An applicant must delete from any information made available to the public under this section, specific site or property locations the disclosure of which would create a risk of harm, theft, or destruction of archeological or Native American cultural resources or to the site at which the sources are located, or would violate any federal law, including the Archaeological Resources Protection Act of l979, 16 U.S.C. 470w–3, and the National Historic Preservation Act of 1966, 16 U.S.C. 470hh.
(4)(i) An applicant must make available the information specified in paragraph (b)(3) of this section in a form that is readily accessible, reviewable, and reproducible, at the same time as the information is filed with the Commission or required by regulation to be made available.
(ii) An applicant must make the information specified in paragraph (b)(3) of this section available to the public for inspection:
(A) At its principal place of business or at any other location that is more accessible to the public, provided that all the information is available in at least one location;
(B) During regular business hours; and
(C) In a form that is readily accessible, reviewable and reproducible.
(iii) The applicant must provide a copy of the complete application (as amended) to a public library or other convenient public office located in each county in which the proposed project is located.
(iv) An applicant must make requested copies of the information specified in paragraph (b)(3) of this section available either:
(A) At its principal place of business or at any other location that is more accessible to the public, after obtaining reimbursement for reasonable costs of reproduction; or
(B) Through the mail, after obtaining reimbursement for postage fees and reasonable costs of reproduction.
(5) Anyone may file a petition with the Commission requesting access to the information specified in paragraph (b)(3) of this section if it believes that an applicant is not making the information reasonably available for public inspection or reproduction. The petition must describe in detail the basis for the petitioner’s belief.
(6) An applicant must publish notice twice of the filing of its application, no later than 14 days after the filing date, in a daily or weekly newspaper of general circulation in each county in which the project is located. The notice must disclose the filing date of the application and briefly summarize it, including the applicant’s name and address, the type of facility applied for, its proposed location, the places where the information specified in paragraph (b)(3) of this section is available for inspection and reproduction, and the date by which any requests for additional scientific studies are due under paragraph (b)(7) of this section, and must state that the Commission will publish subsequent notices soliciting public participation if the application is found acceptable for filing. The applicant must promptly provide the Commission with proof of the publications of this notice.
(7) If any resource agency, Indian tribe, or person believes that an additional scientific study should be conducted in order to form an adequate factual basis for a complete analysis of the application on its merits, the resource agency, Indian tribe, or person must file a request for the study with the Commission not later than 60 days after the application is filed and serve a copy of the request on the applicant. The Commission will issue public notice of the tendering for filing of each application for hydropower license or exemption; each such applicant must submit a draft of this notice to the Commission with its application. For any such additional study request, the requester must describe the recommended study and the basis for the request in detail, including who should conduct and participate in the study, its methodology and objectives, whether the recommended study methods are generally accepted in the Scientific community, how the study and information sought will be useful in furthering the resource goals that are affected by the proposed facilities, and approximately how long the study will take to complete, and must explain why the study objectives cannot be achieved using the data already available. In addition, in the case of a study request by a resource agency or Indian tribe that had failed to request the study during the pre-filing consultation process under § 4.38 of this part or § 16.8 of this chapter, the agency or Indian tribe must explain why this request was not made during the pre-filing consultation process and show good cause why its request for the study should be considered by the Commission.
(8) An applicant may file a response to any such study request within 30 days of its filing, serving a copy of the response on the requester.
(9) The requirements of paragraphs (b)(3) to (b)(8) of this section only apply to an application for license or exemption filed on or after May 20, 1991. Paragraphs (b)(3) and (b)(4) of this section do not apply to applications subject to the requirements of § 16.7 of this chapter.
(c)(1) Every applicant for a license or exemption for a project with a capacity of 80 megawatts or less must include in its application copies of the statements made under § 4.38(b)(2)(vi).
(2) If an applicant reverses a statement of intent not to seek PURPA benefits:
(i) Prior to the Commission issuing a license or exemption, the reversal of intent will be treated as an amendment of the application under § 4.35 and the applicant must:
(A) Repeat the pre-filing consultation process under § 4.38; and
(B) Satisfy all the requirements in § 292.208 of this chapter; or
(ii) After the Commission issues a license or exemption for the project, the applicant is prohibited from obtaining PURPA benefits.
(d) When any application is found to conform to the requirements of paragraphs (a), (b) and (c) of this section, the Commission or its delegate will:
(1) Notify the applicant that the application has been accepted for filing, specifying the project number assigned and the date upon which the application was accepted for filing, and, for a license or exemption application, direct the filing of the originals (microfilm) of required maps and drawings;
(2)(i) For an application for a preliminary permit or a license, issue public notice of the application as required in the Federal Power Act;
(ii) For an application for exemption from licensing, publish notice once in a daily or weekly newspaper of general circulation in each county in which the project is or will be located; and
(3) If the project affects lands of the United States, notify the appropriate Federal office of the application and the specific lands affected, pursuant to section 24 of the Federal Power Act.
(4) For an application for a license seeking benefits under section 210 of the Public Utility Regulatory Policies Act of 1978, as amended, for a project that would be located at a new dam or diversion, serve the public notice issued for the application under paragraph (d)(2)(i) of this section to interested agencies at the time the applicant is notified that the application is accepted for filing.
(e) In order for an application to conform adequately to the requirements of paragraphs (a), (b) and (c) of this section and of § 4.38, an application must be completed fully. No blanks should be left in the application. No material or information required in the application should be omitted. If an applicant believes that its application conforms adequately without containing certain required material or information, it must explain in detail why the material or information is not being submitted and what steps were taken by the applicant to provide the material or information. If the Commission finds that an application does not adequately conform to the requirements of paragraphs (a), (b) and (c) of this section and of § 4.38, the Commission or its designee will consider the application either deficient or patently deficient.
(1) Deficient applications. (i) An application that in the judgment of the Director of the Office of Energy Projects does not conform to the requirements of paragraphs (a), (b) and (c) of this section and of § 4.38, may be considered deficient. An applicant having a deficient application will be afforded additional time to correct deficiencies, not to exceed 45 days from the date of notification in the case of an application for a preliminary permit or exemption from licensing or 90 days from the date of notification in the case of an application for license. Notification will be by letter or, in the case of minor deficiencies, by telephone. Any notification will specify the deficiencies to be corrected. Deficiencies must be corrected by submitting the specified materials or information to the Secretary of the Commission within the time specified in the notification of deficiency in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov.
(ii) Upon submission of a conforming application, action will be taken in accordance with paragraph (d) of this section.
(iii) If the revised application is found not to conform to the requirements of paragraphs (a), (b) and (c) of this section and of § 4.38, or if the revisions are not timely submitted, the revised application will be rejected. Procedures for rejected applications are specified in paragraph (e)(2)(iii).
(2) Patently deficient applications. (i) If, within 90 days of its filing date, the Director of the Office of Energy Projects determines that an application patently fails to substantially comply with the requirements of paragraph (a), (b), and (c) of this section and of § 4.38 of this part or § 16.8 of this chapter, or is for a project that is precluded by law, the application will be rejected as patently deficient with the specification of the deficiencies that render the application patently deficient.
(ii) If, after 90 days of its filing date, the Director of the Office of Energy Projects determines that an application patently fails to substantially comply with the requirements of paragraphs (a), (b), and (c) of this section and of § 4.38 of this part or § 16.8 of this chapter, or is for a project that is precluded by law:
(A) The application will be rejected by order of the Commission, if the Commission determines it is patently deficient; or
(B) The application will be considered deficient under paragraph (e)(1) of this section, if the Commission determines it is not patently deficient.
(iii) Any application that is rejected may be resubmitted if the deficiencies are corrected and if, in the case of a competing application, the resubmittal is timely. The date the rejected application is resubmitted will be considered the new filing date for purposes of determining its timeliness under § 4.36 and the disposition of competing applications under § 4.37.
(f) Any application will be considered accepted for filing as of the application filing date if the Secretary receives all of the information and documents necessary to conform to the requirements of paragraphs (a), (b) and (c) of this section and of § 4.38 within the time prescribed by the Commission or its delegate under paragraph (e) of this section.
(g) An applicant may be required to submit any additional information or documents that the Commission or its designee considers relevant for an informed decision on the application. The information or documents must take the form, and must be submitted within the time, that the Commission or its designee prescribes. An applicant may also be required to provide within a specified time additional copies of the complete application, or any of the additional information or documents that are filed, to the Commission or to any person, agency, or other entity that the Commission or its designee specifies. If an applicant fails to provide timely additional information, documents, or copies of submitted materials as required, the Commission or its designee may dismiss the application, hold it in abeyance, or take other appropriate action under this chapter or the Federal Power Act.
(h) A prospective applicant, prior to submitting its application for filing, may seek advice from the Commission staff regarding the sufficiency of the application. For this purpose, five copies of the draft application should be submitted to the Director of the Division of Hydropower Licensing. An applicant or prospective applicant may confer with the Commission staff at any time regarding deficiencies or other matters related to its application. All conferences are subject to the requirements of § 385.2201 of this chapter governing ex parte communications. The opinions or advice of the staff will not bind the Commission or any person delegated authority to act on its behalf.
(i) Intervention in any preliminary permit proceeding will not constitute intervention in any subsequent licensing or exemption proceeding.
(j) Any application, the effectiveness of which is conditioned upon the future occurrence of any event or circumstance, will be rejected.
(k) Critical Energy Infrastructure Information. (1) If this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined in § 388.113(c) of this chapter, to any person, the applicant shall omit the CEII from the information made available and insert the following in its place:
(i) A statement that CEII is being withheld;
(ii) A brief description of the omitted information that does not reveal any CEII; and
(iii) This statement: “Procedures for obtaining access to Critical Energy Infrastructure Information (CEII) may be found at 18 CFR 388.113. Requests for access to CEII should be made to the Commission’s CEII Coordinator.”
(2) The applicant, in determining whether information constitutes CEII, shall treat the information in a manner consistent with any filings that applicant has made with the Commission and shall to the extent practicable adhere to any previous determinations by the Commission or the CEII Coordinator involving the same or like information.
(3) The procedures contained in §§ 388.112 and 388.113 of this chapter regarding designation of, and access to, CEII, shall apply in the event of a challenge to a CEII designation or a request for access to CEII. If it is determined that information is not CEII or that a requester should be granted access to CEII, the applicant will be directed to make the information available to the requester.
(4) Nothing in this section shall be construed to prohibit any persons from voluntarily reaching arrangements or agreements calling for the disclosure of CEII.
§ 4.33 Limitations on submitting applications.
(a) Limitations on submission and acceptance of a preliminary permit application. The Commission will not accept an application for a preliminary permit for project works that:
(1) Would develop, conserve, and utilize, in whole or in part, the same water resources that would be developed, conserved, and utilized by a project for which there is an unexpired preliminary permit.
(2) Would interfere with a licensed project in a manner that, absent the licensee’s consent, would be precluded by Section 6 of the Federal Power Act.
(3) Would develop, conserve, and utilize, in whole or in part, the same water resources that would be developed, conserved, and utilized by a project for which an initial development application has been filed unless the preliminary permit application is filed not later than the time allowed under § 4.36(a) for the filing of applications in competition against an initial application for a preliminary permit that would develop, conserve, and utilize, in whole or in part, the same resources.
(b) Limitations on submissions and acceptance of a license application. The Commission will not accept an application for a license or project works that would develop, conserve, or utilize, in whole or part, the same water resources that would be developed, conserved, and utilized by a project for which there is:
(1) An unexpired preliminary permit, unless the permittee has submitted an application for license; or
(2) An unexpired license, except as provided for in Section 15 of the Federal Power Act.
(c) Limitations on submission and acceptance of an application for a license that would affect an exempted project. (1) Except as permitted under § 4.33(c)(2), § 4.94(d), or § 4.106 (c), (e) or (f), the Commission will not accept an application for a license for project works that are already exempted from licensing under this part.
(2) If a project is exempted from licensing pursuant to § 4.103 or § 4.109 and real property interests in any non-Federal lands would be necessary to develop or operate the project, any person who is both a qualified license applicant and has any of those real property interests in non-Federal lands may submit a license application for that project. If a license application is submitted under this clause, any other qualified license applicant may submit a competing license application in accordance with § 4.36.
(d) Limitations on submission and acceptance of exemption applications—(1) Unexpired permit or license. (i) If there is an unexpired permit in effect for a project, the Commission will accept an application for exemption of that project from licensing only if the exemption applicant is the permittee. Upon acceptance for filing of the permittee’s application, the permit will be considered to have expired.
(ii) If there is an unexpired license in effect for a project, the Commission will accept an application for exemption of that project from licensing only if the exemption applicant is the licensee.
(2) Pending license applications. If an accepted license application for a project was submitted by a permittee before the preliminary permit expired, the Commission will not accept an application for exemption of that project from licensing submitted by a person other than the former permittee.
(3) Submitted by qualified exemption applicant. If the first accepted license application for a project was filed by a qualified exemption applicant, the applicant may request that its license application be treated initially as an application for exemption from licensing by so notifying the Commission in writing and, unless only rights to use or occupy Federal lands would be necessary to develop and operate the project, by submitting documentary evidence showing that the applicant holds the real property interests required under § 4.31. Such notice and documentation must be submitted not later than the last date for filing protests or motions to intervene prescribed in the public notice issued for its license application under § 4.32(d)(2).
(e) Priority of exemption applicant’s earlier permit or license application. Any accepted preliminary permit or license application submitted by a person who later applies for exemption of the project from licensing will retain its validity and priority under this subpart until the preliminary permit or license application is withdrawn or the project is exempted from licensing.
§ 4.34 Hearings on applications; consultation on terms and conditions; motions to intervene; alternative procedures.
(a) Trial-type hearing. The Commission may order a trial-type hearing on an application for a preliminary permit, a license, or an exemption from licensing upon either its own motion or the motion of any interested party of record. Any trial-type hearing will be limited to the issues prescribed by order of the Commission. In all other cases the hearings will be conducted by notice and comment procedures.
(b) Notice and comment hearings. All comments (including mandatory and recommended terms and conditions or prescriptions) on an application for exemption or license must be filed with the Commission no later than 60 days after issuance by the Commission of public notice declaring that the application is ready for environmental analysis. All reply comments must be filed within 105 days of that notice. All comments and reply comments and all other filings described in this section must be served on all persons listed in the service list prepared by the Commission, in accordance with the requirements of § 385.2010 of this chapter. If a party or interceder (as defined in § 385.2201 of this Chapter) submits any written material to the Commission relating to the merits of an issue that may affect the responsibilities of a particular resource agency, the party or interceder must also serve a copy of the submission on this resource agency. The Commission may allow for longer comment or reply comment periods if appropriate. A commenter or reply commenter may obtain an extension of time from the Commission only upon a showing of good cause or extraordinary circumstances in accordance with § 385.2008 of this chapter. Late-filed fish and wildlife recommendations will not be subject to the requirements of paragraphs (e), (f)(1)(ii), and (f)(3) of this section, and late-filed terms and conditions or prescriptions will not be subject to the requirements of paragraphs (f)(1)(iv), (f)(1)(v), and (f)(2) of this section. Late-filed fish and wildlife recommendations, terms and conditions, or prescriptions will be considered by the Commission under section 10(a) of the Federal Power Act if such consideration would not delay or disrupt the proceeding.
(1) Agencies responsible for mandatory terms and conditions and presentations. Any agency responsible for mandatory terms and conditions or prescriptions for licenses or exemptions, pursuant to sections 4(e), 18, and 30(c) of the Federal Power Act and section 405(d) of the Public Utility Regulatory Policies Act of l978, as amended, must provide these terms and conditions or prescriptions in its initial comments filed with the Commission pursuant to paragraph (b) of this section. In those comments, the agency must specifically identify and explain the mandatory terms and conditions or prescriptions and their evidentiary and legal basis. In the case of an application prepared other than pursuant to part 5 of this chapter, if ongoing agency proceedings to determine the terms and conditions or prescriptions are not completed by the date specified, the agency must submit to the Commission by the due date:
(i) Preliminary terms and conditions or prescriptions and a schedule showing the status of the agency proceedings and when the terms and conditions or prescriptions are expected to become final; or
(ii) A statement waiving the agency’s right to file the terms and conditions or prescriptions or indicating the agency does not intend to file terms and conditions or prescriptions.
(2) Fish and Wildlife agencies and Indian tribes. All fish and wildlife agencies must set forth any recommended terms and conditions for the protection, mitigation of damages to, or enhancement of fish and wildlife, pursuant to the Fish and Wildlife Coordination Act and section 10(j) of the Federal Power Act, in their initial comments filed with the Commission by the date specified in paragraph (b) of this section. All Indian tribes must submit recommendations (including fish and wildlife recommendations) by the same date. In those comments, a fish and wildlife agency or Indian tribe must discuss its understanding of the resource issues presented by the proposed facilities and the evidentiary basis for the recommended terms and conditions.
(3) Other Government agencies and members of the public. Resource agencies, other governmental units, and members of the public must file their recommendations in their initial comments by the date specified in paragraph (b) of this section. The comments must clearly identify all recommendations and present their evidentiary basis.
(4) Submittal of modified recommendations, terms and conditions or prescriptions. (i) If the information and analysis (including reasonable alternatives) presented in a draft environmental document, issued for comment by the Commission, indicate a need to modify the recommendations or terms and conditions or prescriptions previously submitted to the Commission pursuant to paragraphs (b)(1), (b)(2), or (b)(3) of this section, the agency, Indian tribe, or member of the public must file with the Commission any modified recommendations or terms and conditions or prescriptions on the proposed project (and reasonable alternatives) no later than the due date for comments on the draft environmental impact statement. Modified recommendations or terms and conditions or prescriptions must be clearly distinguished from comments on the draft document.
(ii) If an applicant files an amendment to its application that would materially change the project’s proposed plans of development, as provided in § 4.35, an agency, Indian tribe or member of the public may modify the recommendations or terms and conditions or prescriptions it previously submitted to the Commission pursuant to paragraphs (b)(1), (b)(2), or (b)(3) of this section no later than the due date specified by the Commission for comments on the amendment.
(5)(i) With regard to certification requirements for a license applicant under section 401(a)(1) of the Federal Water Pollution Control Act (Clean Water Act), an applicant shall file within 60 days from the date of issuance of the notice of ready for environmental analysis:
(A) A copy of the water quality certification;
(B) A copy of the request for certification, including proof of the date on which the certifying agency received the request; or
(C) Evidence of waiver of water quality certification as described in paragraph (b)(5)(ii) of this section.
(ii) In the case of an application process using the alternative procedures of paragraph 4.34(i), the filing requirement of paragraph (b)(5)(i) shall apply upon issuance of notice the Commission has accepted the application as provided for in paragraph 4.32(d) of this part.
(iii) A certifying agency is deemed to have waived the certification requirements of section 401(a)(1) of the Clean Water Act if the certifying agency has not denied or granted certification by one year after the date the certifying agency received a written request for certification. If a certifying agency denies certification, the applicant must file a copy of the denial within 30 days after the applicant received it.
(c) Additional procedures. If necessary or appropriate the Commission may require additional procedures (e.g., a pre-hearing conference, further notice and comment on specific issues or oral argument). A party may request additional procedures in a motion that clearly and specifically sets forth the procedures requested and the basis for the request. Replies to such requests may be filed within 15 days of the request.
(d) Consultation procedures. Pursuant to the Federal Power Act and the Public Utility Regulatory Policies Act of 1978, as amended, the Commission will coordinate as appropriate with other government agencies responsible for mandatory terms and conditions for exemptions and licenses for hydropower projects. Pursuant to the Federal Power Act and the Fish and Wildlife Coordination Act, the Commission will consult with fish and wildlife agencies concerning the impact of a hydropower proposal on fish and wildlife and appropriate terms and conditions for license to adequately and equitably protect, mitigate damages to, and enhance fish and wildlife (including related spawning grounds and habitat). Pursuant to the Federal Power Act and the Endangered Species Act, the Commission will consult with the U.S. Fish and Wildlife Service or the National Marine Fisheries Service, as appropriate, concerning the impact of a hydropower proposal on endangered or threatened species and their critical habitat.
(e) Consultation on recommended fish and wildlife conditions; Section 10(j) process. (1) In connection with its environmental review of an application for license, the Commission will analyze all terms and conditions timely recommended by fish and wildlife agencies pursuant to the Fish and Wildlife Coordination Act for the protection, mitigation of damages to, and enhancement of fish and wildlife (including related spawning grounds and habitat) affected by the development, operation, and management of the proposed project. Submission of such recommendations marks the beginning of the process under section 10(j) of the Federal Power Act.
(2) The agency must specifically identify and explain the recommendations and the relevant resource goals and objectives and their evidentiary or legal basis. The Commission may seek clarification of any recommendation from the appropriate fish and wildlife agency. If the Commission’s request for clarification is communicated in writing, copies of the request will be sent by the Commission to all parties, affected resource agencies, and Indian tribes, which may file a response to the request for clarification within the time period specified by the Commission. If the Commission believes any fish and wildlife recommendation may be inconsistent with the Federal Power Act or other applicable law, the Commission will make a preliminary determination of inconsistency in the draft environmental document or, if none, the environmental assessment. The preliminary determination, for any recommendations believed to be inconsistent, shall include an explanation why the Commission believes the recommendation is inconsistent with the Federal Power Act or other applicable law, including any supporting analysis and conclusions, and an explanation of how the measures recommended in the environmental document would adequately and equitably protect, mitigate damages to, and enhance, fish and wildlife (including related spawning grounds and habitat) affected by the development, operation, and management of the project.
(3) Any party, affected resource agency, or Indian tribe may file comments in response to the preliminary determination of inconsistency, including any modified recommendations, within the time frame allotted for comments on the draft environmental document or, if none, the time frame for comments on the environmental analysis. In this filing, the fish and wildlife agency concerned may also request a meeting, telephone or video conference, or other additional procedure to attempt to resolve any preliminary determination of inconsistency.
(4) The Commission shall attempt, with the agencies, to reach a mutually acceptable resolution of any such inconsistency, giving due weight to the recommendations, expertise, and statutory responsibilities of the fish and wildlife agency. If the Commission decides, or an affected resource agency requests, the Commission will conduct a meeting, telephone, or video conference, or other procedures to address issues raised by its preliminary determination of inconsistency and comments thereon. The Commission will give at least 15 days’ advance notice to each party, affected resource agency, or Indian tribe, which may participate in the meeting or conference. Any meeting, conference, or additional procedure to address these issues will be scheduled to take place within 90 days of the date the Commission issues a preliminary determination of inconsistency. The Commission will prepare a written summary of any meeting held under this subsection to discuss section 10(j) issues, including any proposed resolutions and supporting analysis, and a copy of the summary will be sent to all parties, affected resource agencies, and Indian tribes.
(5) The section 10(j) process ends when the Commission issues an order granting or denying the license application in question. If, after attempting to resolve inconsistencies between the fish and wildlife recommendations of a fish and wildlife agency and the purposes and requirements of the Federal Power Act or other applicable law, the Commission does not adopt in whole or in part a fish and wildlife recommendation of a fish and wildlife agency, the Commission will publish the findings and statements required by section 10(j)(2) of the Federal Power Act.
(f) Licenses and exemption conditions and required findings—(1) License conditions. (i) All licenses shall be issued on the conditions specified in section 10 of the Federal Power Act and such other conditions as the Commission determines are lawful and in the public interest.
(ii) Subject to paragraph (f)(3) of this section, fish and wildlife conditions shall be based on recommendations timely received from the fish and wildlife agencies pursuant to the Fish and Wildlife Coordination Act.
(iii) The Commission will consider the timely recommendations of resource agencies, other governmental units, and members of the public, and the timely recommendations (including fish and wildlife recommendations) of Indian tribes affected by the project.
(iv) Licenses for a project located within any Federal reservation shall be issued only after the findings required by, and subject to any conditions that may be timely received pursuant to, section 4(e) of the Federal Power Act.
(v) The Commission will require the construction, maintenance, and operation by a licensee at its own expense of such fishways as may be timely prescribed by the Secretary of Commerce or the Secretary of the Interior, as appropriate, pursuant to section 18 of the Federal Power Act.
(2) Exemption conditions. Any exemption from licensing issued for conduit facilities, as provided in section 30(b) of the Federal Power Act, or for small hydroelectric power projects having a proposed installed capacity of 10,000 kilowatts or less, as provided in section 405(d) of the Public Utility Regulatory Policies Act of 1978, as amended, shall include such terms and conditions as the fish and wildlife agencies may timely determine are appropriate to carry out the responsibilities specified in section 30(c) of the Federal Power Act.
(3) Required findings. If, after attempting to resolve inconsistencies between the fish and wildlife recommendations of a fish and wildlife agency and the purposes and requirements of the Federal Power Act or other applicable law, the Commission does not adopt in whole or in part a fish and wildlife recommendation of a fish and wildlife agency, the Commission will publish the findings and statements required by section 10(j)(2) of the Federal Power Act.
(g) Application. The provisions of paragraphs (b) through (d) and (f) of this section apply only to applications for license or exemption; paragraph (e) applies only to applications for license.
(h) Unless otherwise provided by statute, regulation or order, all filings in hydropower hearings, except those conducted by trial-type procedures, shall conform to the requirements of subpart T of part 385 of this chapter.
(i) Alternative procedures. (1) An applicant may submit to the Commission a request to approve the use of alternative procedures for pre-filing consultation and the filing and processing of an application for an original, new or subsequent hydropower license or exemption that is subject to § 4.38 or § 16.8 of this chapter, or for the amendment of a license that is subject to the provisions of § 4.38.
(2) The goal of such alternative procedures shall be to:
(i) Combine into a single process the pre-filing consultation process, the environmental review process under the National Environmental Policy Act and administrative processes associated with the Clean Water Act and other statutes;
(ii) Facilitate greater participation by and improve communication among the potential applicant, resource agencies, Indian tribes, the public and Commission staff in a flexible pre-filing consultation process tailored to the circumstances of each case;
(iii) Allow for the preparation of a preliminary draft environmental assessment by an applicant or its contractor or consultant, or of a preliminary draft environmental impact statement by a contractor or consultant chosen by the Commission and funded by the applicant;
(iv) Promote cooperative efforts by the potential applicant and interested entities and encourage them to share information about resource impacts and mitigation and enhancement proposals and to narrow any areas of disagreement and reach agreement or settlement of the issues raised by the hydropower proposal; and
(v) Facilitate an orderly and expeditious review of an agreement or offer of settlement of an application for a hydropower license, exemption or amendment to a license.
(3) A potential hydropower applicant requesting the use of alternative procedures must:
(i) Demonstrate that a reasonable effort has been made to contact all resource agencies, Indian tribes, citizens’ groups, and others affected by the applicant’s proposal, and that a consensus exists that the use of alternative procedures is appropriate under the circumstances;
(ii) Submit a communications protocol, supported by interested entities, governing how the applicant and other participants in the pre-filing consultation process, including the Commission staff, may communicate with each other regarding the merits of the applicant’s proposal and proposals and recommendations of interested entities; and
(iii) Serve a copy of the request on all affected resource agencies and Indian tribes and on all entities contacted by the applicant that have expressed an interest in the alternative pre-filing consultation process.
(4) As appropriate under the circumstances of the case, the alternative procedures should include provisions for:
(i) Distribution of an initial information package and conduct of an initial information meeting open to the public;
(ii) The cooperative scoping of environmental issues (including necessary scientific studies), the analysis of completed studies and any further scoping; and
(iii) The preparation of a preliminary draft environmental assessment or preliminary draft environmental impact statement and related application.
(5)(i) If the potential applicant’s request to use the alternative procedures is filed prior to July 23, 2005, the Commission will give public notice in the
(ii) If the potential applicant’s request to use the alternative procedures is filed on or after July 23, 2005 and prior to the deadline date for filing a notification of intent to seek a new or subsequent license required by § 5.5 of this chapter, the Commission will give public notice and invite comments as provided for in paragraph (i)(5)(i) of this section. Commission approval of the potential applicant’s request to use the alternative procedures prior to the deadline date for filing of the notification of intent does not waive the potential applicant’s obligation to file the notification of intent required by § 5.5 of this chapter and Pre-Application Document required by § 5.6 of this chapter.
(iii) If the potential applicant’s request to use the alternative procedures is filed on or after July 23, 2005 and is at the same time as the notification of intent to seek a new or subsequent license required by § 5.5, the public notice and comment procedures of part 5 of this chapter shall apply.
(6) If the Commission accepts the use of alternative procedures, the following provisions will apply.
(i) To the extent feasible under the circumstances of the proceeding, the Commission will give notice in the
(ii) Every six months, the applicant shall file with the Commission a report summarizing the progress made in the pre-filing consultation process and referencing the applicant’s public file, where additional information on that process can be obtained. Summaries or minutes of meetings held in the process may be used to satisfy this filing requirement. The applicant must also file with the Commission a copy of its initial information package, each scoping document, and the preliminary draft environmental review document. All filings with the Commission under this section must include the number of copies required by paragraph (h) of this section, and the applicant shall send a copy of these filings to each participant that requests a copy.
(iii) At a suitable location, the applicant will maintain a public file of all relevant documents, including scientific studies, correspondence, and minutes or summaries of meetings, compiled during the pre-filing consultation process. The Commission will maintain a public file of the applicant’s initial information package, scoping documents, periodic reports on the pre-filing consultation process, and the preliminary draft environmental review document.
(iv) An applicant authorized to use alternative procedures may substitute a preliminary draft environmental review document and additional material specified by the Commission instead of Exhibit E to its application and need not supply additional documentation of the pre-filing consultation process. The applicant will file with the Commission the results of any studies conducted or other documentation as directed by the Commission, either on its own motion or in response to a motion by a party to the licensing or exemption proceeding.
(v) Pursuant to the procedures approved, the participants will set reasonable deadlines requiring all resource agencies, Indian tribes, citizens’ groups, and interested persons to submit to the applicant requests for scientific studies during the pre-filing consultation process, and additional requests for studies may be made to the Commission after the filing of the application only for good cause shown.
(vi) During the pre-filing process the Commission may require the filing of preliminary fish and wildlife recommendations, prescriptions, mandatory conditions, and comments, to be submitted in final form after the filing of the application; no notice that the application is ready for environmental analysis need be given by the Commission after the filing of an application pursuant to these procedures.
(vii) Any potential applicant, resource agency, Indian tribe, citizens’ group, or other entity participating in the alternative pre-filing consultation process may file a request with the Commission to resolve a dispute concerning the alternative process (including a dispute over required studies), but only after reasonable efforts have been made to resolve the dispute with other participants in the process. No such request shall be accepted for filing unless the entity submitting it certifies that it has been served on all other participants. The request must document what efforts have been made to resolve the dispute.
(7) If the potential applicant or any resource agency, Indian tribe, citizens’ group, or other entity participating in the alternative pre-filing consultation process can show that it has cooperated in the process but a consensus supporting the use of the process no longer exists and that continued use of the alternative process will not be productive, the participant may petition the Commission for an order directing the use by the potential applicant of appropriate procedures to complete its application. No such request shall be accepted for filing unless the entity submitting it certifies that it has been served on all other participants. The request must recommend specific procedures that are appropriate under the circumstances.
(8) The Commission may participate in the pre-filing consultation process and assist in the integration of this process and the environmental review process in any case, including appropriate cases where the applicant, contractor, or consultant funded by the applicant is not preparing a preliminary draft environmental assessment or preliminary draft environmental impact statement, but where staff assistance is available and could expedite the proceeding.
(9) If this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 4.32(k).
§ 4.35 Amendment of application; date of acceptance.
(a) General rule. Except as provided in paragraph (d) of this section, if an applicant amends its filed application as described in paragraph (b) of this section, the date of acceptance of the application under § 4.32(f) is the date on which the amendment to the application was filed.
(b) Paragraph (a) of this section applies if an applicant:
(1) Amends its filed license or preliminary permit application in order to change the status or identity of the applicant or to materially amend the proposed plans of development; or
(2) Amends its filed application for exemption from licensing in order to materially amend the proposed plans of development, or
(3) Amends its filed application in order to change its statement of intent of whether or not it will seek benefits under section 210 of PURPA, as originally filed under § 4.32(c)(1).
(c) An application amended under paragraph (a) is a new filing for:
(1) The purpose of determining its timeliness under § 4.36 of this part;
(2) Disposing of competing applications under § 4.37; and
(3) Reissuing public notice of the application under § 4.32(d)(2).
(d) If an application is amended under paragraph (a) of this section, the Commission will rescind any acceptance letter already issued for the application.
(e) Exceptions. This section does not apply to:
(1) Any corrections of deficiencies made pursuant to § 4.32(e)(1);
(2) Any amendments made pursuant to § 4.37(b)(4) by a State or a municipality to its proposed plans of development to make them as well adapted as the proposed plans of an applicant that is not a state or a municipality;
(3) Any amendments made pursuant to § 4.37(c)(2) by a priority applicant to its proposed plans of development to make them as well adapted as the proposed plans of an applicant that is not a priority applicant;
(4) Any amendments made by a license or an exemption applicant to its proposed plans of development to satisfy requests of resource agencies or Indian tribes submitted after an applicant has consulted under § 4.38 or concerns of the Commission; and
(5)(i) Any license or exemption applicant with a project located at a new dam or diversion who is seeking PURPA benefits and who:
(A) Has filed an adverse environmental effects (AEE) petition pursuant to § 292.211 of this chapter; and
(B) Has proposed measures to mitigate the adverse environmental effects which the Commission, in its initial determination on the AEE petition, stated the project will have.
(ii) This exception does not protect any proposed mitigative measures that the Commission finds are a pretext to avoid the consequences of materially amending the application or are outside the scope of mitigating the adverse environmental effects.
(f) Definitions. (1) For the purposes of this section, a material amendment to plans of development proposed in an application for a license or exemption from licensing means any fundamental and significant change, including but not limited to:
(i) A change in the installed capacity, or the number or location of any generating units of the proposed project if the change would significantly modify the flow regime associated with the project;
(ii) A material change in the location, size, or composition of the dam, the location of the powerhouse, or the size and elevation of the reservoir if the change would:
(A) Enlarge, reduce, or relocate the area of the body of water that would lie between the farthest reach of the proposed impoundment and the point of discharge from the powerhouse; or
(B) Cause adverse environmental impacts not previously discussed in the original application; or
(iii) A change in the number of discrete units of development to be included within the project boundary.
(2) For purposes of this section, a material amendment to plans of development proposed in an application for a preliminary permit means a material change in the location of the powerhouse or the size and elevation of the reservoir if the change would enlarge, reduce, or relocate the area of the body of water that would lie between the farthest reach of the proposed impoundment and the point of discharge from the powerhouse.
(3) For purposes of this section, a change in the status of an applicant means:
(i) The acquisition or loss of preference as a state or a municipality under section 7(a) of the Federal Power Act; or
(ii) The loss of priority as a permittee under section 5 of the Federal Power Act.
(4) For purposes of this section, a change in the identity of an applicant means a change that either singly, or together with previous amendments, causes a total substitution of all the original applicants in a permit or a license application.
§ 4.36 Competing applications: deadlines for filing; notices of intent; comparisons of plans of development.
The public notice of an initial preliminary permit application or an initial development application shall prescribe the deadline for filing protests and motions to intervene in that proceeding (the prescribed intervention deadline).
(a) Deadlines for filing applications in competition with an initial preliminary permit application. (1) Any preliminary permit application or any development application not filed pursuant to a notice of intent must be submitted for filing in competition with an initial preliminary permit application not later than the prescribed intervention deadline.
(2) Any preliminary permit application filed pursuant to a notice of intent must be submitted for filing in competition with an initial preliminary permit application not later than 30 days after the prescribed intervention deadline.
(3) Any development application filed pursuant to a notice of intent must be submitted for filing in competition with an initial preliminary permit application not later than 120 days after the prescribed intervention deadline.
(b) Deadlines for filing applications in competition with an initial development application. (1) Any development application not filed pursuant to a notice of intent must be submitted for filing in competition with an initial development application not later than the prescribed intervention deadline.
(2) Any development application filed pursuant to a notice of intent must be submitted for filing in competition with an initial development application not later than 120 days after the prescribed intervention deadline.
(3) If the Commission has accepted an application for exemption of a project from licensing and the application has not yet been granted or denied, the applicant for exemption may submit a license application for the project if it is a qualified license applicant. The pending application for exemption from licensing will be considered withdrawn as of the date the Commission accepts the license application for filing. If a license application is accepted for filing under this provision, any qualified license applicant may submit a competing license application not later than the prescribed intervention deadline set for the license application.
(4) Any preliminary permit application must be submitted for filing in competition with an initial development application not later than the deadlines prescribed in paragraphs (a)(1) and (a)(2) for the submission of preliminary permit applications filed in competition with an initial preliminary permit application.
(c) Notices of intent. (1) Any notice of intent to file an application in competition with an initial preliminary permit or an initial development application must be submitted for filing not later than the prescribed intervention deadline for the initial application.
(2) A notice of intent must include:
(i) The exact name, business address, and telephone number of the prospective applicant; and
(ii) An unequivocal statement of intent to submit a preliminary permit application or a development application (specify which type of application).
(d) Requirements for competing applications. (1) Any competing application must:
(i) Conform to all requirements for filing an initial application; and
(ii) Include proof of service of a copy of the competing application on the person(s) designated in the public notice of the initial application for service of pleadings, documents, or communications concerning the initial application.
(2) Comparisons of plans of development. (i) After the deadline for filing applications in competition against an initial development application has expired, the Commission will notify each license and exemption applicant of the identity of the other applicants.
(ii) Not later than 14 days after the Commission serves the notification described in paragraph (d)(2)(i) of this section, if a license or exemption applicant has not already done so, it must serve a copy of its application on each of the other license and exemption applicants.
(iii) Not later than 60 days after the Commission serves the notification described in paragraph (d)(2)(i) of this section, each license and exemption applicant must file with the Commission a detailed and complete statement of how its plans are as well or better adapted than are the plans of each of the other license and exemption applicants to develop, conserve, and utilize in the public interest the water resources of the region. These statements should be supported by any technical analyses that the applicant deems appropriate to support its proposed plans of development.
§ 4.37 Rules of preference among competing applications.
Except as provided in § 4.33(e), the Commission will select among competing applications on the following bases:
(a) If an accepted application for a preliminary permit and an accepted application for a license propose project works that would develop, conserve, and utilize, in whole or in part, the same water resources, and the applicant for a license has demonstrated its ability to carry out its plans, the Commission will favor the license applicant unless the permit applicant substantiates in its filed application that its plans are better adapted to develop, conserve, and utilize in the public interest the water resources of the region.
(b) If two or more applications for preliminary permits or two or more applications for licenses (not including applications for a new license under section 15 of the Federal Power Act) are filed by applicants for project works that would develop, conserve, and utilize, in whole or in part, the same water resources, and if none of the applicants is a preliminary permittee whose application for license was accepted for filing within the permit period, the Commission will select between or among the applicants on the following bases:
(1) If both or neither of two applicants are either a municipality or a state, the Commission will favor the applicant whose plans are better adapted to develop, conserve, and utilize in the public interest the water resources of the region, taking into consideration the ability of each applicant to carry out its plans.
(2) If both of two applicants are either a municipality or a state, or neither of them is a municipality or a state, and the plans of the applicants are equally well adapted to develop, conserve, and utilize in the public interest the water resources of the region, taking into consideration the ability of each applicant to carry out its plans, the Commission will favor the applicant with the earliest application acceptance date.
(3) If one of two applicants is a municipality or a state, and the other is not, and the plans of the municipality or a state are at least as well adapted to develop, conserve, and utilize in the public interest the water resources of the region, the Commission will favor the municipality or state.
(4) If one of two applicant is a municipality or a state, and the other is not, and the plans of the applicant who is not a municipality or a state are better adapted to develop, conserve, and utilize in the public interest the water resources of the region, the Commission will inform the municipality or state of the specific reasons why its plans are not as well adapted and afford a reasonable period of time for the municipality or state to render its plans at least as well adapted as the other plans. If the plans of the municipality or state are rendered at least as well adapted within the time allowed, the Commission will favor the municipality or state. If the plans are not rendered at least as well adapted within the time allowed, the Commission will favor the other applicant.
(c) If two or more applications for licenses are filed for project works which would develop, conserve, and utilize, in whole or in part, the same water resources, and one of the applicants was a preliminary permittee whose application was accepted for filing within the permit period (priority applicant), the Commission will select between or among the applicants on the following bases:
(1) If the plans of the priority applicant are at least as well adapted as the plans of each other applicant to develop, conserve, and utilize in the public interest the water resources of the region, taking into consideration the ability of each applicant to carry out its plans, the Commission will favor the priority applicant.
(2) If the plans of an applicant who is not a priority applicant are better adapted than the plans of the priority applicant to develop, conserve, and utilize in the public interest the water resources of the region, taking into consideration the ability of each applicant to carry out its plans, the Commission will inform the priority applicant of the specific reasons why its plans are not as well adapted and afford a reasonable period of time for the priority applicant to render its plans at least as well adapted as the other plans. If the plans of the priority applicant are rendered at least as well adapted within the time allowed, then the Commission will favor the priority applicant. If the plans of the priority applicant are not rendered as well adapted within the time allowed, the criteria specified in paragraph (b) will govern.
(3) The criteria specified in paragraph (b) will govern selection among applicants other than the priority applicant.
(d) With respect to a project for which an application for an exemption from licensing has been accepted for filing, the Commission will select among competing applications on the following bases:
(1) If an accepted application for a preliminary permit and an accepted application for exemption from licensing propose to develop mutually exclusive small hydroelectric power projects, the Commission will favor the applicant whose substantiated plans in the application received by the Commission are better adapted to develop, conserve, and utilize in the public interest the water resources of the region. If the substantiated plans are equally well adapted, the Commission will favor the application for exemption from licensing.
(2) If an application for a license and an application for exemption from licensing, or two or more applications for exemption from licensing are each accepted for filing and each proposes to develop a mutually exclusive project, the Commission will favor the applicant whose plans are better adapted to develop, conserve, and utilize in the public interest the water resources of the region. If the plans are equally well adapted, the Commission will favor the applicant with the earliest application acceptance date.
(e) A municipal applicant must provide evidence that the municipality is competent under applicable state and local laws to engage in the business of developing, transmitting, utilizing, or distributing power, or such applicant will be considered a non-municipal applicant for the purpose of determining the disposition of competing applications.
§ 4.38 Consultation requirements.
(a) Requirement to consult. (1) Before it files any application for an original license or an exemption from licensing that is described in paragraph (a)(6) of this section, a potential applicant must consult with the relevant Federal, State, and interstate resource agencies, including the National Marine Fisheries Service, the United States Fish and Wildlife Service, the National Park Service, the United States Environmental Protection Agency, the Federal agency administering any federal lands or facilities utilized or occupied by the project, the appropriate State fish and wildlife agencies, the appropriate State water resource management agencies, the certifying agency under section 401(a)(1) of the Federal Water Pollution Control Act (Clean Water Act), 33 U.S.C. § 1341(c)(1), and any Indian tribe that may be affected by the proposed project.
(2) Each requirement in this section to contact or consult with resource agencies or Indian tribes shall be construed to require as well that the potential applicant contact or consult with members of the public.
(3) If a potential applicant for an original license commences first stage pre-filing consultation on or after July 23, 2005 it shall file a notification of intent to file a license application pursuant to § 5.5 and a pre-application document pursuant to the provisions of § 5.6.
(4) The Director of the Office of Energy Projects will, upon request, provide a list of known appropriate Federal, state, and interstate resource agencies, Indian tribes, and local, regional, or national non-governmental organizations likely to be interested in any license application proceeding.
(5) An applicant for an exemption from licensing or an applicant for a license seeking benefits under section 210 of the Public Utility Regulatory Policies Act, as amended, for a project that would be located at a new dam or diversion must, in addition to meeting the requirements of this section, comply with the consultation requirements in § 4.301.
(6) The pre-filing consultation requirements of this section apply only to an application for:
(i) Original license;
(ii) Exemption;
(iii) Amendment to an application for original license or exemption that materially amends the proposed plans of development as defined in § 4.35(f)(1);
(iv) Amendment to an existing license that would increase the capacity of the project as defined in § 4.201(b); or
(v) Amendment to an existing license that would not increase the capacity of the project as defined in § 4.201(b), but that would involve:
(A) The construction of a new dam or diversion in a location where there is no existing dam or diversion;
(B) Any repair, modification, or reconstruction of an existing dam that would result in a significant change in the normal maximum surface area or elevation of an existing impoundment; or
(C) The addition of new water power turbines other than to replace existing turbines.
(7) Before it files a non-capacity related amendment as defined in § 4.201(c), an applicant must consult with the resource agencies and Indian tribes listed in paragraph (a)(1) of this section to the extent that the proposed amendment would affect the interests of the agencies or tribes. When consultation is necessary, the applicant must, at a minimum, provide the resource agencies and Indian tribes with copies of the draft application and allow them at least 60 days to comment on the proposed amendment. The amendment as filed with the Commission must summarize the consultation with the resource agencies and Indian tribes on the proposed amendment, propose reasonable protection, mitigation, or enhancement measures to respond to impacts identified as being caused by the proposed amendment, and respond to any objections, recommendations, or conditions submitted by the agencies or Indian tribes. Copies of all written correspondence between the applicant, the agencies, and the tribes must be attached to the application.
(8) This section does not apply to any application for a new license, a nonpower license, a subsequent license, or surrender of a license subject to sections 14 and 15 of the Federal Power Act.
(9) If a potential applicant has any doubt as to whether a particular application or amendment would be subject to the pre-filing consultation requirements of this section or if a waiver of the pre-filing requirements would be appropriate, the applicant may file a written request for clarification or waiver with the Director, Office of Energy Projects.
(b) First stage of consultation. (1) A potential applicant for an original license that commences pre-filing consultation on or after July 23, 2005 must, at the time it files its notification of intent to seek a license pursuant to § 5.5 of this chapter and a pre-application document pursuant to § 5.6 of this chapter and, at the same time, provide a copy of the pre-application document to the entities specified in § 5.6(a) of this chapter.
(2) A potential applicant for an original license that commences pre-filing consultation under this part prior to July 23, 2005 or for an exemption must promptly contact each of the appropriate resource agencies, affected Indian tribes, and members of the public likely to be interested in the proceeding; provide them with a description of the proposed project and supporting information; and confer with them on project design, the impact of the proposed project (including a description of any existing facilities, their operation, and any proposed changes), reasonable hydropower alternatives, and what studies the applicant should conduct. The potential applicant must provide to the resource agencies, Indian tribes and the Commission the following information:
(i) Detailed maps showing project boundaries, if any, proper land descriptions of the entire project area by township, range, and section, as well as by state, county, river, river mile, and closest town, and also showing the specific location of all proposed project facilities, including roads, transmission lines, and any other appurtenant facilities;
(ii) A general engineering design of the proposed project, with a description of any proposed diversion of a stream through a canal or penstock;
(iii) A summary of the proposed operational mode of the project;
(iv) Identification of the environment to be affected, the significant resources present, and the applicant’s proposed environmental protection, mitigation, and enhancement plans, to the extent known at that time;
(v) Streamflow and water regime information, including drainage area, natural flow periodicity, monthly flow rates and durations, mean flow figures illustrating the mean daily streamflow curve for each month of the year at the point of diversion or impoundment, with location of the stream gauging station, the method used to generate the streamflow data provided, and copies of all records used to derive the flow data used in the applicant’s engineering calculations;
(vi) (A) A statement (with a copy to the Commission) of whether or not the applicant will seek benefits under section 210 of PURPA by satisfying the requirements for qualifying hydroelectric small power production facilities in § 292.203 of this chapter;
(B) If benefits under section 210 of PURPA are sought, a statement on whether or not the applicant believes diversion (as that term is defined in § 292.202(p) of this chapter) and a request for the agencies’ view on that belief, if any;
(vii) Detailed descriptions of any proposed studies and the proposed methodologies to be employed; and
(viii) Any statement required by § 4.301(a) of this part.
(3) (i) A potential exemption applicant and a potential applicant for an original license that commences pre-filing consultation;
(A) On or after July 23, 2005 pursuant to part 5 of this chapter and receives approval from the Commission to use the license application procedures of part 4 of this chapter; or
(B) Elects to commence pre-filing consultation under part 4 of this chapter prior to July 23, 2005; must:
(1) Hold a joint meeting at a convenient place and time, including an opportunity for a site visit, with all pertinent agencies, Indian tribes, and members of the public to explain the applicant’s proposal and its potential environmental impact, to review the information provided, and to discuss the data to be obtained and studies to be conducted by the potential applicant as part of the consultation process;
(2) Consult with the resource agencies, Indian tribes and members of the public on the scheduling and agenda of the joint meeting; and
(3) No later than 15 days in advance of the joint meeting, provide the Commission with written notice of the time and place of the meeting and a written agenda of the issues to be discussed at the meeting.
(ii) The joint meeting must be held no earlier than 30 days, but no later than 60 days, from, as applicable;
(A) The date of the Commission’s approval of the potential applicant’s request to use the license application procedures of this part pursuant to the provisions of part 5 of this chapter; or
(B) The date of the potential applicant’s letter transmitting the information required by paragraph (b)(2) of this section, in the case of a potential exemption applicant or a potential license applicant that commences pre-filing consultation under this part prior to July 23, 2005.
(4) Members of the public must be informed of and invited to attend the joint meeting held pursuant to paragraph (b)(3) of this section by means of the public notice provision published in accordance with paragraph (g) of this section. Members of the public attending the meeting are entitled to participate in the meeting and to express their views regarding resource issues that should be addressed in any application for license or exemption that may be filed by the potential applicant. Attendance of the public at any site visit held pursuant to paragraph (b)(3) of this section will be at the discretion of the potential applicant. The potential applicant must make either audio recordings or written transcripts of the joint meeting, and must promptly provide copies of these recordings or transcripts to the Commission and, upon request, to any resource agency, Indian tribe, or member of the public.
(5) Not later than 60 days after the joint meeting held under paragraph (b)(3) of this Section (unless extended within this time period by a resource agency, Indian tribe, or members of the public for an additional 60 days by sending written notice to the applicant and the Director of the Office of Energy Projects within the first 60 day period, with an explanation of the basis for the extension), each interested resource agency and Indian tribe must provide a potential applicant with written comments:
(i) Identifying its determination of necessary studies to be performed or the information to be provided by the potential applicant;
(ii) Identifying the basis for its determination;
(iii) Discussing its understanding of the resource issues and its goals and objectives for these resources;
(iv) Explaining why each study methodology recommended by it is more appropriate than any other available methodology alternatives, including those identified by the potential applicant pursuant to paragraph (b)(2)(vii) of this section;
(v) Documenting that the use of each study methodology recommended by it is a generally accepted practice; and
(vi) Explaining how the studies and information requested will be useful to the agency, Indian tribe, or member of the public in furthering its resource goals and objectives that are affected by the proposed project.
(6)(i) If a potential applicant and a resource agency or Indian tribe disagree as to any matter arising during the first stage of consultation or as to the need to conduct a study or gather information referenced in paragraph (c)(2) of this section, the potential applicant or resource agency or Indian tribe may refer the dispute in writing to the Director of the Office of Energy Projects (Director) for resolution.
(ii) At the same time as the request for dispute resolution is submitted to the Director, the entity referring the dispute must serve a copy of its written request for resolution on the disagreeing party and any affected resource agency or Indian tribe, which may submit to the Director a written response to the referral within 15 days of the referral’s submittal to the Director.
(iii) Written referrals to the Director and written responses thereto pursuant to paragraphs (b)(6)(i) or (b)(6)(ii) of this section must be filed with the Commission in accordance with the Commission’s Rules of Practice and Procedure, and must indicate that they are for the attention of the Director pursuant to § 4.38(b)(6).
(iv) The Director will resolve the disputes by letter provided to the potential applicant and all affected resource agencies and Indian tribes.
(v) If a potential applicant does not refer a dispute regarding a request for a potential applicant to obtain information or conduct studies (other than a dispute regarding the information specified in paragraph (b)(2) of this section), or a study to the Director under paragraph (b)(6) of this section, or if a potential applicant disagrees with the Director’s resolution of a dispute regarding a request for information (other than a dispute regarding the information specified in paragraph (b)(2) of this section) or a study, and if the potential applicant does not provide the requested information or conduct the requested study, the potential applicant must fully explain the basis for its disagreement in its application.
(vi) Filing and acceptance of an application will not be delayed, and an application will not be considered deficient or patently deficient pursuant to § 4.32(e)(1) or (e)(2) of this part, merely because the application does not include a particular study or particular information if the Director had previously found, under paragraph (b)(6)(iv) of this section, that each study or information is unreasonable or unnecessary for an informed decision by the Commission on the merits of the application or use of the study methodology requested is not a generally accepted practice.
(7) The first stage of consultation ends when all participating agencies and Indian tribes provide the written comments required under paragraph (b)(5) of this section or 60 days after the joint meeting held under paragraph (b)(3) of this section, whichever occurs first, unless a resource agency or Indian tribe timely notifies the applicant and the Director of Energy Projects of its need for more time to provide written comments under paragraph (b)(5) of this section, in which case the first stage of consultation ends when all participating agencies and Indian tribes provide the written comments required under paragraph (b)(5) of this section or 120 days after the joint meeting held under paragraph (b)(5) of this section, whichever occurs first.
(c) Second stage of consultation. (1) Unless determined to be unnecessary by the Director pursuant to paragraph (b)(6) of this section, a potential applicant must diligently conduct all reasonable studies and obtain all reasonable information requested by resource agencies and Indian tribes under paragraph (b) of this section that are necessary for the Commission to make an informed decision regarding the merits of the application. These studies must be completed and the information obtained:
(i) Prior to filing the application, if the results:
(A) Would influence the financial (e.g., instream flow study) or technical feasibility of the project (e.g., study of potential mass soil movement); or
(B) Are needed to determine the design or location of project features, reasonable alternatives to the project, the impact of the project on important natural or cultural resources (e.g., resource surveys), or suitable mitigation or enhancement measures, or to minimize impact on significant resources (e.g., wild and scenic river, anadromous fish, endangered species, caribou migration routes);
(ii) After filing the application but before issuance of a license or exemption, if the applicant otherwise complied with the provisions of paragraph (b)(2) of this section and the study or information gathering would take longer to conduct and evaluate than the time between the conclusion of the first stage of consultation and the expiration of the applicant’s preliminary permit or the application filing deadline set by the Commission;
(iii) After a new license or exemption is issued, if the studies can be conducted or the information obtained only after construction or operation of proposed facilities, would determine the success of protection, mitigation, or enhancement measures (e.g., post-construction monitoring studies), or would be used to refine project operation or modify project facilities.
(2) If, after the end of the first stage of consultation as defined in paragraph (b)(7) of this section, a resource agency or Indian tribe requests that the potential applicant conduct a study or gather information not previously identified and specifies the basis and reasoning for its request, under paragraphs (b)(5) (i)–(vi) of this section, the potential applicant must promptly initiate the study or gather the information, unless the study or information is unreasonable or unnecessary for an informed decision by the Commission on the merits of the application or use of the methodology requested by a resource agency or Indian tribe for conducting the study is not a generally accepted practice. The applicant may refer any such request to the Director of the Office of Energy Projects for dispute resolution under the procedures set forth in paragraph (b)(6) of this section and need not conduct prior to filing any study determined by the Director to be unreasonable or unnecessary or to employ a methodology that is not generally accepted.
(3)(i) The results of studies and information-gathering referenced in paragraphs (c)(1)(ii) and (c)(2) of this section will be treated as additional information; and
(ii) Filing and acceptance of an application will not be delayed and an application will not be considered deficient or patently deficient pursuant to § 4.32 (e)(1) or (e)(2) merely because the study or information gathering is not complete before the application is filed.
(4) A potential applicant must provide each resource agency and Indian tribe with:
(i) A copy of its draft application that:
(A) Indicates the type of application the potential applicant expects to file with the Commission; and
(B) Responds to any comments and recommendations made by any resource agency and Indian tribe either during the first stage of consultation or under paragraph (c)(2) of this section;
(ii) The results of all studies and information-gathering either requested by that resource agency or Indian tribe in the first stage of consultation (or under paragraph (c)(2) of this section if available) or which pertain to resources of interest to that resource agency or Indian tribe and which were identified by the potential applicant pursuant to paragraph (b)(2)(vii) of this section, including a discussion of the results and any proposed protection, mitigation, or enhancement measures; and
(iii) A written request for review and comment.
(5) A resource agency or Indian tribe will have 90 days from the date of the potential applicant’s letter transmitting the paragraph (c)(4) information to it to provide written comments on the information submitted by a potential applicant under paragraph (c)(4) of this section.
(6) If the written comments provided under paragraph (c)(5) of this section indicate that a resource agency or Indian tribe has a substantive disagreement with a potential applicant’s conclusions regarding resource impacts or its proposed protection, mitigation, or enhancement measures, the potential applicant will:
(i) Hold a joint meeting with the disagreeing resource agency or Indian tribe and other agencies with similar or related areas of interest, expertise, or responsibility not later than 60 days from the date of the written comments of the disagreeing agency or Indian tribe to discuss and to attempt to reach agreement on its plan for environmental protection, mitigation, or enhancement measures;
(ii) Consult with the disagreeing agency or Indian tribe and other agencies with similar or related areas of interest, expertise, or responsibility on the scheduling of the joint meeting; and
(iii) At least 15 days in advance of the meeting, provide the Commission with written notice of the time and place of the meeting and a written agenda of the issues to be discussed at the meeting.
(7) The potential applicant and any disagreeing resource agency or Indian tribe may conclude a joint meeting with a document embodying any agreement among them regarding environmental protection, mitigation, or enhancement measures and any issues that are unresolved.
(8) The potential applicant must describe all disagreements with a resource agency or Indian tribe on technical or environmental protection, mitigation, or enhancement measures in its application, including an explanation of the basis for the applicant’s disagreement with the resource agency or Indian tribe, and must include in its application any document developed pursuant to paragraph (c)(7) of this section.
(9) A potential applicant may file an application with the Commission if:
(i) It has complied with paragraph (c)(4) of this section and no resource agency or Indian tribe has responded with substantive disagreements by the deadline specified in paragraph (c)(5) of this section; or
(ii) It has complied with paragraph (c)(6) of this section and a resource agency or Indian tribe has responded with substantive disagreements.
(10) The second stage of consultation ends:
(i) Ninety days after the submittal of information pursuant to paragraph (c)(4) of this section in cases where no resource agency or Indian tribe has responded with substantive disagreements; or
(ii) At the conclusion of the last joint meeting held pursuant to paragraph (c)(6) of this section in cases where a resource agency or Indian tribe has responded with substantive disagreements.
(d) Third stage of consultation. (1) The third stage of consultation is initiated by the filing of an application for a license or exemption, accompanied by a transmittal letter certifying that at the same time copies of the application are being mailed to the resource agencies, Indian tribes, other government offices, and consulted members of the public specified in paragraph (d)(2) of this section.
(2) As soon as an applicant files such application documents with the Commission, or promptly after receipt in the case of documents described in paragraph (d)(2)(iii) of this section, as the Commission may direct the applicant must serve on every resource agency, Indian tribes, and member of the public consulted, and on other government offices copies of:
(i) Its application for a license or an exemption from licensing;
(ii) Any deficiency correction, revision, supplement, response to additional information request, or amendment to the application; and
(iii) Any written correspondence from the Commission requesting the correction of deficiencies or the submittal of additional information.
(e) Waiver of compliance with consultation requirements. (1) If a resource agency or Indian tribe waives in writing compliance with any requirement of this section, a potential applicant does not have to comply with that requirement as to that agency or tribe.
(2) If a resource agency or Indian tribe fails to timely comply with a provision regarding a requirement of this section, a potential applicant may proceed to the next sequential requirement of this section without waiting for the resource agency or Indian tribe to comply.
(3) The failure of a resource agency or Indian tribe to timely comply with a provision regarding a requirement of this section does not preclude its participation in subsequent stages of the consultation process.
(4) Following October 23, 2003, a potential license applicant engaged in pre-filing consultation under part 4 may during first stage consultation request to incorporate into pre-filing consultation any element of the integrated license application process provided for in part 5 of this chapter. Any such request must be accompanied by a:
(i) Specific description of how the element of the part 5 license application would fit into the pre-filing consultation process under this part; and
(ii) Demonstration that the potential license applicant has made every reasonable effort to contact all resource agencies, Indian tribes, non-governmental organizations, and others affected by the applicant’s proposal, and that a consensus exists in favor of incorporating the specific element of the part 5 process into the pre-filing consultation under this part.
(f) Application requirements documenting consultation and any disagreements with resource agencies. An applicant must show in Exhibit E of its application that it has met the requirements of paragraphs (b) through (d) and paragraphs (g) and (h) of this section, and must include a summary of the consultation process and:
(1) Any resource agency’s or Indian tribe’s letters containing comments, recommendations, and proposed terms and conditions;
(2) Any letters from the public containing comments and recommendations;
(3) Notice of any remaining disagreement with a resource agency or Indian tribe on:
(i) The need for a study or the manner in which a study should be conducted and the applicant’s reasons for disagreement, and
(ii) Information on any environmental protection, mitigation, or enhancement measure, including the basis for the applicant’s disagreement with the resource agency or Indian tribe;
(4) Evidence of any waivers under paragraph (e) of this section;
(5) Evidence of all attempts to consult with a resource agency or Indian tribe, copies of related documents showing the attempts, and documents showing the conclusion of the second stage of consultation;
(6) An explanation of how and why the project would, would not, or should not, comply with any relevant comprehensive plan as defined in § 2.l9 of this chapter and a description of any relevant resource agency or Indian tribe determination regarding the consistency of the project with any such comprehensive plan;
(7) A description of how the applicant’s proposal addresses the significant resource issues raised at the joint meeting held pursuant to paragraph (b)(3) of this section; and
(8) A list containing the name and address of every federal, state, and interstate resource agency and Indian tribe with which the applicant consulted pursuant to paragraph (a)(1) of this section.
(g) Public participation. (1) At least 14 days in advance of the joint meeting held pursuant to paragraph (b)(3) of this section, the potential applicant must publish notice, at least once, of the purpose, location, and timing of the joint meeting, in a daily or weekly newspaper published in each county in which the proposed project or any part thereof is situated. The notice shall include a summary of the major issues to be discussed at the joint meeting.
(2)(i) A potential applicant must make available to the public for inspection and reproduction the information specified in paragraph (b)(2) of this section from the date on which the notice required by paragraph (g)(1) of this section is first published until a final order is issued on any license application.
(ii) The provisions of § 4.32(b) will govern the form and manner in which the information is to be made available for public inspection and reproduction.
(iii) A potential applicant must make available to the public for inspection at the joint meeting required by paragraph (b)(3) of this section at least two copies of the information specified in paragraph (b)(2) of this section.
(h) Critical Energy Infrastructure Information. If this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 4.32(k).
§ 4.39 Specifications for maps and drawings.
(a) Full-sized prints of maps and drawings must be on sheets no smaller than 22 by 34 inches and no larger than 24 by 36 inches. A space five inches high by seven inches wide must be provided in the lower right hand corner of each sheet. The upper half of this space must bear the title, numerical and graphical scale, and other pertinent information concerning the map or drawing. The lower half of the space must be left clear. Exhibit G drawings must be stamped by a registered land surveyor. If the drawing size specified in this paragraph limits the scale of structural drawings (exhibit F drawings) described in paragraph (c) of this section, a smaller scale may be used for those drawings. Potential applicants or licensees may be required to file maps or drawings in electronic format as directed by the Commission.
(b) Each map must have a scale in full-sized prints no smaller than one inch equals 0.5 miles for transmission lines, roads, and similar linear features and no smaller than one inch equals 1,000 feet for other project features, including the project boundary. Where maps at this scale do not show sufficient detail, large scale maps may be required. Each map must have:
(1) True and magnetic meridians;
(2) State, county, and town lines; and
(3) Boundaries of public lands and reservations of the United States [see 16 U.S.C. 796 (1) and (2)], if any. If a public land survey is available, the maps must show all lines of that survey crossing the project area and all official subdivisions of sections for the public lands and reservations, including lots and irregular tracts, as designated on the official plats of survey that may be obtained from the Bureau of Land Management, Washington, DC, or examined in the local land survey office; to the extent that a public land survey is not available for public lands and reservations of the United States, the maps must show the protractions of townships and section lines, which, if possible, must be those recognized by the Federal agency administering those lands.
(c) Drawings depicting details of project structures must have a scale in full-sized prints no smaller than:
(1) One inch equals 50 feet for plans, elevations, and profiles; and
(2) One inch equals 10 feet for sections.
(d) Each map or drawing must be drawn and lettered to be legible when it is reduced to a print that is 11 inches on its shorter side. Following notification to the applicant that the application has been accepted for filing [see § 4.32(d)], prints reduced to that size must be bound in each copy of the application which is required to be submitted to the Commission or provided to any person, agency, or other entity.
(e) The maps and drawings showing project location information and details of project structures must be filed in accordance with the Commission’s instructions on submission of privileged materials and Critical Energy Infrastructure Information in §§ 388.112 and 388.113 of this chapter.
Subpart E—Application for License for Major Unconstructed Project and Major Modified Project
§ 4.40 Applicability.
(a) Applicability. The provisions of this subpart apply to any application for an initial license for a major unconstructed project that would have a total installed capacity of more than 10 megawatts, and any application for an initial or new license for a major modified project with a total installed capacity more than 10 megawatts. An applicant for license for any major unconstructed or major modified water power project that would have a total installed generating capacity of 10 megawatts or less must submit application under subpart G of this part (§§ 4.60 and 4.61).
(b) Guidance from Commission staff. A prospective applicant for a license for a major unconstructed project or major modified project may seek advice from the Commission’s Office of Energy Projects regarding the applicability of this subpart to its project [see § 4.32(h)], including the determinations whether any proposed repair, modification or reconstruction of an existing dam would result in a significant change in the normal maximum surface elevation of an existing impoundment, or whether any proposed change in existing project works or operation would result in a significant environmental impact.
§ 4.41 Contents of application.
Any application under this subpart must contain the following information in the form prescribed:
(a) Initial statement.
(1) [Name of applicant] applies to the Federal Energy Regulatory Commission for a [license or new license, as appropriate] for the [name of project] water power project, as described in the attached exhibits. [Specify any previous FERC project number designation.]
(2) The location of the proposed project is:
(3) The exact name, business address, and telephone number of the applicant are:
(4) The applicant is a (citizen of the United States, association of citizens of the United States, domestic corporation, municipality, or State, as appropriate) and (is/is not) claiming preference under section 7(a) of the Federal Power Act. See 16 U.S.C. 796.
(5)(i) The statutory or regulatory requirements of the state(s) in which the project would be located and that affect the project as proposed with respect to bed and banks and to the appropriation, diversion, and use of water for power purposes, and with respect to the right to engage in the business of developing, transmitting, and distributing power and in any other business necessary to accomplish the purposes of the license under the Federal Power Act, are: [provide citation and brief identification of the nature of each requirement; if the applicant is a municipality, the applicant must submit copies of applicable state or local laws or a municipal charter or, if such laws or documents are not clear, any other appropriate legal authority, evidencing that the municipality is competent under such laws to engage in the business of developing, transmitting, utilizing, or distributing power.]
(ii) The steps which the applicant has taken, or plans to take, to comply with each of the laws cited above are: [provide brief description for each requirement]
(b) Exhibit A is a description of the project. If the project includes more than one dam with associated facilities, each dam and the associated component parts must be described together as a discrete development. The description for each development must contain:
(1) The physical composition, dimensions, and general configuration of any dams, spillways, penstocks, powerhouses, tailraces or other structures proposed to be included as part of the project;
(2) The normal maximum water surface area and normal maximum water surface elevation (mean sea level), gross storage capacity of any impoundments to be included as part of the project;
(3) The number, type and rated capacity of any proposed turbines or generators to be included as part of the project;
(4) The number, length, voltage and interconnections of any primary transmission lines proposed to be included a part of the project [See 16 U.S.C. 796(11)];
(5) The description of any additional mechanical, electrical, and transmission equipment appurtenant to the project; and
(6) All lands of the United States, including lands patented subject to the provisions of section 24 of the Act, 16 U.S.C. 818, that are enclosed within the project boundary described under paragraph (h) of this section (Exhibit G), identified and tabulated by legal subdivisions of a public land survey, by the best available legal description. The tabulation must show the total acreage of the lands of the United States within the project boundary.
(c) Exhibit B is a statement of project operation and resource utilization. If the project includes more than one dam with associated facilities, the information must be provided separately for each discrete development. The exhibit must contain:
(1) A description of each alternative site considered in selecting of the proposed site;
(2) A description of any alternative facility designs, processes, and operations that were considered.
(3) A statement as to whether operation of the power plant will be manual or automatic, an estimate of the annual plant factor, and a statement of how the project will be operated during adverse, mean, and high water years;
(4) An estimate of the dependable capacity and average annual energy production in kilowatt-hours (or mechanical equivalent), supported by the following data:
(i) The minimum, mean, and maximum recorded flows in cubic feet per second of the stream or other body of water at the powerplant intake or point of diversion, with a specification of any adjustment made for evaporation, leakage minimum flow releases (including duration of releases) or other reductions in available flow; monthly flow duration curves indicating the period of record and the gauging stations used in deriving the curves; and a specification of the critical streamflow used to determine the dependable capacity;
(ii) An area-capacity curve showing the gross storage capacity and usable storage capacity of the impoundment, with a rule curve showing the proposed operation of the impoundment and how the usable storage capacity is to be utilized;
(iii) The estimated minimum and maximum hydraulic capacity of the powerplant in terms of flow and efficiency (cubic feet per second at one-half, full and best gate), and the corresponding generator output in kilowatts;
(iv) A tailwater rating curve; and
(v) A curve showing powerplant capability versus head and specifying maximum, normal, and minimum heads;
(5) A statement of system and regional power needs and the manner in which the power generated at the project is to be utilized, including the amount of power to be used on-site, if any, supported by the following data:
(i) Load curves and tabular data, if appropriate;
(ii) Details of conservation and rate design programs and their historic and projected impacts on system loads; and
(iii) The amount of power to be sold and the identity of proposed purchaser(s); and
(6) A statement of the applicant’s plans for future development of the project or of any other existing or proposed water power project on the affected stream or other body of water, indicating the approximate location and estimated installed capacity of the proposed developments.
(d) Exhibit C is a proposed construction schedule for the project. The information required may be supplemented with a bar chart. The construction schedule must contain:
(1) The proposed commencement and completion dates of any new construction, modification, or repair of major project works;
(2) The proposed commencement date of first commercial operation of each new major facility and generating unit; and
(3) If any portion of the proposed project consists of previously constructed, unlicensed water power structures or facilities, a chronology of original completion dates of those structures or facilities specifying dates (approximate dates must be identified as such) of:
(i) Commencement and completion of construction or installation;
(ii) Commencement of first commercial operation; and
(iii) Any additions or modifications other than routine maintenance.
(e) Exhibit D is a statement of project costs and financing. The exhibit must contain:
(1) A statement of estimated costs of any new construction, modification, or repair, including:
(i) The cost of any land or water rights necessary to the development;
(ii) The total cost of all major project works;
(iii) Indirect construction costs such as costs of construction equipment, camps, and commissaries;
(iv) Interest during construction; and
(v) Overhead, construction, legal expenses, and contingencies;
(2) If any portion of the proposed project consists of previously constructed, unlicensed water power structures or facilities, a statement of the original cost of those structures or facilities specifying for each, to the extent possible, the actual or approximate total costs (approximate costs must be identified as such) of:
(i) Any land or water rights necessary to the existing project works;
(ii) All major project works; and
(iii) Any additions or modifications other than routine maintenance;
(3) If the applicant is a licensee applying for a new license, and is not a municipality or a state, an estimate of the amount which would be payable if the project were to be taken over pursuant to section 14 of the Federal Power Act, 16 U.S.C. 807, upon expiration of the license in effect including:
(i) Fair value;
(ii) Net investment; and
(iii) Severance damages;
(4) A statement of the estimated average annual cost of the total project as proposed, specifying any projected changes in the costs (life-cycle costs) over the estimated financing or licensing period if the applicant takes such changes into account, including:
(i) Cost of capital (equity and debt);
(ii) Local, state, and Federal taxes;
(iii) Depreciation or amortization,
(iv) Operation and maintenance expenses, including interim replacements, insurance, administrative and general expenses, and contingencies; and
(v) The estimated capital cost and estimated annual operation and maintenance expense of each proposed environmental measure;
(5) A statement of the estimated annual value of project power based on a showing of the contract price for sale of power or the estimated average annual cost of obtaining an equivalent amount of power (capacity and energy) from the lowest cost alternative source of power, specifying any projected changes in the costs (life-cycle costs) of power from that source over the estimated financing or licensing period if the applicant takes such changes into account;
(6) A statement describing other electric energy alternatives, such as gas, oil, coal and nuclear-fueled powerplants and other conventional and pumped storage hydroelectric plants;
(7) A statement and evaluation of the consequences of denial of the license application and a brief perspective of what future use would be made of the proposed site if the proposed project were not constructed;
(8) A statement specifying the sources and extent of financing and annual revenues available to the applicant to meet the costs identified in paragraphs (e) (1) and (4) of this section;
(9) An estimate of the cost to develop the license application; and
(10) The on-peak and off-peak values of project power, and the basis for estimating the values, for projects which are proposed to operate in a mode other than run-of-river.
(f) Exhibit E is an Environmental Report. Information provided in the report must be organized and referenced according to the itemized subparagraphs below. See § 4.38 for consultation requirements. The Environmental Report must contain the following information, commensurate with the scope of the project:
(1) General description of the locale. The applicant must provide a general description of the environment of the proposed project area and its immediate vicinity. The description must include location and general information helpful to an understanding of the environmental setting.
(2) Report on water use and quality. The report must discuss water quality and flows and contain baseline data sufficient to determine the normal and seasonal variability, the impacts expected during construction and operation, and any mitigative, enhancement, and protective measures proposed by the applicant. The report must be prepared in consultation with the state and Federal agencies with responsibility for management of water quality and quantity in the affected stream or other body of water. The report must include:
(i) A description of existing instream flow uses of streams in the project area that would be affected by construction and operation; estimated quantities of water discharged from the proposed project for power production; and any existing and proposed uses of project waters for irrigation, domestic water supply, industrial and other purposes;
(ii) A description of the seasonal variation of existing water quality for any stream, lake, or reservoir that would be affected by the proposed project, including (as appropriate) measurements of: significant ions, chlorophyll a, nutrients, specific conductance, pH, total dissolved solids, total alkalinity, total hardness, dissolved oxygen, bacteria, temperature, suspended sediments, turbidity and vertical illumination;
(iii) A description of any existing lake or reservoir and any of the proposed project reservoirs including surface area, volume, maximum depth, mean depth, flushing rate, shoreline length, substrate classification, and gradient for streams directly affected by the proposed project;
(iv) A quantification of the anticipated impacts of the proposed construction and operation of project facilities on water quality and downstream flows, such as temperature, turbidity and nutrients;
(v) A description of measures recommended by Federal and state agencies and the applicant for the purpose of protecting or improving water quality and stream flows during project construction and operation; an explanation of why the applicant has rejected any measures recommended by an agency; and a description of the applicant’s alternative measures to protect or improve water quality stream flow;
(vi) A description of groundwater in the vicinity of the proposed project, including water table and artesian conditions, the hydraulic gradient, the degree to which groundwater and surface water are hydraulically connected, aquifers and their use as water supply, and the location of springs, wells, artesian flows and disappearing streams; a description of anticipated impacts on groundwater and measures proposed by the applicant and others for the mitigation of impacts on groundwater; and
(3) Report on fish, wildlife, and botanical resources. The applicant must provide a report that describes the fish, wildlife, and botanical resources in the vicinity of the proposed project; expected impacts of the project on these resources; and mitigation, enhancement, or protection measures proposed by the applicant. The report must be prepared in consultation with the state agency or agencies with responsibility for these resources, the U.S. Fish and Wildlife Service, the National Marine Fisheries Service (if the proposed project may affect anadromous, estuarine, or marine fish resources), and any state or Federal agency with managerial authority over any part of the proposed project lands. The report must contain:
(i) A description of existing fish, wildlife, and plant communities of the proposed project area and its vicinity, including any downstream areas that may be affected by the proposed project and the area within the transmission line corridor or right-of-way. A map of vegetation types should be included in the description. For species considered important because of their commercial or recreational value, the information provided should include temporal and spatial distributions and densities of such species. Any fish, wildlife, or plant species proposed or listed as threatened or endangered by the U.S. Fish and Wildlife Service or National Marine Fisheries Service [see 50 CFR 17.11 and 17.12] must be identified;
(ii) A description of the anticipated impacts on fish, wildlife and botanical resources of the proposed construction and operation of project facilities, including possible changes in size, distribution, and reproduction of essential population of these resources and any impacts on human utilization of these resources;
(iii) A description of any measures or facilities recommended by state or Federal agencies for the mitigation of impacts on fish, wildlife, and botanical resources, or for the protection or enhancement of these resources, the impact on threatened or endangered species, and an explanation of why the applicant has determined any measures or facilities recommended by an agency are inappropriate as well as a description of alternative measures proposed by applicant to protect fish, wildlife and botanical resources; and
(iv) The following materials and information regarding any mitigation measures or facilities, identified under clause (iii), proposed for implementation or construction:
(A) Functional design drawings;
(B) A description of proposed operation and maintenance procedures for any proposed measures or facilities;
(C) An implementation, construction and operation schedule for any proposed measures or facilities;
(D) An estimate of the costs of construction, operation, and maintenance of any proposed facilities or implementation of any measures;
(E) A statement of the sources and amount of financing for mitigation measures or facilities; and
(F) A map or drawing showing, by the use of shading, crosshatching or other symbols, the identity and location of any proposed measures or facilities.
(4) Report on historic and archaeological resources. The applicant must provide a report that discusses any historical and archaeological resources in the proposed project area, the impact of the proposed project on those resources and the avoidance, mitigation, and protection measures proposed by the applicant. The report must be prepared in consultation with the State Historic Preservation Officer (SHPO) and the National Park Service of the U.S. Department of Interior. The report must contain:
(i) A description of any discovery measures, such as surveys, inventories, and limited subsurface testing work, recommended by the specified state and Federal agencies for the purpose of locating, identifying, and assessing the significance of historic and archaeological resources that would be affected by construction and operation of the proposed project, together with a statement of the applicant’s position regarding the acceptability of the recommendations;
(ii) The results of surveys, inventories, and subsurface testing work recommended by the state and Federal agencies listed above, together with an explanation by the applicant of any variations from the survey, inventory, or testing procedures recommended;
(iii) An identification (without providing specific site or property locations) of any historic or archaeological site in the proposed project area, with particular emphasis on sites or properties either listed in, or recommended by the SHPO for inclusion in, the National Register of Historic Places that would be affected by the construction of the proposed project;
(iv) A description of the likely direct and indirect impacts of proposed project construction or operation on sites or properties either listed in, or recommended as eligible for, the National Register of Historic Places;
(v) A management plan for the avoidance of, or mitigation of, impacts on historic or archaeological sites and resources based upon the recommendations of the state and Federal agencies listed above and containing the applicant’s explanation of variations from those recommendations; and
(vi) The following materials and information regarding the mitigation measures described under paragraph (f)(4)(v) of this section:
(A) A schedule for implementing the mitigation proposals;
(B) An estimate of the cost of the measures; and
(C) A statement of the sources and extent of financing.
(vii) The applicant must provide five copies (rather than the eight copies required under § 4.32(b)(1) of the Commission’s regulations) of any survey, inventory, or subsurface testing reports containing specific site and property information, and including maps and photographs showing the location and any required alteration of historic and archaeological resources in relation to proposed project facilities.
(5) Report on socio-economic impacts. The applicant must provide a report which identifies and quantifies the impacts of constructing and operating the proposed project on employment, population, housing, personal income, local governmental services, local tax revenues and other factors within the towns and counties in the vicinity of the proposed project. The report must include:
(i) A description of the socio-economic impact area;
(ii) A description of employment, population and personal income trends in the impact area;
(iii) An evaluation of the impact of any substantial in-migration of people on the impact area’s governmental facilities and services, such as police, fire, health and educational facilities and programs;
(iv) On-site manpower requirements and payroll during and after project construction, including a projection of total on-site employment and construction payroll provided by month;
(v) Numbers of project construction personnel who:
(A) Currently reside within the impact area;
(B) Would commute daily to the construction site from places situated outside the impact area; and
(C) Would relocate on a temporary basis within the impact area;
(vi) A determination of whether the existing supply of available housing within the impact area is sufficient to meet the needs of the additional population;
(vii) Numbers and types of residences and business establishments that would be displaced by the proposed project, procedures to be utilized to acquire these properties, and types and amounts of relocation assistance payments that would be paid to the affected property owners and businesses; and
(viii) A fiscal impact analysis evaluating the incremental local government expenditures in relation to the incremental local government revenues that would result from the construction of the proposed project. Incremental expenditures may include, but are not be limited to, school operating costs, road maintenance and repair, public safety, and public utility costs.
(6) Report on geological and soil resources. The applicant must provide a report on the geological and soil resources in the proposed project area and other lands that would be directly or indirectly affected by the proposed action and the impacts of the proposed project on those resources. The information required may be supplemented with maps showing the location and description of conditions. The report must contain:
(i) A detailed description of geological features, including bedrock lithology, stratigraphy, structural features, glacial features, unconsolidated deposits, and mineral resources;
(ii) A detailed description of the soils, including the types, occurrence, physical and chemical characteristics, erodability and potential for mass soil movement;
(iii) A description showing the location of existing and potential geological and soil hazards and problems, including earthquakes, faults, seepage, subsidence, solution cavities, active and abandoned mines, erosion, and mass soil movement, and an identification of any large landslides or potentially unstable soil masses which could be aggravated by reservoir fluctuation;
(iv) A description of the anticipated erosion, mass soil movement and other impacts on the geological and soil resources due to construction and operation of the proposed project; and
(v) A description of any proposed measures or facilities for the mitigation of impacts on soils.
(7) Report on recreational resources. The applicant must prepare a report containing a proposed recreation plan describing utilization, design and development of project recreational facilities, and public access to the project area. Development of the plan should include consideration of the needs of the physically handicapped. Public and private recreational facilities provided by others that would abut the project should be noted in the report. The report must be prepared in consultation with appropriate local, regional, state and Federal recreation agencies and planning commissions, the National Park Service of the U.S. Department of the Interior, and any other state or Federal agency with managerial responsibility for any part of the project lands. The report must contain:
(i) A description of any areas within or in the vicinity of the proposed project boundary that are included in, or have been designated for study for inclusion in:
(A) The National Wild and Scenic Rivers Systems (see 16 U.S.C. 1271);
(B) The National Trails System (see 16 U.S.C. 1241); or
(C) A wilderness area designated under the Wilderness Act (see 16 U.S.C. 1132);
(ii) A detailed description of existing recreational facilities within the project vicinity, and the public recreational facilities which are to be provided by the applicant at its sole cost or in cooperation with others no later than 3 years from the date of first commercial operation of the proposed project and those recreation facilities planned for future development based on anticipated demand. When public recreation facilities are to be provided by other entities, the applicant and those entities should enter into an agreement on the type of facilities to be provided and the method of operation. Copies of agreements with cooperating entities are to be appended to the plan;
(iii) A provision for a shoreline buffer zone that must be within the project boundary, above the normal maximum surface elevation of the project reservoir, and of sufficient width to allow public access to project lands and waters and to protect the scenic, public recreational, cultural, and other environmental values of the reservoir shoreline;
(iv) Estimates of existing and future recreational use at the project, in daytime and overnight visitation (recreation days), with a description of the methodology used in developing these data;
(v) A development schedule and cost estimates of the construction, operation, and maintenance of existing, initial, and future public recreational facilities, including a statement of the source and extent of financing for such facilities;
(vi) A description of any measures or facilities recommended by the agencies consulted for the purpose of creating, preserving, or enhancing recreational opportunities at the proposed project, and for the purpose of ensuring the safety of the public in its use of project lands and waters, including an explanation of why the applicant has rejected any measures or facilities recommended by an agency; and
(vii) A drawing or drawings, one of which describes the entire project area, clearly showing:
(A) The location of project lands, and the types and number of existing recreational facilities and those proposed for initial development, including access roads and trails, and facilities for camping, picnicking, swimming, boat docking and launching, fishing and hunting, as well as provisions for sanitation and waste disposal;
(B) The location of project lands, and the type and number of recreational facilities planned for future development;
(C) The location of all project lands reserved for recreational uses other than those included in paragraphs (f)(7)(vii) (A) and (B) of this section; and
(D) The project boundary (excluding surveying details) of all areas designated for recreational development, sufficiently referenced to the appropriate Exhibit G drawings to show that all lands reserved for existing and future public recreational development and the shoreline buffer zone are included within the project boundary. Recreational cottages, mobile homes and year-round residences for private use are not to be considered as public recreational facilities, and the lands on which these private facilities are to be developed are not to be included within the proposed project boundary.
(8) Report on aesthetic resources. The applicant must provide a report that describes the aesthetic resources of the proposed project area, the expected impacts of the project on these resources, and the mitigation, enhancement or protection measures proposed. The report must be prepared following consultation with Federal, state, and local agencies having managerial responsibility for any part of the proposed project lands or lands abutting those lands. The report must contain:
(i) A description of the aesthetic character of lands and waters directly and indirectly affected by the proposed project facilities;
(ii) A description of the anticipated impacts on aesthetic resources from construction activity and related equipment and material, and the subsequent presence of proposed project facilities in the landscape;
(iii) A description of mitigative measures proposed by the applicant, including architectural design, landscaping, and other reasonable treatment to be given project works to preserve and enhance aesthetic and related resources during construction and operation of proposed project facilities; and
(iv) Maps, drawings and photographs sufficient to provide an understanding of the information required under this paragraph. Maps or drawings may be consolidated with other maps or drawings required in this exhibit and must conform to the specifications of § 4.39.
(9) Report on land use. The applicant must provide a report that describes the existing uses of the proposed project lands and adjacent property, and those land uses which would occur if the project is constructed. The report may reference the discussions of land uses in other sections of this exhibit. The report must be prepared following consultation with local and state zoning or land management authorities, and any Federal or state agency with managerial responsibility for the proposed project or abutting lands. The report must include:
(i) A description of existing land use in the proposed project area, including identification of wetlands, floodlands, prime or unique farmland as designated by the Natural Resources Conservation Service of the U.S. Department of Agriculture, the Special Area Management Plan of the Office of Coastal Zone Management, National Oceanic and Atmospheric Administration, and lands owned or subject to control by government agencies;
(ii) A description of the proposed land uses within and abutting the project boundary that would occur as a result of development and operation of the project; and
(iii) Aerial photographs, maps, drawings or other graphics sufficient to show the location, extent and nature of the land uses referred to in this section.
(10) Alternative locations, designs, and energy sources. The applicant must provide an environment assessment of the following:
(i) Alternative sites considered in arriving at the selection of the proposed project site;
(ii) Alternative facility designs, processes, and operations that were considered and the reasons for their rejection;
(iii) Alternative electrical energy sources, such as gas, oil, coal, and nuclear-fueled power plants, purchased power or diversity exchange, and other conventional and pumped-storage hydroelectric plants; and
(iv) The overall consequences if the license application is denied.
(11) List of literature. Exhibit E must include a list of all publications, reports, and other literature which were cited or otherwise utilized in the preparation of any part of the environmental report.
(g) Exhibit F consists of general design drawings of the principal project works described under paragraph (b) of this section (Exhibit A) and supporting information used as the basis of design. If the Exhibit F submitted with the application is preliminary in nature, applicant must so state in the application. The drawings must conform to the specifications of § 4.39.
(1) The drawings must show all major project structures in sufficient detail to provide a full understanding of the project, including:
(i) Plans (overhead view);
(ii) Elevations (front view);
(iii) Profiles (side view); and
(iv) Sections.
(2) The applicant may submit preliminary design drawings with the application. The final Exhibit F may be submitted during or after the licensing process and must show the precise plans and specifications for proposed structures. If the project is licensed on the basis of preliminary designs, the applicant must submit a final Exhibit F for Commission approval prior to commencement of any construction of the project.
(3) Supporting design report. The applicant must furnish, at a minimum, the following supporting information to demonstrate that existing and proposed structures are safe and adequate to fulfill their stated functions and must submit such information in a separate report at the time the application is filed. The report must include:
(i) An assessment of the suitability of the site and the reservoir rim stability based on geological and subsurface investigations, including investigations of soils and rock borings and tests for the evaluation of all foundations and construction materials sufficient to determine the location and type of dam structure suitable for the site;
(ii) Copies of boring logs, geology reports and laboratory test reports;
(iii) An identification of all borrow areas and quarry sites and an estimate of required quantities of suitable construction material;
(iv) Stability and stress analyses for all major structures and critical abutment slopes under all probable loading conditions, including seismic and hydrostatic forces induced by water loads up to the Probable Maximum Flood as appropriate; and
(v) The bases for determination of seismic loading and the Spillway Design Flood in sufficient detail to permit independent staff evaluation.
(4) The applicant must submit two copies of the supporting design report described in paragraph (g)(3) of this section at the time preliminary and final design drawings are submitted to the Commission for review. If the report contains preliminary drawings, it must be designated a “Preliminary Supporting Design Report.”
(h) Exhibit G is a map of the project that must conform to the specifications of § 4.39. In addition, to the other components of Exhibit G, the Applicant must provide the project boundary data in a geo-referenced electronic format—such as ArcView shape files, GeoMedia files, MapInfo files, or any similar format. The electronic boundary data must be positionally accurate to ±40 feet, in order to comply with the National Map Accuracy Standards for maps at a 1:24,000 scale (the scale of USGS quadrangle maps). The electronic exhibit G data must include a text file describing the map projection used (i.e., UTM, State Plane, Decimal Degrees, etc.), the map datum (i.e., feet, meters, miles, etc.). Three sets of the maps must be submitted on compact disk or other appropriate electronic media. If more than one sheet is used for the paper maps, the sheets must be numbered consecutively, and each sheet must bear a small insert sketch showing the entire project and indicate that portion of the project depicted on that sheet. Each sheet must contain a minimum of three known reference points. The latitude and longitude coordinates, or state plane coordinates, of each reference point must be shown. If at any time after the application is filed there is any change in the project boundary, the applicant must submit, within 90 days following the completion of project construction, a final exhibit G showing the extent of such changes. The map must show:
(1) Location of the project and principal features. The map must show the location of the project as a whole with reference to the affected stream or other body of water and, if possible, to a nearby town or any other permanent monuments or objects, such as roads, transmission lines or other structures, that can be noted on the map and recognized in the field. The map must also show the relative locations and physical interrelationships of the principal project works and other features described under paragraph (b) of this section (Exhibit A).
(2) Project boundary. The map must show a project boundary enclosing all project works and other features described under paragraph (b) of this section (Exhibit A) that are to be licensed. If accurate survey information is not available at the time the application is filed, the applicant must so state, and a tentative boundary may be submitted. The boundary must enclose only those lands necessary for operation and maintenance of the project and for other project purposes, such as recreation, shoreline control, or protection of environmental resources (see paragraph (f) of this section (Exhibit E)). Existing residential, commercial, or other structures may be included within the boundary only to the extent that underlying lands are needed for project purposes (e.g., for flowage, public recreation, shoreline control, or protection of environmental resources). If the boundary is on land covered by a public survey, ties must be shown on the map at sufficient points to permit accurate platting of the position of the boundary relative to the lines of the public land survey. If the lands are not covered by a public land survey, the best available legal description of the position of the boundary must be provided, including distances and directions from fixed monuments or physical features. The boundary must be described as follows:
(i) Impoundments. (A) The boundary around a project impoundment must be described by one of the following:
(1) Contour lines, including the contour elevation (preferred method);
(2) Specified courses and distances (metes and bounds);
(3) If the project lands are covered by a public land survey, lines upon or parallel to the lines of the survey; or
(4) Any combination of the above methods.
(B) The boundary must be located no more than 200 feet (horizontal measurement) from the exterior margin of the reservoir, defined by the normal maximum surface elevation, except where deviations may be necessary in describing the boundary according to the above methods or where additional lands are necessary for project purposes, such as public recreation, shoreline control, or protection of environmental resources.
(ii) Continuous features. The boundary around linear (continuous) project features such as access roads, transmission lines, and conduits may be described by specified distances from center lines or offset lines of survey. The width of such corridors must not exceed 200 feet unless good cause is shown for a greater width. Several sections of a continuous feature may be shown on a single sheet with information showing the sequence of contiguous sections.
(iii) Noncontinuous features. (A) The boundary around noncontinuous project works such as dams, spillways, and powerhouses must be described by one of the following:
(1) Contour lines;
(2) Specified courses and distances;
(3) If the project lands are covered by a public land survey, lines upon or parallel to the lines of the survey; or
(4) Any combination of the above methods.
(B) The boundary must enclose only those lands that are necessary for safe and efficient operation and maintenance of the project or for other specified project purposes, such as public recreation or protection of environmental resources.
(3) Federal lands. Any public lands and reservations of the United States (Federal lands) [see 16 U.S.C. 796 (1) and (2)] that are within the project boundary, such as lands administered by the U.S. Forest Service, Bureau of Land Management, or National Park Service, or Indian tribal lands, and the boundaries of those Federal lands, must be identified as such on the map by:
(i) Legal subdivisions of a public land survey of the affected area (a protraction of identified township and section lines is sufficient for this purpose); and
(ii) The Federal agency, identified by symbol or legend, that maintains or manages each identified subdivision of the public land survey within the project boundary; or
(iii) In the absence of a public land survey, the location of the Federal lands according to the distances and directions from fixed monuments or physical features. When a Federal survey monument or a Federal bench mark will be destroyed or rendered unusable by the construction of project works, at least two permanent, marked witness monuments or bench marks must be established at accessible points. The maps show the location (and elevation, for bench marks) of the survey monument or bench mark which will be destroyed or rendered unusable, as well as of the witness monuments or bench marks. Connecting courses and distances from the witness monuments or bench marks to the original must also be shown.
(iv) The project location must include the most current information pertaining to affected Federal lands as described under § 4.81(b)(5).
(4) Non-Federal lands. For those lands within the project boundary not identified under paragraph (h)(3) of this section, the map must identify by legal subdivision:
(i) Lands owned in fee by the applicant and lands that the applicant plans to acquire in fee; and
(ii) Lands over which the applicant has acquired or plans to acquire rights to occupancy and use other than fee title, including rights acquired or to be acquired by easement or lease.
Subpart F—Application for License for Major Project—Existing Dam
§ 4.50 Applicability.
(a) Applicability. (1) Except as provided in paragraph (a)(2) of this section, the provisions of this subpart apply to any application for either an initial license or new license for a major project—existing dam that is proposed to have a total installed capacity of more than 10 megawatts.
(2) This subpart does not apply to any major project—existing dam (see § 4.40) that is proposed to entail or include:
(i) Any repair, modification or reconstruction of an existing dam that would result in a significant change in the normal maximum surface area or normal maximum surface elevation of an existing impoundment; or
(ii) Any new development or change in project operation that would result in a significant environmental impact.
(3) An applicant for license for any major project—existing dam that would have a total installed capacity of 10 megawatts or less must submit application under subpart G of this part (§§ 4.60 and 4.61).
(b) Guidance from Commission staff. A prospective applicant for a major license—existing dam may seek advice from the Commission staff regarding the applicability of these sections to its project (see § 4.32(h)), including the determinations whether any proposed repair or reconstruction of an existing dam would result in a significant change in the normal maximum surface area or the normal maximum surface elevation of an existing impoundment, or whether any proposed new development or change in project operation would result in a significant environmental impact.
§ 4.51 Contents of application.
An application for license under this subpart must contain the following information in the form specified. As provided in paragraph (f) of this section, the appropriate Federal, state, and local resource agencies must be given the opportunity to comment on the proposed project, prior to filing of the application for license for major project—existing dam. Information from the consultation process must be included in this Exhibit E, as appropriate.
(a) Initial statement.
(1) (Name of applicant) applies to the Federal Energy Regulatory Commission for a (license or new license, as appropriate) for the (name of project) water power project, as described in the attached exhibits. (Specify any previous FERC project number designation.)
(2) The location of the project is:
(3) The exact name and business address of the applicant are:
The exact name and business address of each person authorized to act as agent for the applicant in this application are:
(4) The applicant is a [citizen of the United States, association of citizens of the United States, domestic corporation, municipality, or state, as appropriate] and (is/is not) claiming preference under section 7(a) of the Federal Power Act. See 16 U.S.C. 796.
(5)(i) The statutory or regulatory requirements of the state(s) in which the project would be located that affect the project as proposed, with respect to bed and banks and to the appropriation, diversion, and use of water for power purposes, and with respect to the right to engage in the business of developing, transmitting, and distributing power and in any other business necessary to accomplish the purposes of the license under the Federal Power Act, are: [Provide citation and brief identification of the nature of each requirement; if the applicant is a municipality, the applicant must submit copies of applicable state and local laws or a municipal charter, or, if such laws or documents are not clear, other appropriate legal authority, evidencing that the municipality is competent under such laws to engage in the business of developing, transmitting, utilizing, or distributing power.]
(ii) The steps which the applicant has taken or plans to take to comply with each of the laws cited above are: (provide brief description for each law).
(6) The applicant must provide the name and address of the owner of any existing project facilities. If the dam is federally owned or operated, provide the name of the agency.
(b) Exhibit A is a description of the project. This exhibit need not include information on project works maintained and operated by the U.S. Army Corps of Engineers, the Bureau of Reclamation, or any other department or agency of the United States, except for any project works that are proposed to be altered or modified. If the project includes more than one dam with associated facilities, each dam and the associated component parts must be described together as a discrete development. The description for each development must contain:
(1) The physical composition, dimensions, and general configuration of any dams, spillways, penstocks, powerhouses, tailraces, or other structures, whether existing or proposed, to be included as part of the project;
(2) The normal maximum surface area and normal maximum surface elevation (mean sea level), gross storage capacity, and usable storage capacity of any impoundments to be included as part of the project;
(3) The number, type, and rated capacity of any turbines or generators, whether existing or proposed, to be included as part of the project;
(4) The number, length, voltage, and interconnections of any primary transmission lines, whether existing or proposed, to be included as part of the project (see 16 U.S.C. 796(11));
(5) The specifications of any additional mechanical, electrical, and transmission equipment appurtenant to the project; and
(6) All lands of the United States that are enclosed within the project boundary described under paragraph (h) of this section (Exhibit G), identified and tabulated by legal subdivisions of a public land survey of the affected area or, in the absence of a public land survey, by the best available legal description. The tabulation must show the total acreage of the lands of the United States within the project boundary.
(c) Exhibit B is a statement of project operation and resource utilization. If the project includes more than one dam with associated facilities, the information must be provided separately for each such discrete development. The exhibit must contain:
(1) A statement whether operation of the powerplant will be manual or automatic, an estimate of the annual plant factor, and a statement of how the project will be operated during adverse, mean, and high water years;
(2) An estimate of the dependable capacity and average annual energy production in kilowatt-hours (or a mechanical equivalent), supported by the following data:
(i) The minimum, mean, and maximum recorded flows in cubic feet per second of the stream or other body of water at the powerplant intake or point of diversion, with a specification of any adjustments made for evaporation, leakage, minimum flow releases (including duration of releases), or other reductions in available flow; monthly flow duration curves indicating the period of record and the gauging stations used in deriving the curves; and a specification of the period of critical streamflow used to determine the dependable capacity;
(ii) An area-capacity curve showing the gross storage capacity and usable storage capacity of the impoundment, with a rule curve showing the proposed operation of the impoundment and how the usable storage capacity is to be utilized;
(iii) The estimated hydraulic capacity of the powerplant (minimum and maximum flow through the powerplant) in cubic feet per second;
(iv) A tailwater rating curve; and
(v) A curve showing powerplant capability versus head and specifying maximum, normal, and minimum heads;
(3) A statement, with load curves and tabular data, if necessary, of the manner in which the power generated at the project is to be utilized, including the amount of power to be used on-site, if any, the amount of power to be sold, and the identity of any proposed purchasers; and
(4) A statement of the applicant’s plans, if any, for future development of the project or of any other existing or proposed water power project on the stream or other body of water, indicating the approximate location and estimated installed capacity of the proposed developments.
(d) Exhibit C is a construction history and proposed construction schedule for the project. The construction history and schedules must contain:
(1) If the application is for an initial license, a tabulated chronology of construction for the existing projects structures and facilities described under paragraph (b) of this section (Exhibit A), specifying for each structure or facility, to the extent possible, the actual or approximate dates (approximate dates must be identified as such) of:
(i) Commencement and completion of construction or installation;
(ii) Commencement of commercial operation; and
(iii) Any additions or modifications other than routine maintenance; and
(2) If any new development is proposed, a proposed schedule describing the necessary work and specifying the intervals following issuance of a license when the work would be commenced and completed.
(e) Exhibit D is a statement of costs and financing. The statement must contain:
(1) If the application is for an initial license, a tabulated statement providing the actual or approximate original cost (approximate costs must be identified as such) of:
(i) Any land or water right necessary to the existing project; and
(ii) Each existing structure and facility described under paragraph (b) of this section (Exhibit A).
(2) If the applicant is a licensee applying for a new license, and is not a municipality or a state, an estimate of the amount which would be payable if the project were to be taken over pursuant to section 14 of the Federal Power Act upon expiration of the license in effect [see 16 U.S.C. 807], including:
(i) Fair value;
(ii) Net investment; and
(iii) Severance damages.
(3) If the application includes proposals for any new development, a statement of estimated costs, including:
(i) The cost of any land or water rights necessary to the new development; and
(ii) The cost of the new development work, with a specification of:
(A) Total cost of each major item;
(B) Indirect construction costs such as costs of construction equipment, camps, and commissaries;
(C) Interest during construction; and
(D) Overhead, construction, legal expenses, taxes, administrative and general expenses, and contingencies.
(4) A statement of the estimated average annual cost of the total project as proposed specifying any projected changes in the costs (life-cycle costs) over the estimated financing or licensing period if the applicant takes such changes into account, including:
(i) Cost of capital (equity and debt);
(ii) Local, state, and Federal taxes;
(iii) Depreciation and amortization;
(iv) Operation and maintenance expenses, including interim replacements, insurance, administrative and general expenses, and contingencies; and
(v) The estimated capital cost and estimated annual operation and maintenance expense of each proposed environmental measure.
(5) A statement of the estimated annual value of project power, based on a showing of the contract price for sale of power or the estimated average annual cost of obtaining an equivalent amount of power (capacity and energy) from the lowest cost alternative source, specifying any projected changes in the cost of power from that source over the estimated financing or licensing period if the applicant takes such changes into account.
(6) A statement specifying the sources and extent of financing and annual revenues available to the applicant to meet the costs identified in paragraphs (e) (3) and (4) of this section.
(7) An estimate of the cost to develop the license application;
(8) The on-peak and off-peak values of project power, and the basis for estimating the values, for projects which are proposed to operate in a mode other than run-of-river; and
(9) The estimated average annual increase or decrease in project generation, and the estimated average annual increase or decrease of the value of project power, due to a change in project operations (i.e., minimum bypass flows; limits on reservoir fluctuations).
(f) Exhibit E is an Environmental Report. Information provided in the report must be organized and referenced according to the itemized subparagraphs below. See § 4.38 for consultation requirements. The Environmental Report must contain the following information, commensurate with the scope of the proposed project:
(1) General description of the locale. The applicant must provide a general description of the environment of the project and its immediate vicinity. The description must include general information concerning climate, topography, wetlands, vegetative cover, land development, population size and density, the presence of any floodplain and the occurrence of flood events in the vicinity of the project, and any other factors important to an understanding of the setting.
(2) Report on water use and quality. The report must discuss the consumptive use of project waters and the impact of the project on water quality. The report must be prepared in consultation with the state and Federal agencies with responsibility for management of water quality in the affected stream or other body of water. Consultation must be documented by appending to the report a letter from each agency consulted that indicates the nature, extent, and results of the consultation. The report must include:
(i) A description (including specified volume over time) of existing and proposed uses of project waters for irrigation, domestic water supply, steam-electric plant, industrial, and other consumptive purposes;
(ii) A description of existing water quality in the project impoundment and downstream water affected by the project and the applicable water quality standards and stream segment classifications;
(iii) A description of any minimum flow releases specifying the rate of flow in cubic feet per second (cfs) and duration, changes in the design of project works or in project operation, or other measures recommended by the agencies consulted for the purposes of protecting or improving water quality, including measures to minimize the short-term impacts on water quality of any proposed new development of project works (for any dredging or filling, refer to 40 CFR part 230 and 33 CFR 320.3(f) and 323.3(e))
(iv) A statement of the existing measures to be continued and new measures proposed by the applicant for the purpose of protecting or improving water quality, including an explanation of why the applicant has rejected any measures recommended by an agency and described under paragraph (f)(2)(iii) of this section.
(v) A description of the continuing impact on water quality of continued operation of the project and the incremental impact of proposed new development of project works or changes in project operation; and
(3) Report on fish, wildlife, and botanical resources. The report must discuss fish, wildlife, and botanical resources in the vicinity of the project and the impact of the project on those resources. The report must be prepared in consultation with any state agency with responsibility for fish, wildlife, and botanical resources, the U.S. Fish and Wildlife Service, the National Marine Fisheries Service (if the project may affect anadromous fish resources subject to that agency’s jurisdiction), and any other state or Federal agency with managerial authority over any part of the project lands. Consultation must be documented by appending to the report a letter from each agency consulted that indicates the nature, extent, and results of the consultation. The report must include:
(i) A description of the fish, wildlife, and botanical resources of the project and its vicinity, and of downstream areas affected by the project, including identification of any species listed as threatened or endangered by the U.S. Fish and Wildlife Service (See 50 CFR 17.11 and 17.12);
(ii) A description of any measures or facilities recommended by the agencies consulted for the mitigation of impacts on fish, wildlife, and botanical resources, or for the protection or improvement of those resources;
(iii) A statement of any existing measures or facilities to be continued or maintained and any measures or facilities proposed by the applicant for the mitigation of impacts on fish, wildlife, and botanical resources, or for the protection or improvement of such resources, including an explanation of why the applicant has rejected any measures or facilities recommended by an agency and described under paragraph (f)(3)(ii) of this section.
(iv) A description of any anticipated continuing impact on fish, wildlife, and botanical resources of continued operation of the project, and the incremental impact of proposed new development of project works or changes in project operation; and
(v) The following materials and information regarding the measures and facilities identified under paragraph (f)(3)(iii) of this section:
(A) Functional design drawings of any fish passage and collection facilities, indicating whether the facilities depicted are existing or proposed (these drawings must conform to the specifications of § 4.39 regarding dimensions of full-sized prints, scale, and legibility);
(B) A description of operation and maintenance procedures for any existing or proposed measures or facilities;
(C) An implementation or construction schedule for any proposed measures or facilities, showing the intervals following issuance of a license when implementation of the measures or construction of the facilities would be commenced and completed;
(D) An estimate of the costs of construction, operation, and maintenance, of any proposed facilities, and of implementation of any proposed measures, including a statement of the sources and extent of financing; and
(E) A map or drawing that conforms to the size, scale, and legibility requirements of § 4.39 showing by the use of shading, cross-hatching, or other symbols the identity and location of any measures or facilities, and indicating whether each measure or facility is existing or proposed (the map or drawings in this exhibit may be consolidated).
(4) Report on historical and archeological resources. The report must discuss the historical and archeological resources in the project area and the impact of the project on those resources. The report must be prepared in consultation with the State Historic Preservation Officer and the National Park Service. Consultation must be documented by appending to the report a letter from each agency consulted that indicates the nature, extent, and results of the consultation. The report must contain:
(i) Identification of any sites either listed or determined to be eligible for inclusion in the National Register of Historic Places that are located in the project area, or that would be affected by operation of the project or by new development of project facilities (including facilities proposed in this exhibit);
(ii) A description of any measures recommended by the agencies consulted for the purpose of locating, identifying, and salvaging historical or archaeological resources that would be affected by operation of the project, or by new development of project facilities (including facilities proposed in this exhibit), together with a statement of what measures the applicant proposes to implement and an explanation of why the applicant rejects any measures recommended by an agency.
(iii) The following materials and information regarding the survey and salvage activities described under paragraph (f)(4)(ii) of this section:
(A) A schedule for the activities, showing the intervals following issuance of a license when the activities would be commenced and completed; and
(B) An estimate of the costs of the activities, including a statement of the sources and extent of financing.
(5) Report on recreational resources. The report must discuss existing and proposed recreational facilities and opportunities at the project. The report must be prepared in consultation with local, state, and regional recreation agencies and planning commissions, the National Park Service, and any other state or Federal agency with managerial authority over any part of the project lands. Consultation must be documented by appending to the report a letter from each agency consulted indicating the nature, extent, and results of the consultation. The report must contain:
(i) A description of any existing recreational facilities at the project, indicating whether the facilities are available for public use;
(ii) An estimate of existing and potential recreational use of the project area, in daytime and overnight visits;
(iii) A description of any measures or facilities recommended by the agencies consulted for the purpose of creating, preserving, or enhancing recreational opportunities at the project and in its vicinity (including opportunities for the handicapped), and for the purpose of ensuring the safety of the public in its use of project lands and waters;
(iv) A statement of the existing measures or facilities to be continued or maintained and the new measures or facilities proposed by the applicant for the purpose of creating, preserving, or enhancing recreational opportunities at the project and in its vicinity, and for the purpose of ensuring the safety of the public in its use of project lands and waters, including an explanation of why the applicant has rejected any measures or facilities recommended by an agency and described under paragraph (f)(5)(iii) of this section; and
(v) The following materials and information regarding the measures and facilities identified under paragraphs (f)(5) (i) and (iv) of this section:
(A) Identification of the entities responsible for implementing, constructing, operating, or maintaining any existing or proposed measures or facilities;
(B) A schedule showing the intervals following issuance of a license at which implementation of the measures or construction of the facilities would be commenced and completed;
(C) An estimate of the costs of construction, operation, and maintenance of any proposed facilities, including a statement of the sources and extent of financing;
(D) A map or drawing that conforms to the size, scale, and legibility requirements of § 4.39 showing by the use of shading, cross-hatching, or other symbols the identity and location of any facilities, and indicating whether each facility is existing or proposed (the maps or drawings in this exhibit may be consolidated); and
(vi) A description of any areas within or in the vicinity of the proposed project boundary that are included in, or have been designated for study for inclusion in, the National Wild and Scenic Rivers System, or that have been designated as wilderness area, recommended for such designation, or designated as a wilderness study area under the Wilderness Act.
(6) Report on land management and aesthetics. The report must discuss the management of land within the proposed project boundary, including wetlands and floodplains, and the protection of the recreational and scenic values of the project. The report must be prepared following consultation with local and state zoning and land management authorities and any Federal or state agency with managerial authority over any part of the project lands. Consultation must be documented by appending to the report a letter from each agency consulted indicating the nature, extent, and results of the consultation. The report must contain:
(i) A description of existing development and use of project lands and all other lands abutting the project impoundment;
(ii) A description of the measures proposed by the applicant to ensure that any proposed project works, rights-of-way, access roads, and other topographic alterations blend, to the extent possible, with the surrounding environment; (see, e.g., 44 F.P.C. 1496, et seq.);
(iii) A description of wetlands or floodplains within, or adjacent to, the project boundary, any short-term or long-term impacts of the project on those wetlands or floodplains, and any mitigative measures in the construction or operation of the project that minimize any adverse impacts on the wetlands or floodplains;
(iv) A statement, including an analysis of costs and other constraints, of the applicant’s ability to provide a buffer zone around all or any part of the impoundment, for the purpose of ensuring public access to project lands and waters and protecting the recreational and aesthetic values of the impoundment and its shoreline;
(v) A description of the applicant’s policy, if any, with regard to permitting development of piers, docks, boat landings, bulkheads, and other shoreline facilities on project lands and waters; and
(vi) Maps or drawings that conform to the size, scale and legibility requirements of § 4.39, or photographs, sufficient to show the location and nature of the measures proposed under paragraph (f)(6)(ii) of this section (maps or drawings in this exhibit may be consolidated).
(7) List of literature. The report must include a list of all publications, reports, and other literature which were cited or otherwise utilized in the preparation of any part of the environmental report.
(g) Exhibit F. See § 4.41(g) of this chapter.
(h) Exhibit G. See § 4.41(h) of this chapter.
Subpart G—Application for License for Minor Water Power Projects and Major Water Power Projects 10 Megawatts or Less
§ 4.60 Applicability and notice to agencies.
(a) Applicability. The provisions of this subpart apply to any application for an initial license or a new license for:
(1) A minor water power project, as defined in § 4.30(b)(17);
(2) Any major project—existing dam, as defined in § 4.30(b)(16), that has a total installed capacity of 10 MW or less; or
(3) Any major unconstructed project or major modified project, as defined in § 4.30(b)(15) and (14) respectively, that has a total installed capacity of 10 MW or less.
(b) Notice to agencies. The Commission will supply interested Federal, state, and local agencies with notice of any application for license for a water power project 10 MW or less and request comment on the application. Copies of the application will be available for inspection through the Commission’s website, https://www.ferc.gov. The applicant shall also furnish copies of the filed application to any Federal, state, or local agency that so requests.
(c) Unless an applicant for a license for a minor water power project requests in its application that the Commission apply the following provisions of Part I of the Federal Power Act when it issues a minor license for a project, the Commission, unless it determines it would not be in the public interest to do so, will waive:
(1) Section 4(b), insofar as it requires a licensee to file a statement showing the actual legitimate costs of construction of a project;
(2) Section 4(e), insofar as it relates to approval by the Chief of Engineers and the Secretary of the Army of plans affecting navigation;
(3) Section 6, insofar as it relates to the acceptance and expression in the license of terms and conditions of the Federal Power Act that are waived in the licensing order;
(4) Section 10(c), insofar as it relates to a licensee’s maintenance of depreciation reserves;
(5) Sections 10(d) and 10(f);
(6) Section 14, with the exception of the right of the United States or any state or municipality to take over, maintain, and operate a project through condemnation proceedings; and
(7) Sections 15, 16, 19, 20 and 22.
§ 4.61 Contents of application.
(a) General instructions—(1) Entry upon land. No work may be started on any proposed project works until the applicant receives a signed license from the Commission. Acceptance of an application does not authorize entry upon public lands or reservations of the United States for any purpose. The applicant should determine whether any additional Federal, state, or local permits are required.
(2) Exhibits F and G must be submitted on separate drawings. Drawings for Exhibits F and G must have identifying title blocks and bear the following certification: “This drawing is a part of the application for license made by the undersigned this ______________ day of ______________, 19____.”
(3) Each application for a license for a water power project 10 megawatts or less must include the information requested in the initial statement and lettered exhibits described by paragraphs (b) through (f) of this section, and must be provided in the form specified. The Commission reserves the right to require additional information, or another filing procedure, if data provided indicate such action to be appropriate.
(b) Initial statement.
(1) __________ (Name of Applicant) applies to the Federal Energy Regulatory Commission for __________ (license or new license, as appropriate) for the __________ (name of project) water power project, as described hereinafter. (Specify any previous FERC project number designation.)
(2) The location of the project is:
(3) The exact name, address, and telephone number of the applicant are:
(4) The exact name, address, and telephone number of each person authorized to act as agent for the applicant in this application, if applicable, are:
(5) The applicant is a ______ [citizen of the United States, association of citizens of the United States, domestic corporation, municipality, or State, as appropriate] and (is/is not) claiming preference under section 7(a) of the Federal Power Act. See 16 U.S.C. 796.
(6)(i) The statutory or regulatory requirements of the state(s) in which the project would be located that affect the project as proposed with respect to bed and banks and the appropriation, diversion, and use of water for power purposes, and with respect to the right to engage in the business of developing, transmitting, and distributing power and in any other business necessary to accomplish the purposes of the license under the Federal Power Act, are: [provide citation and brief identification of the nature of each requirement; if the applicant is a municipality, the applicant must submit copies of applicable state or local laws or a municipal charter or, if such laws or documents are not clear, any other appropriate legal authority, evidencing that the municipality is competent under such laws to engage in the business of developing, transmitting, utilizing, or distributing power.]
(ii) The steps which the applicant has taken or plans to take to comply with each of the laws cited above are: [provide brief description for each requirement]
(7) Brief project description
(i) Proposed installed generating capacity ______ MW.
(ii) Check appropriate box:
(8) Lands of the United States affected (shown on Exhibit G):
| (Name) | (Acres) | |
|---|---|---|
| (i) National Forest | ||
| (ii) Indian Reservation | ||
| (iii) Public Lands Under Jurisdiction of | ||
| (iv) Other | ||
| (v) Total U.S. Lands |
(vi) Check appropriate box:
(9) Construction of the project is planned to start within ____ months, and is planned to be completed within ____ months, from the date of issuance of license.
(c) Exhibit A is a description of the project and the proposed mode of operation.
(1) The exhibit must include, in tabular form if possible, as appropriate:
(i) The number of generating units, including auxiliary units, the capacity of each unit, and provisions, if any, for future units;
(ii) The type of hydraulic turbine(s);
(iii) A description of how the plant is to be operated, manual or automatic, and whether the plant is to be used for peaking;
(iv) The estimated average annual generation in kilowatt-hours or mechanical energy equivalent;
(v) The estimated average head on the plant;
(vi) The reservoir surface area in acres and, if known, the net and gross storage capacity;
(vii) The estimated minimum and maximum hydraulic capacity of the plant (flow through the plant) in cubic feet per second and estimated average flow of the stream or water body at the plant or point of diversion; for projects with installed capacity of more than 1.5 megawatts, monthly flow duration curves and a description of the drainage area for the project site must be provided;
(viii) Sizes, capacities, and construction materials, as appropriate, of pipelines, ditches, flumes, canals, intake facilities, powerhouses, dams, transmission lines, and other appurtenances; and
(ix) The estimated cost of the project.
(x) The estimated capital costs and estimated annual operation and maintenance expense of each proposed environmental measure.
(2) State the purposes of project (for example, use of power output).
(3) An estimate of the cost to develop the license application; and
(4) The on-peak and off-peak values of project power, and the basis for estimating the values, for projects which are proposed to operate in a mode other than run-of-river.
(5) The estimated average annual increase or decrease in project generation, and the estimated average annual increase or decrease of the value of project power due to a change in project operations (i.e., minimum bypass flows, limiting reservoir fluctuations) for an application for a new license;
(6) The remaining undepreciated net investment, or book value of the project;
(7) The annual operation and maintenance expenses, including insurance, and administrative and general costs;
(8) A detailed single-line electrical diagram;
(9) A statement of measures taken or planned to ensure safe management, operation, and maintenance of the project.
(d) Exhibit E is an Environmental Report.
(1) For major unconstructed and major modified projects 10 MW or less. Any application must contain an Exhibit E conforming with the data and consultation requirements of § 4.41(f), if the application is for license for a water power project which has or is proposed to have a total installed generating capacity greater than 1.5 MW but not greater than 10 MW, and which:
(i) Would use the water power potential of a dam and impoundment which, at the time of application, has not been constructed (see § 4.30(b)(15)); or
(ii) Involves any repair, modification or reconstruction of an existing dam that would result in a significant change in the normal maximum surface area or elevation of an existing impoundment or involves any change in existing project works or operations that would result in a significant environmental impact (see § 4.30(b)(14)).
(2) For minor projects and major projects at existing dams 10 MW or less. An application for license for either a minor water power project with a total proposed installed generating capacity of 1.5 MW or less or a major project—existing dam with a proposed total installed capacity of 10 MW or less must contain an Exhibit E under this paragraph (d)(2). See § 4.38 for consultation requirements. The Environmental Report must contain the following information:
(i) A description, including any maps or photographs which the applicant considers appropriate, of the environmental setting of the project, including vegetative cover, fish and wildlife resources, water quality and quantity, land and water uses, recreational uses, historical and archeological resources, and scenic and aesthetic resources. The report must include a discussion of endangered or threatened plant and animal species, any critical habitats, and any sites included in, or eligible for inclusion in, the National Register of Historic Places. The applicant may obtain assistance in the preparation of this information from state natural resources agencies, the state historic preservation officer, and from local offices of Federal natural resources agencies.
(ii) A description of the expected environmental impacts from proposed construction or development and the proposed operation of the power project, including any impacts from any proposed changes in the capacity and mode of operation of the project if it is already generating electric power, and an explanation of the specific measures proposed by the applicant, the agencies, and others to protect and enhance environmental resources and values and to mitigate adverse impacts of the project on such resources. The applicant must explain its reasons for not undertaking any measures proposed by any agency consulted.
(iii) A description of the steps taken by the applicant in consulting with Federal, state, and local agencies with expertise in environmental matters during the preparation of this exhibit prior to filing the application for license with the Commission. In this report, the applicant must:
(A) Indicate which agencies were consulted during the preparation of the environmental report and provide copies of letters or other documentation showing that the applicant consulted or attempted to consult with each of the relevant agencies (specifying each agency) before filing the application, including any terms or conditions of license that those agencies have determined are appropriate to prevent loss of, or damage to, natural resources; and
(B) List those agencies that were provided copies of the application as filed with the Commission, the date or dates provided, and copies of any letters that may be received from agencies commenting on the application.
(iv) Any additional information the applicant considers important.
(e) Exhibit F. See § 4.41(g) of this chapter.
(f) Exhibit G. See § 4.41(h) of this chapter.
Subpart H—Application for License for Transmission Line Only
§ 4.70 Applicability.
This subpart applies to any application for license issued solely for a transmission line that transmits power from a licensed water power project to the point of junction with the distribution system or with the interconnected primary transmission system.
§ 4.71 Contents of application.
An application for license for transmission line only must contain the following information in the form specified.
(a) Initial statement.
(1) [Name of applicant] applies to the Federal Energy Regulatory Commission for a [license or new license, as appropriate] for the [name of project] transmission line only, as described in the attached exhibits, that is connected with FERC Project No. ______, for which a license [was issued, or application was made, as appropriate] on the ______________ day of ______________, 19____.
(2) The location of the transmission line would be:
(3) The proposed use or market for the power to be transmitted.
(4) The exact name, business address, and telephone number of the applicant are:
(5) The applicant is a [citizen of the United States, association of citizens of the United States, domestic corporation, municipality, or State, as appropriate] and (is/is not) claiming preference under section 7(a) of the Federal Power Act. See 16 U.S.C. 796.
(6)(i) [For any applicant which, at the time of application for license for transmission line only, is a non-licensee.] The statutory or regulatory requirements of the state(s) in which the project would be located and that affect the project as proposed with respect to bed and banks and to the appropriation, diversion, and use of water for power purposes, and with respect to the right to engage in the business of developing, transmitting, and distributing power and in any other business necessary to accomplish the purposes of the license under the Federal Power Act, are: [provide citation and brief identification of the nature of each requirement; if the applicant is a municipality, the applicant must submit copies of applicable state or local laws or a municipal charter or, if such laws or documents are not clear, other appropriate legal authority, evidencing that the municipality is competent under such laws to engage in the business of developing, transmitting, utilizing, or distributing power.]
(ii) [For any applicant which, at the time of application for license for transmission line only, is a licensee.] The statutory or regulatory requirements of the state(s) in which the transmission line would be located and that affect the project as proposed with respect to bed and banks and to the appropriation, diversion, and use of water for power purposes, are: [provide citations and brief identification of the nature of each requirement.]
(iii) The steps which the applicant has taken or plans to take to comply with each of the laws cited above are: [provide brief descriptions for each law.]
(b) Required exhibits. The application must contain the following exhibits, as appropriate:
(1) For any transmission line that, at the time the application is filed, is not constructed and is proposed to be connected to a licensed water power project with an installed generating capacity of more than 10 MW—Exhibits A, B, C, D, E, F, and G under § 4.41;
(2) For any transmission line that, at the time the application is filed, is not constructed and is proposed to be connected to a licensed water power project with an installed generating capacity of 10 MW or less—Exhibits E, F, and G under § 4.61; and
(3) For any transmission line that, at the time the application is filed, has been constructed and is proposed to be connected to any licensed water power project—Exhibits E, F, and G under § 4.61 of this chapter.
Subpart I—Application for Preliminary Permit; Amendment and Cancellation of Preliminary Permit
§ 4.80 Applicability.
Sections 4.80 through 4.83 pertain to preliminary permits under Part I of the Federal Power Act. The sole purpose of a preliminary permit is to secure priority of application for a license for a water power project under Part I of the Federal Power Act while the permittee obtains the data and performs the acts required to determine the feasibility of the project and to support an application for a license.
§ 4.81 Contents of application.
Each application for a preliminary permit must include the following initial statement and numbered exhibits containing the information and documents specified:
(a) Initial statement:
(1) [Name of applicant] applies to the Federal Energy Regulatory Commission for a preliminary permit for the proposed [name of project] water power project, as described in the attached exhibits. This application is made in order that the applicant may secure and maintain priority of application for a license for the project under Part I of the Federal Power Act while obtaining the data and performing the acts required to determine the feasibility of the project and to support an application for a license.
(2) The location of the proposed project is:
(3) The exact name, business address, and telephone number of the applicant are:
The exact name and business address of each person authorized to act as agent for the applicant in this application are:
(4) [Name of applicant] is a [citizen, association, citizens, domestic corporation, municipality, or State, as appropriate] and (is/is not) claiming preference under section 7(a) of the Federal Power Act. [If the applicant is a municipality, the applicant must submit copies of applicable state or local laws or a municipal charter or, if such laws or documents are not clear, any other appropriate legal authority, evidencing that the municipality is competent under such laws to engage in the business of development, transmitting, utilizing, or distributing power].
(5) The proposed term of the requested permit is [period not to exceed 48 months].
(6) If there is any existing dam or other project facility, the applicant must provide the name and address of the owner of the dam and facility. If the dam is federally owned or operated, provide the name of the agency.
(b) Exhibit 1 must contain a description of the proposed project, specifying and including, to the extent possible:
(1) The number, physical composition, dimensions, general configuration and, where applicable, age and condition, of any dams, spillways, penstocks, powerhouses, tailraces, or other structures, whether existing or proposed, that would be part of the project;
(2) The estimated number, surface area, storage capacity, and normal maximum surface elevation (mean sea level) of any reservoirs, whether existing or proposed, that would be part of the project;
(3) The estimated number, length, voltage, interconnections, and, where applicable, age and condition, of any primary transmission lines whether existing or proposed, that would be part of the project [see 16 U.S.C. 796(11)];
(4) The total estimated average annual energy production and installed capacity (provide only one energy and capacity value), the hydraulic head for estimating capacity and energy output, and the estimated number, rated capacity, and, where applicable, the age and condition, of any turbines and generators, whether existing or proposed, that would be part of the project works;
(5) All lands of the United States that are enclosed within the proposed project boundary described under paragraph (d)(3)(i) of this section, identified and tabulated on a separate sheet by legal subdivisions of a public land survey of the affected area, if available. If the project boundary includes lands of the United States, such lands must be identified on a completed land description form (FERC Form 587), provided by the Commission. The project location must identify any Federal reservation, Federal tracts, and townships of the public land surveys (or official protractions thereof if unsurveyed). A copy of the form must also be sent to the Bureau of Land Management state office where the project is located;
(6) Any other information demonstrating in what manner the proposed project would develop, conserve, and utilize in the public interest the water resources of the region.
(c) Exhibit 2 is a description of studies conducted or to be conducted with respect to the proposed project, including field studies. Exhibit 2 must supply the following information:
(1) General requirement. For any proposed project, a study plan containing a description of:
(i) Any studies, investigations, tests, or surveys that are proposed to be carried out, and any that have already taken place, for the purposes of determining the technical, economic, and financial feasibility of the proposed project, taking into consideration its environmental impacts, and of preparing an application for a license for the project; and
(ii) The approximate locations and nature of any new roads that would be built for the purpose of conducting the studies; and
(2) Work plan for new dam construction. For any development within the project that would entail new dam construction, a work plan and schedule containing:
(i) A description, including the approximate location, of any field study, test, or other activity that may alter or disturb lands or waters in the vicinity of the proposed project, including floodplains and wetlands; measures that would be taken to minimize any such disturbance; and measures that would be taken to restore the altered or disturbed areas; and
(ii) A proposed schedule (a chart or graph may be used), the total duration of which does not exceed the proposed term of the permit, showing the intervals at which the studies, investigations, tests, and surveys, identified under this paragraph are proposed to be completed.
(iii) For purposes of this paragraph, new dam construction means any dam construction the studies for which would require test pits, borings, or other foundation exploration in the field.
(3) Waiver. The Commission may waive the requirements of paragraph (c)(2) pursuant to § 385.207 of this chapter, upon a showing by the applicant that the field studies, tests, and other activities to be conducted under the permit would not adversely affect cultural resources or endangered species and would cause only minor alterations or disturbances of lands and waters, and that any land altered or disturbed would be adequately restored.
(4) Exhibit 2 must contain a statement of costs and financing, specifying and including, to the extent possible:
(i) The estimated costs of carrying out or preparing the studies, investigations, tests, surveys, maps, plans or specifications identified under paragraph (c) of this section;
(ii) The expected sources and extent of financing available to the applicant to carry out or prepare the studies, investigations, tests, surveys, maps, plans, or specifications identified under paragraph (c) of this section; and
(d) Exhibit 3 must include a map or series of maps, to be prepared on United States Geological Survey topographic quadrangle sheets or similar topographic maps of a State agency, if available. The maps need not conform to the precise specifications of § 4.39 (a) and (b). If the scale of any base map is not sufficient to show clearly and legibly all of the information required by this paragraph, the maps submitted must be enlarged to a scale that is adequate for that purpose. (If Exhibit 3 comprises a series of maps, it must also include an index sheet showing, by outline, the parts of the entire project covered by each map of the series.) The maps must show:
(1) The location of the project as a whole with reference to the affected stream or other body of water and, if possible, to a nearby town or any permanent monuments or objects that can be noted on the maps and recognized in the field;
(2) The relative locations and physical interrelationships of the principal project features identified under paragraph (b) of this section;
(3) A proposed boundary for the project, enclosing:
(i) All principal project features identified under paragraph (b) of this section, including but not limited to any dam, reservoir, water conveyance facilities, powerplant, transmission lines, and other appurtenances; if the project is located at an existing Federal dam, the Federal dam and impoundment must be shown, but may not be included within the project boundary;
(ii) Any non-Federal lands and any public lands or reservations of the United States [see 16 U.S.C. 796 (1) and (2)] necessary for the purposes of the project. To the extent that those public lands or reservations are covered by a public land survey, the project boundary must enclose each of and only the smallest legal subdivisions (quarter-quarter section, lots, or other subdivisions, identified on the map by subdivision) that may be occupied in whole or in part by the project.
(4) Areas within or in the vicinity of the proposed project boundary which are included in or have been designated for study for inclusion in the National Wild and Scenic Rivers System; and
(5) Areas within the project boundary that, under the provisions of the Wilderness Act, have been:
(i) Designated as wilderness area;
(ii) Recommended for designation as wilderness area; or
(iii) Designated as wilderness study area.
§ 4.82 Amendments.
(a) Any permittee may file an application for amendment of its permit, including any extension of the term of the permit that would not cause the total term to exceed eight years. (Transfer of a permit is prohibited by section 5 of the Federal Power Act.) Each application for amendment of a permit must conform to any relevant requirements of § 4.81 (b), (c), and (d).
(b) If an application for amendment of a preliminary permit requests any material change in the proposed project, public notice of the application will be issued as required in § 4.32(d)(2)(i).
(c) If an application to extend the term of a permit is submitted not less than 30 days prior to the termination of the permit, the permit term will be automatically extended (not to exceed a total term for the permit of eight years) until the Commission acts on the application for an extension. The Commission will not accept extension requests that are filed less than 30 days prior to the termination of the permit.
(d) At the end of the extension period granted under paragraph (a) of this section, the Commission may issue an additional permit to the permittee if the Commission determines that there are extraordinary circumstances that warrant the issuance of the additional permit.
§ 4.83 Cancellation and loss of priority.
(a) The Commission may cancel a preliminary permit after notice and opportunity for hearing if the permittee fails to comply with the specific terms and conditions of the permit. The Commission may also cancel a permit for other good cause shown after notice and opportunity for hearing. Cancellation of a permit will result in loss of the permittee’s priority of application for a license for the proposed project.
(b) Failure of a permittee to file an acceptable application for a license before the permit expires will result in loss of the permittee’s priority of application for a license for the proposed project.
§ 4.84 Surrender of permit.
A permittee must submit a petition to the Commission before the permittee may voluntarily surrender its permit. Unless the Commission issues an order to the contrary, the permit will remain in effect through the thirtieth day after the Commission issues a public notice of receipt of the petition.
Subpart J—Exemption of Small Conduit Hydroelectric Facilities
§ 4.90 Applicability and purpose.
This subpart implements section 30(b) of the Federal Power Act and provides procedures for obtaining an exemption for constructed or unconstructed small conduit hydroelectric facilities, as defined in § 4.30(b)(30), from all or part of the requirements of Part I of the Federal Power Act, including licensing, and the regulations issued under Part I.
§ 4.91 [Reserved]
§ 4.92 Contents of exemption application.
(a) An application for exemption for this subpart must include:
(1) An introductory statement, including a declaration that the facility for which application is made meets the requirements of § 4.30(b)(30), or if the facility qualifies but for the discharge requirement of § 4.30(b)(30)(iv), the introductory statement must identify that fact and state that the application is accompanied by a petition for waiver of § 4.30(b)(30)(iv) filed pursuant to § 385.207 of this chapter;
(2) Exhibits A, E, F, and G.
(3) If the project structures would use or occupy any lands other than federal lands, an appendix containing documentary evidence showing that the applicant has the real property interests required under § 4.31(b); and
(4) Identification of all Indian tribes that may be affected by the project.
(b) Introductory Statement. The introductory statement must be set forth in the following format:
[Name of applicant] applies to the Federal Energy Regulatory Commission for an exemption for the [name of facility], a small conduit hydroelectric facility that meets the requirements of [insert the following language, as appropriate: “§ 4.30(b)(30) of this subpart” or “§ 4.30(b)(30) of this subpart, except paragraph (b)(30)(iv)”], from certain provisions of Part I of the Federal Power Act.
[Name of applicant] is [a citizen of the United States, an association of citizens of the United States, a municipality, State, or a corporation incorporated under the laws of (specify the United States or the state of incorporation, as appropriate)].
The provisions of Part I of the Federal Power Act for which exemption is requested are:
[List here all sections or subsections for which exemption is requested.]
[If the facility does not meet the requirement of § 4.30(b)(30)(iv), add the following sentence: “This application is accompanied by a petition for waiver of § 4.30(b)(30)(iv), submitted pursuant to 18 CFR 385.207.”]
(c) Exhibit A. Exhibit A must describe the small conduit hydroelectric facility and proposed mode of operation with appropriate references to Exhibits F and G. To the extent feasible the information in this exhibit may be submitted in tabular form. The following information must be included:
(1) A brief description of any conduits and associated consumptive water supply facilities, intake facilities, powerhouses, and any other structures associated with the facility.
(2) The proximate natural sources of water that supply the related conduit.
(3) The purposes for which the conduit is used.
(4) The number of generating units, including auxiliary units, the capacity of each unit, and provisions, if any, for future units.
(5) The type of each hydraulic turbine.
(6) A description of how the plant is to be operated, manually or automatically, and whether the plant is to be used for peaking.
(7) Estimations of:
(i) The average annual generation in kilowatt hours;
(ii) The average head of the plant;
(iii) The hydraulic capacity of the plant (flow through the plant) in cubic feet per second;
(iv) The average flow of the conduit at the plant or point of diversion (using best available data and explaining the sources of the data and the method of calculation); and
(v) The average amount of the flow described in paragraph (c)(7)(iv) of this section available for power generation.
(8) The planned date for beginning construction of the facility.
(9) If the hydroelectric facility discharges directly into a natural body of water and a petition for waiver of § 4.30(b)(30)(iv) has not been submitted, evidence that a quantity of water equal to or greater than the quantity discharged from the hydroelectric facility is withdrawn from that water body downstream into a conduit that is part of the same water supply system as the conduit on which the hydroelectric facility is located.
(10) If the hydroelectric facility discharges directly to a point of agricultural, municipal, or industrial consumption, a description of the nature and location of that point of consumption.
(11) A description of the nature and extent of any construction of a dam that would occur in association with construction of the proposed small conduit hydroelectric facility, including a statement of the normal maximum surface area and normal maximum surface elevation of any existing impoundment before and after that construction; and any evidence that the construction of the dam would occur for agricultural, municipal, or industrial consumptive purposes even if hydroelectric generating facilities were not installed.
(d) Exhibit G. Exhibit G is a map of the project and boundary and must conform to the specifications of § 4.41(h) of this chapter.
(e) Exhibit E. This exhibit is an Environmental Report. It must be prepared pursuant to § 4.38 and must include the following information, commensurate with the scope and environmental impact of the facility’s construction and operation:
(1) A description of the environmental setting in the vicinity of the facility, including vegetative cover, fish and wildlife resources, water quality and quantity, land and water uses, recreational use, socio-economic conditions, historical and archeological resources, and visual resources. The report must give special attention to endangered or threatened plant and animal species, critical habitats, and sites eligible for or included on the National Register of Historic Places. The applicant may obtain assistance in the preparation of this information from State natural resources agencies, the State historic preservation officer, and from local offices of Federal natural resources agencies.
(2) A description of the expected environmental impacts resulting from the continued operation of an existing small conduit hydroelectric facility, or from the construction and operation of a proposed small conduit hydroelectric facility, including a discussion of the specific measures proposed by the applicant and others to protect and enhance environmental resources and to mitigate adverse impacts of the facility on them.
(3) A description of alternative means of obtaining an amount of power equivalent to that provided by the proposed or existing facility.
(4) Any additional information the applicant considers important.
(f) Exhibit F. Exhibit F is a set of drawings showing the structures and equipment of the small conduit hydroelectric facility and must conform to the specifications of § 4.41(g) of this chapter.
§ 4.93 Action on exemption applications.
(a) An application for exemption that does not meet the eligibility requirements of § 4.30(b)(30)(iv) may be accepted, provided the application has been accompanied by a request for waiver under § 4.92(a)(1) and the waiver request has not been denied. Acceptance of an application that has been accompanied by a request for waiver under § 4.92(a)(1) does not constitute a ruling on the waiver request, unless expressly stated in the acceptance.
(b) The Commission will circulate a notice of application for exemption to interested agencies and Indian tribes at the time the applicant is notified that the application is accepted for filing.
(c) In granting an exemption the Commission may prescribe terms or conditions in addition to those set forth in § 4.94, in order to:
(1) Protect the quality or quantity of the related water supply for agricultural, municipal, or industrial consumption;
(2) Otherwise protect life, health, or property;
(3) Avoid or mitigate adverse environmental impact; or
(4) Conserve, develop, or utilize in the public interest the water power resources of the region.
(d) Conversion to license application. (1) If an application for exemption under this subpart is denied by the Commission, the applicant may convert the exemption application into an application for license for the hydroelectric project.
(2) The applicant must provide the Commission with written notification, within 30 days after the date of issuance of the order denying exemption, that it intends to convert the exemption application into a license application. The applicant must submit to the Commission, no later than 90 days after the date of issuance of the order denying exemption, additional information that is necessary to conform the exemption application to the relevant regulations for a license application.
(3) If all the information timely submitted is found sufficient, together with the application for exemption, to conform to the relevant regulations for a license application, the converted application will be considered accepted for filing as of the date that the exemption application was accepted for filing.
§ 4.94 Standard terms and conditions of exemption.
Any exemption granted under § 4.93 for a small conduit hydroelectric facility is subject to the following standard terms and conditions:
(a) Article 1. The Commission reserves the right to conduct investigations under sections 4(g), 306, 307, and 311 of the Federal Power Act with respect to any acts, complaints, facts, conditions, practices, or other matters related to the construction, operation, or maintenance of the exempt facility. If any term or condition of the exemption is violated, the Commission may revoke the exemption, issue a suitable order under section 4(g) of the Federal Power Act, or take appropriate action for enforcement, forfeiture, or penalties under Part III of the Federal Power Act.
(b) Article 2. The construction, operation, and maintenance of the exempt project must comply with any terms and conditions that the United States Fish and Wildlife Service, the National Marine Fisheries Service, and any state fish and wildlife agencies have determined are appropriate to prevent loss of, or damage to, fish or wildlife resources or otherwise to carry out the purposes of the Fish and Wildlife Coordination Act, as specified in exhibit E of the application for exemption from licensing or in the comments submitted in response to the notice of exemption application.
(c) Article 3. The Commission may revoke this exemption if actual construction of any proposed generating facilities has not begun within two years or has not been completed within four years from the effective date of this exemption. If an exemption is revoked under this article, the Commission will not accept from the prior exemption holder a subsequent application for exemption from licensing or a notice of exemption from licensing for the same project within two years of the revocation.
(d) Article 4. This exemption does not confer any right to use or occupy any federal lands that may be necessary for the development or operation of the project. Any right to use or occupy any federal lands for those purposes must be obtained from the administering federal land agencies. The Commission may accept a license application submitted by any qualified license applicant and revoke this exemption, if any necessary right to use or occupy federal lands for those purposes has not been obtained within one year from the date on which this exemption was granted.
(e) Article 5. In order to best develop, conserve, and utilize in the public interest the water resources of the region, the Commission may require that the exempt facilities be modified in structure or operation or may revoke this exemption.
(f) Article 6. The Commission may revoke this exemption if, in the application process, material discrepancies, inaccuracies, or falsehoods were made by or on behalf of the applicant.
(g) Article 7. Before transferring any property interests in the exempt project, the exemption holder must inform the transferee of the terms and conditions of the exemption. Within 30 days of transferring the property interests, the exemption holder must inform the Commission of the identity and address of the transferee.
§ 4.95 Surrender of exemption.
(a) To voluntarily surrender its exemption, a holder of an exemption for a small conduit hydroelectric facility must file a petition with the Commission.
(b)(1) If construction has begun, prior to filing a petition with the Commission, the exemption holder must consult with the fish and wildlife agencies in accordance with § 4.38, substituting for the information required under § 4.38(b)(1) information appropriate to the disposition and restoration of the project works and lands. The petition must set forth the exemption holder’s plans with respect to disposition and restoration of the project works and lands.
(2) If construction has begun, public notice of the petition will be given, and, at least 30 days thereafter, the Commission will act upon the petition.
(c) If no construction has begun, unless the Commission issues an order to the contrary, the exemption will remain in effect through the thirtieth day after the Commission issues a public notice of receipt of the petition. New applications involving the site of the surrendered exemption may be filed on the next business day.
(d) Exemptions may be surrendered only upon fulfillment by the exemption holder of such obligations under the exemption as the Commission may prescribe and, if construction has begun, upon such conditions with respect to the disposition of such project works and restoration of project lands as may be determined by the Commission and the Federal and state fish and wildlife agencies.
(e) Where occupancy of federal lands or reservations has been permitted by a federal agency having supervision over such lands, the exemption holder must concurrently notify that agency of the petition to surrender and of the steps that will be taken to restore the affected federal lands or reservations.
§ 4.96 Amendment of exemption.
(a) An exemption holder must construct and operate its project as described in the exemption application approved by the Commission or its delegate.
(b) If an exemption holder desires to change the design, location, method of construction or operation of its project, it must first notify the appropriate Federal and state fish and wildlife agencies and inform them in writing of the changes it intends to implement. If these agencies determine that the changes would not cause the project to violate the terms and conditions imposed by the agencies, and if the changes would not materially alter the design, location, method of construction or operation of the project, the exemption holder may implement the changes. If any of these agencies determines that the changes would cause the project to violate the terms and conditions imposed by the agencies, or if the changes would materially alter the design, location, method of construction or the operation of the project works, the exemption holder may not implement the changes without first acquiring authorization from the Commission to amend its exemption, or acquiring a license that authorizes the project, as changed.
(c) An application to amend an exemption may be filed only by the holder of the exemption. An application to amend an exemption will be governed by the Commission’s regulations governing applications for exemption. The Commission will not accept applications in competition with an application to amend an exemption, unless the Director of the Office of Energy Projects determines that it is in the public interest to do so.
Subpart K—Exemption of Small Hydroelectric Power Projects of 10 Megawatts or Less
§ 4.101 Applicability.
This subpart provides procedures for exemption on a case-specific basis from all or part of Part I of the Federal Power Act (Act), including licensing, for small hydroelectric power projects as defined in § 4.30(b)(31).
§ 4.102 Surrender of exemption.
(a) To voluntarily surrender its exemption, a holder of an exemption for a small hydroelectric power project must file a petition with the Commission.
(b)(1) If construction has begun, prior to filing a petition with the Commission, the exemption holder must consult with the fish and wildlife agencies in accordance with § 4.38, substituting for the information required under § 4.38(b)(1) information appropriate to the disposition and restoration of the project works and lands. The petition must set forth the exemption holder’s plans with respect to disposition and restoration of the project works and lands.
(2) If construction has begun, public notice of the petition will be given, and, at least 30 days thereafter, the Commission will act upon the petition. New applications involving the site may be filed on the next business day.
(c) If no construction had begun, unless the Commission issues an order to the contrary, the surrender will take effect at the close of the thirtieth day after the Commission issues a public notice of receipt of the petition. New applications involving the site may be filed on the next business day.
(d) Exemptions may be surrendered only upon fulfillment by the exemption holder of such obligations under the exemption as the Commission may prescribe and, if construction has begun, upon such conditions with respect to the disposition of such project works and restoration of project lands as may be determined by the Commission and the Federal and state fish and wildlife agencies.
(e) Where occupancy of federal lands or reservations has been permitted by a Federal agency having supervision over such lands, the exemption holder must concurrently notify that agency of the petition to surrender and of the steps that will be taken to restore the affected U.S. lands or reservations.
§ 4.103 General provisions for case-specific exemption.
(a) Exemptible projects. Subject to the provisions in paragraph (b) of this section, § 4.31(c), and §§ 4.105 and 4.106, the Commission may exempt on a case-specific basis any small hydroelectric power project from all or part of Part I of the Act, including licensing requirements. Any applications for exemption for a project shall conform to the requirements of §§ 4.107 or 4.108, as applicable.
(b) Limitation for licensed water power project. The Commission will not accept for filing an application for exemption from licensing for any project that is only part of a licensed water power project.
(c) Waiver. In applying for case-specific exemption from licensing, a qualified exemption applicant may petition under § 385.207 of this chapter for waiver of any specific provision of §§ 4.102 through 4.107. The Commission will grant a waiver only if consistent with section 408 of the Energy Security Act of 1980.
§ 4.104 Amendment of exemption.
(a) An exemption holder must construct and operate its project as described in the exemption application approved by the Commission or its delegate.
(b) If an exemption holder desires to change the design, location, method of construction or operation of its project, it must first notify the appropriate Federal and state fish and wildlife agencies and inform them in writing of the changes it intends to implement. If these agencies determine that the changes would not cause the project to violate the terms and conditions imposed by the agencies, and if the changes would not materially alter the design, location, method of construction or operation of the project, the exemption holder may implement the changes. If any of these agencies determines that the changes would cause the project to violate the terms and conditions imposed by that agency, or if the changes would materially alter the design, location, method of construction or the operation of the project works, the exemption holder may not implement the changes without first acquiring authorization from the Commission to amend its exemption or acquiring a license for the project works that authorizes the project, as changed.
(c) An application to amend an exemption may be filed only by the holder of an exemption. An application to amend an exemption will be governed by the Commission’s regulations governing applications for exemption. The Commission will not accept applications in competition with an application to amend an exemption, unless the Director of the Office of Energy Projects determines that it is in the public interest to do so.
§ 4.105 Action on exemption applications.
(a) Exemption from provisions other than licensing. An application for exemption of a small hydroelectric power project from provisions of Part I of the Act other than the licensing requirement will be processed and considered as part of the related application for license or amendment of license.
(b)(1) Consultation. The Commission will circulate a notice of application for exemption from licensing to interested agencies and Indian tribes at the time the applicant is notified that the application is accepted for filing.
(2) Non-standard terms and conditions. In approving any application for exemption from licensing, the Commission may prescribe terms or conditions in addition to those set forth in § 4.106 in order to:
(i) Protect the quality or quantity of the related water supply;
(ii) Otherwise protect life, health, or property;
(iii) Avoid or mitigate adverse environmental impact; or
(iv) Better conserve, develop, or utilize in the public interest the water resources of the region.
§ 4.106 Standard terms and conditions of case-specific exemption from licensing.
Any case-specific exemption from licensing granted for a small hydroelectric power project is subject to the following standard terms and conditions:
(a) Article 1. The Commission reserves the right to conduct investigations under sections 4(g), 306, 307, and 311 of the Federal Power Act with respect to any acts, complaints, facts, conditions, practices, or other matters related to the construction, operation, or maintenance of the exempt project. If any term or condition of the exemption is violated, the Commission may revoke the exemption, issue a suitable order under section 4(g) of the Federal Power Act, or take appropriate action for enforcement, forfeiture, or penalties under Part III of the Federal Power Act.
(b) Article 2. The construction, operation, and maintenance of the exempt project must comply with any terms and conditions that the United States Fish and Wildlife Service, the National Marine Fisheries Service, and any state fish and wildlife agencies have determined are appropriate to prevent loss of, or damage to, fish or wildlife resources or otherwise to carry out the purposes of the Fish and Wildlife Coordination Act, as specified in exhibit E of the application for exemption from licensing or in the comments submitted in response to the notice of exemption application.
(c) Article 3. The Commission may revoke this exemption if actual construction of any proposed generating facilities has not begun within two years or has not been completed within four years from the date on which this exemption was granted. If an exemption is revoked under this article, the Commission will not accept from the prior exemption holder a subsequent application for exemption from licensing for the same project within two years of the revocation.
(d) Article 4. This exemption is subject to the navigation servitude of the United States if the project is located on navigable waters of the United States.
(e) Article 5. This exemption does not confer any right to use or occupy any Federal lands that may be necessary for the development or operation of the project. Any right to use or occupy any Federal lands for those purposes must be obtained from the administering Federal land agencies. The Commission may accept a license application submitted by any qualified license applicant and revoke this exemption, if any necessary right to use or occupy Federal lands for those purposes has not been obtained within one year from the date on which this exemption was granted.
(f) Article 6. In order to best develop, conserve, and utilize in the public interest the water resources of the region, the Commission may require that the exempt facilities be modified in structure or operation or may revoke this exemption.
(g) Article 7. The Commission may revoke this exemption if, in the application process, material discrepancies, inaccuracies, or falsehoods were made by or on behalf of the applicant.
(h) Article 8. Any exempted small hydroelectric power project that utilizes a dam that is more than 33 feet in height above streambed, as defined in 18 CFR 12.31(c) of this chapter, impounds more than 2,000 acre-feet of water, or has a significant or high hazard potential, as defined in 33 CFR part 222, is subject to part 12 of the Commission’s regulations, part 12 of this title (as they may be amended from time to time).
(i) Article 9. Before transferring any property interests in the exempt project, the exemption holder must inform the transferee of the terms and conditions of the exemption. Within 30 days of transferring the property interests, the exemption holder must inform the Commission of the identity and address of the transferee.
§ 4.107 Contents of application for exemption from licensing.
(a) General requirements. An application for exemption from licensing submitted under this subpart must contain the introductory statement, the exhibits described in this section, and, if the project structures would use or occupy any lands other than Federal lands, an appendix containing documentary evidence showing that applicant has the real property interests required under § 4.31(c)(2)(ii). The applicant must identify in its application all Indian tribes that may be affected by the project.
(b) Introductory statement. The application must include an introductory statement that conforms to the following format:
(1) [Name of applicant] applies to the Federal Energy Regulatory Commission for an exemption for [name of project], a small hydroelectric power project that is proposed to have an installed capacity of 10 megawatts or less, from licensing under the Federal Power Act. [If applicable: The project is currently licensed as FERC Project No. ________.]
(2) The location of the project is:
(3) The exact name and business address of each applicant are:
(4) The exact name and business address of each person authorized to act as agent for the applicant in this application are:
(5) [Name of applicant] is [specify, as appropriate: a citizen of the United States or other identified nation; an association of citizens of the United States or other identified nation; a municipality; a state; or a corporation incorporated under the laws of (specify the United States or the state or nation of incorporation, as appropriate).]
(c) Exhibit A. Exhibit A must describe the small hydroelectric power project and its proposed mode of operation. To the extent feasible, the information in this exhibit may be submitted in tabular form. The applicant must submit the following information:
(1) A brief description of any existing dam and impoundment proposed to be utilized by the small hydroelectric power project and any other existing or proposed project works and appurtenant facilities, including intake facilities, diversion structures, powerhouses, primary transmission lines, penstocks, pipelines, spillways, and other structures, and the sizes, capacities, and construction materials of those structures.
(2) The number of existing and proposed generating units at the project, including auxiliary units, the capacity of each unit, any provisions for future units, and a brief description of any plans for retirement or rehabilitation of existing generating units.
(3) The type of each hydraulic turbine of the small hydroelectric power project.
(4) A description of how the power plant is to be operated, that is, run-of-river or peaking.
(5) A graph showing a flow duration curve for the project. Identify stream gauge(s) and period of record used. If a synthetic record is utilized, provide details concerning its derivation. Furnish justification for selection of installed capacity if the hydraulic capacity of proposed generating unit(s) plus the minimum flow requirements, if not usable for power production, is less than the stream flow that is exceeded 25 percent of the time.
(6) Estimations of:
(i) The average annual generation in kilowatt-hours;
(ii) The average and design head of the power plant;
(iii) The hydraulic capacity of each turbine of the power plant (flow through the plant) in cubic feet per second;
(iv) The number of surface acres of the man-made or natural impoundment used, if any, at its normal maximum surface elevation and its net and gross storage capacities in acre-feet.
(7) The planned date for beginning and completing the proposed construction or development of generating facilities.
(8) A description of the nature and extent of any repair, reconstruction, or other modification of a dam that would occur in association with construction or development of the proposed small hydroelectric power project, including a statement of the normal maximum surface area and normal maximum surface elevation of any existing impoundment before and after construction.
(d) Exhibit G. Exhibit G is a map of the project and boundary and must conform to the specifications of § 4.41(h) of this chapter.
(e) Exhibit E. This exhibit is an environmental report that must include the following information, commensurate with the scope and environmental impact of the construction and operation of the small hydroelectric power project. See § 4.38 for consultation requirements.
(1) A description of the environmental setting of the project, including vegetative cover, fish and wildlife resources, water quality and quantity, land and water uses, recreational uses, historical and archeological resources, and scenic and aesthetic resources. The report must list any endangered or threatened plant and animal species, any critical habitats, and any sites eligible for or included on the National Register of Historic Places. The applicant may obtain assistance in the preparation of this information from state natural resources agencies, the state historic preservation officer, and from local offices of Federal natural resources agencies.
(2) A description of the expected environmental impacts from the proposed construction or development and the proposed operation of the small hydroelectric power project, including any impacts from any proposed changes in the capacity and mode of operation of the project if it is already generating electric power, and an explanation of the specific measures proposed by the applicant, the agencies consulted, and others to protect and enhance environmental resources and values and to mitigate adverse impacts of the project on such resources.
(3) Any additional information the applicant considers important.
(f) Exhibit F. Exhibit F is a set of drawings showing the structures and equipment of the small hydroelectric facility and must conform to the specifications of § 4.41(g) of this chapter.
§ 4.108 Contents of application for exemption from provisions other than licensing.
An application for exemption of a small hydroelectric power project from provisions of Part I of the Act other than the licensing requirement need not be prepared according to any specific format, but must be included as an identified appendix to the related application for license or amendment of license. The application for exemption must list all sections or subsections of Part I of the Act for which exemption is requested.
Subpart L—Application for Amendment of License
§ 4.200 Applicability.
This part applies to any application for amendment of a license, if the applicant seeks to:
(a) Make a change in the physical features of the project or its boundary, or make an addition, betterment, abandonment, or conversion, of such character as to constitute an alteration of the license;
(b) Make a change in the plans for the project under license; or
(c) Extend the time fixed in the license for commencement or completion of project works.
§ 4.201 Contents of application.
An application for amendment of a license for a water power project must contain the following information in the form specified.
(a) Initial statement.
(1) [Name of applicant] applies to the Federal Energy Regulatory Commission for an amendment of license for the [name of project] water power project.
(2) The exact name, business address, and telephone number of the applicant are:
(3) The applicant is a [citizen of the United States, association of citizens of the United States, domestic corporation, municipality, or state, as appropriate, see 16 U.S.C. 796], licensee for the water power project, designated as Project No. ______ in the records of the Federal Energy Regulatory Commission, issued on the ____________ day of ______________, 19____.
(4) The amendments of license proposed and the reason(s) why the proposed changes are necessary, are: [Give a statement or description]
(5)(i) The statutory or regulatory requirements of the state(s) in which the project would be located that affect the project as proposed with respect to bed and banks and to the appropriation, diversion, and use of water for power purposes are: [provide citation and brief identification of the nature of each requirement.]
(ii) The steps which the applicant has taken or plans to take to comply with each of the laws cited above are: [provide brief description for each law.]
(b) Required exhibits for capacity related amendments. Any application to amend a license for a hydropower project that involves additional capacity not previously authorized, and that would increase the actual or proposed total installed capacity of the project, would result in an increase in the maximum hydraulic capacity of the project of 15 percent or more, and would result in an increase in the installed name-plate capacity of 2 megawatts or more, must contain the following exhibits, or revisions or additions to any exhibits on file, commensurate with the scope of the licensed project:
(1) For amendment of a license for a water power project that, at the time the application is filed, is not constructed and is proposed to have a total installed generating capacity of more than 10 MW—Exhibits A, B, C, D, E, F, and G under § 4.41;
(2) For amendment of a license for a water power project that, at the time the application is filed, is not constructed and is proposed to have a total installed generating capacity of 1.5 MW or less—Exhibits E, F, and G under § 4.61 of this chapter;
(3) For amendment of a license for a water power project that, at the time the application is filed, is not constructed and is proposed to have a total installed generating capacity of 10 MW or less, but more than 1.5 MW—Exhibits F and G under § 4.61, and Exhibit E under § 4.41;
(4) For amendment of a license for a water power project that, at the time the application for amendment is filed, has been constructed, and is proposed to have a total installed generating capacity of 10 MW or less—Exhibit E, F, and G under § 4.61; and
(5) For amendment of a license for a water power project that, at the time the application is filed, has been constructed and is proposed to have a total installed generating capacity of more than 10 MW—Exhibits A, B, C, D, E, F, and G under § 4.51.
(c) Required exhibits for non-capacity related amendments. Any application to amend a license for a water power project that would not be a capacity related amendment as described in paragraph (b) of this section must contain those exhibits that require revision in light of the nature of the proposed amendments.
(d) Consultation and waiver. (1) If an applicant for license amendment under this subpart believes that any exhibit required under paragraph (b) of this section is inappropriate with respect to the particular amendment of license sought by the applicant, a petition for waiver of the requirement to submit such exhibit may be submitted to the Commission under § 385.207 of this chapter, after consultation with the Commission’s Division of Hydropower Compliance and Administration.
(2) A licensee wishing to file an application for amendment of license under this section may seek advice from the Commission staff regarding which exhibits(s) must be submitted and whether the proposed amendment is consistent with the scope of the existing licensed project.
§ 4.202 Alteration and extension of license.
(a) If it is determined that approval of the application for amendment of license would constitute a significant alteration of license pursuant to section 6 of the Act, 16 U.S.C. 799, public notice of such application shall be given at least 30 days prior to action upon the application.
(b) Any application for extension of time fixed in the license for commencement or completion of construction of project works must be filed with the Commission not less than three months prior to the date or dates so fixed.
Subpart M—Fees Under Section 30(e) of the Act
§ 4.300 Purpose, definitions, and applicability.
(a) Purpose. This subpart implements the amendments of section 30 of the Federal Power Act enacted by section 7(c) of the Electric Consumers Protection Act of 1986 (ECPA). It establishes procedures for reimbursing fish and wildlife agencies for costs incurred in connection with applications for an exemption from licensing and applications for licenses seeking benefits under section 210 of the Public Utility Regulatory Policies Act of 1978, as amended, for a project that would impound or divert the water of a natural watercourse by means of a new dam or diversion.
(b) Definitions. For the purposes of this subpart—
(1) Cost means an expenditure made by a fish and wildlife agency:
(i) On or after the effective date of this regulation for an application filed on or after the effective date of this regulation; and
(ii) Directly related to setting mandatory terms and conditions for a proposed project pursuant to section 30(c) of the Federal Power Act.
(2) Cost statement means a statement of the total costs for which a fish and wildlife agency requests reimbursement including an itemized schedule of costs including, but not limited to, costs of fieldwork and testing, contract costs, travel costs, personnel costs, and administrative and overhead costs.
(3) Mandatory terms and conditions means terms and conditions of a license or exemption that a fish and wildlife agency determines are appropriate to prevent loss of, or damage to, fish and wildlife resources pursuant to section 30(c) of the Federal Power Act.
(4) New dam or diversion license applicant means an applicant for a license for a project that would impound or divert the water of a natural watercourse by means of a new dam or diversion, as defined in section 210(k) of the Public Utility Regulatory Policies Act of 1978, as amended.
(5) PURPA benefits means benefits under section 210 of the Public Utility Regulatory Policies Act of 1978, as amended.
(6) Section 30(c) application means an application for an exemption from licensing or a new dam or diversion license application seeking PURPA benefits.
(c) Applicability. Except as provided in paragraph (d) of this section, this subpart applies to:
(1) Any application for exemption filed on or after the effective date of these regulations for costs incurred by fish and wildlife agencies after the effective date of these regulations;
(2) Any new dam or diversion license application seeking PURPA benefits filed on or after April 16, 1988;
(3) Any new dam or diversion license application seeking PURPA benefits filed after the effective date of this regulation, but before April 16, 1988, if the applicant fails to demonstrate in a monetary resources petition filed with the Commission pursuant to § 292.208 of this chapter that, before October 16, 1986, it had committed substantial monetary resources directly related to the development of the proposed project and to the diligent and timely completion of all requirements of the Commission for filing an acceptable application; and
(4) Any new dam or diversion license application seeking PURPA benefits filed after the effective date of this regulation, if the application is not accepted for filing before October 16, 1989.
(d) Exceptions. (1) This subpart does not apply to any new dam or diversion license application seeking PURPA benefits if the moratorium described in section 8(e) of ECPA is in effect. The moratorium will end at the expiration of the first full session of Congress following the session during which the Commission reports to Congress on the results of the study required under section 8(d) of ECPA.
(2) This subpart does not apply to any new dam or diversion license application seeking PURPA benefits for a project located at a Government dam, as defined in section 3(10) of the Federal Power Act, at which non-Federal hydroelectric development is permissible.
§ 4.301 Notice to fish and wildlife agencies and estimation of fees prior to filing.
(a) Notice to agencies—(1) New dam or diversion license applicants. During the initial stage or pre-filing agency consultation under § 4.38(b)(1), a prospective new dam or diversion license applicant must inform each fish and wildlife agency consulted in writing with a copy to the Commission whether it will seek PURPA benefits.
(2) Exemption applicants. During the initial stage of pre-filing agency consultation under § 4.38(b)(1), a prospective exemption applicant must notify each fish and wildlife agency consulted that it will seek an exemption from licensing.
(b) Estimate of fees. Within the comment period provided in § 4.38(c)(5), a fish and wildlife agency must provide a prospective section 30(c) applicant with a reasonable estimate of the total costs the agency anticipates it will incur to set mandatory terms and conditions for the proposed project. An agency may provide an applicant with an updated estimate as it deems necessary. If an agency believes that its most recent estimate will be exceeded by more than 25 percent, it must supply the prospective applicant or applicant with a new estimate and submit a copy to the Commission.
§ 4.302 Fees at filing.
(a) Filing requirement. A section 30(c) application must be accompanied by a fee or a bond, together with copies of the most recent cost estimates provided by fish and wildlife agencies pursuant to § 4.301(b).
(b) Amount. The fee required under paragraph (a) of this section must be in an amount equal to 50 percent of the most recent cost estimates provided by fish and wildlife agencies pursuant to § 4.301(b). In lieu of this amount, an applicant may provide an unlimited term surety bond from a company on the Department of Treasury’s list of companies certified to write surety bonds. Applicants bonded by a company whose certification by the Department of the Treasury lapses must provide evidence of purchase of another bond from a certified company. A bond must be for an amount no less than 100 percent of the agencies’ most recent cost estimates pursuant to § 4.301(b).
(c) Failure to file. The Commission will reject a section 30(c) application if the applicant fails to comply with the provisions of paragraphs (a) and (b) of this section.
§ 4.303 Post-filing procedures.
(a) Submission of cost statement—(1) Accepted applications. Within 60 days after the last date for filing mandatory terms and conditions pursuant to § 4.32(c)(4) for a new dam or diversion license application seeking PURPA benefits, § 4.93(b) for an application for exemption of a small conduit hydroelectric facility, or § 4.105(b)(1) for an application for case-specific exemption of a small hydroelectric power project, a fish and wildlife agency must file with the Commission a cost statement of the reasonable costs the agency incurred in setting mandatory terms and conditions for the proposed project. An agency may request, in writing, along with any supporting documentation an extension of this 60-day period.
(2) Rejected, withdrawn or dismissed applications. The Director of the Office of Energy Projects (Director) will, by letter, notify each fish and wildlife agency if a section 30(c) application is rejected, withdrawn or dismissed. Within 60 days from the date of notification, a fish and wildlife agency must file with the Commission a cost statement of the reasonable costs the agency incurred prior to the date the application was rejected, withdrawn, or dismissed. An agency may submit a written request for an extension of this 60-day period along with any supporting documentation.
(b) If an agency has not submitted a cost statement or extension request within the time provided in paragraph (a)(2) of this section, it waives its right to receive fees for that project pursuant to this subpart.
(c) Billing. After the Commission receives a cost statement from all fish and wildlife agencies as required by paragraph (a) of this section, the Commission will bill the section 30(c) applicant. The bill will show:
(1) The cost statement submitted to the Commission by each fish and wildlife agency;
(2) Any amounts already paid by the applicant pursuant to § 4.302; and
(3)(i) The amount due, if the amount already paid by the applicant pursuant to § 4.302 is less than the total of all the cost statements; or
(ii) The amount to be refunded to the applicant, if the amount already paid by the applicant pursuant to § 4.302 is more than the total of all the cost statements.
(d) Within 45 days from the date of a bill issued under paragraph (b) of this section, a section 30(c) applicant must pay in full to the Commission any remaining amounts due on the cost statements regardless of whether any of these amounts are in dispute.
(e) Dispute procedures—(1) When to dispute. Any dispute regarding the reasonableness of any fish and wildlife agency cost statement must be made within 45 days from the date of a bill issued under paragraph (b) of this section.
(2) Assessment of disputed cost statements The burden of showing that an agency’s cost statement is unreasonable is on the applicant. However, a fish and wildlife agency must supply the disputing applicant and the Commission with the documentation necessary to support its cost statement. The Director of the Office of Energy Projects will determine the reasonableness of a disputed fish and wildlife agency cost statement. The Director’s decision will be in writing. The Director will notify the disputing applicant and the fish and wildlife agency of the decision by letter. Any decision of the Director may be appealed by either party pursuant to 18 CFR 385.1902. In deciding whether or not a disputed cost statement is reasonable, the Director will review the application, the disputed cost statement and any other documentation relating to the particular environmental problems associated with the disputing applicant’s proposed project. The Director will consider such factors as:
(i) The time the fish and wildlife agency spent reviewing the application;
(ii) The proportion of the cost statement to the time the fish and wildlife agency spent reviewing the application;
(iii) Whether the fish and wildlife agency’s expenditures conform to Federal expenditure guidelines for such items as travel, per diem, personnel, and contracting; and
(iv) Whether the studies conducted by the agency, if any, are duplicative, limited to the proposed project area, unnecessary to determine the impacts to or mitigation measures for the particular fish and wildlife resources affected by the proposed project, or otherwise unnecessary to set terms and conditions for the proposed project.
(3) Unreasonable cost statements. If the Director determines that a disputed fish and wildlife agency cost statement is unreasonable, the disputing applicant and the fish and wildlife agency will be afforded 45 days from the date of notification to attempt to reach an agreement regarding the reimbursable costs of the agency. If the disputing applicant and the fish and wildlife agency fail to reach an agreement on the disputed cost statement within 45 days from the date of notification, the Director will determine the costs that the agency should reasonably have incurred.
(f) Refunds. (1) If the amount paid by a section 30(c) applicant under § 4.302 exceeds the total amount of the cost statements submitted by fish and wildlife agencies under paragraph (a) of this section, the Commission will notify the Treasury to refund the difference to the applicant within 45 days from the date of the bill issued to the applicant under paragraph (b) of this section.
(2) If the amount paid by a section 30(c) applicant exceeds the amount determined to be reasonable by the Director pursuant to paragraph (d)(2) of this section, the Commission will notify the Treasury to refund the difference to the applicant within 45 days of the resolution of all dispute proceedings.
§ 4.304 Payment.
(a) A payment required under this subpart must be made by check payable to the United States Treasury. The check must indicate that the payment is for ECPA Fees.
(b) If a payment required under this subpart is not made within the time period prescribed for making such payment, interest and penalty charges will be assessed. Interest and penalty charges will be computed in accordance with 31 U.S.C. 3717 and 4 CFR part 102.
(c) The Commission will not issue a license or exemption, unless the applicant has made full payments of any fees due under § 4.303(c).
§ 4.305 Enforcement.
(a) The Commission may take any appropriate action permitted by law if a section 30(c) applicant does not make a payment required under this subpart. The Commission will not be liable to any fish and wildlife agency for failure to collect any amounts under this subpart.
(b) If the Commission is unable to collect the full amount due by a section 30(c) applicant on behalf of more than one agency, the amount the Commission does collect will be distributed to the agencies on a pro-rata basis except if an agency’s cost statement is greater than its most recent estimate to the applicant under § 4.301(b), then the difference between the estimate and the cost statement will not be reimbursed until any amounts owed to other agencies have been paid.
Subpart N—Notice of Intent To Construct Qualifying Conduit Hydropower Facilities
§ 4.400 Applicability and purpose.
This part implements section 30(a) of the Federal Power Act, as amended, and provides procedures for obtaining a determination from the Commission that the facility to be constructed is a qualifying conduit hydropower facility, as defined in § 4.30(b)(26), and thus, is not required to be licensed under Part I of the FPA.
§ 4.401 Contents of notice of intent to construct a qualifying conduit hydropower facility.
(a) A notice of intent to construct a qualifying conduit hydropower facility submitted under this subpart must contain the following:
(1) An introductory statement as described in paragraph (b) of this section;
(2) A statement that the proposed project will use the hydroelectric potential of a non-federally owned conduit as set forth in paragraph (c) of this section;
(3) A statement that the proposed facility has not been licensed or exempted from the licensing requirements of Part I of the FPA, on or before August 9, 2013, as set forth in in paragraph (d) of this section;
(4) A description of the proposed facility as set forth in paragraph (e) of this section;
(5) Project drawings as set forth in paragraph (f) of this section;
(6) If applicable, the preliminary permit project number for the proposed facility; and,
(7) Verification as set forth in paragraph (g) of this section.
(b) Introductory statement. The introductory statement must be set forth in the following format:
[Name of applicant] applies to the Federal Energy Regulatory Commission for a determination that the [facility name] is a qualifying conduit hydropower facility, meeting the requirements of section 30(a) of the Federal Power Act, as amended.
The location of the facility is:
The exact name and business address of the applicant(s) are:
The exact name and business address of each person authorized to act as an agent for the applicant(s) in this notice of intent are:
[Name of applicant] is [a citizen of the United States, an association of citizens of the United States, a municipality, State, or a corporation incorporated under the laws of (specify the United States or the state of incorporation), as appropriate].
(c) Non-Federal Conduit Statement. The non-federal conduit statement must be set forth in the following format:
The [facility name] will use the hydroelectric potential of a non-federally owned conduit.
(d) Original facility statement. The original facility statement must be set forth in the following format:
The [facility name] has not been licensed or exempted from the licensing requirements of Part I of the FPA, on or before August 9, 2013, the date of enactment of the Hydropower Regulatory Efficiency Act.
(e) Description of proposed facility. Description of proposed facility must include:
(1) A detailed description of any conduits and associated consumptive water supply facilities, intake facilities, powerhouses, and any other structures associated with the facility;
(2) The purposes for which the conduit is used;
(3) The number, type, generating capacity (kW or MW), and estimated average annual generation (kWh or MWh) of the generating units and brief description of any plans for future units; and,
(4) A description of the nature and extent of the dam that would occur in association with construction of the proposed qualifying conduit hydroelectric facility, including a statement of the normal maximum surface area and normal maximum surface elevation of any existing impoundment before and after that construction; and any evidence that the construction of the dam would occur for agricultural, municipal, or industrial consumptive purposes even if the hydropower generating facilities were not installed.
(f) Drawings, maps, diagrams. Include a set of drawings/maps/diagrams showing the structures and equipment of the hydropower facility in relation to the existing conduit. Drawings of the facility must include:
(1) A Plan View (overhead view) drawing of the proposed hydropower facilities, which includes the following:
(i) The hydropower facilities, including all intake and discharge pipes, and how those pipes connect to the conduit;
(ii) The portion of the conduit in proximity to the facilities on which the hydropower facilities will be located;
(iii) The dimensions (e.g., length, width, diameter) of all facilities, intakes, discharges, and conduits;
(iv) Identification of facilities as either existing or proposed;
(v) The flow direction labelled on all intakes, discharges, and conduits; and,
(2) A Location Map showing the facilities and their relationship to the nearest town, which includes the following:
(i) The powerhouse location labeled, and its latitude and longitude identified; and,
(ii) The nearest town, if possible, or other permanent monuments or objects, such as roads or other structures that can be easily noted on the map and identified in the field.
(g) Verification. Provide verification using either a sworn, notarized statement set forth in paragraph (g)(1) of this section or an unsworn statement set forth in paragraph (g)(2) of this section.
(1) As to any facts alleged in the notice of intent to construct or other materials filed, be subscribed and verified under oath in the form set forth below by the person filing, an officer thereof, or other person having knowledge of the matters set forth. If the subscription and verification is by anyone other than the person filing or an officer thereof, it shall include a statement of the reasons therefor.
This (notice of intent to construct, etc.) is executed in the:
Subscribed and sworn to before me, a ____________ [Notary Public, or title of other official authorized by the state to notarize documents, as appropriate] of the State of ____________this day of ____________, 20____.
/SEAL/[if any]
(Notary Public, or other authorized official)
(2) I declare (or certify, verify, or state) under penalty of perjury that the foregoing is true and correct. Executed on ____________[date].
(Signature)
PART 5—INTEGRATED LICENSE APPLICATION PROCESS
§ 5.1 Applicability, definitions, and requirement to consult.
(a) This part applies to the filing and processing of an application for an:
(1) Original license;
(2) New license for an existing project subject to Sections 14 and 15 of the Federal Power Act; or
(3) Subsequent license.
(b) Definitions. The definitions in § 4.30(b) of this chapter and § 16.2 of this chapter apply to this chapter.
(c) Who may file. Any citizen, association of citizens, domestic corporation, municipality, or state may develop and file a license application under this part.
(d) Requirement to consult. (1) Before it files any application for an original, new, or subsequent license under this part, a potential applicant must consult with the relevant Federal, state, and interstate resource agencies, including as appropriate the National Marine Fisheries Service, the United States Fish and Wildlife Service, Bureau of Indian Affairs, the National Park Service, the United States Environmental Protection Agency, the Federal agency administering any United States lands utilized or occupied by the project, the appropriate state fish and wildlife agencies, the appropriate state water resource management agencies, the certifying agency or Indian tribe under Section 401(a)(1) of the Federal Water Pollution Control Act (Clean Water Act), 33 U.S.C. 1341(c)(1)), the agency that administers the Coastal Zone Management Act, 16 U.S.C. § 1451–1465, any Indian tribe that may be affected by the project, and members of the public. A potential license applicant must file a notification of intent to file a license application pursuant to § 5.5 and a pre-application document pursuant to the provisions of § 5.6.
(2) The Director of the Office of Energy Projects will, upon request, provide a list of known appropriate Federal, state, and interstate resource agencies, Indian tribes, and local, regional, or national non-governmental organizations likely to be interested in any license application proceeding.
(e) Purpose. The purpose of the integrated licensing process provided for in this part is to provide an efficient and timely licensing process that continues to ensure appropriate resource protections through better coordination of the Commission’s processes with those of Federal and state agencies and Indian tribes that have authority to condition Commission licenses.
(f) Default process. Each potential original, new, or subsequent license applicant must use the license application process provided for in this part unless the potential applicant applies for and receives authorization from the Commission under this part to use the licensing process provided for in:
(1) 18 CFR part 4, Subparts D-H and, as applicable, part 16 (i.e., traditional process), pursuant to paragraph (c) of this section; or
(2) Section 4.34(i) of this chapter, Alternative procedures.
§ 5.2 Document availability.
(a) Pre-application document. (1) From the date a potential license applicant files a notification of intent to seek a license pursuant to § 5.5 until any related license application proceeding is terminated by the Commission, the potential license applicant must make reasonably available to the public for inspection at its principal place of business or another location that is more accessible to the public, the pre-application document and any materials referenced therein. These materials must be available for inspection during regular business hours in a form that is readily accessible, reviewable, and reproducible.
(2) The materials specified in paragraph (a)(1) of this section must be made available to the requester at the location specified in paragraph (a)(1) of this section or through the mail, or otherwise. Except as provided in paragraph (a)(3) of this section, copies of the pre-application document and any materials referenced therein must be made available at their reasonable cost of reproduction plus, if applicable, postage.
(3) A potential licensee must make requested copies of the materials specified in paragraph (a)(1) of this section available to the United States Fish and Wildlife Service, the National Marine Fisheries Service, the state agency responsible for fish and wildlife resources, any affected Federal land managing agencies, and Indian tribes without charge for the costs of reproduction or postage.
(b) License application. (1) From the date on which a license application is filed under this part until the licensing proceeding for the project is terminated by the Commission, the license applicant must make reasonably available to the public for inspection at its principal place of business or another location that is more accessible to the public, a copy of the complete application for license, together with all exhibits, appendices, and any amendments, pleadings, supplementary or additional information, or correspondence filed by the applicant with the Commission in connection with the application. These materials must be available for inspection during regular business hours in a form that is readily accessible, reviewable, and reproducible at the same time as the information is filed with the Commission or required by regulation to be made available.
(2) The applicant must provide a copy of the complete application (as amended) to a public library or other convenient public office located in each county in which the proposed project is located.
(3) The materials specified in paragraph (b)(1) of this section must be made available to the requester at the location specified in paragraph (b)(1) of this section or through the mail. Except as provided in paragraph (b)(4) of this section, copies of the license application and any materials referenced therein must be made available at their reasonable cost of reproduction plus, if applicable, postage.
(4) A licensee applicant must make requested copies of the materials specified in paragraph (b)(1) of this section available to the United States Fish and Wildlife Service, the National Marine Fisheries Service, and the state agency responsible for fish and wildlife resources, any affected Federal land managing agencies, and Indian tribes without charge for the costs of reproduction or postage.
(c) Confidentiality of cultural information. A potential applicant must delete from any information made available to the public under paragraphs (a) and (b) of this section, specific site or property locations the disclosure of which would create a risk of harm, theft, or destruction of archeological or native American cultural resources or of the site at which the sources are located, or would violate any Federal law, include the Archeological Resources Protection Act of 1979, 16 U.S.C. 470w–3, and the National Historic Preservation Act of 1966, 16 U.S.C. 470hh.
(d) Access. Anyone may file a petition with the Commission requesting access to the information specified in paragraphs (a) or (b) of this section if it believes that the potential applicant or applicant is not making the information reasonably available for public inspection or reproduction. The petition must describe in detail the basis for the petitioner’s belief.
§ 5.3 Process selection.
(a)(1) Notwithstanding any other provision of this part or of parts 4 and 16 of this chapter, a potential applicant for a new, subsequent, or original license may until July 23, 2005 elect to use the licensing procedures of this part or the licensing procedures of parts 4 and 16.
(2) Any potential license applicant that files its notification of intent pursuant to § 5.5 and pre-application document pursuant to § 5.6 after July 23, 2005 must request authorization to use the licensing procedures of parts 4 and 16, as provided for in paragraphs (b)–(f) of this section.
(b) A potential license applicant may file with the Commission a request to use the traditional licensing process or alternative procedures pursuant to this Section with its notification of intent pursuant to § 5.5.
(c)(1)(i) An application for authorization to use the traditional process must include justification for the request and any existing written comments on the potential applicant’s proposal and a response thereto.
(ii) A potential applicant requesting authorization to use the traditional process should address the following considerations:
(A) Likelihood of timely license issuance;
(B) Complexity of the resource issues;
(C) Level of anticipated controversy;
(D) Relative cost of the traditional process compared to the integrated process;
(E) The amount of available information and potential for significant disputes over studies; and
(F) Other factors believed by the applicant to be pertinent
(2) A potential applicant requesting the use of § 4.34(i) alternative procedures of this chapter must:
(i) Demonstrate that a reasonable effort has been made to contact all agencies, Indian tribes, and others affected by the applicant’s request, and that a consensus exists that the use of alternative procedures is appropriate under the circumstances;
(ii) Submit a communications protocol, supported by interested entities, governing how the applicant and other participants in the pre-filing consultation process, including the Commission staff, may communicate with each other regarding the merits of the potential applicant’s proposal and proposals and recommendations of interested entities; and
(iii) Provide a copy of the request to all affected resource agencies and Indian tribes and to all entities contacted by the applicant that have expressed an interest in the alternative pre-filing consultation process.
(d)(1) The potential applicant must provide a copy of the request to use the traditional process or alternative procedures to all affected resource agencies, Indian tribes, and members of the public likely to be interested in the proceeding. The request must state that comments on the request to use the traditional process or alternative procedures, as applicable, must be filed with the Commission within 30 days of the filing date of the request and, if there is no project number, that responses must reference the potential applicant’s name and address.
(2) The potential applicant must also publish notice of the filing of its notification of intent, of the pre-application document, and of any request to use the traditional process or alternative procedures no later than the filing date of the notification of intent in a daily or weekly newspaper of general circulation in each county in which the project is located. The notice must:
(i) Disclose the filing date of the request to use the traditional process or alternative procedures, and the notification of intent and pre-application document;
(ii) Briefly summarize these documents and the basis for the request to use the traditional process or alternative procedures;
(iii) Include the potential applicant’s name and address, and telephone number, the type of facility proposed to be applied for, its proposed location, the places where the pre-application document is available for inspection and reproduction;
(iv) Include a statement that comments on the request to use the traditional process or alternative procedures are due to the Commission and the potential applicant no later than 30 days following the filing date of that document and, if there is no project number, that responses must reference the potential applicant’s name and address;
(v) State that comments on any request to use the traditional process should address, as appropriate to the circumstances of the request, the:
(A) Likelihood of timely license issuance;
(B) Complexity of the resource issues;
(C) Level of anticipated controversy;
(D) Relative cost of the traditional process compared to the integrated process; and
(E) The amount of available information and potential for significant disputes over studies; and
(F) Other factors believed by the commenter to be pertinent; and
(vi) State that respondents must submit comments to the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov.
§ 5.4 Acceleration of a license expiration date.
(a) Request for acceleration. (1) No later than five and one-half years prior to expiration of an existing license, a licensee may file with the Commission, in accordance with the formal filing requirements in subpart T of part 385 of this chapter, a written request for acceleration of the expiration date of its existing license, containing the statements and information specified in § 16.6(b) of this chapter and a detailed explanation of the basis for the acceleration request.
(2) If the Commission grants the request for acceleration pursuant to paragraph (c) of this section, the Commission will deem the request for acceleration to be a notice of intent under § 16.6 of this chapter and, unless the Commission directs otherwise, the licensee must make available the Pre-Application Document provided for in § 5.6 no later than 90 days from the date that the Commission grants the request for acceleration.
(b) Notice of request for acceleration. (1) Upon receipt of a request for acceleration, the Commission will give notice of the licensee’s request and provide a 45-day period for comments by interested persons by:
(i) Publishing notice in the
(ii) Publishing notice once in a daily or weekly newspaper published in the county or counties in which the project or any part thereof or the lands affected thereby are situated; and
(iii) Notifying appropriate Federal, state, and interstate resource agencies and Indian tribes, and non-governmental organizations likely to be interested, by electronic means if practical, otherwise by mail.
(2) The notice issued pursuant to paragraphs (b)(1)(A) and (B) and the written notice given pursuant to paragraph (b)(1)(C) will be considered as fulfilling the notice provisions of § 16.6(d) of this chapter should the Commission grant the acceleration request and will include an explanation of the basis for the licensee’s acceleration request.
(c) Commission order. If the Commission determines it is in the public interest, the Commission will issue an order accelerating the expiration date of the license to not less than five years and 90 days from the date of the Commission order.
§ 5.5 Notification of intent.
(a) Notification of intent. A potential applicant for an original, new, or subsequent license, must file a notification of its intent to do so in the manner provided for in paragraphs (b) and (c) of this section.
(b) Requirement to notify. In order for a non-licensee to notify the Commission that it intends to file an application for an original, new, or subsequent license, or for an existing licensee to notify the Commission whether or not it intends to file an application for a new or subsequent license, a potential license applicant must file with the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov, a letter that contains the following information:
(1) The potential applicant or existing licensee’s name and address.
(2) The project number, if any.
(3) The license expiration date, if any.
(4) An unequivocal statement of the potential applicant’s intention to file an application for an original license, or, in the case of an existing licensee, to file or not to file an application for a new or subsequent license.
(5) The type of principal project works licensed, if any, such as dam and reservoir, powerhouse, or transmission lines.
(6) The location of the project by state, county, and stream, and, when appropriate, by city or nearby city.
(7) The installed plant capacity, if any.
(8) The names and mailing addresses of:
(i) Every county in which any part of the project is located, and in which any Federal facility that is used or to be used by the project is located;
(ii) Every city, town, or similar political subdivision;
(A) In which any part of the project is or is to be located and any Federal facility that is or is to be used by the project is located, or
(B) That has a population of 5,000 or more people and is located within 15 miles of the existing or proposed project dam;
(iii) Every irrigation district, drainage district, or similar special purpose political subdivision:
(A) In which any part of the project is or is proposed to be located and any Federal facility that is or is proposed to be used by the project is located; or
(B) That owns, operates, maintains, or uses any project facility or any Federal facility that is or is proposed to be used by the project;
(iv) Every other political subdivision in the general area of the project or proposed project that there is reason to believe would be likely to be interested in, or affected by, the notification; and
(v) Affected Indian tribes.
(c) Requirement to distribute. Before it files any application for an original, new, or subsequent license, a potential license applicant proposing to file a license application pursuant to this part or to request to file a license application pursuant to part 4 of this chapter and, as appropriate, part 16 of this chapter (i.e., the “traditional process”), including an application pursuant to § 4.34(i) alternative procedures of this chapter must distribute to appropriate Federal, state, and interstate resource agencies, Indian tribes, local governments, and members of the public likely to be interested in the proceeding the notification of intent provided for in paragraph (a) of this section.
(d) When to notify. An existing licensee or non-licensee potential applicant must notify the Commission as required in paragraph (b) of this section at least five years, but not more than five and one-half years, before the existing license expires.
(e) Non-Federal representatives. A potential license applicant may at the same time it files its notification of intent and distributes its pre-application document, request to be designated as the Commission’s non-Federal representative for purposes of consultation under section 7 of the Endangered Species Act and the joint agency regulations thereunder at 50 CFR part 402, Section 305(b) of the Magnuson-Stevens Fishery Conservation and Management Act and the implementing regulations at 50 CFR 600.920. A potential license applicant may at the same time request authorization to initiate consultation under section 106 of the National Historic Preservation Act and the implementing regulations at 36 CFR 800.2(c)(4).
(f) Procedural matters. The provisions of subpart F of part 16 of this chapter apply to projects to which this part applies.
(g) Construction of regulations. The provisions of this part and parts 4 and 16 shall be construed in a manner that best implements the purposes of each part and gives full effect to applicable provisions of the Federal Power Act.
§ 5.6 Pre-application document.
(a) Pre-application document. (1) Simultaneously with the filing of its notification of intent to seek a license as provided for in § 5.5, and before it files any application for an original, new, or subsequent license, a potential applicant for a license to be filed pursuant to this part or part 4 of this chapter and, as appropriate, part 16 of this chapter, must file with the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov and distribute to the appropriate Federal, state, and interstate resource agencies, Indian tribes, local governments, and members of the public likely to be interested in the proceeding, the pre-application document provided for in this section.
(2) The agencies referred to in paragraph (a)(1) of this section include: Any state agency with responsibility for fish, wildlife, and botanical resources, water quality, coastal zone management plan consistency certification, shoreline management, and water resources; the U.S. Fish and Wildlife Service; the National Marine Fisheries Service; Environmental Protection Agency; State Historic Preservation Officer; Tribal Historic Preservation Officer; National Park Service; local, state, and regional recreation agencies and planning commissions; local and state zoning agencies; and any other state or Federal agency or Indian tribe with managerial authority over any part of project lands and waters.
(b) Purpose of pre-application document. (1) The pre-application document provides the Commission and the entities identified in paragraph (a) of this section with existing information relevant to the project proposal that is in the potential applicant’s possession or that the potential applicant can obtain with the exercise of due diligence. This existing, relevant, and reasonably available information is distributed to these entities to enable them to identify issues and related information needs, develop study requests and study plans, and prepare documents analyzing any license application that may be filed. It is also a precursor to the environmental analysis section of the Preliminary Licensing Proposal or draft license application provided for in § 5.16, Exhibit E of the final license application, and the Commission’s scoping document(s) and environmental impact statement or environmental assessment under the National Environmental Policy Act (NEPA).
(2) A potential applicant is not required to conduct studies in order to generate information for inclusion in the pre-application document. Rather, a potential applicant must exercise due diligence in determining what information exists that is relevant to describing the existing environment and potential impacts of the project proposal (including cumulative impacts), obtaining that information if the potential applicant does not already possess it, and describing or summarizing it as provided for in paragraph (d) of this section. Due diligence includes, but is not limited to, contacting appropriate agencies and Indian tribes that may have relevant information and review of Federal and state comprehensive plans filed with the Commission and listed on the Commission’s Web site at http://www.ferc.gov.
(c) Form and distribution protocol—(1) General requirements. As specifically provided for in the content requirements of paragraph (d) of this section, the pre-application document must describe the existing and proposed (if any) project facilities and operations, provide information on the existing environment, and existing data or studies relevant to the existing environment, and any known and potential impacts of the proposed project on the specified resources.
(2) Availability of source information and studies. The sources of information on the existing environment and known or potential resource impacts included in the descriptions and summaries must be referenced in the relevant section of the document, and in an appendix to the document. The information must be provided upon request to recipients of the pre-application document. A potential applicant must provide the requested information within 20 days from receipt of the request. Potential applicants and requesters are strongly encouraged to use electronic means or compacts disks to distribute studies and other forms of information, but a potential applicant must, upon request, provide the information in hard copy form. The potential applicant is also strongly encouraged to include with the pre-application document any written protocol for distribution consistent with this paragraph to which it has agreed with agencies, Indian tribes, or other entities.
(d) Content requirements—(1) Process plan and schedule. The pre-application document must include a plan and schedule for all pre-application activity that incorporates the time frames for pre-filing consultation, information gathering, and studies set forth in this part. The plan and schedule must include a proposed location and date for the scoping meeting and site visit required by § 5.8(b)(3)(viii).
(2) Project location, facilities, and operations. The potential applicant must include in the pre-application document:
(i) The exact name and business address, and telephone number of each person authorized to act as agent for the applicant;
(ii) Detailed maps showing lands and waters within the project boundary by township, range, and section, as well as by state, county, river, river mile, and closest town, and also showing the specific location of any Federal and tribal lands, and the location of proposed project facilities, including roads, transmission lines, and any other appurtenant facilities;
(iii) A detailed description of all existing and proposed project facilities and components, including:
(A) The physical composition, dimensions, and general configuration of any dams, spillways, penstocks, canals, powerhouses, tailraces, and other structures proposed to be included as part of the project or connected directly to it;
(B) The normal maximum water surface area and normal maximum water surface elevation (mean sea level), gross storage capacity of any impoundments;
(C) The number, type, and minimum and maximum hydraulic capacity and installed (rated) capacity of any proposed turbines or generators to be included as part of the project;
(D) The number, length, voltage, and interconnections of any primary transmission lines proposed to be included as part of the project, including a single-line diagram showing the transfer of electricity from the project to the transmission grid or point of use; and
(E) An estimate of the dependable capacity, average annual, and average monthly energy production in kilowatt hours (or mechanical equivalent);
(iv) A description of the current (if applicable) and proposed operation of the project, including any daily or seasonal ramping rates, flushing flows, reservoir operations, and flood control operations.
(v) In the case of an existing licensed project;
(A) A complete description of the current license requirements; i.e., the requirements of the original license as amended during the license term;
(B) A summary of project generation and outflow records for the five years preceding filing of the pre-application document;
(C) Current net investment; and
(D) A summary of the compliance history of the project, if applicable, including a description of any recurring situations of non-compliance.
(vi) A description of any new facilities or components to be constructed, plans for future development or rehabilitation of the project, and changes in project operation.
(3) Description of existing environment and resource impacts—(i) General requirements. A potential applicant must, based on the existing, relevant, and reasonably available information, include a discussion with respect to each resource that includes:
(A) A description of the existing environment as required by paragraphs (d)(3)(ii)–(xiii) of this section;
(B) Summaries (with references to sources of information or studies) of existing data or studies regarding the resource;
(C) A description of any known or potential adverse impacts and issues associated with the construction, operation or maintenance of the proposed project, including continuing and cumulative impacts; and
(D) A description of any existing or proposed project facilities or operations, and management activities undertaken for the purpose of protecting, mitigating impacts to, or enhancing resources affected by the project, including a statement of whether such measures are required by the project license, or were undertaken for other reasons. The type and amount of the information included in the discussion must be commensurate with the scope and level of resource impacts caused or potentially caused by the proposed project. Potential license applicants are encouraged to provide photographs or other visual aids, as appropriate, to supplement text, charts, and graphs included in the discussion.
(ii) Geology and soils. Descriptions and maps showing the existing geology, topography, and soils of the proposed project and surrounding area. Components of the description must include:
(A) A description of geological features, including bedrock lithology, stratigraphy, structural features, glacial features, unconsolidated deposits, and mineral resources at the project site;
(B) A description of the soils, including the types, occurrence, physical and chemical characteristics, erodability and potential for mass soil movement;
(C) A description of reservoir shorelines and streambanks, including:
(1) Steepness, composition (bedrock and unconsolidated deposits), and vegetative cover; and
(2) Existing erosion, mass soil movement, slumping, or other forms of instability, including identification of project facilities or operations that are known to or may cause these conditions.
(iii) Water resources. A description of the water resources of the proposed project and surrounding area. This must address the quantity and quality (chemical/physical parameters) of all waters affected by the project, including but not limited to the project reservoir(s) and tributaries thereto, bypassed reach, and tailrace. Components of the description must include:
(A) Drainage area;
(B) The monthly minimum, mean, and maximum recorded flows in cubic feet per second of the stream or other body of water at the powerplant intake or point of diversion, specifying any adjustments made for evaporation, leakage, minimum flow releases, or other reductions in available flow;
(C) A monthly flow duration curve indicating the period of record and the location of gauging station(s), including identification number(s), used in deriving the curve; and a specification of the critical streamflow used to determine the project’s dependable capacity;
(D) Existing and proposed uses of project waters for irrigation, domestic water supply, industrial and other purposes, including any upstream or downstream requirements or constraints to accommodate those purposes;
(E) Existing instream flow uses of streams in the project area that would be affected by project construction and operation; information on existing water rights and water rights applications potentially affecting or affected by the project;
(F) Any federally-approved water quality standards applicable to project waters;
(G) Seasonal variation of existing water quality data for any stream, lake, or reservoir that would be affected by the proposed project, including information on:
(1) Water temperature and dissolved oxygen, including seasonal vertical profiles in the reservoir;
(2) Other physical and chemical parameters to include, as appropriate for the project; total dissolved gas, pH, total hardness, specific conductance, cholorphyll a, suspended sediment concentrations, total nitrogen (mg/L as N), total phosphorus (mg/L as P), and fecal coliform (E. Coli) concentrations;
(H) The following data with respect to any existing or proposed lake or reservoir associated with the proposed project; surface area, volume, maximum depth, mean depth, flushing rate, shoreline length, substrate composition; and
(I) Gradient for downstream reaches directly affected by the proposed project.
(iv) Fish and aquatic resources. A description of the fish and other aquatic resources, including invasive species, in the project vicinity. This section must discuss the existing fish and macroinvertebrate communities, including the presence or absence of anadromous, catadromous, or migratory fish, and any known or potential upstream or downstream impacts of the project on the aquatic community. Components of the description must include:
(A) Identification of existing fish and aquatic communities;
(B) Identification of any essential fish habitat as defined under the Magnuson-Stevens Fishery Conservation and Management Act and established by the National Marine Fisheries Service; and
(C) Temporal and spacial distribution of fish and aquatic communities and any associated trends with respect to:
(1) Species and life stage composition;
(2) Standing crop;
(3) Age and growth data;
(4) Spawning run timing; and
(5) The extent and location of spawning, rearing, feeding, and wintering habitat.
(v) Wildlife and botanical resources. A description of the wildlife and botanical resources, including invasive species, in the project vicinity. Components of this description must include:
(A) Upland habitat(s) in the project vicinity, including the project’s transmission line corridor or right-of-way and a listing of plant and animal species that use the habitat(s); and
(B) Temporal or spacial distribution of species considered important because of their commercial, recreational, or cultural value.
(vi) Wetlands, riparian, and littoral habitat. A description of the floodplain, wetlands, riparian habitats, and littoral in the project vicinity. Components of this description must include:
(A) A list of plant and animal species, including invasive species, that use the wetland, littoral, and riparian habitat;
(B) A map delineating the wetlands, riparian, and littoral habitat; and
(C) Estimates of acreage for each type of wetland, riparian, or littoral habitat, including variability in such availability as a function of storage at a project that is not operated in run-of-river mode.
(vii) Rare, threatened and endangered species. A description of any listed rare, threatened and endangered, candidate, or special status species that may be present in the project vicinity. Components of this description must include:
(A) A list of Federal- and state-listed, or proposed to be listed, threatened and endangered species known to be present in the project vicinity;
(B) Identification of habitat requirements;
(C) References to any known biological opinion, status reports, or recovery plan pertaining to a listed species;
(D) Extent and location of any federally-designated critical habitat, or other habitat for listed species in the project area; and
(E) Temporal and spatial distribution of the listed species within the project vicinity.
(viii) Recreation and land use. A description of the existing recreational and land uses and opportunities within the project boundary. The components of this description include:
(A) Text description illustrated by maps of existing recreational facilities, type of activity supported, location, capacity, ownership and management;
(B) Current recreational use of project lands and waters compared to facility or resource capacity;
(C) Existing shoreline buffer zones within the project boundary;
(D) Current and future recreation needs identified in current State Comprehensive Outdoor Recreation Plans, other applicable plans on file with the Commission, or other relevant local, state, or regional conservation and recreation plans;
(E) If the potential applicant is an existing licensee, its current shoreline management plan or policy, if any, with regard to permitting development of piers, boat docks and landings, bulkheads, and other shoreline facilities on project lands and waters;
(F) A discussion of whether the project is located within or adjacent to a:
(1) River segment that is designated as part of, or under study for inclusion in, the National Wild and Scenic River System; or
(2) State-protected river segment;
(G) Whether any project lands are under study for inclusion in the National Trails System or designated as, or under study for inclusion as, a Wilderness Area.
(H) Any regionally or nationally important recreation areas in the project vicinity;
(I) Non-recreational land use and management within the project boundary; and
(J) Recreational and non-recreational land use and management adjacent to the project boundary.
(ix) Aesthetic resources. A description of the visual characteristics of the lands and waters affected by the project. Components of this description include a description of the dam, natural water features, and other scenic attractions of the project and surrounding vicinity. Potential applicants are encouraged to supplement the text description with visual aids.
(x) Cultural resources. A description of the known cultural or historical resources of the proposed project and surrounding area. Components of this description include:
(A) Identification of any historic or archaeological site in the proposed project vicinity, with particular emphasis on sites or properties either listed in, or recommended by the State Historic Preservation Officer or Tribal Historic Preservation Officer for inclusion in, the National Register of Historic Places;
(B) Existing discovery measures, such as surveys, inventories, and limited subsurface testing work, for the purpose of locating, identifying, and assessing the significance of historic and archaeological resources that have been undertaken within or adjacent to the project boundary; and
(C) Identification of Indian tribes that may attach religious and cultural significance to historic properties within the project boundary or in the project vicinity; as well as available information on Indian traditional cultural and religious properties, whether on or off of any federally-recognized Indian reservation (A potential applicant must delete from any information made available under this section specific site or property locations, the disclosure of which would create a risk of harm, theft, or destruction of archaeological or Native American cultural resources or to the site at which the resources are located, or would violate any Federal law, including the Archaeological Resources Protection Act of 1979, 16 U.S.C. 470w-3, and the National Historic Preservation Act of 1966, 16 U.S.C. 470hh).
(xi) Socio-economic resources. A general description of socio-economic conditions in the vicinity of the project. Components of this description include general land use patterns (e.g., urban, agricultural, forested), population patterns, and sources of employment in the project vicinity.
(xii) Tribal resources. A description of Indian tribes, tribal lands, and interests that may be affected by the project Components of this description include:
(A) Identification of information on resources specified in paragraphs (d)(2)(ii)–(xi) of this section to the extent that existing project construction and operation affecting those resources may impact tribal cultural or economic interests, e.g., impacts of project-induced soil erosion on tribal cultural sites; and
(B) Identification of impacts on Indian tribes of existing project construction and operation that may affect tribal interests not necessarily associated with resources specified in paragraphs (d)(3)(ii)–(xi) of this Section, e.g., tribal fishing practices or agreements between the Indian tribe and other entities other than the potential applicant that have a connection to project construction and operation.
(xiii) River basin description. A general description of the river basin or sub-basin, as appropriate, in which the proposed project is located, including information on:
(A) The area of the river basin or sub-basin and length of stream reaches therein;
(B) Major land and water uses in the project area;
(C) All dams and diversion structures in the basin or sub-basin, regardless of function; and
(D) Tributary rivers and streams, the resources of which are or may be affected by project operations;
(4) Preliminary issues and studies list. Based on the resource description and impacts discussion required by paragraph (d)(3) of this section; the pre-application document must include with respect to each resource area identified above, a list of:
(i) Issues pertaining to the identified resources;
(ii) Potential studies or information gathering requirements associated with the identified issues;
(iii) Relevant qualifying Federal and state or tribal comprehensive waterway plans; and
(iv) Relevant resource management plans.
(5) Summary of contacts. An appendix summarizing contacts with Federal, state, and interstate resource agencies, Indian tribes, non-governmental organizations, or other members of the public made in connection with preparing the pre-application document sufficient to enable the Commission to determine if due diligence has been exercised in obtaining relevant information.
(e) If applicable, the applicant must also provide a statement of whether or not it will seek benefits under section 210 of the Public Utility Regulatory Policies Act of 1978 (PURPA) by satisfying the requirements for qualifying hydroelectric small power production facilities in § 292.203 of this chapter. If benefits under section 210 of PURPA are sought, a statement of whether or not the applicant believes the project is located at a new dam or diversion (as that term is defined in § 292.202(p) of this chapter), and a request for the agencies’ view on that belief, if any.
§ 5.7 Tribal consultation.
A meeting shall be held no later than 30 days following filing of the notification of intent required by § 5.5 between each Indian tribe likely to be affected by the potential license application and the Commission staff if the affected Indian tribe agrees to such meeting.
§ 5.8 Notice of commencement of proceeding and scoping document, or of approval to use traditional licensing process or alternative procedures.
(a) Notice. Within 60 days of the notification of intent required under § 5.5, filing of the pre-application document pursuant to § 5.6, and filing of any request to use the traditional licensing process or alternative procedures, the Commission will issue a notice of commencement of proceeding and scoping document or of approval of a request to use the traditional licensing process or alternative procedures.
(b) Notice contents. The notice shall include:
(1) The decision of the Director of the Office of Energy Projects on any request to use the traditional licensing process or alternative procedures.
(2) If appropriate, a request by the Commission to initiate informal consultation under section 7 of the Endangered Species Act and the joint agency regulations thereunder at 50 CFR part 402, section 305(b) of the Magnuson-Stevens Fishery Conservation and Management Act and implementing regulations at 50 CFR 600.920, or section 106 of the National Historic Preservation Act and implementing regulations at 36 CFR 800.2, and, if applicable, designation of the potential applicant as the Commission’s non-federal representative.
(3) If the potential license application is to be developed and filed pursuant to this part, notice of:
(i) The applicant’s intent to file a license application;
(ii) The filing of the pre-application document;
(iii) Commencement of the proceeding;
(iv) A request for comments on the pre-application document (including the proposed process plan and schedule);
(v) A statement that all communications to or from the Commission staff related to the merits of the potential application must be filed with the Commission;
(vi) The request for other Federal or state agencies or Indian tribes to be cooperating agencies for purposes of developing an environmental document;
(vii) The Commission’s intent with respect to preparation of an environmental impact statement; and
(viii) A public scoping meeting and site visit to be held within 30 days of the notice.
(c) Scoping Document 1. At the same time the Commission issues the notice provided for in paragraph (a) of this Section, the Commission staff will issue Scoping Document 1. Scoping Document 1 will include:
(1) An introductory section describing the purpose of the scoping document, the date and time of the scoping meeting, procedures for submitting written comments, and a request for information or study requests from state and Federal resource agencies, Indian tribes, non-governmental organizations, and individuals;
(2) Identification of the proposed action, including a description of the project’s location, facilities, and operation, and any proposed protection and enhancement measures, and other alternatives to the proposed action, including alternatives considered but eliminated from further study, and the no action alternative;
(3) Identification of resource issues to be analyzed in the environmental document, including those that would be cumulatively affected along with a description of the geographic and temporal scope of the cumulatively affected resources;
(4) A list of qualifying Federal and state comprehensive waterway plans;
(5) A list of qualifying tribal comprehensive waterway plans;
(6) A process plan and schedule and a draft outline of the environmental document; and
(7) A list of recipients.
(d) Scoping meeting and site visit. The purpose of the public meeting and site visit is to:
(1) Initiate issues scoping pursuant to the National Environmental Policy Act;
(2) Review and discuss existing conditions and resource management objectives;
(3) Review and discuss existing information and make preliminary identification of information and study needs;
(4) Review, discuss, and finalize the process plan and schedule for pre-filing activity that incorporates the time periods provided for in this part and, to the extent reasonably possible, maximizes coordination of Federal, state, and tribal permitting and certification processes, including consultation under section 7 of the Endangered Species Act and water quality certification or waiver thereof under section 401 of the Clean Water Act; and
(5) Discuss the appropriateness of any Federal or state agency or Indian tribe acting as a cooperating agency for development of an environmental document pursuant to the National Environmental Policy Act.
(e) Method of notice. The public notice provided for in this section will be given by:
(1) Publishing notice in the
(2) Publishing notice in a daily or weekly newspaper published in the county or counties in which the project or any part thereof or the lands affected thereby are situated, and, as appropriate, tribal newspapers;
(3) Notifying appropriate Federal, state, and interstate resource agencies, state water quality and coastal zone management plan consistency certification agencies, Indian tribes, and non-governmental organizations, by electronic means if practical, otherwise by mail.
§ 5.9 Comments and information or study requests.
(a) Comments and study requests. Comments on the pre-application document and the Commission staff’s Scoping Document 1 must be filed with the Commission within 60 days following the Commission’s notice of consultation procedures issued pursuant to § 5.8. Comments, including those by Commission staff, must be accompanied by any information gathering and study requests, and should include information and studies needed for consultation under section 7 of the Endangered Species Act and water quality certification under Section 401 of the Clean Water Act.
(b) Content of study request. Any information or study request must:
(1) Describe the goals and objectives of each study proposal and the information to be obtained;
(2) If applicable, explain the relevant resource management goals of the agencies or Indian tribes with jurisdiction over the resource to be studied;
(3) If the requester is not a resource agency, explain any relevant public interest considerations in regard to the proposed study;
(4) Describe existing information concerning the subject of the study proposal, and the need for additional information;
(5) Explain any nexus between project operations and effects (direct, indirect, and/or cumulative) on the resource to be studied, and how the study results would inform the development of license requirements;
(6) Explain how any proposed study methodology (including any preferred data collection and analysis techniques, or objectively quantified information, and a schedule including appropriate field season(s) and the duration) is consistent with generally accepted practice in the scientific community or, as appropriate, considers relevant tribal values and knowledge; and
(7) Describe considerations of level of effort and cost, as applicable, and why any proposed alternative studies would not be sufficient to meet the stated information needs.
(c) Applicant seeking PURPA benefits; estimate of fees. If a potential applicant has stated that it intends to seek PURPA benefits, comments on the pre-application document by a fish and wildlife agency must provide the potential applicant with a reasonable estimate of the total costs the agency anticipates it will incur in order to set mandatory terms and conditions for the proposed project. An agency may provide a potential applicant with an updated estimate as it deems necessary. If any agency believes that its most recent estimate will be exceeded by more than 25 percent, it must supply the potential applicant with a new estimate and submit a copy to the Commission.
§ 5.10 Scoping Document 2.
Within 45 days following the deadline for filing of comments on Scoping Document 1, the Commission staff shall, if necessary, issue Scoping Document 2.
§ 5.11 Potential Applicant’s proposed study plan and study plan meetings.
(a) Within 45 days following the deadline for filing of comments on the pre-application document, including information and study requests, the potential applicant must file with the Commission a proposed study plan.
(b) The potential applicant’s proposed study plan must include with respect to each proposed study:
(1) A detailed description of the study and the methodology to be used;
(2) A schedule for conducting the study;
(3) Provisions for periodic progress reports, including the manner and extent to which information will be shared; and sufficient time for technical review of the analysis and results; and
(4) If the potential applicant does not adopt a requested study, an explanation of why the request was not adopted, with reference to the criteria set forth in § 5.9(b).
(c) The potential applicant’s proposed study plan must also include provisions for the initial and updated study reports and meetings provided for in § 5.15.
(d) The applicant’s proposed study plan must:
(1) Describe the goals and objectives of each study proposal and the information to be obtained;
(2) Address any known resource management goals of the agencies or Indian tribes with jurisdiction over the resource to be studied;
(3) Describe existing information concerning the subject of the study proposal, and the need for additional information;
(4) Explain any nexus between project operations and effects (direct, indirect, and/or cumulative) on the resource to be studied;
(5) Explain how any proposed study methodology (including any preferred data collection and analysis techniques, or objectively quantified information, and a schedule including appropriate field season(s) and the duration) is consistent with generally accepted practice in the scientific community or, as appropriate, considers any known tribal interests;
(6) Describe considerations of level of effort and cost, as applicable.
(e) The potential applicant’s proposed study plan must be accompanied by a proposal for conducting a study plan meeting or meetings during the 90-day period provided for in § 5.12 for the purpose of clarifying the potential applicant’s proposed study plan and any initial information gathering or study requests, and to resolve any outstanding issues with respect to the proposed study plan. The initial study plan meeting must be held no later than 30 days after the deadline date for filing of the potential applicant’s proposed study plan.
§ 5.12 Comments on proposed study plan.
Comments on the potential applicant’s proposed study plan, including any revised information or study requests, must be filed within 90 days after the proposed study plan is filed. This filing must also include an explanation of any study plan concerns and any accommodations reached with the potential applicant regarding those concerns. Any proposed modifications to the potential applicant’s proposed study plan must address the criteria in § 5.9(b).
§ 5.13 Revised study plan and study plan determination.
(a) Within 30 days following the deadline for filing comments on the potential applicant’s proposed study plan, as provided for in § 5.12, the potential applicant must file a revised study plan for Commission approval. The revised study plan shall include the comments on the proposed study plan and a description of the efforts made to resolve differences over study requests. If the potential applicant does not adopt a requested study, it must explain why the request was not adopted, with reference to the criteria set forth in § 5.9(b).
(b) Within 15 days following filing of the potential applicant’s revised study plan, participants may file comments thereon.
(c) Within 30 days following the date the potential applicant files its revised study plan, the Director of Energy Projects will issue a Study Plan Determination with regard to the potential applicant’s study plan, including any modifications determined to be necessary in light of the record.
(d) If no notice of study dispute is filed pursuant to § 5.14 within 20 days of the Study Plan Determination, the study plan as approved in the Study Plan Determination shall be deemed to be approved and the potential applicant shall proceed with the approved studies. If a potential applicant fails to obtain or conduct a study as required by Study Plan Determination, its license application may be considered deficient.
§ 5.14 Formal study dispute resolution process.
(a) Within 20 days of the Study Plan Determination, any Federal agency with authority to provide mandatory conditions on a license pursuant to FPA Section 4(e), 16 U.S.C. 797(e), or to prescribe fishways pursuant to FPA Section 18, 16 U.S.C. 811, or any agency or Indian tribe with authority to issue a water quality certification for the project license under section 401 of the Clean Water Act, 42 U.S.C. 1341, may file a notice of study dispute with respect to studies pertaining directly to the exercise of their authorities under sections 4(e) and 18 of the Federal Power Act or section 401 of the Clean Water Act.
(b) The notice of study dispute must explain how the disputing agency’s or Indian tribe’s study request satisfies the criteria set forth in § 5.9(b), and shall identify and provide contact information for the panel member designated by the disputing agency or Indian tribe, as discussed in paragraph (d) of this section.
(c) Studies and portions of study plans approved in the Study Plan Determination that are not the subject of a notice of dispute shall be deemed to be approved, and the potential applicant shall proceed with those studies or portions thereof.
(d) Within 20 days of a notice of study dispute, the Commission will convene one or more three-person Dispute Resolution Panels, as appropriate to the circumstances of each proceeding. Each such panel will consist of:
(1) A person from the Commission staff who is not otherwise involved in the proceeding, and who shall serve as the panel chair;
(2) One person designated by the Federal or state agency or Indian tribe that filed the notice of dispute who is not otherwise involved in the proceeding; and
(3) A third person selected by the other two panelists from a pre-established list of persons with expertise in the resource area. The two panelists shall make every reasonable effort to select the third panel member. If however no third panel member has been selected by the other two panelists within 15 days, an appropriate third panel member will be selected at random from the list of technical experts maintained by the Commission.
(e) If more than one agency or Indian tribe files a notice of dispute with respect to the decision in the preliminary determination on any information-gathering or study request, the disputing agencies or Indian tribes must select one person to represent their interests on the panel.
(f) The list of persons available to serve as a third panel member will be posted, as revised from time-to-time, on the hydroelectric page of the Commission’s Web site. A person on the list who is requested and willing to serve with respect to a specific dispute will be required to file with the Commission at that time a current statement of their qualifications, a statement that they have had no prior involvement with the proceeding in which the dispute has arisen, or other financial or other conflict of interest.
(g) All costs of the panel members representing the Commission staff and the agency or Indian tribe which filed the notice of dispute will be borne by the Commission or the agency or Indian tribe, as applicable. The third panel member will serve without compensation, except for certain allowable travel expenses as defined in 31 CFR part 301.
(h) To facilitate the delivery of information to the dispute resolution panel, the identity of the panel members and their addresses for personal service with respect to a specific dispute resolution will be posted on the hydroelectric page of the Commission’s Web site.
(i) No later than 25 days following the notice of study dispute, the potential applicant may file with the Commission and serve upon the panel members comments and information regarding the dispute.
(j) Prior to engaging in deliberative meetings, the panel shall hold a technical conference for the purpose of clarifying the matters in dispute with reference to the study criteria. The technical conference shall be chaired by the Commission staff member of the panel. It shall be open to all participants, and the panel shall receive information from the participants as it deems appropriate.
(k) No later than 50 days following the notice of study dispute, the panel shall make and deliver to the Director of the Office of Energy Projects a finding, with respect to each information or study request in dispute, concerning the extent to which each criteria set forth in § 5.9(b) is met or not met, and why, and make recommendations regarding the disputed study request based on its findings. The panel’s findings and recommendations must be based on the record in the proceeding. The panel shall file with its findings and recommendations all of the materials received by the panel. Any recommendation for the potential applicant to provide information or a study must include the technical specifications, including data acquisition techniques and methodologies.
(l) No later than 70 days from the date of filing of the notice of study dispute, the Director of the Office of Energy Projects will review and consider the recommendations of the panel, and will issue a written determination. The Director’s determination will be made with reference to the study criteria set forth in § 5.9(b) and any applicable law or Commission policies and practices, will take into account the technical expertise of the panel, and will explain why any panel recommendation was rejected, if applicable. The Director’s determination shall constitute an amendment to the approved study plan.
§ 5.15 Conduct of studies.
(a) Implementation. The potential applicant must gather information and conduct studies as provided for in the approved study plan and schedule.
(b) Progress reports. The potential applicant must prepare and provide to the participants the progress reports provided for in § 5.11(b)(3). Upon request of any participant, the potential applicant will provide documentation of study results.
(c) Initial study report. (1) Pursuant to the Commission-approved study plan and schedule provided for in § 5.13 or no later than one year after Commission approval of the study plan, whichever comes first, the potential applicant must prepare and file with the Commission an initial study report describing its overall progress in implementing the study plan and schedule and the data collected, including an explanation of any variance from the study plan and schedule. The report must also include any modifications to ongoing studies or new studies proposed by the potential applicant.
(2) Within 15 days following the filing of the initial study report, the potential applicant shall hold a meeting with the participants and Commission staff to discuss the study results and the potential applicant’s and or other participant’s proposals, if any, to modify the study plan in light of the progress of the study plan and data collected.
(3) Within 15 days following the meeting provided for in paragraph (c)(2) of this section, the potential applicant shall file a meeting summary, including any modifications to ongoing studies or new studies proposed by the potential applicant.
(4) Any participant or the Commission staff may file a disagreement concerning the applicant’s meeting summary within 30 days, setting forth the basis for the disagreement. This filing must also include any modifications to ongoing studies or new studies proposed by the Commission staff or other participant.
(5) Responses to any filings made pursuant to paragraph (c)(4) of this section must be filed within 30 days.
(6) No later than 30 days following the due date for responses provided for in paragraph (c)(5) of this section, the Director will resolve the disagreement and amend the approved study plan as appropriate.
(7) If no participant or the Commission staff files a disagreement concerning the potential applicant’s meeting summary and request to amend the approved study plan within 30 days, any proposed amendment shall be deemed to be approved.
(d) Criteria for modification of approved study. Any proposal to modify an ongoing study pursuant to paragraphs (c)(1)–(4) of this section must be accompanied by a showing of good cause why the proposal should be approved, and must include, as appropriate to the facts of the case, a demonstration that:
(1) Approved studies were not conducted as provided for in the approved study plan; or
(2) The study was conducted under anomalous environmental conditions or that environmental conditions have changed in a material way.
(e) Criteria for new study. Any proposal for new information gathering or studies pursuant to paragraphs (c)(1)–(4) of this section must be accompanied by a showing of good cause why the proposal should be approved, and must include, as appropriate to the facts of the case, a statement explaining:
(1) Any material changes in the law or regulations applicable to the information request;
(2) Why the goals and objectives of any approved study could not be met with the approved study methodology;
(3) Why the request was not made earlier;
(4) Significant changes in the project proposal or that significant new information material to the study objectives has become available; and
(5) Why the new study request satisfies the study criteria in § 5.9(b).
(f) Updated study report. Pursuant to the Commission-approved study plan and schedule provided for in § 5.13, or no later than two years after Commission approval of the study plan and schedule, whichever comes first, the potential applicant shall prepare and file with the Commission an updated study report describing its overall progress in implementing the study plan and schedule and the data collected, including an explanation of any variance from the study plan and schedule. The report must also include any modifications to ongoing studies or new studies proposed by the potential applicant. The review, comment, and disagreement resolution provisions of paragraphs (c)(2)–(7) of this section shall apply to the updated study report. Any proposal to modify an ongoing study must be accompanied by a showing of good cause why the proposal should be approved as set forth in paragraph (d) of this section. Any proposal for new information gathering or studies is subject to paragraph (e) of this section except that the proponent must demonstrate extraordinary circumstances warranting approval. The applicant must promptly proceed to complete any remaining undisputed information-gathering or studies under its proposed amendments to the study plan, if any, and must proceed to complete any information-gathering or studies that are the subject of a disagreement upon the Director’s resolution of the disagreement.
§ 5.16 Preliminary licensing proposal.
(a) No later than 150 days prior to the deadline for filing a new or subsequent license application, if applicable, the potential applicant must file for comment a preliminary licensing proposal.
(b) The preliminary licensing proposal must:
(1) Clearly describe, as applicable, the existing and proposed project facilities, including project lands and waters;
(2) Clearly describe, as applicable, the existing and proposed project operation and maintenance plan, to include measures for protection, mitigation, and enhancement measures with respect to each resource affected by the project proposal; and
(3) Include the potential applicant’s draft environmental analysis by resource area of the continuing and incremental impacts, if any, of its preliminary licensing proposal, including the results of its studies conducted under the approved study plan.
(c) A potential applicant may elect to file a draft license application which includes the contents of a license application required by § 5.18 instead of the Preliminary Licensing Proposal. A potential applicant that elects to file a draft license application must include notice of its intent to do so in the updated study report required by § 5.15(f).
(d) A potential applicant that has been designated as the Commission’s non-Federal representative may include a draft Biological Assessment, draft Essential Fish Habitat Assessment, and draft Historic Properties Management Plan with its Preliminary Licensing Proposal or draft license application.
(e) Within 90 days of the date the potential applicant files the Preliminary Licensing Proposal or draft license application, participants and the Commission staff may file comments on the Preliminary Licensing Proposal or draft application, which may include recommendations on whether the Commission should prepare an Environmental Assessment (with or without a draft Environmental Assessment) or an Environmental Impact Statement. Any participant whose comments request new information, studies, or other amendments to the approved study plan must include a demonstration of extraordinary circumstances, pursuant to the requirements of § 5.15(f).
(f) A waiver of the requirement to file the Preliminary Licensing Proposal or draft license application may be requested, based on a consensus of the participants in favor of such waiver.
§ 5.17 Filing of application.
(a) Deadline—new or subsequent license application. An application for a new or subsequent license must be filed no later than 24 months before the existing license expires.
(b) Subsequent licenses. An applicant for a subsequent license must file its application under part I of the Federal Power Act. The provisions of section 7(a) of the Federal Power Act do not apply to licensing proceedings involving a subsequent license.
(c) Rejection or dismissal of application. If the Commission rejects or dismisses an application for a new or subsequent license filed under this part pursuant to the provisions of § 5.20, the application may not be refiled after the new or subsequent license application filing deadline specified in paragraph (a) of this section.
(d)(1) Filing and service. Each applicant for a license under this part must submit the application to the Commission’s Secretary for filing pursuant to the requirements of subpart T of part 385 of this chapter. The applicant must serve one copy of the application on the Director of the Commission’s Regional Office for the appropriate region and on each resource agency, Indian tribe, or member of the public consulted pursuant to this part.
(2) An applicant must publish notice twice of the filing of its application, no later than 14 days after the filing date in a daily or weekly newspaper of general circulation in each county in which the project is located. The notice must disclose the filing date of the application and briefly summarize it, including the applicant’s name and address, the type of facility applied for, its proposed location, and the places where the information specified in § 5.2(b) is available for inspection and reproduction. The applicant must promptly provide the Commission with proof of the publication of this notice.
(e) PURPA benefits. (1) Every application for a license for a project with a capacity of 80 megawatts or less must include in its application copies of the statements made under § 4.38(b)(2)(vi).
(2) If an applicant reverses a statement of intent not to seek PURPA benefits:
(i) Prior to the Commission issuing a license, the reversal of intent will be treated as an amendment of the application under § 4.35 of this chapter and the applicant must:
(A) Repeat the pre-filing consultation process under this part; and
(B) Satisfy all the requirements in § 292.208 of this chapter; or
(ii) After the Commission issues a license for the project, the applicant is prohibited from obtaining PURPA benefits.
(f) Limitations on submitting applications. The provisions of §§ 4.33(b), (c), and (e) of this chapter apply to license applications filed under this Section.
(g) Applicant notice. An applicant for a subsequent license that proposes to expand an existing project to encompass additional lands must include in its application a statement that the applicant has notified, by certified mail, property owners on the additional lands to be encompassed by the project and governmental agencies and subdivisions likely to be interested in or affected by the proposed expansion.
§ 5.18 Application content.
(a) General content requirements. Each license application filed pursuant to this part must:
(1) Identify every person, citizen, association of citizens, domestic corporation, municipality, or state that has or intends to obtain and will maintain any proprietary right necessary to construct, operate, or maintain the project;
(2) Identify (providing names and mailing addresses):
(i) Every county in which any part of the project, and any Federal facilities that would be used by the project, would be located;
(ii) Every city, town, or similar local political subdivision:
(A) In which any part of the project, and any Federal facilities that would be used by the project, would be located; or
(B) That has a population of 5,000 or more people and is located within 15 miles of the project dam;
(iii) Every irrigation district, drainage district, or similar special purpose political subdivision:
(A) In which any part of the project, and any Federal facilities that would be used by the project, would be located; or
(B) That owns, operates, maintains, or uses any project facilities that would be used by the project;
(iv) Every other political subdivision in the general area of the project that there is reason to believe would likely be interested in, or affected by, the application; and
(v) All Indian tribes that may be affected by the project.
(3)(i) For a license (other than a license under section 15 of the Federal Power Act) state that the applicant has made, either at the time of or before filing the application, a good faith effort to give notification by certified mail of the filing of the application to:
(A) Every property owner of record of any interest in the property within the bounds of the project, or in the case of the project without a specific project boundary, each such owner of property which would underlie or be adjacent to any project works including any impoundments; and
(B) The entities identified in paragraph (a)(2) of this section, as well as any other Federal, state, municipal or other local government agencies that there is reason to believe would likely be interested in or affected by such application.
(ii) Such notification must contain the name, business address, and telephone number of the applicant and a copy of the Exhibit G contained in the application, and must state that a license application is being filed with the Commission.
(4)(i) As to any facts alleged in the application or other materials filed, be subscribed and verified under oath in the form set forth in paragraph (a)(3)(B) of this Section by the person filing, an officer thereof, or other person having knowledge of the matters set forth. If the subscription and verification is by anyone other than the person filing or an officer thereof, it must include a statement of the reasons therefor.
(ii) This application is executed in the:
Subscribed and sworn to before me, a [Notary Public, or title of other official authorized by the state to notarize documents, as appropriate] this ____ day of ____________________, 2______.
(5) Contain the information and documents prescribed in the following Sections of this chapter, except as provided in paragraph (b) of this Section, according to the type of application:
(i) License for a minor water power project and a major water power project 10 MW or less: § 4.61 of this chapter (General instructions, initial statement, and Exhibits A, F, and G);
(ii) License for a major unconstructed project and a major modified project: § 4.41 of this chapter (General instructions, initial statement, Exhibits A, B, C, D, F, and G);
(iii) License for a major project—existing dam: § 4.51 of this chapter (General instructions, initial statement, Exhibits A, B, C, D, F, and G); or
(iv) License for a project located at a new dam or diversion where the applicant seeks PURPA benefits: § 292.208 of this chapter.
(b) Exhibit E—Environmental Exhibit. The specifications for Exhibit E in §§ 4.41, 4.51, or 4.61 of this chapter shall not apply to applications filed under this part. The Exhibit E included in any license application filed under this part must address the resources listed in the Pre-Application Document provided for in § 5.6; follow the Commission’s “Preparing Environmental Assessments: Guidelines for Applicants, Contractors, and Staff,” as they may be updated from time-to-time; and meet the following format and content requirements:
(1) General description of the river basin. Describe the river system, including relevant tributaries; give measurements of the area of the basin and length of stream; identify the project’s river mile designation or other reference point; describe the topography and climate; and discuss major land uses and economic activities.
(2) Cumulative effects. List cumulatively affected resources based on the Commission’s Scoping Document, consultation, and study results. Discuss the geographic and temporal scope of analysis for those resources. Describe how resources are cumulatively affected and explain the choice of the geographic scope of analysis. Include a brief discussion of past, present, and future actions, and their effects on resources based on the new license term (30–50 years). Highlight the effect on the cumulatively affected resources from reasonably foreseeable future actions. Discuss past actions’ effects on the resource in the Affected Environment Section.
(3) Applicable laws. Include a discussion of the status of compliance with or consultation under the following laws, if applicable:
(i) Section 401 of the Clean Water Act. The applicant must file a request for a water quality certification (WQC), as required by Section 401 of the Clean Water Act no later than the deadline specified in § 5.23(b). Potential applicants are encouraged to consult with the certifying agency or tribe concerning information requirements as early as possible.
(ii) Endangered Species Act (ESA). Briefly describe the process used to address project effects on Federally listed or proposed species in the project vicinity. Summarize any anticipated environmental effects on these species and provide the status of the consultation process. If the applicant is the Commission’s non-Federal designee for informal consultation under the ESA, the applicant’s draft biological assessment must be included.
(iii) Magnuson-Stevens Fishery Conservation and Management Act. Document from the National Marine Fisheries Service (NMFS) and/or the appropriate Regional Fishery Management Council any essential fish habitat (EFH) that may be affected by the project. Briefly discuss each managed species and life stage for which EFH was designated. Include, as appropriate, the abundance, distribution, available habitat, and habitat use by the managed species. If the project may affect EFH, prepare a draft “EFH Assessment” of the impacts of the project. The draft EFH Assessment should contain the information outlined in 50 CFR 600.920(e).
(iv) Coastal Zone Management Act (CZMA). Section 307(c)(3) of the CZMA requires that all Federally licensed and permitted activities be consistent with approved state Coastal Zone Management Programs. If the project is located within a coastal zone boundary or if a project affects a resource located in the boundaries of the designated coastal zone, the applicant must certify that the project is consistent with the state Coastal Zone Management Program. If the project is within or affects a resource within the coastal zone, provide the date the applicant sent the consistency certification information to the state agency, the date the state agency received the certification, and the date and action taken by the state agency (for example, the agency will either agree or disagree with the consistency statement, waive it, or ask for additional information). Describe any conditions placed on the state agency’s concurrence and assess the conditions in the appropriate section of the license application. If the project is not in or would not affect the coastal zone, state so and cite the coastal zone program office’s concurrence.
(v) National Historic Preservation Act (NHPA). Section 106 of NHPA requires the Commission to take into account the effect of licensing a hydropower project on any historic properties, and allow the Advisory Council on Historic Preservation (Advisory Council) a reasonable opportunity to comment on the proposed action. “Historic Properties” are defined as any district, site, building, structure, or object that is included in or eligible for inclusion in the National Register of Historic Places (NRHP). If there would be an adverse effect on historic properties, the applicant may include a Historic Properties Management Plan (HPMP) to avoid or mitigate the effects. The applicant must include documentation of consultation with the Advisory Council, the State Historic Preservation Officer, Tribal Historic Preservation Officer, National Park Service, members of the public, and affected Indian tribes, where applicable.
(vi) Pacific Northwest Power Planning and Conservation Act (Act). If the project is not within the Columbia River Basin, this section shall not be included. The Columbia River Basin Fish and Wildlife Program (Program) developed under the Act directs agencies to consult with Federal and state fish and wildlife agencies, appropriate Indian tribes, and the Northwest Power Planning Council (Council) during the study, design, construction, and operation of any hydroelectric development in the basin. Section 12.1A of the Program outlines conditions that should be provided for in any original or new license. The program also designates certain river reaches as protected from development. The applicant must document consultation with the Council, describe how the act applies to the project, and how the proposal would or would not be consistent with the program.
(vii) Wild and Scenic Rivers and Wilderness Acts. Include a description of any areas within or in the vicinity of the proposed project boundary that are included in, or have been designated for study for inclusion in, the National Wild and Scenic Rivers System, or that have been designated as wilderness area, recommended for such designation, or designated as a wilderness study area under the Wilderness Act.
(4) Project facilities and operation. Provide a description of the project to include:
(i) Maps showing existing and proposed project facilities, lands, and waters within the project boundary;
(ii) The configuration of any dams, spillways, penstocks, canals, powerhouses, tailraces, and other structures;
(iii) The normal maximum water surface area and normal maximum water surface elevation (mean sea level), gross storage capacity of any impoundments;
(iv) The number, type, and minimum and maximum hydraulic capacity and installed (rated) capacity of existing and proposed turbines or generators to be included as part of the project;
(v) An estimate of the dependable capacity, and average annual energy production in kilowatt hours (or mechanical equivalent);
(vi) A description of the current (if applicable) and proposed operation of the project, including any daily or seasonal ramping rates, flushing flows, reservoir operations, and flood control operations.
(5) Proposed action and action alternatives. (i) The environmental document must explain the effects of the applicant’s proposal on resources. For each resource area addressed include:
(A) A discussion of the affected environment;
(B) A detailed analysis of the effects of the applicant’s licensing proposal and, if reasonably possible, any preliminary terms and conditions filed with the Commission; and
(C) Any unavoidable adverse impacts.
(ii) The environmental document must contain, with respect to the resources listed in the Pre-Application Document provided for in § 5.6, and any other resources identified in the Commission’s scoping document prepared pursuant to the National Environmental Policy Act and § 5.8, the following information, commensurate with the scope of the project:
(A) Affected environment. The applicant must provide a detailed description of the affected environment or area(s) to be affected by the proposed project by each resource area. This description must include the information on the affected environment filed in the Pre-Application Document provided for in § 5.6, developed under the applicant’s approved study plan, and otherwise developed or obtained by the applicant. This section must include a general description of socio-economic conditions in the vicinity of the project including general land use patterns (e.g., urban, agricultural, forested), population patterns, and sources of employment in the project vicinity.
(B) Environmental analysis. The applicant must present the results of its studies conducted under the approved study plan by resource area and use the data generated by the studies to evaluate the beneficial and adverse environmental effects of its proposed project. This section must also include, if applicable, a description of any anticipated continuing environmental impacts of continued operation of the project, and the incremental impact of proposed new development of project works or changes in project operation. This analysis must be based on the information filed in the Pre-Application Document provided for in § 5.6, developed under the applicant’s approved study plan, and other appropriate information, and otherwise developed or obtained by the Applicant.
(C) Proposed environmental measures. The applicant must provide, by resource area, any proposed new environmental measures, including, but not limited to, changes in the project design or operations, to address the environmental effects identified above and its basis for proposing the measures. The applicant must describe how each proposed measure would protect or enhance the existing environment, including, where possible, a non-monetary quantification of the anticipated environmental benefits of the measure. This section must also include a statement of existing measures to be continued for the purpose of protecting and improving the environment and any proposed preliminary environmental measures received from the consulted resource agencies, Indian tribes, or the public. If an applicant does not adopt a preliminary environmental measure proposed by a resource agency, Indian tribe, or member of the public, it must include its reasons, based on project-specific information.
(D) Unavoidable adverse impacts. Based on the environmental analysis, discuss any adverse impacts that would occur despite the recommended environmental measures. Discuss whether any such impacts are short- or long-term, minor or major, cumulative or site-specific.
(E) Economic analysis. The economic analysis must include annualized, current cost-based information. For a new or subsequent license, the applicant must include the cost of operating and maintaining the project under the existing license. For an original license, the applicant must estimate the cost of constructing, operating, and maintaining the proposed project. For either type of license, the applicant should estimate the cost of each proposed resource protection, mitigation, or enhancement measure and any specific measure filed with the Commission by agencies, Indian tribes, or members of the public when the application is filed. For an existing license, the applicant’s economic analysis must estimate the value of developmental resources associated with the project under the current license and the applicant’s proposal. For an original license, the applicant must estimate the value of the developmental resources for the proposed project. As applicable, these developmental resources may include power generation, water supply, irrigation, navigation, and flood control. Where possible, the value of developmental resources must be based on market prices. If a protection, mitigation, or enhancement measure reduces the amount or value of the project’s developmental resources, the applicant must estimate the reduction.
(F) Consistency with comprehensive plans. Identify relevant comprehensive plans and explain how and why the proposed project would, would not, or should not comply with such plans and a description of any relevant resource agency or Indian tribe determination regarding the consistency of the project with any such comprehensive plan.
(G) Consultation Documentation. Include a list containing the name, and address of every Federal, state, and interstate resource agency, Indian tribe, or member of the public with which the applicant consulted in preparation of the Environmental Document.
(H) Literature cited. Cite all materials referenced including final study reports, journal articles, other books, agency plans, and local government plans.
(iii) The applicant must also provide in the Environmental Document:
(A) Functional design drawings of any fish passage and collection facilities or any other facilities necessary for implementation of environmental measures, indicating whether the facilities depicted are existing or proposed (these drawings must conform to the specifications of § 4.39 of this chapter regarding dimensions of full-sized prints, scale, and legibility);
(B) A description of operation and maintenance procedures for any existing or proposed measures or facilities;
(C) An implementation or construction schedule for any proposed measures or facilities, showing the intervals following issuance of a license when implementation of the measures or construction of the facilities would be commenced and completed;
(D) An estimate of the costs of construction, operation, and maintenance, of any proposed facilities, and of implementation of any proposed environmental measures.
(E) A map or drawing that conforms to the size, scale, and legibility requirements of § 4.39 of this chapter showing by the use of shading, cross-hatching, or other symbols the identity and location of any measures or facilities, and indicating whether each measure or facility is existing or proposed (the map or drawings in this exhibit may be consolidated).
(c) Exhibit H. The information required to be provided by this paragraph (c) must be included in the application as a separate exhibit labeled “Exhibit H.”
(1) Information to be provided by an applicant for new license: Filing requirements—(i) Information to be supplied by all applicants. All Applicants for a new license under this part must file the following information with the Commission:
(A) A discussion of the plans and ability of the applicant to operate and maintain the project in a manner most likely to provide efficient and reliable electric service, including efforts and plans to:
(1) Increase capacity or generation at the project;
(2) Coordinate the operation of the project with any upstream or downstream water resource projects; and
(3) Coordinate the operation of the project with the applicant’s or other electrical systems to minimize the cost of production.
(B) A discussion of the need of the applicant over the short and long term for the electricity generated by the project, including:
(1) The reasonable costs and reasonable availability of alternative sources of power that would be needed by the applicant or its customers, including wholesale customers, if the applicant is not granted a license for the project;
(2) A discussion of the increase in fuel, capital, and any other costs that would be incurred by the applicant or its customers to purchase or generate power necessary to replace the output of the licensed project, if the applicant is not granted a license for the project;
(3) The effect of each alternative source of power on:
(i) The applicant’s customers, including wholesale customers;
(ii) The applicant’s operating and load characteristics; and
(iii) The communities served or to be served, including any reallocation of costs associated with the transfer of a license from the existing licensee.
(C) The following data showing need and the reasonable cost and availability of alternative sources of power:
(1) The average annual cost of the power produced by the project, including the basis for that calculation;
(2) The projected resources required by the applicant to meet the applicant’s capacity and energy requirements over the short and long term including:
(i) Energy and capacity resources, including the contributions from the applicant’s generation, purchases, and load modification measures (such as conservation, if considered as a resource), as separate components of the total resources required;
(ii) A resource analysis, including a statement of system reserve margins to be maintained for energy and capacity; and
(iii) If load management measures are not viewed as resources, the effects of such measures on the projected capacity and energy requirements indicated separately;
(iv) For alternative sources of power, including generation of additional power at existing facilities, restarting deactivated units, the purchase of power off-system, the construction or purchase and operation of a new power plant, and load management measures such as conservation: The total annual cost of each alternative source of power to replace project power; the basis for the determination of projected annual cost; and a discussion of the relative merits of each alternative, including the issues of the period of availability and dependability of purchased power, average life of alternatives, relative equivalent availability of generating alternatives, and relative impacts on the applicant’s power system reliability and other system operating characteristics; and the effect on the direct providers (and their immediate customers) of alternate sources of power.
(D) If an applicant uses power for its own industrial facility and related operations, the effect of obtaining or losing electricity from the project on the operation and efficiency of such facility or related operations, its workers, and the related community.
(E) If an applicant is an Indian tribe applying for a license for a project located on the tribal reservation, a statement of the need of such Indian tribe for electricity generated by the project to foster the purposes of the reservation.
(F) A comparison of the impact on the operations and planning of the applicant’s transmission system of receiving or not receiving the project license, including:
(1) An analysis of the effects of any resulting redistribution of power flows on line loading (with respect to applicable thermal, voltage, or stability limits), line losses, and necessary new construction of transmission facilities or upgrading of existing facilities, together with the cost impact of these effects;
(2) An analysis of the advantages that the applicant’s transmission system would provide in the distribution of the project’s power; and
(3) Detailed single-line diagrams, including existing system facilities identified by name and circuit number, that show system transmission elements in relation to the project and other principal interconnected system elements. Power flow and loss data that represent system operating conditions may be appended if applicants believe such data would be useful to show that the operating impacts described would be beneficial.
(G) If the applicant has plans to modify existing project facilities or operations, a statement of the need for, or usefulness of, the modifications, including at least a reconnaissance-level study of the effect and projected costs of the proposed plans and any alternate plans, which in conjunction with other developments in the area would conform with a comprehensive plan for improving or developing the waterway and for other beneficial public uses as defined in Section 10(a)(1) of the Federal Power Act.
(H) If the applicant has no plans to modify existing project facilities or operations, at least a reconnaissance-level study to show that the project facilities or operations in conjunction with other developments in the area would conform with a comprehensive plan for improving or developing the waterway and for other beneficial public uses as defined in Section 10(a)(1) of the Federal Power Act.
(I) A statement describing the applicant’s financial and personnel resources to meet its obligations under a new license, including specific information to demonstrate that the applicant’s personnel are adequate in number and training to operate and maintain the project in accordance with the provisions of the license.
(J) If an applicant proposes to expand the project to encompass additional lands, a statement that the applicant has notified, by certified mail, property owners on the additional lands to be encompassed by the project and governmental agencies and subdivisions likely to be interested in or affected by the proposed expansion.
(K) The applicant’s electricity consumption efficiency improvement program, as defined under Section 10(a)(2)(C) of the Federal Power Act, including:
(1) A statement of the applicant’s record of encouraging or assisting its customers to conserve electricity and a description of its plans and capabilities for promoting electricity conservation by its customers; and
(2) A statement describing the compliance of the applicant’s energy conservation programs with any applicable regulatory requirements.
(L) The names and mailing addresses of every Indian tribe with land on which any part of the proposed project would be located or which the applicant reasonably believes would otherwise be affected by the proposed project.
(ii) Information to be provided by an applicant licensee. An existing licensee that applies for a new license must provide:
(A) The information specified in paragraph (c)(1) of this section.
(B) A statement of measures taken or planned by the licensee to ensure safe management, operation, and maintenance of the project, including:
(1) A description of existing and planned operation of the project during flood conditions;
(2) A discussion of any warning devices used to ensure downstream public safety;
(3) A discussion of any proposed changes to the operation of the project or downstream development that might affect the existing Emergency Action Plan, as described in subpart C of part 12 of this chapter, on file with the Commission;
(4) A description of existing and planned monitoring devices to detect structural movement or stress, seepage, uplift, equipment failure, or water conduit failure, including a description of the maintenance and monitoring programs used or planned in conjunction with the devices; and
(5) A discussion of the project’s employee safety and public safety record, including the number of lost-time accidents involving employees and the record of injury or death to the public within the project boundary.
(C) A description of the current operation of the project, including any constraints that might affect the manner in which the project is operated.
(D) A discussion of the history of the project and record of programs to upgrade the operation and maintenance of the project.
(E) A summary of any generation lost at the project over the last five years because of unscheduled outages, including the cause, duration, and corrective action taken.
(F) A discussion of the licensee’s record of compliance with the terms and conditions of the existing license, including a list of all incidents of noncompliance, their disposition, and any documentation relating to each incident.
(G) A discussion of any actions taken by the existing licensee related to the project which affect the public.
(H) A summary of the ownership and operating expenses that would be reduced if the project license were transferred from the existing licensee.
(I) A statement of annual fees paid under part I of the Federal Power Act for the use of any Federal or Indian lands included within the project boundary.
(iii) Information to be provided by an applicant who is not an existing licensee. An applicant that is not an existing licensee must provide:
(A) The information specified in paragraph (c)(1) of this section.
(B) A statement of the applicant’s plans to manage, operate, and maintain the project safely, including:
(1) A description of the differences between the operation and maintenance procedures planned by the applicant and the operation and maintenance procedures of the existing licensee;
(2) A discussion of any measures proposed by the applicant to implement the existing licensee’s Emergency Action Plan, as described in subpart C of part 12 of this chapter, and any proposed changes;
(3) A description of the applicant’s plans to continue safety monitoring of existing project instrumentation and any proposed changes; and
(4) A statement indicating whether or not the applicant is requesting the licensee to provide transmission services under section 15(d) of the Federal Power Act.
(d) Consistency with comprehensive plans. An application for license under this part must include an explanation of why the project would, would not, or should not, comply with any relevant comprehensive plan as defined in § 2.19 of this chapter and a description of any relevant resource agency or Indian tribe determination regarding the consistency of the project with any such comprehensive plan.
(e) Response to information requests. An application for license under this Section must respond to any requests for additional information-gathering or studies filed with comments on its preliminary licensing proposal or draft license application. If the license applicant agrees to do the information-gathering or study, it must provide the information or include a plan and schedule for doing so, along with a schedule for completing any remaining work under the previously approved study plan, as it may have been amended. If the applicant does not agree to any additional information-gathering or study requests made in comments on the draft license application, it must explain the basis for declining to do so.
(f) Maps and drawings. All required maps and drawings must conform to the specifications of § 4.39 of this chapter.
§ 5.19 Tendering notice and schedule.
(a) Notice. Within 14 days of the filing date of any application for a license developed pursuant to this part, the Commission will issue public notice of the tendering for filing of the application. The tendering notice will include a preliminary schedule for expeditious processing of the application, including dates for:
(1) Issuance of the acceptance for filing and ready for environmental analysis notice provided for in § 5.22.
(2) Filing of recommendations, preliminary terms and conditions, and fishway prescriptions;
(3) Issuance of a draft environmental assessment or environmental impact statement, or an environmental assessment not preceded by a draft.
(4) Filing of comments on the draft environmental assessment or environmental impact statement, as applicable;
(5) Filing of modified recommendations, mandatory terms and conditions, and fishway prescriptions in response to a draft NEPA document or Environmental Analysis, if no draft NEPA document is issued;
(6) Issuance of a final NEPA document, if any;
(7) In the case of a new or subsequent license application, a deadline for submission of final amendments, if any, to the application; and
(8) Readiness of the application for Commission decision.
(b) Modifications to process plan and schedule. The tendering notice shall also include any known modifications to the schedules developed pursuant to § 5.8 for completion of consultation under section 7 of the Endangered Species Act and water quality certification under section 401 of the Clean Water Act.
(c) Method of notice. The public notice provided for in paragraphs (a) and (b) of this Section will be given by:
(1) Publishing notice in the
(2) Notifying appropriate Federal, state, and interstate resource agencies, state water quality and coastal zone management plan consistency certification agencies, Indian tribes, and non-governmental organizations, by electronic means if practical, otherwise by mail.
(d) Resolution of pending information requests. Within 30 days of the filing date of any application for a license developed pursuant to this part, the Director of the Office of Energy Projects will issue an order resolving any requests for additional information-gathering or studies made in comments on the preliminary licensing proposal or draft license application.
§ 5.20 Deficient applications.
(a) Deficient applications. (1) If an applicant believes that its application conforms adequately to the pre-filing consultation and filing requirements of this part without containing certain required materials or information, it must explain in detail why the material or information is not being submitted and what steps were taken by the applicant to provide the material or information.
(2) Within 30 days of the filing date of any application for a license under this part, the Director of the Office of Energy Projects will notify the applicant if, in the Director’s judgment, the application does not conform to the prefiling consultation and filing requirements of this part, and is therefore considered deficient. An applicant having a deficient application will be afforded additional time to correct the deficiencies, not to exceed 90 days from the date of notification. Notification will be by letter or, in the case of minor deficiencies, by telephone. Any notification will specify the deficiencies to be corrected. Deficiencies must be corrected by submitting an a filing pursuant to the requirements of subpart T of part 385 of this chapter within the time specified in the notification of deficiency.
(3) If the revised application is found not to conform to the prefiling consultation and filing requirements of this part, or if the revisions are not timely submitted, the revised application will be rejected. Procedures for rejected applications are specified in paragraph (b)(3) of this section.
(b) Patently deficient applications. (1) If, within 30 days of its filing date, the Director of the Office of Energy Projects determines that an application patently fails to substantially comply with the prefiling consultation and filing requirements of this part, or is for a project that is precluded by law, the application will be rejected as patently deficient with the specification of the deficiencies that render the application patently deficient.
(2) If, after 30 days following its filing date, the Director of the Office of Energy Projects determines that an application patently fails to comply with the prefiling consultation and filing requirements of this part, or is for a project that is precluded by law:
(i) The application will be rejected by order of the Commission, if the Commission determines that it is patently deficient; or
(ii) The application will be considered deficient under paragraph (a)(2) of this Section, if the Commission determines that it is not patently deficient.
(3) Any application for an original license that is rejected may be submitted if the deficiencies are corrected and if, in the case of a competing application, the resubmittal is timely. The date the rejected application is resubmitted will be considered the new filing date for purposes of determining its timeliness under § 4.36 of this chapter and the disposition of competing applications under § 4.37 of this chapter.
§ 5.21 Additional information.
An applicant may be required to submit any additional information or documents that the Commission considers relevant for an informed decision on the application. The information or documents must take the form, and must be submitted within the time, that the Commission prescribes. An applicant may also be required to provide within a specified time additional copies of the complete application, or any of the additional information or documents that are filed, to the Commission or to any person, agency, Indian tribe or other entity that the Commission specifies. If an applicant fails to provide timely additional information, documents, or copies of submitted materials as required, the Commission may dismiss the application, hold it in abeyance, or take other appropriate action under this chapter or the Federal Power Act.
§ 5.22 Notice of acceptance and ready for environmental analysis.
(a) When the Commission has determined that the application meets the Commission’s requirements as specified in §§ 5.18 and 5.19, the approved studies have been completed, any deficiencies in the application have been cured, and no other additional information is needed, it will issue public notice as required in the Federal Power Act:
(1) Accepting the application for filing and specifying the date upon which the application was accepted for filing (which will be the application filing date if the Secretary receives all of the information and documents necessary to conform to the requirements of §§ 5.1 through 5.21, as applicable, within the time frame prescribed in § 5.20 or § 5.21);
(2) Finding that the application is ready for environmental analysis;
(3) Requesting comments, protests, and interventions;
(4) Requesting recommendations, preliminary terms and conditions, and preliminary fishway prescriptions, including all supporting documentation; and
(5) Establishing the date for final amendments to applications for new or subsequent licenses; and
(6) Updating the schedule issued with the tendering notice for processing the application.
(b) If the project affects lands of the United States, the Commission will notify the appropriate Federal office of the application and the specific lands affected, pursuant to Section 24 of the Federal Power Act.
(c) For an application for a license seeking benefits under Section 210 of the Public Utility Regulatory Policies Act of 1978, as amended, for a project that would be located at a new dam or diversion, the Applicant must serve the public notice issued under paragraph (a)(1) of this Section to interested agencies at the time the applicant is notified that the application is accepted for filing.
§ 5.23 Response to notice.
(a) Comments and reply comments. Comments, protests, interventions, recommendations, and preliminary terms and conditions or preliminary fishway prescriptions must be filed no later than 60 days after the notice of acceptance and ready for environmental analysis. All reply comments must be filed within 105 days of that notice.
(b) Water quality certification. (1) With regard to certification requirements for a license applicant under Section 401(a)(1) of the Federal Water Pollution Control Act (Clean Water Act), the license applicant must file no later than 60 days following the date of issuance of the notice of acceptance and ready for environmental analysis provide for in § 5.22:
(i) A copy of the water quality certification;
(ii) A copy of the request for certification, including proof of the date on which the certifying agency received the request; or
(iii) Evidence of waiver of water quality certification as described in paragraph (b)(5)(2) of this Section.
(2) A certifying agency is deemed to have waived the certification requirements of section 401(a)(1) of the Clean Water Act if the certifying agency has not denied or granted certification by one year after the date the certifying agency received a written request for certification. If a certifying agency denies certification, the applicant must file a copy of the denial within 30 days after the applicant received it.
(3) Notwithstanding any other provision in 18 CFR part 4, subpart B, any application to amend an existing license, and any application to amend a pending application for a license, requires a new request for water quality certification pursuant to § 4.34(b)(5) of this chapter if the amendment would have a material adverse impact on the water quality in the discharge from the project or proposed project.
§ 5.24 Applications not requiring a draft NEPA document.
(a) If the Commission determines that a license application will be processed with an environmental assessment rather than an environmental impact statement and that a draft environmental assessment will not be required, the Commission will issue the environmental assessment for comment no later than 120 days from the date responses are due to the notice of acceptance and ready for environmental analysis.
(b) Each environmental assessment issued pursuant to this paragraph must include draft license articles, a preliminary determination of consistency of each fish and wildlife agency recommendation made pursuant to Federal Power Act section 10(j) with the purposes and requirements of the Federal Power Act and other applicable law, as provided for in § 5.26, and any preliminary mandatory terms and conditions and fishway prescriptions.
(c) Comments on an environmental assessment issued pursuant to paragraph (a) of this section, including comments in response to the Commission’s preliminary determination with respect to fish and wildlife agency recommendations and on preliminary mandatory terms and conditions or fishway prescriptions, must be filed no later than 30 or 45 days after issuance of the environmental assessment, as specified in the notice accompanying issuance of the environmental assessment, as should any revisions to supporting documentation.
(d) Modified mandatory prescriptions or terms and conditions must be filed no later than 60 days following the date for filing of comments provided for in paragraph (c) of this section, as specified in the notice accompanying issuance of the environmental analysis.
§ 5.25 Applications requiring a draft NEPA document.
(a) If the Commission determines that a license application will be processed with an environmental impact statement, or a draft and final environmental assessment, the Commission will issue the draft environmental impact statement or environmental assessment for comment no later than 180 days from the date responses are due to the notice of acceptance and ready for environmental analysis provided for in § 5.22.
(b) Each draft environmental document will include for comment draft license articles, a preliminary determination of the consistency of each fish and wildlife agency recommendation made pursuant to section 10(j) of the Federal Power Act with the purposes and requirements of the Federal Power Act and other applicable law, as provided for in § 5.26, and any preliminary mandatory terms and conditions and fishways prescriptions.
(c) Comments on a draft environmental document issued pursuant to paragraph (b) of this section, including comments in response to the Commission’s preliminary determination with respect to fish and wildlife agency recommendations and on preliminary mandatory terms and conditions or prescriptions must be filed no later than 30 or 60 days after issuance of the draft environmental document, as specified in the notice accompanying issuance of the draft environmental document.
(d) Modified mandatory prescriptions or terms and conditions must be filed no later than 60 days following the date for filing of comments provided for in paragraph (c) of this section.
(e) The Commission will issue a final environmental document within 90 days following the date for filing of modified mandatory prescriptions or terms and conditions.
§ 5.26 Section 10(j) process.
(a) In connection with its environmental review of an application for license, the Commission will analyze all terms and conditions timely recommended by fish and wildlife agencies pursuant to the Fish and Wildlife Coordination Act for the protection, mitigation of damages to, and enhancement of fish and wildlife (including related spawning grounds and habitat) affected by the development, operation, and management of the proposed project. Submission of such recommendations marks the beginning of the process under section 10(j) of the Federal Power Act.
(b) The agency must specifically identify and explain the recommendations and the relevant resource goals and objectives and their evidentiary or legal basis. The Commission may seek clarification of any recommendation from the appropriate fish and wildlife agency. If the Commission’s request for clarification is communicated in writing, copies of the request will be sent by the Commission to all parties, affected resource agencies, and Indian tribes, which may file a response to the request for clarification within the time period specified by the Commission. If the Commission believes any fish and wildlife recommendation may be inconsistent with the Federal Power Act or other applicable law, the Commission will make a preliminary determination of inconsistency in the draft environmental document or, if none, the environmental assessment. The preliminary determination, for any recommendations believed to be inconsistent, shall include an explanation why the Commission believes the recommendation is inconsistent with the Federal Power Act or other applicable law, including any supporting analysis and conclusions and an explanation of how the measures recommended in the environmental document would adequately and equitably protect, mitigate damages to, and enhance, fish and wildlife (including related spawning grounds and habitat) affected by the development, operation, and management of the project.
(c) Any party, affected resource agency, or Indian tribe may file comments in response to the preliminary determination of inconsistency, including any modified recommendations, within the time frame allotted for comments on the draft environmental document or, if none, the time frame for comments on the environmental assessment. In this filing, the fish and wildlife agency concerned may also request a meeting, telephone or video conference, or other additional procedure to attempt to resolve any preliminary determination of inconsistency.
(d) The Commission shall attempt, with the agencies, to reach a mutually acceptable resolution of any such inconsistency, giving due weight to the recommendations, expertise, and statutory responsibilities of the fish and wildlife agency. If the Commission decides, or an affected resource agency requests, the Commission will conduct a meeting, telephone or video conference, or other procedures to address issues raised by its preliminary determination of inconsistency and comments thereon. The Commission will give at least 15 days’ advance notice to each party, affected resource agency, or Indian tribe, which may participate in the meeting or conference. Any meeting, conference, or additional procedure to address these issues will be scheduled to take place within 90 days of the date the Commission issues a preliminary determination of inconsistency. The Commission will prepare a written summary of any meeting held under this paragraph to discuss section 10(j) issues, including any proposed resolutions and supporting analysis, and a copy of the summary will be sent to all parties, affected resource agencies, and Indian tribes.
(e) The section 10(j) process ends when the Commission issues an order granting or denying the license application in question. If, after attempting to resolve inconsistencies between the fish and wildlife recommendations of a fish and wildlife agency and the purposes and requirements of the Federal Power Act or other applicable law, the Commission does not adopt in whole or in part a fish and wildlife recommendation of a fish and wildlife agency, the Commission will publish the findings and statements required by section 10(j)(2) of the Federal Power Act.
§ 5.27 Amendment of application.
(a) Procedures. If an Applicant files an amendment to its application that would materially change the project’s proposed plans of development, as provided in § 4.35 of this chapter, an agency, Indian tribe, or member of the public may modify the recommendations or terms and conditions or prescriptions it previously submitted to the Commission pursuant to §§ 5.20–5.26. Such modified recommendations, terms and conditions, or prescriptions must be filed no later than the due date specified by the Commission for comments on the amendment.
(b) Date of acceptance. The date of acceptance of an amendment of application for an original license filed under this part is governed by the provisions of § 4.35 of this chapter.
(c) New and subsequent licenses. The requirements of § 4.35 of this chapter do not apply to an application for a new or subsequent license, except that the Commission will reissue a public notice of the application in accordance with the provisions of § 4.32(d)(2) of this chapter if a material amendment, as that term is used in § 4.35(f) of this chapter, is filed.
(d) Deadline. All amendments to an application for a new or subsequent license, including the final amendment, must be filed with the Commission and served on all competing applicants no later than the date specified in the notice issued under § 5.22.
§ 5.28 Competing applications.
(a) Site access for a competing applicant. The provisions of § 16.5 of this chapter shall govern site access for a potential license application to be filed in competition with an application for a new or subsequent license by an existing licensee pursuant to this part, except that references in § 16.5 to the pre-filing consultation provisions in parts 4 and 16 of this chapter shall be construed in a manner compatible with the effective administration of this part.
(b) Competing applications. The provisions of § 4.36 of this chapter shall apply to competing applications for original, new, or subsequent licenses filed under this part.
(c) New or subsequent license applications—final amendments; better adapted statement. Where two or more mutually exclusive competing applications for new or subsequent license have been filed for the same project, the final amendment date and deadlines for complying with provisions of § 4.36(d)(2) (ii) and (iii) of this chapter established pursuant to the notice issued under § 5.22 will be the same for all such applications.
(d) Rules of preference among competing applicants. The Commission will select among competing applications according to the provisions of § 4.37 of this chapter.
§ 5.29 Other provisions.
(a) Filing requirement. Unless otherwise provided by statute, regulation or order, all filings in hydropower hearings, except those conducted by trial-type procedures, must conform to the requirements of 18 CFR part 385, subpart T of this chapter.
(b) Waiver of compliance with consultation requirements. (1) If an agency, Indian tribe, or member of the public waives in writing compliance with any consultation requirement of this part, an applicant does not have to comply with the requirement as to that agency, Indian tribe, or member of the public.
(2) If an agency, Indian tribe, member of the public fails to timely comply with a provision regarding a requirement of this section, an applicant may proceed to the next sequential requirement of this section without waiting for the agency, Indian tribe, or member of the public.
(c) Requests for privileged or Critical Energy Infrastructure Information treatment of pre-filing submission. If a potential Applicant requests privileged or critical energy infrastructure information treatment of any information submitted to the Commission during pre-filing consultation (except for the information specified in § 5.4), the Commission will treat the request in accordance with the provisions in § 388.112 of this chapter until the date the application is filed with the Commission.
(d) Conditional applications. Any application, the effectiveness of which is conditioned upon the future occurrence of any event or circumstance, will be rejected.
(e) Trial-type hearing. The Commission may order a trial-type hearing on an application for a license under this part either upon its own motion or the motion of any interested party of record. Any trial-type hearing will be limited to the issues prescribed by order of the Commission. In all other cases, the hearings will be conducted by notice and comment procedures.
(f) Notice and comment hearings. (1) All comments and reply comments and all other filings described in this part must be served on all persons on the service list prepared by the Commission, in accordance with the requirements of § 385.2010 of this chapter. If a party submits any written material to the Commission relating to the merits of an issue that may affect the responsibility of particular resource agency, the party must also serve a copy of the submission on that resource agency.
(2) The Director of Energy Projects may waive or modify any of the provisions of this part for good cause. A commenter or reply commenter may obtain an extension of time from the Commission only upon a showing of good cause or extraordinary circumstances in accordance with § 385.2008 of this chapter.
(3) Late-filed recommendations by fish and wildlife agencies pursuant to the Fish and Wildlife Coordination Act and section 10(j) of the Federal Power Act for the protection, mitigation of damages to, and enhancement of fish and wildlife affected by the development, operation, and management of the proposed project and late-filed terms and conditions or prescriptions filed pursuant to sections 4(e) and 18 of the Federal Power Act, respectively, will be considered by Commission under section 10(a) of the Federal Power Act if such consideration would not delay or disrupt the proceeding.
(g) Settlement negotiations. (1) The Commission will consider, on a case-by-case basis, requests for a short suspension of the procedural schedule for the purpose of participants conducting settlement negotiations, where it determines that the suspension will not adversely affect timely action on a license application. In acting on such requests, the Commission will consider, among other things:
(i) Whether requests for suspension of the procedural schedule have previously been made or granted;
(ii) Whether the request is supported by a consensus of participants in the proceeding and an explanation of objections to the request expressed by any participant;
(iii) The likelihood that a settlement agreement will be filed within the requested suspension period; and
(iv) Whether the requested suspension is likely to cause any new or subsequent license to be issued after the expiration of the existing license.
(2) The Commission reserves the right to terminate any suspension of the procedural schedule if it concludes that insufficient progress is being made toward the filing of a settlement agreement.
(h) License conditions and required findings. (1) All licenses shall be issued on the conditions specified in Section 10 of the Federal Power Act and such other conditions as the Commission determines are lawful and in the public interest.
(2) Subject to paragraph (f)(3) of this section, fish and wildlife conditions shall be based on recommendations timely received from the fish and wildlife agencies pursuant to the Fish and Wildlife Coordination Act.
(3) The Commission will consider the timely recommendations of resource agencies, other governmental units, and members of the public, and the timely recommendations (including fish and wildlife recommendations) of Indian tribes affected by the project.
(4) Licenses for a project located within any Federal reservation shall be issued only after the findings required by, and subject to any conditions that may be timely filed pursuant to section 4(e) of the Federal Power Act.
(5) The Commission will require the construction, maintenance, and operation of such fishways as may be timely prescribed by the Secretary of Commerce or the Secretary of the Interior, as appropriate, pursuant to section 18 of the Federal Power Act.
(i) Standards and factors for issuing a new license. (1) In determining whether a final proposal for a new license under section 15 of the Federal Power Act is best adapted to serve the public interest, the Commission will consider the factors enumerated in sections 15(a)(2) and (a)(3) of the Federal Power Act.
(2) If there are only insignificant differences between the final applications of an existing licensee and a competing Applicant after consideration of the factors enumerated in section 15(a)(2) of the Federal Power Act, the Commission will determine which Applicant will receive the license after considering:
(i) The existing licensee’s record of compliance with the terms and conditions of the existing license; and
(ii) The actions taken by the existing licensee related to the project which affect the public.
(iii) An existing licensee that files an application for a new license in conjunction with an entity or entities that are not currently licensees of all or part of the project will not be considered an existing licensee for the purpose of the insignificant differences provision of section 15(a)(2) of the Federal Power Act.
(j) Fees under section 30(e) of the Federal Power Act. The requirements of 18 CFR part 4, subpart M, of this chapter, fees under section 30(e) of the Federal Power Act, apply to license applications developed under this part.
§ 5.30 Critical energy infrastructure information.
If any action required by this part requires a potential Applicant or Applicant to reveal Critical Energy Infrastructure Information, as defined by § 388.113(c) of this chapter, to the public, the Applicant must follow the procedures set out in § 4.32(k) of this chapter.
§ 5.31 Transition provision.
This part shall apply to license applications for which the deadline for filing a notification of intent to seek a new or subsequent license, or for filing a notification of intent to file an original license application, as required by § 5.5 of this part, is July 23, 2005 or later.
PART 6—SURRENDER OR TERMINATION OF LICENSE
§ 6.1 Application for surrender.
Every application for surrender of a license shall state the reason therefor; and, except in the case of an application for surrender of a license for a minor project, or for a transmission line only, shall be executed by the licensee and filed in the same form and manner as the application for license, and shall be accompanied by the license and all amendments thereof. Public notice of such application shall be given at least 30 days prior to action upon the application.
For application for license, general provisions, see §§ 4.30 to 4.33, inclusive, of this chapter. For application for license for proposed major project or minor part thereof, see §§ 4.40 to 4.41, inclusive, of this chapter. For application for license for constructed major project or minor part thereof, see §§ 4.50 and 4.51 of this chapter.
§ 6.2 Surrender of license.
Licenses may be surrendered only upon the fulfillment by the licensee of such obligations under the license as the Commission may prescribe, and, if the project works authorized under the license have been constructed in whole or in part, upon such conditions with respect to the disposition of such works as may be determined by the Commission. Where project works have been constructed on lands of the United States the licensee will be required to restore the lands to a condition satisfactory to the Department having supervision over such lands and annual charges will continue until such restoration has been satisfactorily completed.
§ 6.3 Termination of license.
Licenses may be terminated by written order of the Commission not less than 90 days after notice thereof shall have been mailed to the licensee by certified mail to the last address whereof the Commission has been notified by the licensee, if there is failure to commence actual construction of the project works within the time prescribed in the license, or as extended by the Commission. Upon like notice, the authority granted under a license with respect to any separable part of the project works may be terminated if there is failure to begin construction of such separable part within the time prescribed or as extended by the Commission.
§ 6.4 Termination by implied surrender.
If any licensee holding a license subject to the provisions of section 10(i) of the Act shall cause or suffer essential project property to be removed or destroyed, or become unfit for use, without replacement, or shall abandon, or shall discontinue good faith operation of the project for a period of three years, the Commission will deem it to be the intent of the licensee to surrender the license; and not less than 90 days after public notice may in its discretion terminate the license.
§ 6.5 Annual charges.
Annual charges arising under a license surrendered or terminated shall continue until the effective date set forth in the Commission’s order with respect to such surrender or termination.
For annual charges, see part 11 of this chapter.
PART 7—EXPEDITED LICENSING PROCESS FOR QUALIFYING NON-FEDERAL HYDROPOWER PROJECTS AT EXISTING NONPOWERED DAMS AND FOR CLOSED-LOOP PUMPED STORAGE PROJECTS
§ 7.1 Applicability and definitions.
(a) Applicability of the expedited licensing process. This part applies to the processing of applications for original licenses for qualifying non-federal hydropower projects at existing nonpowered dams and for closed-loop pumped storage projects pursuant to sections 34 and 35 of the Federal Power Act.
(b) Applicability of existing regulations. Except where superseded by the expedited licensing process set forth in this part, the regulations governing license applications under parts 4 and 5 of this chapter, as applicable, also apply to license applications filed under this part.
(c) Definitions. The definitions in § 4.30(b) of this chapter apply to this part. In addition, for the purposes of this part—
(1) Qualifying nonpowered dam means any dam, dike, embankment, or other barrier—
(i) The construction of which was completed on or before October 23, 2018;
(ii) That is or was operated for the control, release, or distribution of water for agricultural, municipal, navigational, industrial, commercial, environmental, recreational, aesthetic, drinking water, or flood control purposes; and
(iii) That, as of October 23, 2018, was not generating electricity with hydropower generating works that were licensed under, or exempted from the license requirements contained in, Part I of the Federal Power Act.
(2) Qualifying facility means a facility that is determined under section 34 of the Federal Power Act to meet the qualifying criteria for non-federal hydropower projects at existing nonpowered dams.
(3) Qualifying criteria for closed-loop pumped storage projects means criteria that a pumped storage project must meet in order to qualify as a closed-loop pumped storage project eligible for the expedited process established under this part. These criteria require that the pumped storage project:
(i) Cause little to no change to existing surface and groundwater flows and uses;
(ii) Is unlikely to adversely affect species listed as a threatened species or endangered species, or designated critical habitat of such species, under the Endangered Species Act of 1973;
(iii) Utilize only reservoirs situated at locations other than natural waterways, lakes, wetlands, and other natural surface water features; and
(iv) Rely only on temporary withdrawals from surface waters or groundwater for the sole purposes of initial fill and periodic recharge needed for project operation.
(d) Who may file. Any citizen, association of citizens, domestic corporation, municipality, or state that develops and files a license application under 18 CFR parts 4 and 5, as applicable, may request expedited processing under this part.
(e) Use of expedited licensing process. An applicant wishing to use this expedited licensing process must apply for and receive authorization from the Commission under this part. An applicant under this part may elect to use the licensing process provided for in 18 CFR part 5 (i.e., integrated license application process), or as provided under 18 CFR 5.1:
(1) 18 CFR part 4, subparts D–H (i.e., traditional process); or
(2) Section 4.34(i) of this chapter, Alternative procedures.
§ 7.2 Use of expedited licensing process.
(a) In order to pursue the expedited licensing process, an applicant must request authorization for the expedited process, as provided for in paragraph (b) of this section. The licensing procedures in this part do not apply to an application for a new or subsequent license.
(b) An application that accompanies a request for authorization to use the expedited licensing process must include the information specified below.
(1) Section 34 of the Federal Power Act qualification—projects at nonpowered dams. The application must demonstrate that the proposed facility meets the following qualifications pursuant to section 34(e) of the Federal Power Act:
(i) As of October 23, 2018, the proposed hydropower facility was not licensed under or exempted from the license requirements contained in Part I of the Federal Power Act;
(ii) The facility will be associated with a qualifying nonpowered dam;
(iii) The facility will be constructed, operated, and maintained for the generation of electric power;
(iv) The facility will use for such generation any withdrawals, diversions, releases, or flows from the associated qualifying nonpowered dam, including its associated impoundment or other infrastructure; and
(v) The operation of the facility will not result in any material change to the storage, release, or flow operations of the associated qualifying nonpowered dam.
(2) Section 35 of the Federal Power Act qualification—closed-loop pumped storage projects. The application must demonstrate that the proposed closed-loop pumped storage project meets the following qualifications pursuant to section 35(g)(2) of the Federal Power Act:
(i) The project will cause little to no change to existing surface and groundwater flows and uses; and
(ii) The project is unlikely to adversely affect species listed as a threatened species or endangered species, or designated critical habitat of such species, under the Endangered Species Act of 1973.
(3) Section 401 of the Clean Water Act. The application must include a copy of a request for certification under section 401(a)(1) of the Clean Water Act, including proof of the date on which the certifying agency received the request; or
(i) A copy of water quality certification; or
(ii) Evidence of waiver of water quality certification. A certifying agency is deemed to have waived the certification requirements of section 401(a)(1) of the Clean Water Act if the certifying agency has not denied or granted certification by one year after the date the certifying agency received a written request for certification. If a certifying agency denies certification, the applicant must file a copy of the denial within 30 days after the applicant received it.
(4) Endangered Species Act (ESA). The application must include:
(i) A no-effect determination that includes documentation that no listed species or critical habitat are present in the action area;
(ii) Documentation of concurrence from the U.S. Fish and Wildlife Service and the National Marine Fisheries Service (Service(s)), as necessary, that the action is not likely to adversely affect ESA-listed species or critical habitat; or
(iii) A draft Biological Assessment that includes documentation of consultation with the Service(s).
(5) Section 106 of the National Historic Preservation Act. Documentation that section 106 consultation has been initiated with the state historic preservation officer(s) and any Indian Tribes identified as having an interest in the project.
(6) Dam owner documentation. For projects to be located at existing nonpowered dams:
(i) Documentation of consultation with any nonfederal owner of the nonpowered dam if the applicant is not the owner and confirmation that the owner is not opposed to a hydropower development at the location; or
(ii) Documentation from the federal entity that non-federal hydropower development is not precluded at the proposed location and confirmation that the federal entity is not opposed to a hydropower development at the location.
(7) Public parks, recreation areas, and wildlife refuges. If the project would use any public park, recreation area, or wildlife refuge established under state or local law, documentation from the managing entity indicating it is not opposed to the site’s use for hydropower development.
§ 7.3 Adequacy review of application.
(a) Adequacy review of license applications. Review of the original license application for which expedited processing under this part is requested will be conducted pursuant to 18 CFR part 4 or 5, as applicable.
(b) Deficient license applications. If an original license application for which expedited processing is requested under this part is rejected under 18 CFR parts 4 and 5, as applicable, the request for authorization for the expedited licensing process under this part is deemed rejected.
§ 7.4 Additional information.
An applicant may be required to submit any additional information or documentation that the Commission considers relevant for an informed decision on the application for authorization under this part. The information or documents must take the form, and must be submitted within the time, that the Commission prescribes. An applicant may also be required to provide within a specified time additional copies of the application, or any of the additional information or documents that are filed, to the Commission or to any person, agency, Indian Tribe or other entity that the Commission specifies. If an applicant fails to provide timely additional information, documents, or copies of submitted materials as required, the Director of the Office of Energy Projects (Director) may dismiss the application, hold it in abeyance, or take other appropriate action under this chapter or the Federal Power Act.
§ 7.5 Decision on request to use expedited licensing process.
When the Commission has determined that the original license application is complete insofar as it meets the Commission’s requirements as specified in 18 CFR parts 4, 5, and this part; any deficiencies have been cured; and no other additional information is needed, the Director will make a decision on the request to use the expedited licensing process under this part no later than 180 days after receipt of a request for authorization to use the expedited process. If the Commission cannot deem the application complete within 180 days of application filing, the Director will deny the request to use the expedited licensing process. If the Director denies the request to use the expedited licensing process, the original license application will be processed pursuant to a standard processing schedule under 18 CFR parts 4 and 5, as applicable.
§ 7.6 Notice of acceptance and ready for environmental analysis.
If the Director deems the application complete and approves the request to use the expedited licensing process under § 7.5, the Commission will issue a public notice as required in the Federal Power Act, no later than 180 days after application filing, that:
(a) Accepts the application for filing and specifies the date upon which the application was accepted for filing;
(b) Finds the application ready for environmental analysis;
(c) Requests comments, protests, and interventions;
(d) Requests recommendations, preliminary terms and conditions, and preliminary fishway prescriptions, including all supporting documentation; and
(e) Establishes an expedited licensing process schedule, including estimated dates for:
(1) Filing of recommendations, preliminary terms and conditions, and fishway prescriptions;
(2) Issuance of a draft National Environmental Policy Act (NEPA) document, or an environmental assessment not preceded by a draft;
(3) Filing of a response, as applicable, to Commission staff’s request for ESA concurrence or request for formal consultation under the ESA, or responding to other Commission staff requests to federal and state agencies, or Indian Tribes pursuant to Federal law, including the Magnuson-Stevens Fishery Conservation and Management Act and the National Historic Preservation Act;
(4) Filing of comments on the draft NEPA document, as applicable;
(5) Filing of modified recommendations, mandatory terms and conditions, and fishway prescriptions in response to a draft NEPA document or environmental assessment, if no draft NEPA document is issued; and
(6) Issuance of a final NEPA document, if any.
§ 7.7 Amendment of application.
(a) Any proposed amendments to the pending license application after issuance of the notice of acceptance and ready for environmental analysis under this section must include:
(1) An amended or new section 401 of the Clean Water Act water quality certification if the amendment would have a material adverse impact on the water quality in the discharge from the proposed project; and
(2) Updates to all other material submitted under § 7.2(b).
(b) If based on the information provided under paragraph (a) of this section, the proposed project under the amended license application no longer meets the requirements for expedited processing under § 7.2 of this part or if the proposed amendment significantly amends the license application, the Director will notify the applicant that the application will no longer be processed under the expedited licensing process under this part and that further processing of the application will proceed under parts 4 and 5 of this chapter, as applicable.
(c) If the Director approves the continued processing of the amended application under this part and the amendment to the application would materially change the project’s proposed plans of development, as provided in § 4.35 of this chapter, an agency, Indian Tribe, or member of the public may modify the recommendations or terms and conditions or prescriptions it previously submitted to the Commission pursuant to § 7.6. Such modified recommendations, terms and conditions, or prescriptions must be filed no later than the due date specified by the Commission for comments on the amendment.
(d) Date of acceptance. The date of acceptance of an amendment of application for an original license filed under this part is governed by the provisions of § 4.35 of this chapter.
§ 7.8 Other provisions.
(a) Except for provisions required by statute, the Director may waive or modify any of the provisions of this part for good cause.
(b) Late-filed recommendations by fish and wildlife agencies pursuant to the Fish and Wildlife Coordination Act and section 10(j) of the Federal Power Act for the protection, mitigation of damages to, and enhancement of fish and wildlife affected by the development, operation, and management of the proposed project and late-filed terms and conditions or prescriptions filed pursuant to sections 4(e) and 18 of the Federal Power Act, respectively, may be considered by the Commission as cause to remove the application from the expedited licensing process. If the Director determines that late-filed recommendations, terms and conditions, or prescriptions are likely to prevent the Commission from issuing a final licensing decision within two years from application receipt, the Director will notify the applicant that the application will no longer be processed under the expedited licensing process under this part and that further processing of the application will proceed under 18 CFR parts 4 and 5, as applicable.
(c) License conditions and required findings. (1) All licenses shall be issued on the conditions specified in section 10 of the Federal Power Act and such other conditions as the Commission determines are lawful and in the public interest.
(2) Subject to paragraph (b) of this section, fish and wildlife conditions shall be based on recommendations timely received from the fish and wildlife agencies pursuant to the Fish and Wildlife Coordination Act.
(3) The Commission will consider the timely recommendations of resource agencies, other governmental units, and members of the public, and the timely recommendations (including fish and wildlife recommendations) of Indian Tribes affected by the project.
(4) Licenses for a project located within any Federal reservation shall be issued only after the findings required by, and subject to, any conditions that may be filed pursuant to section 4(e) of the Federal Power Act.
(5) The Commission will require the construction, maintenance, and operation of such fishways as may be prescribed by the Secretary of Commerce or the Secretary of the Interior, as appropriate, pursuant to section 18 of the Federal Power Act.
§ 7.9 Transition provision.
This part shall only apply to original license applications filed on or after July 23, 2019.
PART 8—RECREATIONAL OPPORTUNITIES AND DEVELOPMENT AT LICENSED PROJECTS
§ 8.1 Publication of license conditions relating to recreation.
Following the issuance or amendment of a license, the licensee shall make reasonable efforts to keep the public informed of the availability of project lands and waters for recreational purposes, and of the license conditions of interest to persons who may be interested in the recreational aspects of the project or who may wish to acquire lands in its vicinity. Such efforts shall include, but are not limited to: the publication of notice in a local newspaper once each week for 4 weeks, and publication on any project website, of the project’s license conditions which relate to public access to and the use of the project waters and lands for recreational purposes, recreational plans, installation of recreation and fish and wildlife facilities, reservoir water surface elevations, minimum water releases or rates of change of water releases, and such other conditions of general public interest as the Commission may designate in the order issuing or amending the license.
§ 8.2 Posting of project lands as to recreational use and availability of information.
(a) Following the issuance or amendment of a license, the licensee shall post and maintain at all points of public access required by the license (or at such access points as are specifically designated for this purpose by the licensee) and at such other points as are subsequently prescribed by the Commission on its own motion or upon the recommendation of a public recreation agency operating in the project vicinity, a conspicuous sign that, at a minimum, identifies: the FERC project name and number, and a statement that the project is licensed by the Commission; the licensee name and contact information for obtaining additional project recreation information; and permissible times and activities. In addition, the licensee shall post at such locations conspicuous notice that the recreation facilities are open to all members of the public without discrimination.
(b) The licensee shall make available for inspection at its local offices in the project vicinity, and on any project website, the approved recreation plan, any recreation-related reports approved by the Commission, and the entire license instrument, properly indexed for easy reference to the license conditions designated for publications in § 8.1.
§ 8.3 Discrimination prohibited.
Every licensee maintaining recreation facilities for the use of the public at a licensed project, or employing or permitting any other person to maintain such facilities, shall permit, or require such other person to permit, equal and unobstructed use of such facilities to all members of the public without regard to race, color, religious creed or national origin.
PART 9—TRANSFER OF LICENSE OR LEASE OF PROJECT PROPERTY
For application for approval of transfer of license, see § 131.20 of this chapter.
Application for Transfer of License
§ 9.1 Filing.
Any licensee desiring to transfer a license or rights thereunder granted, and the person, association, corporation, State, or municipality desiring to acquire the same, shall jointly or severally file an application for approval of such transfer and acquisition. Such application shall be verified, shall conform to § 131.20 of this chapter, and shall be filed in accordance with § 4.32 of this chapter.
§ 9.2 Contents of application.
Every application for approval of such transfer and acquisition by the proposed transferee shall set forth in appropriate detail the qualifications of the transferee to hold such license and to operate the property under license, which qualifications shall be the same as those required of applicants for license.
For administrative rules relating to applicants for license, see part 385 of this chapter. For regulations as to licenses and permits, see part 4 of this chapter.
§ 9.3 Transfer.
(a) Approval by the Commission of transfer of a license is contingent upon the transfer of title to the properties under license, delivery of all license instruments, and a showing that such transfer is in the public interest. The transferee shall be subject to all the conditions of the license and to all the provisions and conditions of the act, as though such transferee were the original licensee and shall be responsible for the payment of annual charges which accrue prior to the date of transfer.
(b) When the Commission shall have approved the transfer of the license, its order of approval shall be forwarded to the transferee for acknowledgment of acceptance. Unless application for rehearing is filed, or unless the order is stayed by the Commission, the order shall become final thirty (30) days from date of issuance and the acknowledgment of acceptance shall be filed in triplicate with the Commission within sixty (60) days from date of issuance accompanied by a certified copy of the deed of conveyance or other instrument evidencing transfer of the property under license, together with evidence of the recording thereof.
Application for Lease of Project Property
§ 9.10 Filing.
Any licensee desiring to lease the project property covered by a license or any part thereof, where the lessee is granted the exclusive occupancy, possession, or use of project works for purposes of generating, transmitting, or distributing power, and the person, association, or corporation, State, or municipality desiring to acquire the project property by lease, must file the proposed lease together with the application in accordance with § 4.32(b)(1) of this chapter. The application and the Commission’s action on it will, in general, be subject to the provisions of §§ 9.1 through 9.3.
PART 11—ANNUAL CHARGES UNDER PART I OF THE FEDERAL POWER ACT
Subpart A—Charges for Costs of Administration, Use of Tribal Lands and Other Government Lands, and Use of Government Dams
§ 11.1 Costs of administration.
(a) Authority. Pursuant to section 10(e) of the Federal Power Act and section 3401 of the Omnibus Budget Reconciliation Act of 1986, the Commission will assess reasonable annual charges against licensees and exemptees to reimburse the United States for the costs of administration of the Commission’s hydropower regulatory program.
(b) Scope. The annual charges under this section will be charged to and allocated among:
(1) All licensees of projects of more than 1.5 megawatts of installed capacity; and
(2) All holders of exemptions under either section 30 of the Federal Power Act or sections 405 and 408 of the Public Utility Regulatory Policies Act of 1978, as amended by section 408 of the Energy Security Act of 1980, but only if the exemption was issued subsequent to April 21, 1995 and is for a project of more than 1.5 megawatts of installed capacity.
(3) If the exemption for a project of more than 1.5 megawatts of installed capacity was issued subsequent to April 21, 1995 but pursuant to an application filed prior to that date, the exemptee may credit against its annual charge any filing fee paid pursuant to § 381.601 of this chapter, which was removed effective April 21, 1995, 18 CFR 381.601 (1994), until the total of all such credits equals the filing fee that was paid.
(c) Licenses and exemptions other than State or municipal. For licensees and exemptees, other than State or municipal:
(1) A determination shall be made for each fiscal year of the costs of administration of Part I of the Federal Power Act chargeable to such licensees or exemptees, from which shall be deducted any administrative costs that are stated in the license or exemption or fixed by the Commission in determining headwater benefit payments.
(2) For each fiscal year the costs of administration determined under paragraph (c)(1) of this section will be assessed against such licenses or exemptee in the proportion that the annual charge factor for each such project bears to the total of the annual charge factors under all such outstanding licenses and exemptions.
(3) The annual charge factor for each such project shall be found as follows:
(i) For a conventional project the factor is its authorized installed capacity plus 112.5 times its annual energy output in millions of kilowatt-hours.
(ii) For a pure pumped storage project the factor is its authorized installed capacity.
(iii) For a mixed conventional-pumped storage project the factor is its authorized installed capacity plus 112.5 times its gross annual energy output in millions of kilowatt-hours less 75 times the annual energy used for pumped storage pumping in million of kilowatt-hours.
(iv) For purposes of determining their annual charges factor, projects that are operated pursuant to an exemption will be deemed to have an annual energy output of zero.
(4) To enable the Commission to determine such charges annually, each licensee whose authorized installed capacity exceeds 1.5 megawatts must file with the Commission, on or before November 1 of each year, a statement under oath showing the gross amount of power generated (or produced by nonelectrical equipment) and the amount of power used for pumped storage pumping by the project during the preceding fiscal year, expressed in kilowatt hours. If any licensee does not report the gross energy output of its project within the time specified above, the Commission’s staff will estimate the energy output and this estimate may be used in lieu of the filings required by this section made by such licensee after November 1.
(5) For unconstructed projects, the assessments begin on the date by which the licensee or exemptee is required to commence project construction, or as that deadline may be extended. For constructed projects, the assessments begin on the effective date of the license or exemption, except for any new capacity authorized therein. The assessments for new authorized capacity at licensed or exempted projects begin on the date by which the licensee or exemptee is required to commence construction of the new capacity. In the event that assessments begin during a fiscal year, the charges will be prorated.
(d) State and municipal licensees and exemptees. For State or municipal licensees and exemptees:
(1) A determination shall be made for each fiscal year of the cost of administration under Part I of the Federal Power Act chargeable to such licensees and exemptees, from which shall be deducted any administrative costs that are stated in the license or exemption or that are fixed by the Commission in determining headwater benefit payments.
(2) An exemption will be granted to a licensee or exemptee to the extent, if any, to which it may be entitled under section 10(e) of the Act provided the data is submitted as requested in paragraphs (d) (4) and (5) of this section.
(3) For each fiscal year the total actual cost of administration as determined under paragraph (d)(1) of this section will be assessed against each such licensee or exemptee (except to the extent of the exemptions granted pursuant to paragraph (d)(2) of this section) in the proportion that the authorized installed capacity of each such project bears to the total such capacity under all such outstanding licenses or exemptions.
(4) To enable the Commission to compute on the bill for annual charges the exemption to which State and municipal licensees and exemptees are entitled because of the use of power by the licensee or exemptee for State or municipal purposes, each such licensee or exemptee must file with the Commission, on or before November 1 of each year, a statement under oath showing the following information with respect to the power generated by the project and the disposition thereof during the preceding fiscal year, expressed in kilowatt-hours:
(i) Gross amount of power generated by the project.
(ii) Amount of power used for station purposes and lost in transmission, etc.
(iii) Net amount of power available for sale or use by licensee or exemptee, classified as follows:
(A) Used by licensee or exemptee.
(B) Sold by licensee or exemptee.
(5) When the power from a licensed or exempted project owned by a State or municipality enters into its electric system, making it impracticable to meet the requirements of this section with respect to the disposition of project power, such licensee or exemptee may, in lieu thereof, furnish similar information with respect to the disposition of the available power of the entire electric system of the licensee or exemptee.
(6) The assessments commence on the date of commencement of project operation. In the event that project operation commences during a fiscal year, the charges will be prorated based on the date on which operation commenced.
(e) Transmission lines. For projects involving transmission lines only, the administrative charge will be stated in the license.
(f) Maximum charge. No licensed or exempted project’s annual charge may exceed a maximum charge established each year by the Commission to equal 2.0 percent of the adjusted Commission costs of administration of the hydropower regulatory program. For every project with an annual charge determined to be above the maximum charge, that project’s annual charge will be set at the maximum charge, and any amount above the maximum charge will be reapportioned to the remaining projects. The reapportionment will be computed using the method outlined in paragraphs (c) and (d) of this section (but excluding any project whose annual charge is already set at the maximum amount). This procedure will be repeated until no project’s annual charge exceeds the maximum charge.
(g) Commission’s costs. (1) With respect to costs incurred by the Commission, the assessment of annual charges will be based on an estimate of the costs of administration of Part I of the Federal Power Act that will be incurred during the fiscal year in which the annual charges are assessed. After the end of the fiscal year, the assessment will be recalculated based on the costs of administration that were actually incurred during that fiscal year; the actual costs will be compared to the estimated costs; and the difference between the actual and estimated costs will be carried over as an adjustment to the assessment for the subsequent fiscal year.
(2) The issuance of bills based on the administrative costs incurred by the Commission during the year in which the bill is issued will commence in 1993. The annual charge for the administrative costs that were incurred in fiscal year 1992 will be billed in 1994. At the licensee’s option, the charge may be paid in three equal annual installments in fiscal years 1994, 1995, and 1996, plus any accrued interest. If the licensee elects the three-year installment plan, the Commission will accrue interest (at the most recent yield of two-year Treasury securities) on the unpaid charges and add the accrued interest to the installments billed in fiscal years 1995 and 1996.
(h) In making their annual reports to the Commission on their costs in administering Part I of the Federal Power Act, the United States Fish and Wildlife Service and the National Marine Fisheries Service are to deduct any amounts that were deposited into their Treasury accounts during that year as reimbursements for conducting studies and reviews pursuant to section 30(e) of the Federal Power Act.
(i) Definition. As used in paragraphs (c) and (d) of this section, authorized installed capacity means the lesser of the ratings of the generator or turbine units. The rating of a generator is the product of the continuous-load capacity rating of the generator in kilovolt-amperes (kVA) and the system power factor in kW/kVA. If the licensee or exemptee does not know its power factor, a factor of 1.0 kW/kVA will be used. The rating of a turbine is the product of the turbine’s capacity in horsepower (hp) at best gate (maximum efficiency point) opening under the manufacturer’s rated head times a conversion factor of 0.75 kW/hp. If the generator or turbine installed has a rating different from that authorized in the license or exemption, or the installed generator is rewound or otherwise modified to change its rating, or the turbine is modified to change its rating, the licensee or exemptee must apply to the Commission to amend its authorized installed capacity to reflect the change.
(j) Transition. For a license having the capacity of the project for annual charge purposes stated in horsepower, that capacity shall be deemed to be the capacity stated in kilowatts elsewhere in the license, including any amendments thereto.
§ 11.2 Use of government lands.
(a) Reasonable annual charges for recompensing the United States for the use, occupancy, and enjoyment of its lands (other than lands adjoining or pertaining to Government dams or other structures owned by the United States Government) or its other property, will be fixed by the Commission.
(b) General rule. Annual charges for the use of government lands will be payable in advance, and will be set on the basis of an annual schedule of per-acre rental fees, as set forth in Appendix A of this part. The Executive Director will publish the updated fee schedule in the
(c) The annual per-acre rental fee is the product of four factors: the adjusted per-acre value multiplied by the encumbrance factor multiplied by the rate of return multiplied by the annual adjustment factor.
(1) Adjusted per-acre value. (i) Counties (or other geographical areas) are assigned a per-acre value based on their average per-acre land and building value published in the Census of Agriculture (Census) by the National Agricultural Statistics Service (NASS). The adjusted per-acre value is computed by reducing the NASS Census land and building value by the sum of a state-specific modifier and seven percent. A table of state-specific adjustments will be available on the Commission’s Web site.
(ii) The state-specific modifier is a percentage reduction applicable to all counties or geographic areas in a state (except Puerto Rico), and represents the ratio of the total value of irrigated farmland in the state to the total value of all farmland in the state. The state-specific modifier will be recalculated every five years beginning in payment year 2016.
(iii) The state-specific modifier for Puerto Rico is 13 percent.
(iv) For all geographic areas in Alaska except for the Aleutian Islands Area, the Commission will calculate a statewide per-acre value based on the average per-acre land and building values published in the NASS Census for the Kenai Peninsula Area and the Fairbanks Area. This statewide per-acre value will be reduced by the sum of the state-specific modifier and seven percent. The resulting adjusted statewide per-acre value will be applied to all projects located in Alaska, except for projects located in the Aleutian Island Area.
(2) Encumbrance factor. The encumbrance factor is 50 percent.
(3) Rate of return. The rate of return is 5.77 percent through payment year 2025. The rate of return will be adjusted every 10 years thereafter, and will be based on the 10-year average of the 30-year Treasury bond yield rate immediately preceding the applicable NASS Census. For example, for years 2026 through 2035, the rate of return will be based on the 10-year average (2012–2021) of the 30-year Treasury bond yield rate immediately preceding the 2022 NASS Census. If the 30-year Treasury bond yield rate is not available, the next longest term Treasury bond available should be used in its place.
(4) Annual adjustment factor. The annual adjustment factor is 1.9 percent through payment year 2015. For years 2016 through 2025, the annual adjustment factor is the annual change in the Implicit Price Deflator for the Gross Domestic Product (IPD–GDP) for the ten years (2014–2023) preceding issuance (2024) of the most recent NASS Census (2022). Each subsequent ten year adjustment will be made in the same manner.
(d) The annual charge for the use of Government lands for 2013 will be reduced by 25 percent for all licensees subject to this section.
(e) The minimum annual charge for the use of Government lands under any license will be $25.
§ 11.3 Use of government dams, excluding pumped storage projects.
(a) General rule. (1) Any licensee whose non-Federal project uses a Government dam or other structure for electric power generation and whose annual charges are not already specified in final form in the license must pay the United States an annual charge for the use of that dam or other structure as determined in accordance with this section. Payment of such annual charge is in addition to any reimbursement paid by a licensee for costs incurred by the United States as a direct result of the licensee’s project development at such Government dam.
(2) Any licensee that is obligated under the terms of a license issued on or before September 16, 1986 to pay specified annual charges for the use of a Government dam must continue to pay the annual charges prescribed in the project license pending any readjustment of the annual charge for the project made pursuant to section 10(e) of the Federal Power Act.
(b) Graduated flat rates. Annual charges for the use of Government dams or other structures owned by the United States are 1 mill per kilowatt-hour for the first 40 gigawatt-hours of energy a project produces, 1
(c) Information reporting. (1) Except as provided in paragraph (c)(2) of this section, each licensee must file with the Commission, on or before November 1 of each year, a sworn statement showing the gross amount of energy generated during the preceding fiscal year and the amount of energy provided free of charge to the Government. The determination of the annual charge will be based on the gross energy production less the energy provided free of charge to the Government.
(2) A licensee who has filed these data under another section of part 11 or who has submitted identical data with FERC or the Energy Information Administration for the same fiscal year is not required to file the information described in paragraph (c)(1) of this section. Referenced filings should be identified by company name, date filed, docket or project number, and form, number.
(d) Credits. A licensee may file a request with the Director of the Office of Energy Projects for a credit for contractual payments made for construction, operation, and maintenance of a Government dam at any time before 30 days after receiving a billing for annual charges determined under this section. The Director, or his designee, will grant such a credit only when the licensee demonstrates that a credit is reasonably justified. The Director, or his designee, shall consider, among other factors, the contractual arrangements between the licensee and the Federal agency which owns the dam and whether these arrangements reveal clearly that substantial payments are being made for power purposes, relevant legislation, and other equitable factors.
§ 11.4 Use of government dams for pumped storage projects, and use of tribal lands.
(a) General Rule. The Commission will determine on a case-by-case basis under section 10(e) of the Federal Power Act the annual charges for any pumped storage project using a Government dam or other structure and for any project using tribal lands within Indian reservations.
(b) Information reporting. (1) Except as provided in paragraph (b)(2) of this section a Licensee whose project includes pumped storage facilities must file with the Commission, on or before November 1 of each year, a sworn statement showing the gross amount of energy generated during the preceding fiscal year, and the amount of energy provided free of charge to the Government, and the amount of energy used for pumped storage pumping.
(2) A licensee who has filed these data under another section of part 11 or who has submitted identical data with FERC or the Energy Information Administration for the same fiscal year is not required to file the information required in paragraph (b)(1) of this section. Referenced filings should be identified by company name, date filed, docket or project number, and form number.
(c) Commencing in 1993, the annual charges for any project using tribal land within Indian reservations will be billed during the fiscal year in which the land is used, for the use of that land during that year.
§ 11.5 Exemption of minor projects.
No exemption will be made from payment of annual charges for the use of Government dams or tribal lands within Indian reservations but licenses may be issued without charges other than for such use for the development, transmission, or distribution of power for domestic, mining, or other beneficial use in minor projects.
§ 11.6 Exemption of State and municipal licensees and exemptees.
(a) Bases for exemption. A State or municipal licensee or exemptee may claim total or partial exemption from the assessment of annual charges upon one or more of the following grounds:
(1) The project was primarily designed to provide or improve navigation;
(2) To the extent that power generated, transmitted, or distributed by the project was sold directly or indirectly to the public (ultimate consumer) without profit;
(3) To the extent that power generated, transmitted, or distributed by the project was used by the licensee for State or municipal purposes.
(b) Projects primarily for navigation. No State or municipal licensee shall be entitled to exemption from the payment of annual charges on the ground that the project was primarily designed to provide or improve navigation unless the licensee establishes that fact from the actual conditions under which the project was constructed and was operated during the calendar year for which the charge is made.
(c) State or municipal use. A State or municipal licensee shall be entitled to exemption from the payment of annual charges for the project to the extent that power generated, transmitted, or distributed by the project is used by the licensee itself for State or municipal purposes, such as lighting streets, highways, parks, public buildings, etc., for operating licensee’s water or sewerage system, or in performing other public functions of the licensee.
(d) Sales to public. No State or municipal licensee shall be entitled to exemption from the payment of annual charges on the ground that power generated, transmitted, or distributed by the project is sold to the public without profit, unless such licensee shall show:
(1) That it maintains an accounting system which segregates the operations of the licensed project and reflects with reasonable accuracy the revenues and expenses of the project;
(2) That an income statement, prepared in accordance with the Commission’s Uniform System of Accounts, shows that the revenues from the sale of project power do not exceed the total amount of operating expenses, maintenance, depreciation, amortization, taxes, and interest on indebtedness, applicable to the project property. Periodic accruals or payments for redemption of the principal of bonds or other indebtedness may not be deducted in determining the net profit of the project.
(e) Sales for resale. Notwithstanding compliance by a State or municipal licensee with the requirements of paragraph (d) of this section, it shall be subject to the payment of annual charges to the extent that electric power generated, transmitted, or distributed by the project is sold to another State, municipality, person, or corporation for resale, unless the licensee shall show that the power was sold to the ultimate consumer without profit. The matter of whether or not a profit was made is a question of fact to be established by the licensee.
(f) Interchange of power. Notwithstanding compliance by a State or municipal licensee with the requirements of paragraph (d) of this section, it shall be subject to the payment of annual charges to the extent that power generated, transmitted, or distributed by the project was supplied under an interchange agreement to a State, municipality, person, or corporation for sale at a profit (which power was not offset by an equivalent amount of power received under such interchange agreement) unless the licensee shall show that the power was sold to ultimate consumers without profit.
(g) Construction period. During the period when the licensed project is under construction and is not generating power, it will be considered as operating without profit within the meaning of this section, and licensee will be entitled to total exemption from the payment of annual charges, except as to those charges relating to the use of a Government dam or tribal lands within Indian reservations.
(h) Optional showing. When the power from the licensed project enters into the electric power system of the State or municipal licensee, making it impracticable to meet the requirements set forth in this section with respect to the operations of the project only, such licensee may, in lieu thereof, furnish the same information with respect to the operations of said electric power system as a whole.
(i) Application for exemption. Applications for exemption from payment of annual charges shall be signed by an authorized executive officer or chief accounting officer of the licensee or exemptee and verified under oath. The application must be filed with the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov within the time allowed (by § 11.20) for the payment of the annual charges. If the licensee or exemptee, within the time allowed for the payment of the annual charges, files notice that it intends to file an application for exemption, an additional period of 30 days is allowed within which to complete and file the application for exemption. The filing of an application for exemption does not by itself alleviate the requirement to pay the annual charges, nor does it exonerate the licensee or exemptee from the assessment of penalties under § 11.21. If a bill for annual charges becomes payable after an application for an exemption has been filed and while the application is still pending for decision, the bill may be paid under protest and subject to refund.
§ 11.7 Effective date.
All annual charges imposed under this subpart will be computed beginning on the effective date of the license unless some other date is fixed in the license.
§ 11.8 Adjustment of annual charges.
All annual charges imposed under this subpart continue in effect as fixed unless changed as authorized by law.
Subpart B—Charges for Headwater Benefits
§ 11.10 General provision; waiver and exemptions; definitions.
(a) Headwater benefits charges. (1) The Commission will assess or approve charges under this subpart for direct benefits derived from headwater projects constructed by the United States, a licensee, or a pre-1920 permittee. Charges under this subpart will amount to an equitable part of the annual costs of interest, maintenance, and depreciation expenses of such headwater projects and the costs to the Commission of determining headwater benefits charges. Except as provided in paragraph (b) of this section, the owner of any non-Federal downstream project that receives headwater benefits must pay charges determined under this subpart.
(2) Headwater benefits are the additional electric generation at a downstream project that results from regulation of the flow of the river by the headwater, or upstream, project, usually by increasing or decreasing the release of water from a storage reservoir.
(b) Waiver and exemptions. The owner of a downstream project with installed generating capacity of 1.5 MW (2000 horsepower) or less or for which the Commission has granted an exemption from section 10(f) is not required to pay headwater benefits charges.
(c) Definitions. For purposes of this subpart:
(1) Energy gains means the difference between the number of kilowatt-hours of energy produced at a downstream project with the headwater project and that which would be produced without the headwater project.
(2) Generation means gross generation of electricity at a hydroelectric project, including generation needed for station use or the equivalent for direct drive units, measured in kilowatt-hours. It does not include energy used for or derived from pumping in a pumped storage facility.
(3) Headwater project costs means the total costs of an upstream project constructed by the United States, a licensee, or pre-1920 permittee.
(4) Separable cost means the difference between the cost of a multiple-function headwater project with and without any particular function.
(5) Remaining benefits means the difference between the separable cost of a specific function in a multiple-function project and the lesser of:
(i) The benefits of that function in the project, as determined by the responsible Federal agency at the time the project or function was authorized; or
(ii) The cost of the most likely alternative single-function project providing the same benefits.
(6) Joint-use cost means the difference between the total project cost and the total separable costs. Joint-use costs are allocated among the project functions according to each function’s percentage of the total remaining benefits.
(7) Specific power cost means that portion of the headwater project costs that is directly attributable to the function of power generation at the headwater project, including, but not limited to, the cost of the electric generators, turbines, penstocks, and substation.
(8) Joint-use power cost means the portion of the joint-use cost allocated to the power function of the project.
(9) Section 10(f) costs means the annual interest, depreciation, and maintenance expense portion of the joint-use power cost, including costs of non-power functions required by statute to be paid by revenues from the power function.
(10) Party means:
(i) The owner of a non-Federal downstream hydroelectric project which is directly benefited by a headwater project constructed by the United States, a licensee, or a pre-1920 permittee;
(ii) The owner of a headwater project constructed by the United States, a licensee, or a pre-1920 permittee;
(iii) An operating agency of, or an agency marketing power from, a headwater project constructed by the United States; or
(iv) Any party, as defined in § 385.102(c) of this chapter.
(11) Final charge means a charge assessed on an annual basis to recover section 10(f) costs and which represents the final determination of the charge for the period for which headwater benefits are assessed. Final charges may be established retroactively, to finalize an interim charge, or prospectively.
(12) Interim charge means a charge assessed to recover section 10(f) costs for a specified period of headwater benefits pending determination of a final charge for that period.
(13) Investment cost means the sum of:
(i) Project construction costs, including cost of land, labor and materials, cost of pre- and post-authorization investigations, and cost of engineering, supervision, and administration during construction of the project; and
(ii) Interest during construction.
§ 11.11 Energy gains method of determining headwater benefits charges.
(a) Applicability. This section applies to any determination of headwater benefits charges, unless:
(1) The Commission has approved headwater benefits charges pursuant to an existing coordination agreement among the parties;
(2) The parties reach, and the Commission approves, a settlement with respect to headwater benefits charges, pursuant to § 11.14(a) of this subpart; or
(3) Charges may be assessed under § 11.14(b).
(b) General rule—(1) Summary. Except as provided in paragraph (b)(3) of this section, a headwater benefits charge for a downstream project is determined under this subpart by apportioning the section 10(f) costs of the headwater project among the headwater project and all downstream projects that are not exempt from or waived from headwater benefits charges under § 11.10(b) of this chapter, according to each project’s share of the total energy benefits to those projects resulting from the headwater project.
(2) Calculation; headwater benefits formula. The annual headwater benefits charge for a downstream project is derived by multiplying the section 10(f) cost by the ratio of the energy gains received by the downstream project to the sum of total energy gains received by all downstream projects (except those projects specified in § 11.10(b) of this chapter) plus the energy generated at the headwater project that is assigned to the joint-use power cost, as follows:
(3) If power generation is not a function of the headwater project, section 10(f) costs will be apportioned only among the downstream projects.
(4) If the headwater project is constructed after the downstream project, liability for headwater benefits charges will accrue beginning on the day on which any energy losses at the downstream project due to filling the headwater reservoir have been offset by subsequent energy gains. If the headwater project is constructed prior to the downstream project, liability for headwater benefits charges will accrue beginning on the day on which benefits are first realized by the downstream project.
(5) No final charge assessed by the Commission under this subpart may exceed 85 percent of the value of the energy gains. If a party demonstrates, within the time specified in § 11.17(b)(3) for response to a preliminary assessment, that any final charge assessed under this subpart, not including the cost of the investigation assessed under § 11.17(c), exceeds 85 percent of the value of the energy gains provided to the downstream project for the period for which the charge is assessed, the Commission will reduce the charge to not more than 85 percent of the value. For purposes of this paragraph, the value of the energy gains is the cost of obtaining an equivalent amount of electricity from the most likely alternative source during the period for which the charge is assessed.
§ 11.12 Determination of section 10(f) costs.
(a) for non-Federal headwater projects. If the headwater project was constructed by a licensee or pre-1920 permittee and a party requests the Commission to determine charges, the Commission will determine on a case-by-case basis what portion of the annual interest, maintenance, and depreciation costs of the headwater project constitutes the section 10(f) costs, for purposes of this subpart.
(b) For Federal headwater projects. (1) If the headwater project was constructed or is operated by the United States, and the Commission has not approved a settlement between the downstream project owner and the headwater project owner, the section 10(f) cost will be determined by deriving, from information provided by the headwater project owner pursuant to § 11.16 of this subpart, the joint-use power cost and the portion of the annual joint-use power cost that represents the interest, maintenance, and depreciation costs of the project.
(2) If power is not an authorized function of the headwater project, the section 10(f) cost is the annual interest, maintenance, and depreciation portion of the headwater project costs designated as the joint-use power cost, derived by deeming a power function at the project. The value of the benefits assigned to the deemed power function, for purposes of determining the value of remaining benefits of the joint-use power cost, is the total value of downstream energy gains included in the headwater benefits formula.
(3) For purposes of this paragraph, total value of downstream energy gains means the lesser of:
(i) The cost of generating an equivalent amount of electricity at the most likely alternative facility at the time the headwater project became operational; or
(ii) The incremental cost of installing electrical generation at the headwater project at the time the project became operational.
§ 11.13 Energy gains calculations.
(a) Energy gains at a downstream project. (1) Energy gains at a downstream project are determined by simulating operation of the downstream project with and without the effects of the headwater project. Except for determinations which are not complex or in which headwater benefits are expected to be small, calculations will be made by application of the Headwater Benefits Energy Gains Model, as presented in The Headwater Benefits Energy Gains (HWBEG) Model Description and Users Manual, which is available for the National Technical Information Service, U.S. Department of Commerce, 5285 Port Royal Road, Springfield, VA 22161.
(2) If more than one headwater project provide energy gains to a downstream project, the energy gains at the downstream project are attributed to the headwater projects according to the time sequence of commencement of operation in which each headwater project provided energy gains at the downstream project, by:
(i) Crediting the headwater project that is first in time with the amount of energy gains that it provided to the downstream project prior to operation of the headwater project that is next in time; and
(ii) Crediting any subsequent headwater project with the additional increment of energy gains provided by it to the downstream project.
(3) Annual energy losses at a downstream project, or group of projects owned by the same entity, that are attributable to the headwater project will be subtracted from energy gains for the same annual period at the downstream project or group of projects. A net loss in one calendar year will be subtracted from net gains in subsequent years until no net loss remains.
(b) Energy generated at the headwater project. (1) Except as provided in paragraphs (b)(2) and (b)(3) of this section, the portion of the total annual energy generation at the headwater project that is to be attributed to the joint-use power cost is derived by multiplying the total annual generation at the headwater project and the ratio of the project investment cost assigned to the joint-use power cost to the sum of the investment cost assigned to both the specific power cost and the joint-use power cost of the headwater project, as follows:
(2) If the headwater project contains a pumped storage facility, calculation of the portion of the total annual energy generation at the headwater project that is attributable to the joint-use power cost will be determined on a case-by-case basis.
(3) If no power is generated at the headwater project, the amount of energy attributable to the joint-use power cost under this section is the total of all downstream energy gains included in the headwater benefits formula.
§ 11.14 Procedures for establishing charges without an energy gains investigation.
(a) Settlements. (1) Owners of downstream and headwater projects subject to this subpart may negotiate a settlement for headwater benefits charges. Settlements must be filed with the Commission for its approval, according to the provisions of § 385.602.
(2) If the headwater project is a Federal project, any settlement under this section must result in headwater benefits payments that approximate those that would result under the energy gains method.
(b) Continuation of previous headwater benefits determinations. (1) For any downstream project being assessed headwater benefit charges on or before September 16, 1986, the Commission will continue to assess charges to that project on the same basis until changes occur in the river basin, including hydrology or project development, that affect headwater benefits.
(2) Any procedures that apply to § 11.17(b)(5) of this subpart will apply to any prospectively fixed charges that are continued under this paragraph.
§ 11.15 Procedures for determining charges by energy gains investigation.
(a) Purpose of investigations; limitation. Except as permitted under § 11.14, the Commission will conduct an investigation to obtain information for establishing headwater benefits charges under this subpart. The Commission will investigate and determine charges for a project downstream from a non-Federal headwater project only if the parties are unable to agree to a settlement and one of the parties requests the Commission to determine charges.
(b) Notification. The Commission will notify each downstream project owner and each headwater project owner when it initiates an investigation under this section, and the period of project operations to be studied will be specified. An investigation will continue until a final charge has been established for all years studied in the investigation.
(c) Jurisdictional objections. If any project owner wishes to object to the assessment of a headwater benefits charge on jurisdictional grounds, such objection must:
(1) Be raised within 30 days after the notice of the investigation is issued; and
(2) State in detail the grounds for its objection.
(d) Investigations. (1) For any downstream project for which a final charge pursuant to an investigation has never been established, the Commission will conduct an initial investigation to determine a final charge.
(2) The Commission may, for good cause shown by a party or on its own motion, initiate a new investigation of a river basin to determine whether, because of any change in the hydrology, project development, or other characteristics of the river basin that effects headwater benefits, it should:
(i) Establish a new final charge to replace a final charge previously established under § 11.17(b)(5); or
(ii) Revise any variable of the headwater benefits formula that has become a constant in calculating a final charge.
(3) Scope of investigations. (i) The Commission will establish a final charge pursuant to an investigation based on information available to the Commission through the annual data submission requirements of § 11.16, if such information is adequate to establish a reasonably accurate final charge.
(ii) If the information available to the Commission is not sufficient to provide a reasonably accurate calculation of the final charge, the Commission will request additional data and conduct any studies, including studies of the hydrology of the river basin and project operations, that it determines necessary to establish the charge.
§ 11.16 Filing requirements.
(a) Applicability. (1) Any party subject to a headwater benefits determination under this subpart must supply project-specific data, in accordance with this section, by February 1 of each year for data from the preceding calendar year.
(2) Within 30 days of notice of initiation of an investigation under § 11.15, a party must supply project-specific data, in accordance with this section, for the years specified in the notice.
(b) Data required from owner of the headwater project. The owner of any headwater project constructed by the United States, a licensee, or a pre-1920 permittee that is upstream from a non-Federal hydroelectric project must submit the following:
(1) Name and location of the headwater project, including the name of the stream on which it is located.
(2) The total nameplate rating of installed generating capacity of the project, expressed in kilowatts, with the portion of total capacity that represents pumped storage generating capacity separately designated.
(3) A description of the total storage capacity of the reservoir and allocation of storage capacity to each of its functions, such as dead storage, power storage, irrigation storage, and flood control storage. Identification, by reservoir elevation, of the portion of the reservoir assigned to each of its respective storage functions.
(4) An elevation-capacity curve, or a tabulation of reservoir pool elevations with corresponding reservoir storage capacities.
(5) A copy of rule curves, coordination contracts, agreements, or other relevant data governing the release of water from the reservoir, including a separate statement of their effective dates.
(6) A curve or tabulation showing actual reservoir pool elevations throughout the immediately preceding calendar year and for each year included in an investigation.
(7) The total annual gross generation of the hydroelectric plant in kilowatt-hours, not including energy from pumped storage operation.
(8) The total number of kilowatt-hours of energy produced from pumped storage operation.
(9) The investigation costs attributed to the power generation function of the project as of the close of the calendar year or at a specified date during the year, categorized according to that portion that is attributed to the specific power costs, and that portion that is attributed to the joint-use power costs.
(10) The portion of the joint-use power cost, and other costs required by law to be allocated to joint-use power cost, each item shown separately, that are attributable to the annual costs of interest, maintenance, and depreciation, identifying the annual interest rate and the method used to compute the depreciation charge, or the interest rate and period used to compute amortization if used in lieu of depreciation, including any differing interest rates used for major replacements or rehabilitation.
(c) Data required from owners of downstream projects. The owner of any hydroelectric project which is downstream from a headwater project constructed by the United States, a licensee, or pre-1920 permittee must submit the following:
(1) Name and location of the downstream project, including the name of the stream on which it is located.
(2) Total nameplate rating of the installed generating capacity of the plant, expressed in kilowatts, with the portion of total capacity that represents pumped storage generating capacity separately designated.
(3) Record of daily gross generation, not including energy used for pumped storage, and any unit outage which may have occurred.
(4) The total number of kilowatt-hours of energy produced from pumped storage operation.
(d) Abbreviated data submissions. (1) For those items in paragraphs (b) and (c) of this section in which data for the current period are the same as data furnished for a prior period, the data need not be resubmitted if the owner identifies the last period for which the data were reported.
(2) The Commission will notify the project owner that certain data items in paragraphs (b) and (c) are no longer required to be submitted annually if:
(i) A variable in the headwater benefits formula has become a constant; or
(ii) A prospective final charge, as described in § 11.17(b)(5), has been established.
(e) Additional data. Owners of headwater projects or downstream projects must furnish any additional data required by the Commission staff under paragraph (a) of this section and may provide other data which they consider relevant.
§ 11.17 Procedures for payment of charges and costs.
(a) Payment for benefits from a non-Federal headwater project. Any billing procedures and payments determined between a non-Federal headwater project owner and a downstream project owner will occur according to the agreement of those parties.
(b) Charges and payment for benefits from a Federal headwater project—(1) Interim charges. (i) If the Commission has not established a final charge and an investigation is pending, the Commission will issue a downstream project owner a bill for the interim charge and costs and a staff report explaining the calculation of the interim charge.
(ii) An interim charge will be a percentage of the estimate by the Commission staff of what the final charge will be, as follows:
(A) 100 percent of the estimated final charge if the Commission previously has completed an investigation of the project for which it is assessed; or
(B) 80 percent of the estimated final charge if the Commission has not completed an investigation of the project for which it is assessed.
(iii) When a final charge is established for a period for which an interim charge was paid, the Commission will apply the amount paid to the final charge.
(2) Preliminary assessment of a final charge. Unless the project owner was assessed a final charge in the previous year, the Commission will issue to the downstream project owner a preliminary assessment of any final charge when it is determined. A staff technical report explaining the basis of the assessment will be enclosed with the preliminary assessment. Copies of the preliminary assessment will be mailed to all parties.
(3) Opportunity to respond. After issuance of a preliminary assessment of a final charge, parties may respond in writing within 60 days after the preliminary assessment.
(4) Order and bill. (i) After the opportunity for written response by the parties to the preliminary assessment of a final charge, the Commission will issue to the downstream project owner an order establishing the final charge. Copies of the order will be mailed to all parties. A bill will be issued for the amount of the final charge and costs.
(ii) If a final charge is not established prospectively under paragraph (b)(5) of this section, the Commission will issue an order and a bill for the final charge and costs each year until prospective final charges are established. After the Commission issues an order establishing a prospective final charge, a bill will be issued annually for the amount of the final charge and costs.
(5) Prospective final charges. When the Commission determines that historical data, including the hydrology, development, and other characteristics of the river basin, demonstrate sufficient stability to project average energy gains and section 10(f) costs, the Commission will issue to the downstream project owner an order establishing the final charge from future years. Copies of the order will be mailed to all parties. The prospective final charge will remain in effect until a new investigation is initiated under § 11.15(d)(2).
(6) Payment under protest. Any payment of a final charge required by this section may be made under protest if a party is also appealing the final charge pursuant to § 385.1902, or requesting rehearing. If payment is made under protest, that party will avoid any penalty for failure to pay under § 11.21.
(7) Accounting for payments pending appeal or rehearing. The Commission will retain any payment received for final charges from bills issued pursuant to this section in a special account. No disbursements to the U.S. Treasury will be made from the account until 31 days after the bill is issued. If an appeal under § 385.1902 or a request for rehearing is filed by any party, no disbursements to the U.S. Treasury will be made until final disposition of the appeal or request for rehearing.
(c) Charges for costs of determinations of headwater benefits charges. (1) Any owner of a downstream project that benefits from a Federal headwater project must pay to the United States the cost of making any investigation, study, or determination relating to the assessment of the relevant headwater benefits charge under this subpart.
(2) If any owner of a headwater or downstream project requests that the Commission determine headwater benefits charges for benefits provided by non-Federal headwater projects, the headwater project owners must pay a pro rata share of 50 percent of the cost of making the investigation and determination, in proportion to the benefits provided by their projects, and the downstream project owners must pay a pro rata share of the remaining 50 percent in proportion to the energy gains received by their projects.
(3) Any charge assessed under this paragraph is separate from and will be added to, any final or interim charge under this subpart.
Subpart C—General Procedures
§ 11.20 Time for payment.
Annual charges must be paid no later than 45 days after rendition of a bill by the Commission. If the licensee or exemptee believes that the bill is incorrect, no later than 45 days after its rendition the licensee or exemptee may file an appeal of the bill with the Chief Financial Officer. No later than 30 days after the date of issuance of the Chief Financial Officer’s decision on the appeal, the licensee or exemptee may file a request for rehearing of that decision pursuant to § 385.713 of this chapter. In the event that a timely appeal to the Chief Financial Officer or a timely request to the Commission for rehearing is filed, the payment of the bill may be made under protest, and subject to refund pending the outcome of the appeal or rehearing.
§ 11.21 Penalties.
If any person fails to pay annual charges within the periods specified in § 11.20, a penalty of 5 percent of the total delinquent amount will be assessed and added to the total charges for the first month or part of month in which payment is delinquent. An additional penalty of 3 percent for each full month thereafter will be assessed until the charges and penalties are satisfied in accordance with law. The Commission may, by order, waive any penalty imposed by this subsection, for good cause shown.
Appendix A to Part 11—Fee Schedule for FY 2024
| State | County | Fee/acre/yr |
|---|---|---|
| Alabama | Autauga | $61.84 |
| Baldwin | 163.30 | |
| Barbour | 62.63 | |
| Bibb | 78.73 | |
| Blount | 101.02 | |
| Bullock | 60.08 | |
| Butler | 68.83 | |
| Calhoun | 119.09 | |
| Chambers | 70.48 | |
| Cherokee | 88.82 | |
| Chilton | 98.98 | |
| Choctaw | 57.50 | |
| Clarke | 63.92 | |
| Clay | 78.73 | |
| Cleburne | 97.04 | |
| Coffee | 73.85 | |
| Colbert | 74.74 | |
| Conecuh | 60.08 | |
| Coosa | 64.28 | |
| Covington | 75.28 | |
| Crenshaw | 69.95 | |
| Cullman | 111.54 | |
| Dale | 84.39 | |
| Dallas | 52.59 | |
| DeKalb | 110.36 | |
| Elmore | 84.03 | |
| Escambia | 68.94 | |
| Etowah | 107.59 | |
| Fayette | 61.87 | |
| Franklin | 68.74 | |
| Geneva | 69.44 | |
| Greene | 54.72 | |
| Hale | 63.39 | |
| Henry | 72.36 | |
| Houston | 99.09 | |
| Jackson | 85.32 | |
| Jefferson | 123.77 | |
| Lamar | 52.14 | |
| Lauderdale | 101.70 | |
| Lawrence | 106.47 | |
| Lee | 116.39 | |
| Limestone | 115.89 | |
| Lowndes | 53.23 | |
| Macon | 65.83 | |
| Madison | 148.82 | |
| Marengo | 56.29 | |
| Marion | 65.60 | |
| Marshall | 124.28 | |
| Mobile | 132.89 | |
| Monroe | 67.20 | |
| Montgomery | 74.60 | |
| Morgan | 123.49 | |
| Perry | 61.93 | |
| Pickens | 70.90 | |
| Pike | 73.48 | |
| Randolph | 88.54 | |
| Russell | 71.27 | |
| Shelby | 111.51 | |
| St. Clair | 119.96 | |
| Sumter | 52.50 | |
| Talladega | 92.81 | |
| Tallapoosa | 80.07 | |
| Tuscaloosa | 94.35 | |
| Walker | 84.67 | |
| Washington | 56.82 | |
| Wilcox | 50.99 | |
| Winston | 77.55 | |
| Alaska | Aleutian Islands | 0.94 |
| Statewide | 50.28 | |
| Arizona | Apache | 4.65 |
| Cochise | 33.93 | |
| Coconino | 3.59 | |
| Gila | 6.58 | |
| Graham | 10.97 | |
| Greenlee | 26.38 | |
| La Paz | 34.11 | |
| Maricopa | 156.29 | |
| Mohave | 14.20 | |
| Navajo | 3.74 | |
| Pima | 8.92 | |
| Pinal | 46.77 | |
| Santa Cruz | 33.74 | |
| Yavapai | 27.94 | |
| Yuma | 156.28 | |
| Arkansas | Arkansas | 65.87 |
| Ashley | 60.50 | |
| Baxter | 56.23 | |
| Benton | 135.42 | |
| Boone | 55.10 | |
| Bradley | 68.71 | |
| Calhoun | 54.16 | |
| Carroll | 57.49 | |
| Chicot | 62.11 | |
| Clark | 50.61 | |
| Clay | 90.10 | |
| Cleburne | 61.42 | |
| Cleveland | 88.47 | |
| Columbia | 48.56 | |
| Conway | 53.12 | |
| Craighead | 96.43 | |
| Crawford | 64.14 | |
| Crittenden | 80.50 | |
| Cross | 70.45 | |
| Dallas | 40.74 | |
| Desha | 68.02 | |
| Drew | 60.48 | |
| Faulkner | 80.27 | |
| Franklin | 53.60 | |
| Fulton | 39.03 | |
| Garland | 109.25 | |
| Grant | 75.51 | |
| Greene | 88.61 | |
| Hempstead | 52.35 | |
| Hot Spring | 58.18 | |
| Howard | 59.68 | |
| Independence | 48.06 | |
| Izard | 42.79 | |
| Jackson | 70.43 | |
| Jefferson | 68.30 | |
| Johnson | 58.37 | |
| Lafayette | 53.24 | |
| Lawrence | 74.96 | |
| Lee | 66.33 | |
| Lincoln | 64.43 | |
| Little River | 50.46 | |
| Logan | 52.24 | |
| Lonoke | 76.99 | |
| Madison | 65.49 | |
| Marion | 50.97 | |
| Miller | 53.89 | |
| Mississippi | 71.83 | |
| Monroe | 59.01 | |
| Montgomery | 54.33 | |
| Nevada | 49.46 | |
| Newton | 50.92 | |
| Ouachita | 46.64 | |
| Perry | 57.65 | |
| Phillips | 66.60 | |
| Pike | 54.52 | |
| Poinsett | 79.88 | |
| Polk | 61.86 | |
| Pope | 67.10 | |
| Prairie | 61.04 | |
| Pulaski | 82.13 | |
| Randolph | 61.38 | |
| Saline | 71.58 | |
| Scott | 51.30 | |
| Searcy | 39.36 | |
| Sebastian | 69.88 | |
| Sevier | 55.77 | |
| Sharp | 44.57 | |
| St. Francis | 64.97 | |
| Stone | 45.22 | |
| Union | 57.80 | |
| Van Buren | 57.57 | |
| Washington | 107.28 | |
| White | 58.09 | |
| Woodruff | 68.02 | |
| Yell | 56.34 | |
| California | Alameda | 47.28 |
| Alpine | 30.43 | |
| Amador | 29.64 | |
| Butte | 80.13 | |
| Calaveras | 23.65 | |
| Colusa | 53.01 | |
| Contra Costa | 46.06 | |
| Del Norte | 55.33 | |
| El Dorado | 66.05 | |
| Fresno | 75.58 | |
| Glenn | 59.32 | |
| Humboldt | 20.56 | |
| Imperial | 74.09 | |
| Inyo | 4.13 | |
| Kern | 49.11 | |
| Kings | 71.96 | |
| Lake | 43.62 | |
| Lassen | 14.23 | |
| Los Angeles | 123.63 | |
| Madera | 72.91 | |
| Marin | 39.01 | |
| Mariposa | 13.73 | |
| Mendocino | 25.48 | |
| Merced | 87.07 | |
| Modoc | 13.02 | |
| Mono | 12.78 | |
| Monterey | 49.03 | |
| Napa | 293.80 | |
| Nevada | 49.41 | |
| Orange | 127.05 | |
| Placer | 44.68 | |
| Plumas | 15.29 | |
| Riverside | 120.73 | |
| Sacramento | 66.86 | |
| San Benito | 23.75 | |
| San Bernardino | 132.39 | |
| San Diego | 154.43 | |
| San Francisco | 517.41 | |
| San Joaquin | 99.94 | |
| San Luis Obispo | 50.22 | |
| San Mateo | 65.00 | |
| Santa Barbara | 69.08 | |
| Santa Clara | 54.14 | |
| Santa Cruz | 142.08 | |
| Shasta | 19.42 | |
| Sierra | 11.33 | |
| Siskiyou | 20.40 | |
| Solano | 60.87 | |
| Sonoma | 147.63 | |
| Stanislaus | 103.93 | |
| Sutter | 63.38 | |
| Tehama | 28.70 | |
| Trinity | 12.78 | |
| Tulare | 78.02 | |
| Tuolumne | 24.72 | |
| Ventura | 169.66 | |
| Yolo | 64.56 | |
| Yuba | 54.70 | |
| Colorado | Adams | 28.67 |
| Alamosa | 37.68 | |
| Arapahoe | 40.17 | |
| Archuleta | 55.17 | |
| Baca | 13.93 | |
| Bent | 12.26 | |
| Boulder | 223.42 | |
| Broomfield | 97.16 | |
| Chaffee | 90.20 | |
| Cheyenne | 14.89 | |
| Clear Creek | 56.11 | |
| Conejos | 29.98 | |
| Costilla | 21.59 | |
| Crowley | 9.05 | |
| Custer | 34.53 | |
| Delta | 85.54 | |
| Denver | 1,132.61 | |
| Dolores | 31.69 | |
| Douglas | 119.91 | |
| Eagle | 58.81 | |
| El Paso | 25.01 | |
| Elbert | 27.12 | |
| Fremont | 41.52 | |
| Garfield | 42.64 | |
| Gilpin | 75.11 | |
| Grand | 39.08 | |
| Gunnison | 45.62 | |
| Hinsdale | 32.72 | |
| Huerfano | 17.10 | |
| Jackson | 23.51 | |
| Jefferson | 137.12 | |
| Kiowa | 13.40 | |
| Kit Carson | 21.66 | |
| La Plata | 40.15 | |
| Lake | 36.52 | |
| Larimer | 82.41 | |
| Las Animas | 10.70 | |
| Lincoln | 12.51 | |
| Logan | 21.11 | |
| Mesa | 98.16 | |
| Mineral | 61.16 | |
| Moffat | 14.20 | |
| Montezuma | 21.52 | |
| Montrose | 54.97 | |
| Morgan | 30.84 | |
| Otero | 13.33 | |
| Ouray | 54.28 | |
| Park | 29.86 | |
| Phillips | 30.07 | |
| Pitkin | 135.37 | |
| Prowers | 14.32 | |
| Pueblo | 18.27 | |
| Rio Blanco | 24.40 | |
| Rio Grande | 55.50 | |
| Routt | 55.82 | |
| Saguache | 33.73 | |
| San Juan | 28.58 | |
| San Miguel | 26.48 | |
| Sedgwick | 24.05 | |
| Summit | 75.09 | |
| Teller | 35.95 | |
| Washington | 19.51 | |
| Weld | 45.96 | |
| Yuma | 29.02 | |
| Connecticut | Fairfield | 290.28 |
| Hartford | 433.67 | |
| Litchfield | 304.47 | |
| Middlesex | 400.99 | |
| New Haven | 631.70 | |
| New London | 308.37 | |
| Tolland | 260.94 | |
| Windham | 254.19 | |
| Delaware | Kent | 216.57 |
| New Castle | 259.65 | |
| Sussex | 231.60 | |
| Florida | Alachua | 159.68 |
| Baker | 93.54 | |
| Bay | 41.82 | |
| Bradford | 97.40 | |
| Brevard | 102.49 | |
| Broward | 675.68 | |
| Calhoun | 43.92 | |
| Charlotte | 146.31 | |
| Citrus | 161.66 | |
| Clay | 116.75 | |
| Collier | 96.83 | |
| Columbia | 88.92 | |
| Dade | 763.56 | |
| DeSoto | 102.11 | |
| Dixie | 75.89 | |
| Duval | 153.38 | |
| Escambia | 126.53 | |
| Flagler | 113.46 | |
| Franklin | 120.31 | |
| Gadsden | 86.77 | |
| Gilchrist | 108.49 | |
| Glades | 87.83 | |
| Gulf | 29.26 | |
| Hamilton | 78.80 | |
| Hardee | 108.81 | |
| Hendry | 99.90 | |
| Hernando | 213.84 | |
| Highlands | 79.64 | |
| Hillsborough | 238.10 | |
| Holmes | 67.98 | |
| Indian River | 117.13 | |
| Jackson | 75.32 | |
| Jefferson | 70.71 | |
| Lafayette | 61.66 | |
| Lake | 161.72 | |
| Lee | 248.87 | |
| Leon | 86.98 | |
| Levy | 93.95 | |
| Liberty | 79.84 | |
| Madison | 71.91 | |
| Manatee | 158.71 | |
| Marion | 226.60 | |
| Martin | 89.63 | |
| Monroe | 120.31 | |
| Nassau | 76.34 | |
| Okaloosa | 97.11 | |
| Okeechobee | 86.10 | |
| Orange | 171.92 | |
| Osceola | 79.11 | |
| Palm Beach | 170.84 | |
| Pasco | 146.00 | |
| Pinellas | 1,171.62 | |
| Polk | 123.64 | |
| Putnam | 81.09 | |
| Santa Rosa | 109.32 | |
| Sarasota | 187.47 | |
| Seminole | 168.64 | |
| St. Johns | 173.45 | |
| St. Lucie | 121.84 | |
| Sumter | 122.84 | |
| Suwannee | 90.08 | |
| Taylor | 74.42 | |
| Union | 75.89 | |
| Volusia | 210.19 | |
| Wakulla | 69.73 | |
| Walton | 76.89 | |
| Washington | 77.89 | |
| Georgia | Appling | 85.06 |
| Atkinson | 76.03 | |
| Bacon | 107.76 | |
| Baker | 58.17 | |
| Baldwin | 56.68 | |
| Banks | 140.87 | |
| Barrow | 171.66 | |
| Bartow | 157.73 | |
| Ben Hill | 64.64 | |
| Berrien | 81.89 | |
| Bibb | 104.88 | |
| Bleckley | 67.54 | |
| Brantley | 76.42 | |
| Brooks | 91.53 | |
| Bryan | 80.56 | |
| Bulloch | 74.98 | |
| Burke | 74.43 | |
| Butts | 102.02 | |
| Calhoun | 78.91 | |
| Camden | 75.01 | |
| Candler | 82.73 | |
| Carroll | 125.30 | |
| Catoosa | 144.07 | |
| Charlton | 63.54 | |
| Chatham | 132.94 | |
| Chattahoochee | 77.44 | |
| Chattooga | 92.73 | |
| Cherokee | 227.11 | |
| Clarke | 202.50 | |
| Clay | 61.97 | |
| Clayton | 218.73 | |
| Clinch | 104.27 | |
| Cobb | 299.11 | |
| Coffee | 78.96 | |
| Colquitt | 86.60 | |
| Columbia | 116.55 | |
| Cook | 79.53 | |
| Coweta | 126.32 | |
| Crawford | 105.48 | |
| Crisp | 80.24 | |
| Dade | 104.22 | |
| Dawson | 182.81 | |
| Decatur | 85.35 | |
| DeKalb | 1,228.70 | |
| Dodge | 68.07 | |
| Dooly | 76.50 | |
| Dougherty | 101.29 | |
| Douglas | 175.27 | |
| Early | 67.26 | |
| Echols | 73.07 | |
| Effingham | 85.08 | |
| Elbert | 102.76 | |
| Emanuel | 54.74 | |
| Evans | 70.66 | |
| Fannin | 154.51 | |
| Fayette | 142.44 | |
| Floyd | 127.39 | |
| Forsyth | 206.27 | |
| Franklin | 150.48 | |
| Fulton | 499.07 | |
| Gilmer | 200.46 | |
| Glascock | 41.68 | |
| Glynn | 403.46 | |
| Gordon | 171.35 | |
| Grady | 98.44 | |
| Greene | 93.88 | |
| Gwinnett | 244.49 | |
| Habersham | 187.45 | |
| Hall | 244.31 | |
| Hancock | 54.77 | |
| Haralson | 124.35 | |
| Harris | 113.15 | |
| Hart | 147.18 | |
| Heard | 94.54 | |
| Henry | 195.88 | |
| Houston | 105.27 | |
| Irwin | 85.06 | |
| Jackson | 166.77 | |
| Jasper | 91.13 | |
| Jeff Davis | 65.58 | |
| Jefferson | 67.81 | |
| Jenkins | 68.59 | |
| Johnson | 54.79 | |
| Jones | 73.46 | |
| Lamar | 91.66 | |
| Lanier | 79.33 | |
| Laurens | 54.87 | |
| Lee | 88.59 | |
| Liberty | 138.47 | |
| Lincoln | 81.81 | |
| Long | 87.99 | |
| Lowndes | 142.71 | |
| Lumpkin | 155.12 | |
| Macon | 84.22 | |
| Madison | 148.28 | |
| Marion | 62.18 | |
| McDuffie | 78.38 | |
| McIntosh | 62.10 | |
| Meriwether | 85.40 | |
| Miller | 84.88 | |
| Mitchell | 96.92 | |
| Monroe | 85.84 | |
| Montgomery | 67.65 | |
| Morgan | 122.34 | |
| Murray | 132.68 | |
| Muscogee | 130.98 | |
| Newton | 117.16 | |
| Oconee | 189.41 | |
| Oglethorpe | 113.96 | |
| Paulding | 151.35 | |
| Peach | 150.95 | |
| Pickens | 223.29 | |
| Pierce | 75.32 | |
| Pike | 128.20 | |
| Polk | 94.67 | |
| Pulaski | 69.93 | |
| Putnam | 110.11 | |
| Quitman | 60.40 | |
| Rabun | 215.72 | |
| Randolph | 74.14 | |
| Richmond | 96.34 | |
| Rockdale | 184.83 | |
| Schley | 74.56 | |
| Screven | 57.60 | |
| Seminole | 82.23 | |
| Spalding | 134.07 | |
| Stephens | 151.16 | |
| Stewart | 54.17 | |
| Sumter | 74.85 | |
| Talbot | 71.60 | |
| Taliaferro | 86.18 | |
| Tattnall | 101.42 | |
| Taylor | 54.43 | |
| Telfair | 57.86 | |
| Terrell | 73.38 | |
| Thomas | 95.29 | |
| Tift | 83.10 | |
| Toombs | 72.78 | |
| Towns | 143.91 | |
| Treutlen | 49.30 | |
| Troup | 84.98 | |
| Turner | 80.74 | |
| Twiggs | 63.28 | |
| Union | 151.08 | |
| Upson | 103.52 | |
| Walker | 110.98 | |
| Walton | 148.28 | |
| Ware | 67.15 | |
| Warren | 78.07 | |
| Washington | 55.13 | |
| Wayne | 54.45 | |
| Webster | 63.93 | |
| Wheeler | 47.88 | |
| White | 212.74 | |
| Whitfield | 161.92 | |
| Wilcox | 68.28 | |
| Wilkes | 90.24 | |
| Wilkinson | 53.67 | |
| Worth | 78.62 | |
| Hawaii | Hawaii | 156.43 |
| Honolulu | 559.34 | |
| Kauai | 202.63 | |
| Maui | 258.67 | |
| Idaho | Ada | 128.41 |
| Adams | 20.93 | |
| Bannock | 26.37 | |
| Bear Lake | 19.43 | |
| Benewah | 26.14 | |
| Bingham | 34.35 | |
| Blaine | 34.16 | |
| Boise | 19.35 | |
| Bonner | 67.99 | |
| Bonneville | 39.36 | |
| Boundary | 64.59 | |
| Butte | 27.72 | |
| Camas | 18.11 | |
| Canyon | 111.25 | |
| Caribou | 25.06 | |
| Cassia | 43.07 | |
| Clark | 23.69 | |
| Clearwater | 33.34 | |
| Custer | 36.80 | |
| Elmore | 33.65 | |
| Franklin | 31.39 | |
| Fremont | 37.36 | |
| Gem | 38.01 | |
| Gooding | 81.22 | |
| Idaho | 22.20 | |
| Jefferson | 47.55 | |
| Jerome | 81.54 | |
| Kootenai | 74.60 | |
| Latah | 34.32 | |
| Lemhi | 34.10 | |
| Lewis | 26.52 | |
| Lincoln | 49.29 | |
| Madison | 56.19 | |
| Minidoka | 61.28 | |
| Nez Perce | 28.07 | |
| Oneida | 22.39 | |
| Owyhee | 21.98 | |
| Payette | 47.32 | |
| Power | 33.31 | |
| Shoshone | 90.66 | |
| Teton | 53.38 | |
| Twin Falls | 59.93 | |
| Valley | 35.02 | |
| Washington | 18.28 | |
| Illinois | Adams | 185.37 |
| Alexander | 97.53 | |
| Bond | 195.85 | |
| Boone | 222.55 | |
| Brown | 159.50 | |
| Bureau | 234.18 | |
| Calhoun | 119.35 | |
| Carroll | 229.05 | |
| Cass | 182.29 | |
| Champaign | 265.46 | |
| Christian | 246.11 | |
| Clark | 162.63 | |
| Clay | 145.91 | |
| Clinton | 197.39 | |
| Coles | 224.38 | |
| Cook | 587.93 | |
| Crawford | 149.70 | |
| Cumberland | 180.75 | |
| De Witt | 238.96 | |
| DeKalb | 268.40 | |
| Douglas | 258.45 | |
| DuPage | 478.87 | |
| Edgar | 211.55 | |
| Edwards | 153.06 | |
| Effingham | 188.13 | |
| Fayette | 153.80 | |
| Ford | 221.36 | |
| Franklin | 127.07 | |
| Fulton | 176.45 | |
| Gallatin | 151.21 | |
| Greene | 176.20 | |
| Grundy | 252.67 | |
| Hamilton | 137.05 | |
| Hancock | 202.04 | |
| Hardin | 93.48 | |
| Henderson | 198.33 | |
| Henry | 225.14 | |
| Iroquois | 209.36 | |
| Jackson | 153.46 | |
| Jasper | 160.52 | |
| Jefferson | 118.47 | |
| Jersey | 180.35 | |
| Jo Daviess | 174.09 | |
| Johnson | 105.45 | |
| Kane | 300.82 | |
| Kankakee | 222.87 | |
| Kendall | 258.11 | |
| Knox | 208.53 | |
| La Salle | 259.99 | |
| Lake | 346.15 | |
| Lawrence | 160.98 | |
| Lee | 246.97 | |
| Livingston | 234.49 | |
| Logan | 238.76 | |
| Macon | 263.55 | |
| Macoupin | 205.00 | |
| Madison | 248.05 | |
| Marion | 139.18 | |
| Marshall | 230.07 | |
| Mason | 198.96 | |
| Massac | 110.29 | |
| McDonough | 208.96 | |
| McHenry | 271.84 | |
| McLean | 280.48 | |
| Menard | 222.44 | |
| Mercer | 186.65 | |
| Monroe | 189.73 | |
| Montgomery | 207.31 | |
| Morgan | 234.97 | |
| Moultrie | 248.94 | |
| Ogle | 245.00 | |
| Peoria | 224.86 | |
| Perry | 136.25 | |
| Piatt | 263.84 | |
| Pike | 168.56 | |
| Pope | 99.47 | |
| Pulaski | 116.90 | |
| Putnam | 238.54 | |
| Randolph | 154.51 | |
| Richland | 150.44 | |
| Rock Island | 198.45 | |
| Saline | 137.45 | |
| Sangamon | 254.46 | |
| Schuyler | 156.25 | |
| Scott | 185.14 | |
| Shelby | 200.78 | |
| St. Clair | 211.33 | |
| Stark | 236.88 | |
| Stephenson | 240.02 | |
| Tazewell | 235.69 | |
| Union | 121.03 | |
| Vermilion | 233.72 | |
| Wabash | 157.65 | |
| Warren | 230.56 | |
| Washington | 182.98 | |
| Wayne | 135.74 | |
| White | 141.98 | |
| Whiteside | 224.86 | |
| Will | 253.24 | |
| Williamson | 112.63 | |
| Winnebago | 203.35 | |
| Woodford | 255.63 | |
| Indiana | Adams | 234.96 |
| Allen | 225.76 | |
| Bartholomew | 189.92 | |
| Benton | 219.62 | |
| Blackford | 187.56 | |
| Boone | 216.41 | |
| Brown | 124.66 | |
| Carroll | 214.08 | |
| Cass | 177.28 | |
| Clark | 156.61 | |
| Clay | 144.82 | |
| Clinton | 203.58 | |
| Crawford | 87.86 | |
| Daviess | 216.38 | |
| Dearborn | 138.04 | |
| Decatur | 201.14 | |
| DeKalb | 157.52 | |
| Delaware | 188.36 | |
| Dubois | 154.91 | |
| Elkhart | 317.42 | |
| Fayette | 160.61 | |
| Floyd | 154.93 | |
| Fountain | 191.17 | |
| Franklin | 161.01 | |
| Fulton | 179.24 | |
| Gibson | 184.13 | |
| Grant | 200.45 | |
| Greene | 140.62 | |
| Hamilton | 248.47 | |
| Hancock | 214.20 | |
| Harrison | 129.92 | |
| Hendricks | 216.90 | |
| Henry | 170.01 | |
| Howard | 220.50 | |
| Huntington | 194.63 | |
| Jackson | 150.36 | |
| Jasper | 183.33 | |
| Jay | 215.39 | |
| Jefferson | 117.59 | |
| Jennings | 129.60 | |
| Johnson | 191.54 | |
| Knox | 176.74 | |
| Kosciusko | 202.19 | |
| LaGrange | 262.64 | |
| Lake | 197.81 | |
| LaPorte | 208.86 | |
| Lawrence | 105.52 | |
| Madison | 230.24 | |
| Marion | 299.98 | |
| Marshall | 177.74 | |
| Martin | 110.35 | |
| Miami | 191.68 | |
| Monroe | 186.54 | |
| Montgomery | 198.32 | |
| Morgan | 178.59 | |
| Newton | 191.20 | |
| Noble | 181.57 | |
| Ohio | 124.04 | |
| Orange | 127.47 | |
| Owen | 129.01 | |
| Parke | 165.84 | |
| Perry | 113.96 | |
| Pike | 140.03 | |
| Porter | 192.13 | |
| Posey | 172.45 | |
| Pulaski | 174.64 | |
| Putnam | 182.73 | |
| Randolph | 182.22 | |
| Ripley | 146.61 | |
| Rush | 206.02 | |
| Scott | 152.43 | |
| Shelby | 197.22 | |
| Spencer | 130.88 | |
| St. Joseph | 229.65 | |
| Starke | 142.10 | |
| Steuben | 157.23 | |
| Sullivan | 141.33 | |
| Switzerland | 116.37 | |
| Tippecanoe | 256.34 | |
| Tipton | 231.92 | |
| Union | 180.04 | |
| Vanderburgh | 224.51 | |
| Vermillion | 161.12 | |
| Vigo | 154.05 | |
| Wabash | 178.62 | |
| Warren | 192.70 | |
| Warrick | 154.17 | |
| Washington | 127.81 | |
| Wayne | 155.96 | |
| Wells | 214.23 | |
| White | 221.92 | |
| Whitley | 180.12 | |
| Iowa | Adair | 149.19 |
| Adams | 142.26 | |
| Allamakee | 152.47 | |
| Appanoose | 115.96 | |
| Audubon | 195.86 | |
| Benton | 210.72 | |
| Black Hawk | 248.83 | |
| Boone | 227.24 | |
| Bremer | 227.95 | |
| Buchanan | 224.90 | |
| Buena Vista | 229.49 | |
| Butler | 204.50 | |
| Calhoun | 226.55 | |
| Carroll | 229.06 | |
| Cass | 168.16 | |
| Cedar | 224.16 | |
| Cerro Gordo | 209.41 | |
| Cherokee | 225.75 | |
| Chickasaw | 212.89 | |
| Clarke | 121.83 | |
| Clay | 227.78 | |
| Clayton | 158.18 | |
| Clinton | 215.20 | |
| Crawford | 193.23 | |
| Dallas | 233.03 | |
| Davis | 111.71 | |
| Decatur | 109.68 | |
| Delaware | 221.73 | |
| Des Moines | 197.11 | |
| Dickinson | 212.20 | |
| Dubuque | 246.26 | |
| Emmet | 204.87 | |
| Fayette | 204.70 | |
| Floyd | 209.92 | |
| Franklin | 222.90 | |
| Fremont | 171.21 | |
| Greene | 236.68 | |
| Grundy | 259.19 | |
| Guthrie | 179.74 | |
| Hamilton | 231.49 | |
| Hancock | 217.40 | |
| Hardin | 222.87 | |
| Harrison | 175.75 | |
| Henry | 178.77 | |
| Howard | 212.66 | |
| Humboldt | 230.72 | |
| Ida | 209.58 | |
| Iowa | 182.99 | |
| Jackson | 170.38 | |
| Jasper | 185.76 | |
| Jefferson | 157.98 | |
| Johnson | 229.26 | |
| Jones | 198.60 | |
| Keokuk | 166.51 | |
| Kossuth | 225.13 | |
| Lee | 147.36 | |
| Linn | 237.56 | |
| Louisa | 189.15 | |
| Lucas | 97.36 | |
| Lyon | 284.92 | |
| Madison | 161.68 | |
| Mahaska | 176.66 | |
| Marion | 164.62 | |
| Marshall | 216.80 | |
| Mills | 170.93 | |
| Mitchell | 224.36 | |
| Monona | 164.37 | |
| Monroe | 119.98 | |
| Montgomery | 162.03 | |
| Muscatine | 191.69 | |
| O’Brien | 277.47 | |
| Osceola | 249.94 | |
| Page | 153.18 | |
| Palo Alto | 228.61 | |
| Plymouth | 244.21 | |
| Pocahontas | 230.03 | |
| Polk | 252.20 | |
| Pottawattamie | 193.52 | |
| Poweshiek | 191.35 | |
| Ringgold | 109.94 | |
| Sac | 226.58 | |
| Scott | 273.51 | |
| Shelby | 195.49 | |
| Sioux | 296.81 | |
| Story | 270.05 | |
| Tama | 206.98 | |
| Taylor | 137.27 | |
| Union | 127.17 | |
| Van Buren | 133.33 | |
| Wapello | 139.09 | |
| Warren | 160.77 | |
| Washington | 196.51 | |
| Wayne | 121.29 | |
| Webster | 226.72 | |
| Winnebago | 199.37 | |
| Winneshiek | 182.59 | |
| Woodbury | 210.38 | |
| Worth | 198.43 | |
| Wright | 216.03 | |
| Kansas | Allen | 57.30 |
| Anderson | 57.55 | |
| Atchison | 85.85 | |
| Barber | 40.55 | |
| Barton | 44.34 | |
| Bourbon | 56.71 | |
| Brown | 99.04 | |
| Butler | 64.05 | |
| Chase | 53.97 | |
| Chautauqua | 46.06 | |
| Cherokee | 62.44 | |
| Cheyenne | 41.71 | |
| Clark | 33.52 | |
| Clay | 76.59 | |
| Cloud | 65.01 | |
| Coffey | 51.54 | |
| Comanche | 32.73 | |
| Cowley | 52.22 | |
| Crawford | 56.88 | |
| Decatur | 41.17 | |
| Dickinson | 60.43 | |
| Doniphan | 96.89 | |
| Douglas | 114.99 | |
| Edwards | 52.05 | |
| Elk | 43.63 | |
| Ellis | 38.10 | |
| Ellsworth | 45.41 | |
| Finney | 44.20 | |
| Ford | 43.69 | |
| Franklin | 67.86 | |
| Geary | 64.98 | |
| Gove | 36.74 | |
| Graham | 36.29 | |
| Grant | 44.51 | |
| Gray | 45.07 | |
| Greeley | 39.99 | |
| Greenwood | 47.08 | |
| Hamilton | 30.10 | |
| Harper | 46.37 | |
| Harvey | 89.44 | |
| Haskell | 43.12 | |
| Hodgeman | 33.21 | |
| Jackson | 75.60 | |
| Jefferson | 82.01 | |
| Jewell | 58.18 | |
| Johnson | 106.55 | |
| Kearny | 40.72 | |
| Kingman | 45.72 | |
| Kiowa | 44.37 | |
| Labette | 59.90 | |
| Lane | 35.98 | |
| Leavenworth | 96.61 | |
| Lincoln | 48.77 | |
| Linn | 72.13 | |
| Logan | 38.01 | |
| Lyon | 56.14 | |
| Marion | 57.67 | |
| Marshall | 87.38 | |
| McPherson | 77.35 | |
| Meade | 41.68 | |
| Miami | 87.40 | |
| Mitchell | 52.75 | |
| Montgomery | 56.76 | |
| Morris | 45.81 | |
| Morton | 28.92 | |
| Nemaha | 84.89 | |
| Neosho | 55.44 | |
| Ness | 30.61 | |
| Norton | 38.44 | |
| Osage | 56.25 | |
| Osborne | 39.82 | |
| Ottawa | 56.79 | |
| Pawnee | 46.82 | |
| Phillips | 40.72 | |
| Pottawatomie | 69.50 | |
| Pratt | 58.03 | |
| Rawlins | 43.55 | |
| Reno | 60.41 | |
| Republic | 73.03 | |
| Rice | 57.50 | |
| Riley | 85.34 | |
| Rooks | 35.33 | |
| Rush | 36.68 | |
| Russell | 37.81 | |
| Saline | 66.96 | |
| Scott | 42.78 | |
| Sedgwick | 97.82 | |
| Seward | 39.82 | |
| Shawnee | 84.52 | |
| Sheridan | 44.17 | |
| Sherman | 49.73 | |
| Smith | 53.91 | |
| Stafford | 50.92 | |
| Stanton | 30.05 | |
| Stevens | 39.17 | |
| Sumner | 51.91 | |
| Thomas | 49.34 | |
| Trego | 32.22 | |
| Wabaunsee | 54.42 | |
| Wallace | 38.18 | |
| Washington | 68.51 | |
| Wichita | 39.56 | |
| Wilson | 54.98 | |
| Woodson | 46.94 | |
| Wyandotte | 190.40 | |
| Kentucky | Adair | 85.49 |
| Allen | 98.40 | |
| Anderson | 105.53 | |
| Ballard | 102.72 | |
| Barren | 102.37 | |
| Bath | 67.07 | |
| Bell | 56.56 | |
| Boone | 170.64 | |
| Bourbon | 161.55 | |
| Boyd | 68.35 | |
| Boyle | 105.73 | |
| Bracken | 71.00 | |
| Breathitt | 44.59 | |
| Breckinridge | 87.74 | |
| Bullitt | 146.68 | |
| Butler | 75.26 | |
| Caldwell | 94.90 | |
| Calloway | 117.15 | |
| Campbell | 143.81 | |
| Carlisle | 107.94 | |
| Carroll | 96.43 | |
| Carter | 54.94 | |
| Casey | 66.59 | |
| Christian | 136.91 | |
| Clark | 125.94 | |
| Clay | 51.56 | |
| Clinton | 79.24 | |
| Crittenden | 78.07 | |
| Cumberland | 58.35 | |
| Daviess | 141.71 | |
| Edmonson | 90.32 | |
| Elliott | 46.01 | |
| Estill | 68.33 | |
| Fayette | 415.49 | |
| Fleming | 75.12 | |
| Floyd | 87.77 | |
| Franklin | 112.75 | |
| Fulton | 104.42 | |
| Gallatin | 80.86 | |
| Garrard | 82.91 | |
| Grant | 94.05 | |
| Graves | 108.71 | |
| Grayson | 84.01 | |
| Green | 73.75 | |
| Greenup | 70.23 | |
| Hancock | 84.61 | |
| Hardin | 130.57 | |
| Harlan | 44.45 | |
| Harrison | 88.11 | |
| Hart | 87.48 | |
| Henderson | 144.84 | |
| Henry | 109.74 | |
| Hickman | 114.08 | |
| Hopkins | 95.84 | |
| Jackson | 66.96 | |
| Jefferson | 349.47 | |
| Jessamine | 188.72 | |
| Johnson | 85.29 | |
| Kenton | 159.07 | |
| Knott | 36.35 | |
| Knox | 68.04 | |
| Larue | 100.87 | |
| Laurel | 95.01 | |
| Lawrence | 45.45 | |
| Lee | 58.18 | |
| Leslie | 108.57 | |
| Letcher | 85.26 | |
| Lewis | 59.57 | |
| Lincoln | 92.26 | |
| Livingston | 79.92 | |
| Logan | 137.25 | |
| Lyon | 88.70 | |
| Madison | 98.57 | |
| Magoffin | 58.83 | |
| Marion | 98.96 | |
| Marshall | 107.89 | |
| Martin | 98.08 | |
| Mason | 84.04 | |
| McCracken | 126.65 | |
| McCreary | 69.77 | |
| McLean | 126.93 | |
| Meade | 123.01 | |
| Menifee | 54.94 | |
| Mercer | 111.55 | |
| Metcalfe | 76.08 | |
| Monroe | 80.92 | |
| Montgomery | 99.62 | |
| Morgan | 55.37 | |
| Muhlenberg | 85.15 | |
| Nelson | 115.42 | |
| Nicholas | 65.99 | |
| Ohio | 97.14 | |
| Oldham | 226.35 | |
| Owen | 80.46 | |
| Owsley | 38.14 | |
| Pendleton | 80.72 | |
| Perry | 32.57 | |
| Pike | 40.19 | |
| Powell | 66.34 | |
| Pulaski | 92.03 | |
| Robertson | 62.16 | |
| Rockcastle | 61.93 | |
| Rowan | 78.73 | |
| Russell | 87.91 | |
| Scott | 159.02 | |
| Shelby | 165.10 | |
| Simpson | 161.29 | |
| Spencer | 129.09 | |
| Taylor | 86.34 | |
| Todd | 147.37 | |
| Trigg | 116.81 | |
| Trimble | 92.23 | |
| Union | 143.22 | |
| Warren | 151.60 | |
| Washington | 91.29 | |
| Wayne | 75.77 | |
| Webster | 104.68 | |
| Whitley | 71.96 | |
| Wolfe | 57.30 | |
| Woodford | 230.53 | |
| Louisiana | Acadia | 71.89 |
| Allen | 66.79 | |
| Ascension | 94.38 | |
| Assumption | 76.63 | |
| Avoyelles | 66.22 | |
| Beauregard | 79.10 | |
| Bienville | 66.30 | |
| Bossier | 81.26 | |
| Caddo | 77.65 | |
| Calcasieu | 90.58 | |
| Caldwell | 65.26 | |
| Cameron | 64.50 | |
| Catahoula | 70.33 | |
| Claiborne | 62.18 | |
| Concordia | 72.93 | |
| De Soto | 77.20 | |
| East Baton Rouge | 214.77 | |
| East Carroll | 96.65 | |
| East Feliciana | 72.86 | |
| Evangeline | 63.54 | |
| Franklin | 73.82 | |
| Grant | 71.27 | |
| Iberia | 74.65 | |
| Iberville | 46.75 | |
| Jackson | 104.20 | |
| Jefferson | 60.75 | |
| Jefferson Davis | 57.97 | |
| La Salle | 82.90 | |
| Lafayette | 145.27 | |
| Lafourche | 75.46 | |
| Lincoln | 83.55 | |
| Livingston | 139.28 | |
| Madison | 71.55 | |
| Morehouse | 82.77 | |
| Natchitoches | 60.78 | |
| Orleans | 269.54 | |
| Ouachita | 110.91 | |
| Plaquemines | 36.73 | |
| Pointe Coupee | 80.46 | |
| Rapides | 97.53 | |
| Red River | 58.25 | |
| Richland | 73.69 | |
| Sabine | 98.37 | |
| St. Bernard | 45.60 | |
| St. Charles | 90.87 | |
| St. Helena | 108.26 | |
| St. James | 79.70 | |
| St. John the Baptist | 91.10 | |
| St. Landry | 75.98 | |
| St. Martin | 83.42 | |
| St. Mary | 85.85 | |
| St. Tammany | 279.32 | |
| Tangipahoa | 131.74 | |
| Tensas | 72.96 | |
| Terrebonne | 107.19 | |
| Union | 79.23 | |
| Vermilion | 74.89 | |
| Vernon | 96.39 | |
| Washington | 94.02 | |
| Webster | 76.50 | |
| West Baton Rouge | 73.40 | |
| West Carroll | 85.79 | |
| West Feliciana | 76.40 | |
| Winn | 72.99 | |
| Maine | Androscoggin | 94.04 |
| Aroostook | 46.43 | |
| Cumberland | 182.16 | |
| Franklin | 66.25 | |
| Hancock | 74.52 | |
| Kennebec | 80.63 | |
| Knox | 126.02 | |
| Lincoln | 123.86 | |
| Oxford | 77.72 | |
| Penobscot | 65.77 | |
| Piscataquis | 37.55 | |
| Sagadahoc | 110.26 | |
| Somerset | 39.37 | |
| Waldo | 79.96 | |
| Washington | 40.91 | |
| York | 136.56 | |
| Maryland | Allegany | 156.34 |
| Anne Arundel | 288.30 | |
| Baltimore | 414.47 | |
| Calvert | 286.76 | |
| Caroline | 199.23 | |
| Carroll | 228.64 | |
| Cecil | 224.14 | |
| Charles | 264.42 | |
| Dorchester | 158.69 | |
| Frederick | 266.21 | |
| Garrett | 127.52 | |
| Harford | 304.91 | |
| Howard | 255.98 | |
| Kent | 184.77 | |
| Montgomery | 229.62 | |
| Prince George’s | 227.35 | |
| Queen Anne’s | 205.18 | |
| Somerset | 160.09 | |
| St. Mary’s | 278.15 | |
| Talbot | 196.49 | |
| Washington | 225.26 | |
| Wicomico | 196.66 | |
| Worcester | 148.18 | |
| Massachusetts | Barnstable | 767.18 |
| Berkshire | 191.93 | |
| Bristol | 456.62 | |
| Dukes | 286.96 | |
| Essex | 438.14 | |
| Franklin | 161.17 | |
| Hampden | 259.69 | |
| Hampshire | 192.38 | |
| Middlesex | 400.33 | |
| Nantucket | 982.34 | |
| Norfolk | 430.61 | |
| Plymouth | 240.41 | |
| Suffolk | 5,772.37 | |
| Worcester | 308.76 | |
| Michigan | Alcona | 71.88 |
| Alger | 56.61 | |
| Allegan | 165.99 | |
| Alpena | 70.63 | |
| Antrim | 116.64 | |
| Arenac | 93.11 | |
| Baraga | 60.75 | |
| Barry | 133.24 | |
| Bay | 140.20 | |
| Benzie | 109.93 | |
| Berrien | 178.86 | |
| Branch | 117.56 | |
| Calhoun | 147.34 | |
| Cass | 128.27 | |
| Charlevoix | 104.63 | |
| Cheboygan | 71.10 | |
| Chippewa | 60.06 | |
| Clare | 83.56 | |
| Clinton | 156.94 | |
| Crawford | 97.19 | |
| Delta | 49.54 | |
| Dickinson | 75.68 | |
| Eaton | 115.89 | |
| Emmet | 104.54 | |
| Genesee | 146.03 | |
| Gladwin | 108.48 | |
| Gogebic | 72.18 | |
| Grand Traverse | 176.56 | |
| Gratiot | 150.75 | |
| Hillsdale | 119.58 | |
| Houghton | 65.33 | |
| Huron | 167.84 | |
| Ingham | 147.78 | |
| Ionia | 137.51 | |
| Iosco | 87.50 | |
| Iron | 54.84 | |
| Isabella | 113.76 | |
| Jackson | 138.37 | |
| Kalamazoo | 195.79 | |
| Kalkaska | 73.65 | |
| Kent | 204.81 | |
| Keweenaw | 93.66 | |
| Lake | 68.33 | |
| Lapeer | 127.85 | |
| Leelanau | 203.17 | |
| Lenawee | 145.03 | |
| Livingston | 158.21 | |
| Luce | 69.96 | |
| Mackinac | 55.42 | |
| Macomb | 141.40 | |
| Manistee | 80.04 | |
| Marquette | 61.22 | |
| Mason | 86.34 | |
| Mecosta | 97.27 | |
| Menominee | 58.97 | |
| Midland | 153.80 | |
| Missaukee | 101.52 | |
| Monroe | 170.84 | |
| Montcalm | 110.76 | |
| Montmorency | 59.56 | |
| Muskegon | 178.31 | |
| Newaygo | 107.93 | |
| Oakland | 322.56 | |
| Oceana | 115.42 | |
| Ogemaw | 77.62 | |
| Ontonagon | 44.32 | |
| Osceola | 83.34 | |
| Oscoda | 76.07 | |
| Otsego | 77.15 | |
| Ottawa | 229.54 | |
| Presque Isle | 65.08 | |
| Roscommon | 68.02 | |
| Saginaw | 161.10 | |
| Sanilac | 136.82 | |
| Schoolcraft | 50.51 | |
| Shiawassee | 125.19 | |
| St. Clair | 145.81 | |
| St. Joseph | 158.66 | |
| Tuscola | 144.78 | |
| Van Buren | 160.66 | |
| Washtenaw | 217.10 | |
| Wayne | 320.84 | |
| Wexford | 93.47 | |
| Minnesota | Aitkin | 59.93 |
| Anoka | 215.70 | |
| Becker | 82.58 | |
| Beltrami | 55.87 | |
| Benton | 124.76 | |
| Big Stone | 123.56 | |
| Blue Earth | 204.67 | |
| Brown | 186.82 | |
| Carlton | 61.24 | |
| Carver | 191.60 | |
| Cass | 71.13 | |
| Chippewa | 167.50 | |
| Chisago | 130.01 | |
| Clay | 112.20 | |
| Clearwater | 57.58 | |
| Cook | 168.44 | |
| Cottonwood | 179.63 | |
| Crow Wing | 76.39 | |
| Dakota | 196.14 | |
| Dodge | 195.86 | |
| Douglas | 112.14 | |
| Faribault | 193.22 | |
| Fillmore | 157.84 | |
| Freeborn | 171.36 | |
| Goodhue | 176.31 | |
| Grant | 125.13 | |
| Hennepin | 382.63 | |
| Houston | 121.91 | |
| Hubbard | 75.20 | |
| Isanti | 110.46 | |
| Itasca | 80.77 | |
| Jackson | 182.96 | |
| Kanabec | 75.37 | |
| Kandiyohi | 148.29 | |
| Kittson | 63.91 | |
| Koochiching | 41.01 | |
| Lac qui Parle | 127.26 | |
| Lake | 103.13 | |
| Lake of the Woods | 48.23 | |
| Le Sueur | 175.48 | |
| Lincoln | 137.43 | |
| Lyon | 166.30 | |
| Mahnomen | 83.98 | |
| Marshall | 70.31 | |
| Martin | 190.74 | |
| McLeod | 162.67 | |
| Meeker | 147.49 | |
| Mille Lacs | 88.15 | |
| Morrison | 94.06 | |
| Mower | 193.61 | |
| Murray | 175.23 | |
| Nicollet | 198.99 | |
| Nobles | 196.40 | |
| Norman | 93.81 | |
| Olmsted | 189.18 | |
| Otter Tail | 84.37 | |
| Pennington | 54.79 | |
| Pine | 67.18 | |
| Pipestone | 165.76 | |
| Polk | 93.21 | |
| Pope | 117.77 | |
| Ramsey | 757.24 | |
| Red Lake | 67.35 | |
| Redwood | 177.30 | |
| Renville | 186.42 | |
| Rice | 194.86 | |
| Rock | 216.86 | |
| Roseau | 49.53 | |
| Scott | 215.70 | |
| Sherburne | 146.50 | |
| Sibley | 191.71 | |
| St. Louis | 56.61 | |
| Stearns | 146.33 | |
| Steele | 176.22 | |
| Stevens | 144.28 | |
| Swift | 143.31 | |
| Todd | 78.01 | |
| Traverse | 141.50 | |
| Wabasha | 156.84 | |
| Wadena | 62.52 | |
| Waseca | 188.16 | |
| Washington | 247.10 | |
| Watonwan | 201.69 | |
| Wilkin | 110.04 | |
| Winona | 163.49 | |
| Wright | 183.04 | |
| Yellow Medicine | 153.69 | |
| Mississippi | Adams | 78.59 |
| Alcorn | 56.77 | |
| Amite | 85.04 | |
| Attala | 49.18 | |
| Benton | 51.31 | |
| Bolivar | 80.59 | |
| Calhoun | 47.31 | |
| Carroll | 56.96 | |
| Chickasaw | 53.36 | |
| Choctaw | 49.05 | |
| Claiborne | 72.14 | |
| Clarke | 59.59 | |
| Clay | 50.00 | |
| Coahoma | 88.10 | |
| Copiah | 68.28 | |
| Covington | 96.04 | |
| DeSoto | 80.16 | |
| Forrest | 113.06 | |
| Franklin | 84.56 | |
| George | 99.40 | |
| Greene | 67.35 | |
| Grenada | 58.61 | |
| Hancock | 102.86 | |
| Harrison | 223.09 | |
| Hinds | 87.70 | |
| Holmes | 64.60 | |
| Humphreys | 87.11 | |
| Issaquena | 72.92 | |
| Itawamba | 45.61 | |
| Jackson | 133.52 | |
| Jasper | 74.73 | |
| Jefferson | 67.13 | |
| Jefferson Davis | 68.47 | |
| Jones | 100.86 | |
| Kemper | 53.87 | |
| Lafayette | 73.00 | |
| Lamar | 94.52 | |
| Lauderdale | 54.75 | |
| Lawrence | 85.54 | |
| Leake | 80.64 | |
| Lee | 48.81 | |
| Leflore | 77.31 | |
| Lincoln | 81.81 | |
| Lowndes | 67.40 | |
| Madison | 70.01 | |
| Marion | 76.75 | |
| Marshall | 64.02 | |
| Monroe | 58.56 | |
| Montgomery | 53.25 | |
| Neshoba | 70.97 | |
| Newton | 63.16 | |
| Noxubee | 67.48 | |
| Oktibbeha | 74.49 | |
| Panola | 65.62 | |
| Pearl River | 94.44 | |
| Perry | 85.52 | |
| Pike | 99.26 | |
| Pontotoc | 52.43 | |
| Prentiss | 54.51 | |
| Quitman | 76.22 | |
| Rankin | 87.91 | |
| Scott | 67.83 | |
| Sharkey | 88.18 | |
| Simpson | 73.47 | |
| Smith | 76.54 | |
| Stone | 88.13 | |
| Sunflower | 84.82 | |
| Tallahatchie | 75.13 | |
| Tate | 75.26 | |
| Tippah | 55.20 | |
| Tishomingo | 50.35 | |
| Tunica | 78.72 | |
| Union | 53.25 | |
| Walthall | 82.69 | |
| Warren | 64.66 | |
| Washington | 98.78 | |
| Wayne | 82.48 | |
| Webster | 48.83 | |
| Wilkinson | 63.96 | |
| Winston | 60.66 | |
| Yalobusha | 49.66 | |
| Yazoo | 74.30 | |
| Missouri | Adair | 77.90 |
| Andrew | 107.23 | |
| Atchison | 136.81 | |
| Audrain | 118.75 | |
| Barry | 95.68 | |
| Barton | 76.82 | |
| Bates | 86.22 | |
| Benton | 76.37 | |
| Bollinger | 69.95 | |
| Boone | 157.76 | |
| Buchanan | 113.09 | |
| Butler | 131.00 | |
| Caldwell | 88.45 | |
| Callaway | 110.49 | |
| Camden | 61.61 | |
| Cape Girardeau | 121.18 | |
| Carroll | 99.89 | |
| Carter | 53.27 | |
| Cass | 104.89 | |
| Cedar | 69.45 | |
| Chariton | 95.96 | |
| Christian | 112.36 | |
| Clark | 99.75 | |
| Clay | 116.33 | |
| Clinton | 103.83 | |
| Cole | 101.73 | |
| Cooper | 91.19 | |
| Crawford | 72.07 | |
| Dade | 78.32 | |
| Dallas | 70.82 | |
| Daviess | 91.10 | |
| DeKalb | 91.32 | |
| Dent | 58.34 | |
| Douglas | 58.60 | |
| Dunklin | 142.02 | |
| Franklin | 107.82 | |
| Gasconade | 77.76 | |
| Gentry | 86.44 | |
| Greene | 132.40 | |
| Grundy | 81.70 | |
| Harrison | 77.23 | |
| Henry | 75.06 | |
| Hickory | 58.82 | |
| Holt | 136.53 | |
| Howard | 84.35 | |
| Howell | 59.82 | |
| Iron | 57.62 | |
| Jackson | 162.23 | |
| Jasper | 89.87 | |
| Jefferson | 117.19 | |
| Johnson | 93.31 | |
| Knox | 84.88 | |
| Laclede | 70.23 | |
| Lafayette | 126.54 | |
| Lawrence | 89.23 | |
| Lewis | 92.41 | |
| Lincoln | 121.68 | |
| Linn | 80.44 | |
| Livingston | 94.09 | |
| Macon | 89.12 | |
| Madison | 58.57 | |
| Maries | 55.00 | |
| Marion | 110.66 | |
| McDonald | 74.83 | |
| Mercer | 75.14 | |
| Miller | 69.67 | |
| Mississippi | 162.87 | |
| Moniteau | 99.61 | |
| Monroe | 99.31 | |
| Montgomery | 105.22 | |
| Morgan | 107.06 | |
| New Madrid | 156.00 | |
| Newton | 101.54 | |
| Nodaway | 111.94 | |
| Oregon | 49.69 | |
| Osage | 67.38 | |
| Ozark | 59.52 | |
| Pemiscot | 146.07 | |
| Perry | 91.32 | |
| Pettis | 97.66 | |
| Phelps | 73.55 | |
| Pike | 98.11 | |
| Platte | 123.58 | |
| Polk | 70.45 | |
| Pulaski | 62.42 | |
| Putnam | 70.31 | |
| Ralls | 107.42 | |
| Randolph | 96.57 | |
| Ray | 98.11 | |
| Reynolds | 44.62 | |
| Ripley | 68.25 | |
| Saline | 111.89 | |
| Schuyler | 72.02 | |
| Scotland | 94.03 | |
| Scott | 141.94 | |
| Shannon | 54.77 | |
| Shelby | 104.05 | |
| St Louis | 121.32 | |
| St. Charles | 136.30 | |
| St. Clair | 68.44 | |
| St. Francois | 81.84 | |
| Ste. Genevieve | 82.34 | |
| Stoddard | 149.36 | |
| Stone | 80.75 | |
| Sullivan | 65.24 | |
| Taney | 62.36 | |
| Texas | 57.65 | |
| Vernon | 79.27 | |
| Warren | 112.95 | |
| Washington | 66.18 | |
| Wayne | 65.57 | |
| Webster | 86.55 | |
| Worth | 79.35 | |
| Wright | 60.21 | |
| Montana | Beaverhead | 28.32 |
| Big Horn | 8.45 | |
| Blaine | 12.73 | |
| Broadwater | 25.16 | |
| Carbon | 31.91 | |
| Carter | 11.57 | |
| Cascade | 26.06 | |
| Chouteau | 20.06 | |
| Custer | 11.53 | |
| Daniels | 13.63 | |
| Dawson | 14.36 | |
| Deer Lodge | 41.78 | |
| Fallon | 12.99 | |
| Fergus | 23.52 | |
| Flathead | 137.39 | |
| Gallatin | 65.16 | |
| Garfield | 8.69 | |
| Glacier | 25.09 | |
| Golden Valley | 14.41 | |
| Granite | 34.79 | |
| Hill | 18.51 | |
| Jefferson | 36.60 | |
| Judith Basin | 19.98 | |
| Lake | 34.53 | |
| Lewis and Clark | 28.08 | |
| Liberty | 19.29 | |
| Lincoln | 112.89 | |
| Madison | 36.77 | |
| McCone | 11.35 | |
| Meagher | 19.53 | |
| Mineral | 107.56 | |
| Missoula | 60.12 | |
| Musselshell | 13.74 | |
| Park | 56.10 | |
| Petroleum | 14.58 | |
| Phillips | 11.40 | |
| Pondera | 25.95 | |
| Powder River | 11.85 | |
| Powell | 27.85 | |
| Prairie | 16.64 | |
| Ravalli | 123.30 | |
| Richland | 18.86 | |
| Roosevelt | 15.53 | |
| Rosebud | 9.25 | |
| Sanders | 21.25 | |
| Sheridan | 14.92 | |
| Silver Bow | 48.40 | |
| Stillwater | 28.90 | |
| Sweet Grass | 24.43 | |
| Teton | 25.50 | |
| Toole | 18.86 | |
| Treasure | 12.43 | |
| Valley | 13.85 | |
| Wheatland | 14.90 | |
| Wibaux | 13.27 | |
| Yellowstone | 21.57 | |
| Nebraska | Adams | 137.57 |
| Antelope | 118.58 | |
| Arthur | 20.70 | |
| Banner | 22.54 | |
| Blaine | 25.66 | |
| Boone | 114.99 | |
| Box Butte | 34.48 | |
| Boyd | 52.41 | |
| Brown | 30.29 | |
| Buffalo | 113.54 | |
| Burt | 159.21 | |
| Butler | 147.14 | |
| Cass | 144.91 | |
| Cedar | 133.93 | |
| Chase | 53.89 | |
| Cherry | 24.11 | |
| Cheyenne | 26.36 | |
| Clay | 125.35 | |
| Colfax | 160.09 | |
| Cuming | 157.32 | |
| Custer | 63.97 | |
| Dakota | 146.18 | |
| Dawes | 22.98 | |
| Dawson | 88.18 | |
| Deuel | 33.73 | |
| Dixon | 120.85 | |
| Dodge | 165.72 | |
| Douglas | 197.56 | |
| Dundy | 39.54 | |
| Fillmore | 140.80 | |
| Franklin | 89.48 | |
| Frontier | 48.56 | |
| Furnas | 63.76 | |
| Gage | 114.42 | |
| Garden | 22.38 | |
| Garfield | 38.33 | |
| Gosper | 72.68 | |
| Grant | 21.63 | |
| Greeley | 76.63 | |
| Hall | 131.37 | |
| Hamilton | 163.88 | |
| Harlan | 74.38 | |
| Hayes | 36.57 | |
| Hitchcock | 40.68 | |
| Holt | 61.51 | |
| Hooker | 19.00 | |
| Howard | 90.23 | |
| Jefferson | 107.28 | |
| Johnson | 93.84 | |
| Kearney | 135.22 | |
| Keith | 42.02 | |
| Keya Paha | 36.60 | |
| Kimball | 27.78 | |
| Knox | 86.45 | |
| Lancaster | 144.68 | |
| Lincoln | 43.26 | |
| Logan | 31.01 | |
| Loup | 30.06 | |
| Madison | 150.39 | |
| McPherson | 21.17 | |
| Merrick | 131.14 | |
| Morrill | 29.59 | |
| Nance | 109.25 | |
| Nemaha | 117.54 | |
| Nuckolls | 92.73 | |
| Otoe | 128.11 | |
| Pawnee | 83.84 | |
| Perkins | 55.31 | |
| Phelps | 132.17 | |
| Pierce | 125.92 | |
| Platte | 163.55 | |
| Polk | 152.77 | |
| Red Willow | 50.32 | |
| Richardson | 110.28 | |
| Rock | 29.41 | |
| Saline | 121.89 | |
| Sarpy | 192.26 | |
| Saunders | 145.79 | |
| Scotts Bluff | 52.67 | |
| Seward | 147.58 | |
| Sheridan | 25.07 | |
| Sherman | 69.16 | |
| Sioux | 23.29 | |
| Stanton | 128.99 | |
| Thayer | 101.31 | |
| Thomas | 20.16 | |
| Thurston | 124.75 | |
| Valley | 74.38 | |
| Washington | 168.49 | |
| Wayne | 142.46 | |
| Webster | 70.79 | |
| Wheeler | 39.49 | |
| York | 177.76 | |
| Nevada | Carson City | 6.57 |
| Churchill | 13.85 | |
| Clark | 22.48 | |
| Douglas | 14.86 | |
| Elko | 3.97 | |
| Esmeralda | 15.06 | |
| Eureka | 3.62 | |
| Humboldt | 6.41 | |
| Lander | 7.59 | |
| Lincoln | 18.63 | |
| Lyon | 16.53 | |
| Mineral | 2.12 | |
| Nye | 12.52 | |
| Pershing | 5.79 | |
| Storey | 6.57 | |
| Washoe | 7.42 | |
| White Pine | 9.59 | |
| New Hampshire | Belknap | 133.27 |
| Carroll | 106.55 | |
| Cheshire | 102.81 | |
| Coos | 69.53 | |
| Grafton | 105.96 | |
| Hillsborough | 210.85 | |
| Merrimack | 157.24 | |
| Rockingham | 305.94 | |
| Strafford | 176.09 | |
| Sullivan | 129.96 | |
| New Jersey | Atlantic | 326.48 |
| Bergen | 2,544.38 | |
| Burlington | 257.11 | |
| Camden | 419.97 | |
| Cape May | 372.44 | |
| Cumberland | 250.69 | |
| Essex | 2,159.58 | |
| Gloucester | 324.23 | |
| Hudson | 1,286.78 | |
| Hunterdon | 399.45 | |
| Mercer | 463.32 | |
| Middlesex | 556.91 | |
| Monmouth | 536.68 | |
| Morris | 548.04 | |
| Ocean | 486.78 | |
| Passaic | 817.30 | |
| Salem | 215.37 | |
| Somerset | 505.83 | |
| Sussex | 295.04 | |
| Union | 4,001.49 | |
| Warren | 311.64 | |
| New Mexico | Bernalillo | 56.63 |
| Catron | 8.62 | |
| Chaves | 9.71 | |
| Cibola | 6.51 | |
| Colfax | 10.37 | |
| Curry | 14.27 | |
| De Baca | 7.70 | |
| Dona Ana | 50.99 | |
| Eddy | 12.13 | |
| Grant | 10.00 | |
| Guadalupe | 6.38 | |
| Harding | 7.51 | |
| Hidalgo | 10.69 | |
| Lea | 8.46 | |
| Lincoln | 10.22 | |
| Los Alamos | 10.69 | |
| Luna | 10.57 | |
| McKinley | 8.79 | |
| Mora | 11.33 | |
| Otero | 9.01 | |
| Quay | 7.23 | |
| Rio Arriba | 17.61 | |
| Roosevelt | 9.38 | |
| San Juan | 10.96 | |
| San Miguel | 8.25 | |
| Sandoval | 9.22 | |
| Santa Fe | 18.08 | |
| Sierra | 7.41 | |
| Socorro | 12.89 | |
| Taos | 33.56 | |
| Torrance | 9.79 | |
| Union | 8.48 | |
| Valencia | 23.85 | |
| New York | Albany | 123.24 |
| Allegany | 55.80 | |
| Bronx | 89.50 | |
| Broome | 85.62 | |
| Cattaraugus | 63.50 | |
| Cayuga | 109.63 | |
| Chautauqua | 73.31 | |
| Chemung | 72.59 | |
| Chenango | 56.99 | |
| Clinton | 73.31 | |
| Columbia | 116.08 | |
| Cortland | 64.31 | |
| Delaware | 79.83 | |
| Dutchess | 250.57 | |
| Erie | 126.84 | |
| Essex | 66.02 | |
| Franklin | 68.94 | |
| Fulton | 77.36 | |
| Genesee | 92.72 | |
| Greene | 87.48 | |
| Hamilton | 92.61 | |
| Herkimer | 63.45 | |
| Jefferson | 74.20 | |
| Kings | 12,295.95 | |
| Lewis | 55.69 | |
| Livingston | 102.89 | |
| Madison | 72.65 | |
| Monroe | 119.35 | |
| Montgomery | 68.88 | |
| Nassau | 481.25 | |
| New York | 89.50 | |
| Niagara | 85.10 | |
| Oneida | 73.70 | |
| Onondaga | 114.25 | |
| Ontario | 111.62 | |
| Orange | 192.25 | |
| Orleans | 87.95 | |
| Oswego | 61.34 | |
| Otsego | 73.90 | |
| Putnam | 166.34 | |
| Queens | 1,344.81 | |
| Rensselaer | 97.37 | |
| Richmond | 89.50 | |
| Rockland | 797.51 | |
| Saratoga | 163.26 | |
| Schenectady | 118.86 | |
| Schoharie | 67.49 | |
| Schuyler | 90.64 | |
| Seneca | 104.11 | |
| St. Lawrence | 50.78 | |
| Steuben | 58.18 | |
| Suffolk | 338.69 | |
| Sullivan | 116.78 | |
| Tioga | 63.34 | |
| Tompkins | 105.02 | |
| Ulster | 191.23 | |
| Warren | 115.70 | |
| Washington | 77.44 | |
| Wayne | 95.27 | |
| Westchester | 295.09 | |
| Wyoming | 95.99 | |
| Yates | 144.88 | |
| North Carolina | Alamance | 166.99 |
| Alexander | 156.75 | |
| Alleghany | 137.41 | |
| Anson | 113.72 | |
| Ashe | 146.34 | |
| Avery | 180.74 | |
| Beaufort | 95.19 | |
| Bertie | 84.39 | |
| Bladen | 92.79 | |
| Brunswick | 109.10 | |
| Buncombe | 276.90 | |
| Burke | 158.67 | |
| Cabarrus | 242.39 | |
| Caldwell | 126.30 | |
| Camden | 88.56 | |
| Carteret | 126.25 | |
| Caswell | 90.20 | |
| Catawba | 182.10 | |
| Chatham | 153.21 | |
| Cherokee | 136.54 | |
| Chowan | 97.24 | |
| Clay | 174.70 | |
| Cleveland | 129.81 | |
| Columbus | 90.84 | |
| Craven | 109.57 | |
| Cumberland | 143.78 | |
| Currituck | 136.54 | |
| Dare | 117.09 | |
| Davidson | 161.34 | |
| Davie | 141.64 | |
| Duplin | 133.54 | |
| Durham | 296.58 | |
| Edgecombe | 84.86 | |
| Forsyth | 259.03 | |
| Franklin | 98.97 | |
| Gaston | 170.92 | |
| Gates | 100.89 | |
| Graham | 133.26 | |
| Granville | 96.97 | |
| Greene | 109.80 | |
| Guilford | 227.61 | |
| Halifax | 71.42 | |
| Harnett | 155.16 | |
| Haywood | 179.82 | |
| Henderson | 215.86 | |
| Hertford | 89.03 | |
| Hoke | 122.52 | |
| Hyde | 82.77 | |
| Iredell | 151.35 | |
| Jackson | 228.08 | |
| Johnston | 131.95 | |
| Jones | 112.83 | |
| Lee | 160.42 | |
| Lenoir | 110.77 | |
| Lincoln | 159.50 | |
| Macon | 221.71 | |
| Madison | 138.02 | |
| Martin | 74.53 | |
| McDowell | 146.34 | |
| Mecklenburg | 954.30 | |
| Mitchell | 161.84 | |
| Montgomery | 132.01 | |
| Moore | 141.97 | |
| Nash | 128.78 | |
| New Hanover | 947.37 | |
| Northampton | 77.85 | |
| Onslow | 174.90 | |
| Orange | 186.08 | |
| Pamlico | 101.64 | |
| Pasquotank | 110.88 | |
| Pender | 148.87 | |
| Perquimans | 99.08 | |
| Person | 105.15 | |
| Pitt | 107.01 | |
| Polk | 179.29 | |
| Randolph | 140.61 | |
| Richmond | 121.49 | |
| Robeson | 92.26 | |
| Rockingham | 107.79 | |
| Rowan | 162.82 | |
| Rutherford | 133.09 | |
| Sampson | 136.13 | |
| Scotland | 100.19 | |
| Stanly | 128.00 | |
| Stokes | 113.67 | |
| Surry | 124.44 | |
| Swain | 101.81 | |
| Transylvania | 215.28 | |
| Tyrrell | 115.45 | |
| Union | 148.51 | |
| Vance | 82.88 | |
| Wake | 324.46 | |
| Warren | 80.96 | |
| Washington | 102.09 | |
| Watauga | 179.21 | |
| Wayne | 138.88 | |
| Wilkes | 142.61 | |
| Wilson | 105.32 | |
| Yadkin | 152.27 | |
| Yancey | 151.57 | |
| North Dakota | Adams | 30.37 |
| Barnes | 65.78 | |
| Benson | 38.94 | |
| Billings | 26.16 | |
| Bottineau | 44.01 | |
| Bowman | 29.26 | |
| Burke | 30.00 | |
| Burleigh | 54.08 | |
| Cass | 105.83 | |
| Cavalier | 59.21 | |
| Dickey | 67.60 | |
| Divide | 30.43 | |
| Dunn | 32.65 | |
| Eddy | 41.42 | |
| Emmons | 45.12 | |
| Foster | 57.16 | |
| Golden Valley | 29.94 | |
| Grand Forks | 97.09 | |
| Grant | 30.49 | |
| Griggs | 50.58 | |
| Hettinger | 39.99 | |
| Kidder | 35.81 | |
| LaMoure | 72.27 | |
| Logan | 33.90 | |
| McHenry | 31.00 | |
| McIntosh | 38.83 | |
| McKenzie | 29.20 | |
| McLean | 50.81 | |
| Mercer | 38.94 | |
| Morton | 39.96 | |
| Mountrail | 36.38 | |
| Nelson | 38.71 | |
| Oliver | 41.07 | |
| Pembina | 78.48 | |
| Pierce | 40.11 | |
| Ramsey | 51.49 | |
| Ransom | 57.27 | |
| Renville | 45.69 | |
| Richland | 90.77 | |
| Rolette | 36.43 | |
| Sargent | 79.33 | |
| Sheridan | 31.25 | |
| Sioux | 35.38 | |
| Slope | 30.09 | |
| Stark | 37.89 | |
| Steele | 62.54 | |
| Stutsman | 57.07 | |
| Towner | 39.42 | |
| Traill | 87.78 | |
| Walsh | 71.53 | |
| Ward | 46.48 | |
| Wells | 48.70 | |
| Williams | 31.20 | |
| Ohio | Adams | 110.18 |
| Allen | 205.94 | |
| Ashland | 172.42 | |
| Ashtabula | 124.11 | |
| Athens | 91.19 | |
| Auglaize | 231.05 | |
| Belmont | 108.67 | |
| Brown | 125.11 | |
| Butler | 234.29 | |
| Carroll | 133.68 | |
| Champaign | 203.50 | |
| Clark | 214.05 | |
| Clermont | 159.08 | |
| Clinton | 169.10 | |
| Columbiana | 163.73 | |
| Coshocton | 149.83 | |
| Crawford | 182.95 | |
| Cuyahoga | 463.02 | |
| Darke | 236.11 | |
| Defiance | 162.80 | |
| Delaware | 222.06 | |
| Erie | 185.73 | |
| Fairfield | 218.59 | |
| Fayette | 202.70 | |
| Franklin | 228.22 | |
| Fulton | 198.25 | |
| Gallia | 89.20 | |
| Geauga | 205.62 | |
| Greene | 202.64 | |
| Guernsey | 105.64 | |
| Hamilton | 377.28 | |
| Hancock | 171.48 | |
| Hardin | 167.11 | |
| Harrison | 93.94 | |
| Henry | 185.90 | |
| Highland | 142.50 | |
| Hocking | 128.48 | |
| Holmes | 219.70 | |
| Huron | 172.64 | |
| Jackson | 79.87 | |
| Jefferson | 155.08 | |
| Knox | 171.62 | |
| Lake | 231.65 | |
| Lawrence | 93.29 | |
| Licking | 187.77 | |
| Logan | 171.74 | |
| Lorain | 212.41 | |
| Lucas | 234.91 | |
| Madison | 196.80 | |
| Mahoning | 188.06 | |
| Marion | 165.69 | |
| Medina | 222.31 | |
| Meigs | 98.40 | |
| Mercer | 274.53 | |
| Miami | 210.62 | |
| Monroe | 92.75 | |
| Montgomery | 204.74 | |
| Morgan | 98.14 | |
| Morrow | 170.35 | |
| Muskingum | 116.39 | |
| Noble | 87.36 | |
| Ottawa | 153.52 | |
| Paulding | 177.67 | |
| Perry | 129.82 | |
| Pickaway | 171.23 | |
| Pike | 117.95 | |
| Portage | 184.79 | |
| Preble | 181.56 | |
| Putnam | 189.99 | |
| Richland | 213.00 | |
| Ross | 130.07 | |
| Sandusky | 168.19 | |
| Scioto | 89.06 | |
| Seneca | 167.14 | |
| Shelby | 218.20 | |
| Stark | 262.36 | |
| Summit | 379.32 | |
| Trumbull | 122.92 | |
| Tuscarawas | 157.66 | |
| Union | 180.22 | |
| Van Wert | 212.69 | |
| Vinton | 89.86 | |
| Warren | 222.06 | |
| Washington | 90.51 | |
| Wayne | 253.73 | |
| Williams | 146.48 | |
| Wood | 188.99 | |
| Wyandot | 161.95 | |
| Oklahoma | Adair | 66.90 |
| Alfalfa | 47.63 | |
| Atoka | 51.29 | |
| Beaver | 25.11 | |
| Beckham | 37.25 | |
| Blaine | 45.53 | |
| Bryan | 63.40 | |
| Caddo | 48.44 | |
| Canadian | 65.69 | |
| Carter | 56.77 | |
| Cherokee | 69.44 | |
| Choctaw | 49.61 | |
| Cimarron | 23.07 | |
| Cleveland | 135.67 | |
| Coal | 50.93 | |
| Comanche | 53.92 | |
| Cotton | 38.01 | |
| Craig | 58.87 | |
| Creek | 61.33 | |
| Custer | 40.61 | |
| Delaware | 76.32 | |
| Dewey | 38.34 | |
| Ellis | 27.80 | |
| Garfield | 48.55 | |
| Garvin | 53.61 | |
| Grady | 58.67 | |
| Grant | 44.89 | |
| Greer | 32.33 | |
| Harmon | 35.01 | |
| Harper | 30.79 | |
| Haskell | 53.19 | |
| Hughes | 44.61 | |
| Jackson | 39.10 | |
| Jefferson | 43.24 | |
| Johnston | 52.35 | |
| Kay | 46.01 | |
| Kingfisher | 53.78 | |
| Kiowa | 35.07 | |
| Latimer | 50.23 | |
| Le Flore | 60.46 | |
| Lincoln | 62.67 | |
| Logan | 62.65 | |
| Love | 68.66 | |
| Major | 41.50 | |
| Marshall | 67.74 | |
| Mayes | 77.75 | |
| McClain | 73.72 | |
| McCurtain | 59.88 | |
| McIntosh | 53.17 | |
| Murray | 59.79 | |
| Muskogee | 63.09 | |
| Noble | 49.75 | |
| Nowata | 57.70 | |
| Okfuskee | 47.91 | |
| Oklahoma | 181.23 | |
| Okmulgee | 61.86 | |
| Osage | 44.52 | |
| Ottawa | 77.64 | |
| Pawnee | 49.87 | |
| Payne | 67.71 | |
| Pittsburg | 49.00 | |
| Pontotoc | 60.63 | |
| Pottawatomie | 63.04 | |
| Pushmataha | 43.13 | |
| Roger Mills | 35.85 | |
| Rogers | 81.38 | |
| Seminole | 50.98 | |
| Sequoyah | 61.28 | |
| Stephens | 49.19 | |
| Texas | 28.33 | |
| Tillman | 37.11 | |
| Tulsa | 163.02 | |
| Wagoner | 79.23 | |
| Washington | 65.83 | |
| Washita | 41.56 | |
| Woods | 37.08 | |
| Woodward | 34.01 | |
| Oregon | Baker | 24.75 |
| Benton | 127.45 | |
| Clackamas | 425.89 | |
| Clatsop | 141.60 | |
| Columbia | 171.32 | |
| Coos | 60.34 | |
| Crook | 18.91 | |
| Curry | 70.10 | |
| Deschutes | 171.57 | |
| Douglas | 67.58 | |
| Gilliam | 14.25 | |
| Grant | 20.49 | |
| Harney | 13.50 | |
| Hood River | 275.68 | |
| Jackson | 168.15 | |
| Jefferson | 16.93 | |
| Josephine | 356.17 | |
| Klamath | 43.33 | |
| Lake | 21.40 | |
| Lane | 169.38 | |
| Lincoln | 108.84 | |
| Linn | 140.39 | |
| Malheur | 29.46 | |
| Marion | 244.82 | |
| Morrow | 22.31 | |
| Multnomah | 413.32 | |
| Polk | 140.87 | |
| Sherman | 16.83 | |
| Tillamook | 154.33 | |
| Umatilla | 36.11 | |
| Union | 35.87 | |
| Wallowa | 32.31 | |
| Wasco | 18.03 | |
| Washington | 338.49 | |
| Wheeler | 17.92 | |
| Yamhill | 201.49 | |
| Pennsylvania | Adams | 193.70 |
| Allegheny | 246.59 | |
| Armstrong | 102.50 | |
| Beaver | 170.19 | |
| Bedford | 114.66 | |
| Berks | 315.31 | |
| Blair | 189.79 | |
| Bradford | 101.91 | |
| Bucks | 264.64 | |
| Butler | 148.83 | |
| Cambria | 130.27 | |
| Cameron | 80.00 | |
| Carbon | 186.19 | |
| Centre | 188.47 | |
| Chester | 341.50 | |
| Clarion | 90.30 | |
| Clearfield | 101.49 | |
| Clinton | 183.91 | |
| Columbia | 169.59 | |
| Crawford | 93.98 | |
| Cumberland | 214.15 | |
| Dauphin | 247.29 | |
| Delaware | 404.93 | |
| Elk | 118.09 | |
| Erie | 126.89 | |
| Fayette | 116.49 | |
| Forest | 137.84 | |
| Franklin | 211.76 | |
| Fulton | 117.44 | |
| Greene | 102.50 | |
| Huntingdon | 135.42 | |
| Indiana | 101.27 | |
| Jefferson | 93.22 | |
| Juniata | 183.46 | |
| Lackawanna | 149.12 | |
| Lancaster | 514.35 | |
| Lawrence | 123.43 | |
| Lebanon | 405.07 | |
| Lehigh | 220.79 | |
| Luzerne | 170.55 | |
| Lycoming | 144.00 | |
| McKean | 80.11 | |
| Mercer | 112.43 | |
| Mifflin | 173.81 | |
| Monroe | 165.74 | |
| Montgomery | 544.59 | |
| Montour | 181.21 | |
| Northampton | 211.09 | |
| Northumberland | 165.18 | |
| Perry | 186.47 | |
| Philadelphia | 1,651.53 | |
| Pike | 62.62 | |
| Potter | 96.46 | |
| Schuylkill | 186.92 | |
| Snyder | 206.25 | |
| Somerset | 90.66 | |
| Sullivan | 115.08 | |
| Susquehanna | 133.34 | |
| Tioga | 106.81 | |
| Union | 270.02 | |
| Venango | 106.81 | |
| Warren | 97.36 | |
| Washington | 183.15 | |
| Wayne | 120.79 | |
| Westmoreland | 166.22 | |
| Wyoming | 116.57 | |
| York | 230.69 | |
| Puerto Rico | All Areas | 152.36 |
| Rhode Island | Bristol | 1,072.48 |
| Kent | 336.72 | |
| Newport | 580.59 | |
| Providence | 339.12 | |
| Washington | 323.71 | |
| South Carolina | Abbeville | 85.52 |
| Aiken | 104.06 | |
| Allendale | 60.94 | |
| Anderson | 156.76 | |
| Bamberg | 80.99 | |
| Barnwell | 76.93 | |
| Beaufort | 100.05 | |
| Berkeley | 73.84 | |
| Calhoun | 84.28 | |
| Charleston | 258.80 | |
| Cherokee | 92.92 | |
| Chester | 91.79 | |
| Chesterfield | 81.54 | |
| Clarendon | 62.81 | |
| Colleton | 83.70 | |
| Darlington | 71.71 | |
| Dillon | 63.28 | |
| Dorchester | 77.65 | |
| Edgefield | 97.43 | |
| Fairfield | 79.20 | |
| Florence | 87.45 | |
| Georgetown | 56.43 | |
| Greenville | 253.80 | |
| Greenwood | 94.36 | |
| Hampton | 67.37 | |
| Horry | 124.58 | |
| Jasper | 101.13 | |
| Kershaw | 85.33 | |
| Lancaster | 109.17 | |
| Laurens | 105.91 | |
| Lee | 66.74 | |
| Lexington | 152.84 | |
| Marion | 64.39 | |
| Marlboro | 53.23 | |
| McCormick | 55.36 | |
| Newberry | 91.54 | |
| Oconee | 176.37 | |
| Orangeburg | 83.37 | |
| Pickens | 194.74 | |
| Richland | 132.51 | |
| Saluda | 85.44 | |
| Spartanburg | 227.37 | |
| Sumter | 82.73 | |
| Union | 70.00 | |
| Williamsburg | 62.01 | |
| York | 192.78 | |
| South Dakota | Aurora | 75.23 |
| Beadle | 76.33 | |
| Bennett | 26.98 | |
| Bon Homme | 112.93 | |
| Brookings | 130.44 | |
| Brown | 95.29 | |
| Brule | 73.07 | |
| Buffalo | 43.79 | |
| Butte | 27.18 | |
| Campbell | 51.90 | |
| Charles Mix | 79.03 | |
| Clark | 89.29 | |
| Clay | 133.28 | |
| Codington | 98.27 | |
| Corson | 26.05 | |
| Custer | 45.24 | |
| Davison | 96.32 | |
| Day | 74.97 | |
| Deuel | 97.73 | |
| Dewey | 27.49 | |
| Douglas | 105.47 | |
| Edmunds | 69.73 | |
| Fall River | 20.29 | |
| Faulk | 72.19 | |
| Grant | 105.70 | |
| Gregory | 53.26 | |
| Haakon | 26.16 | |
| Hamlin | 111.28 | |
| Hand | 58.28 | |
| Hanson | 122.51 | |
| Harding | 18.85 | |
| Hughes | 53.60 | |
| Hutchinson | 127.41 | |
| Hyde | 43.28 | |
| Jackson | 24.80 | |
| Jerauld | 67.77 | |
| Jones | 32.40 | |
| Kingsbury | 107.99 | |
| Lake | 145.15 | |
| Lawrence | 50.71 | |
| Lincoln | 195.75 | |
| Lyman | 46.80 | |
| Marshall | 79.76 | |
| McCook | 123.78 | |
| McPherson | 61.05 | |
| Meade | 26.96 | |
| Mellette | 27.35 | |
| Miner | 100.14 | |
| Minnehaha | 182.79 | |
| Moody | 164.97 | |
| Oglala Lakota | 19.10 | |
| Pennington | 29.99 | |
| Perkins | 23.55 | |
| Potter | 59.92 | |
| Roberts | 85.23 | |
| Sanborn | 80.98 | |
| Spink | 88.78 | |
| Stanley | 26.11 | |
| Sully | 61.05 | |
| Todd | 24.09 | |
| Tripp | 45.92 | |
| Turner | 142.26 | |
| Union | 166.53 | |
| Walworth | 56.12 | |
| Yankton | 125.34 | |
| Ziebach | 24.23 | |
| Tennessee | Anderson | 155.09 |
| Bedford | 118.25 | |
| Benton | 70.63 | |
| Bledsoe | 97.76 | |
| Blount | 182.64 | |
| Bradley | 172.12 | |
| Campbell | 117.43 | |
| Cannon | 101.79 | |
| Carroll | 77.62 | |
| Carter | 147.54 | |
| Cheatham | 129.32 | |
| Chester | 72.08 | |
| Claiborne | 88.77 | |
| Clay | 94.59 | |
| Cocke | 125.63 | |
| Coffee | 116.49 | |
| Crockett | 95.49 | |
| Cumberland | 114.73 | |
| Davidson | 254.78 | |
| Decatur | 62.69 | |
| DeKalb | 96.03 | |
| Dickson | 119.22 | |
| Dyer | 95.47 | |
| Fayette | 95.72 | |
| Fentress | 98.53 | |
| Franklin | 116.38 | |
| Gibson | 100.49 | |
| Giles | 92.94 | |
| Grainger | 107.78 | |
| Greene | 127.50 | |
| Grundy | 98.16 | |
| Hamblen | 156.28 | |
| Hamilton | 279.53 | |
| Hancock | 75.54 | |
| Hardeman | 64.96 | |
| Hardin | 63.34 | |
| Hawkins | 105.77 | |
| Haywood | 94.19 | |
| Henderson | 71.57 | |
| Henry | 94.33 | |
| Hickman | 89.51 | |
| Houston | 91.75 | |
| Humphreys | 78.98 | |
| Jackson | 88.12 | |
| Jefferson | 146.12 | |
| Johnson | 112.75 | |
| Knox | 279.39 | |
| Lake | 99.64 | |
| Lauderdale | 96.06 | |
| Lawrence | 93.54 | |
| Lewis | 81.13 | |
| Lincoln | 103.95 | |
| Loudon | 161.47 | |
| Macon | 106.79 | |
| Madison | 92.60 | |
| Marion | 92.34 | |
| Marshall | 99.27 | |
| Maury | 114.56 | |
| McMinn | 132.41 | |
| McNairy | 62.52 | |
| Meigs | 94.42 | |
| Monroe | 120.67 | |
| Montgomery | 139.54 | |
| Moore | 102.76 | |
| Morgan | 86.78 | |
| Obion | 102.13 | |
| Overton | 95.75 | |
| Perry | 62.89 | |
| Pickett | 99.35 | |
| Polk | 116.72 | |
| Putnam | 131.93 | |
| Rhea | 122.34 | |
| Roane | 149.44 | |
| Robertson | 149.98 | |
| Rutherford | 208.89 | |
| Scott | 75.80 | |
| Sequatchie | 109.65 | |
| Sevier | 173.51 | |
| Shelby | 148.62 | |
| Smith | 97.93 | |
| Stewart | 75.20 | |
| Sullivan | 200.49 | |
| Sumner | 150.75 | |
| Tipton | 93.37 | |
| Trousdale | 97.39 | |
| Unicoi | 202.76 | |
| Union | 116.12 | |
| Van Buren | 95.07 | |
| Warren | 98.08 | |
| Washington | 223.37 | |
| Wayne | 67.17 | |
| Weakley | 102.62 | |
| White | 108.29 | |
| Williamson | 172.00 | |
| Wilson | 139.37 | |
| Texas | Anderson | 76.82 |
| Andrews | 21.32 | |
| Angelina | 98.71 | |
| Aransas | 45.62 | |
| Archer | 40.25 | |
| Armstrong | 25.17 | |
| Atascosa | 61.84 | |
| Austin | 105.81 | |
| Bailey | 23.08 | |
| Bandera | 68.56 | |
| Bastrop | 111.44 | |
| Baylor | 27.96 | |
| Bee | 55.45 | |
| Bell | 88.91 | |
| Bexar | 160.88 | |
| Blanco | 80.78 | |
| Borden | 23.92 | |
| Bosque | 67.26 | |
| Bowie | 81.35 | |
| Brazoria | 126.80 | |
| Brazos | 154.11 | |
| Brewster | 18.45 | |
| Briscoe | 24.19 | |
| Brooks | 42.04 | |
| Brown | 65.31 | |
| Burleson | 92.83 | |
| Burnet | 80.29 | |
| Caldwell | 103.51 | |
| Calhoun | 58.08 | |
| Callahan | 46.92 | |
| Cameron | 96.44 | |
| Camp | 89.23 | |
| Carson | 36.81 | |
| Cass | 63.52 | |
| Castro | 37.38 | |
| Chambers | 64.12 | |
| Cherokee | 84.16 | |
| Childress | 25.06 | |
| Clay | 52.12 | |
| Cochran | 25.08 | |
| Coke | 26.06 | |
| Coleman | 44.51 | |
| Collin | 269.43 | |
| Collingsworth | 27.47 | |
| Colorado | 81.51 | |
| Comal | 92.51 | |
| Comanche | 71.49 | |
| Concho | 39.96 | |
| Cooke | 89.58 | |
| Coryell | 70.59 | |
| Cottle | 30.07 | |
| Crane | 22.97 | |
| Crockett | 22.00 | |
| Crosby | 26.28 | |
| Culberson | 19.94 | |
| Dallam | 30.72 | |
| Dallas | 219.34 | |
| Dawson | 28.17 | |
| Deaf Smith | 30.56 | |
| Delta | 53.31 | |
| Denton | 258.70 | |
| DeWitt | 83.22 | |
| Dickens | 28.85 | |
| Dimmit | 38.20 | |
| Donley | 23.43 | |
| Duval | 45.97 | |
| Eastland | 53.20 | |
| Ector | 31.37 | |
| Edwards | 31.69 | |
| El Paso | 108.76 | |
| Ellis | 86.98 | |
| Erath | 85.76 | |
| Falls | 68.07 | |
| Fannin | 77.83 | |
| Fayette | 109.22 | |
| Fisher | 30.64 | |
| Floyd | 27.25 | |
| Foard | 30.23 | |
| Fort Bend | 84.06 | |
| Franklin | 83.98 | |
| Freestone | 69.48 | |
| Frio | 50.06 | |
| Gaines | 31.29 | |
| Galveston | 143.54 | |
| Garza | 27.22 | |
| Gillespie | 82.32 | |
| Glasscock | 24.89 | |
| Goliad | 72.00 | |
| Gonzales | 86.14 | |
| Gray | 30.99 | |
| Grayson | 183.39 | |
| Gregg | 153.02 | |
| Grimes | 104.21 | |
| Guadalupe | 105.46 | |
| Hale | 35.24 | |
| Hall | 24.89 | |
| Hamilton | 67.99 | |
| Hansford | 36.35 | |
| Hardeman | 28.28 | |
| Hardin | 84.71 | |
| Harris | 233.91 | |
| Harrison | 71.19 | |
| Hartley | 33.62 | |
| Haskell | 28.50 | |
| Hays | 264.74 | |
| Hemphill | 30.18 | |
| Henderson | 86.36 | |
| Hidalgo | 117.00 | |
| Hill | 68.51 | |
| Hockley | 27.31 | |
| Hood | 92.86 | |
| Hopkins | 79.05 | |
| Houston | 75.60 | |
| Howard | 25.06 | |
| Hudspeth | 24.46 | |
| Hunt | 83.81 | |
| Hutchinson | 26.22 | |
| Irion | 26.95 | |
| Jack | 63.20 | |
| Jackson | 78.83 | |
| Jasper | 86.87 | |
| Jeff Davis | 18.61 | |
| Jefferson | 63.79 | |
| Jim Hogg | 47.05 | |
| Jim Wells | 56.05 | |
| Johnson | 107.03 | |
| Jones | 30.91 | |
| Karnes | 66.26 | |
| Kaufman | 81.54 | |
| Kendall | 83.87 | |
| Kenedy | 19.96 | |
| Kent | 23.22 | |
| Kerr | 67.64 | |
| Kimble | 53.96 | |
| King | 18.77 | |
| Kinney | 33.62 | |
| Kleberg | 35.76 | |
| Knox | 30.18 | |
| La Salle | 42.91 | |
| Lamar | 67.91 | |
| Lamb | 33.75 | |
| Lampasas | 76.61 | |
| Lavaca | 95.11 | |
| Lee | 99.58 | |
| Leon | 82.27 | |
| Liberty | 81.48 | |
| Limestone | 49.90 | |
| Lipscomb | 30.45 | |
| Live Oak | 58.48 | |
| Llano | 70.97 | |
| Loving | 5.17 | |
| Lubbock | 46.11 | |
| Lynn | 27.28 | |
| Madison | 81.16 | |
| Marion | 54.26 | |
| Martin | 24.11 | |
| Mason | 62.79 | |
| Matagorda | 64.93 | |
| Maverick | 38.06 | |
| McCulloch | 53.39 | |
| McLennan | 97.74 | |
| McMullen | 49.19 | |
| Medina | 72.44 | |
| Menard | 40.15 | |
| Midland | 43.59 | |
| Milam | 85.68 | |
| Mills | 67.97 | |
| Mitchell | 27.01 | |
| Montague | 74.01 | |
| Montgomery | 309.19 | |
| Moore | 30.72 | |
| Morris | 61.84 | |
| Motley | 22.94 | |
| Nacogdoches | 78.42 | |
| Navarro | 63.63 | |
| Newton | 60.16 | |
| Nolan | 29.85 | |
| Nueces | 82.68 | |
| Ochiltree | 33.37 | |
| Oldham | 22.08 | |
| Orange | 125.12 | |
| Palo Pinto | 66.10 | |
| Panola | 72.33 | |
| Parker | 116.37 | |
| Parmer | 30.47 | |
| Pecos | 18.75 | |
| Polk | 81.56 | |
| Potter | 27.52 | |
| Presidio | 21.21 | |
| Rains | 94.24 | |
| Randall | 42.85 | |
| Reagan | 22.70 | |
| Real | 52.04 | |
| Red River | 52.20 | |
| Reeves | 14.25 | |
| Refugio | 33.86 | |
| Roberts | 20.61 | |
| Robertson | 78.26 | |
| Rockwall | 149.96 | |
| Runnels | 37.46 | |
| Rusk | 69.37 | |
| Sabine | 61.11 | |
| San Augustine | 76.39 | |
| San Jacinto | 111.06 | |
| San Patricio | 71.79 | |
| San Saba | 66.34 | |
| Schleicher | 31.99 | |
| Scurry | 28.33 | |
| Shackelford | 34.94 | |
| Shelby | 95.00 | |
| Sherman | 38.76 | |
| Smith | 142.16 | |
| Somervell | 84.87 | |
| Starr | 49.68 | |
| Stephens | 47.38 | |
| Sterling | 18.37 | |
| Stonewall | 24.76 | |
| Sutton | 34.40 | |
| Swisher | 28.33 | |
| Tarrant | 165.35 | |
| Taylor | 55.61 | |
| Terrell | 20.34 | |
| Terry | 27.60 | |
| Throckmorton | 38.14 | |
| Titus | 68.26 | |
| Tom Green | 42.58 | |
| Travis | 169.47 | |
| Trinity | 71.62 | |
| Tyler | 92.43 | |
| Upshur | 93.27 | |
| Upton | 21.89 | |
| Uvalde | 35.19 | |
| Val Verde | 27.31 | |
| Van Zandt | 99.50 | |
| Victoria | 79.10 | |
| Walker | 99.66 | |
| Waller | 126.50 | |
| Ward | 28.82 | |
| Washington | 129.51 | |
| Webb | 46.40 | |
| Wharton | 78.61 | |
| Wheeler | 29.50 | |
| Wichita | 39.93 | |
| Wilbarger | 34.65 | |
| Willacy | 47.60 | |
| Williamson | 100.82 | |
| Wilson | 85.98 | |
| Winkler | 30.37 | |
| Wise | 105.54 | |
| Wood | 91.07 | |
| Yoakum | 25.44 | |
| Young | 45.81 | |
| Zapata | 38.25 | |
| Zavala | 47.16 | |
| Utah | Beaver | 26.42 |
| Box Elder | 18.20 | |
| Cache | 57.37 | |
| Carbon | 14.70 | |
| Daggett | 32.97 | |
| Davis | 110.70 | |
| Duchesne | 11.59 | |
| Emery | 24.94 | |
| Garfield | 37.12 | |
| Grand | 9.78 | |
| Iron | 23.21 | |
| Juab | 15.75 | |
| Kane | 21.53 | |
| Millard | 24.25 | |
| Morgan | 26.12 | |
| Piute | 24.70 | |
| Rich | 10.36 | |
| Salt Lake | 114.93 | |
| San Juan | 4.36 | |
| Sanpete | 33.48 | |
| Sevier | 50.83 | |
| Summit | 38.76 | |
| Tooele | 16.32 | |
| Uintah | 7.48 | |
| Utah | 103.68 | |
| Wasatch | 65.97 | |
| Washington | 44.36 | |
| Wayne | 53.88 | |
| Weber | 110.63 | |
| Vermont | Addison | 93.40 |
| Bennington | 133.48 | |
| Caledonia | 89.37 | |
| Chittenden | 178.88 | |
| Essex | 54.78 | |
| Franklin | 87.35 | |
| Grand Isle | 120.54 | |
| Lamoille | 97.63 | |
| Orange | 103.09 | |
| Orleans | 75.84 | |
| Rutland | 77.33 | |
| Washington | 119.95 | |
| Windham | 140.34 | |
| Windsor | 108.25 | |
| Virginia | Accomack | 120.54 |
| Albemarle | 279.38 | |
| Alleghany | 119.05 | |
| Amelia | 87.38 | |
| Amherst | 131.44 | |
| Appomattox | 87.38 | |
| Arlington | 8,416.52 | |
| Augusta | 197.68 | |
| Bath | 103.85 | |
| Bedford | 124.24 | |
| Bland | 97.33 | |
| Botetourt | 118.57 | |
| Brunswick | 71.00 | |
| Buchanan | 68.29 | |
| Buckingham | 105.38 | |
| Campbell | 87.16 | |
| Caroline | 104.39 | |
| Carroll | 90.92 | |
| Charles City | 95.26 | |
| Charlotte | 74.03 | |
| Chesapeake City | 165.17 | |
| Chesterfield | 260.29 | |
| Clarke | 199.00 | |
| Craig | 84.45 | |
| Culpeper | 162.31 | |
| Cumberland | 107.49 | |
| Dickenson | 79.65 | |
| Dinwiddie | 86.65 | |
| Essex | 90.21 | |
| Fairfax | 474.66 | |
| Fauquier | 207.84 | |
| Floyd | 107.38 | |
| Fluvanna | 121.87 | |
| Franklin | 101.73 | |
| Frederick | 204.00 | |
| Giles | 86.79 | |
| Gloucester | 133.22 | |
| Goochland | 153.36 | |
| Grayson | 117.35 | |
| Greene | 184.46 | |
| Greensville | 76.60 | |
| Halifax | 74.87 | |
| Hanover | 142.21 | |
| Henrico | 171.32 | |
| Henry | 83.63 | |
| Highland | 90.32 | |
| Isle of Wight | 104.90 | |
| James City | 285.63 | |
| King and Queen | 95.38 | |
| King George | 144.35 | |
| King William | 114.27 | |
| Lancaster | 119.67 | |
| Lee | 74.73 | |
| Loudoun | 277.24 | |
| Louisa | 139.89 | |
| Lunenburg | 75.24 | |
| Madison | 168.02 | |
| Mathews | 120.83 | |
| Mecklenburg | 78.06 | |
| Middlesex | 112.04 | |
| Montgomery | 136.75 | |
| Nelson | 143.28 | |
| New Kent | 151.19 | |
| Northampton | 129.50 | |
| Northumberland | 84.90 | |
| Nottoway | 89.64 | |
| Orange | 177.85 | |
| Page | 184.01 | |
| Patrick | 78.38 | |
| Pittsylvania | 80.07 | |
| Powhatan | 149.66 | |
| Prince Edward | 80.44 | |
| Prince George | 107.52 | |
| Prince William | 302.03 | |
| Pulaski | 99.36 | |
| Rappahannock | 194.63 | |
| Richmond | 111.70 | |
| Roanoke | 162.20 | |
| Rockbridge | 138.90 | |
| Rockingham | 249.78 | |
| Russell | 81.62 | |
| Scott | 74.48 | |
| Shenandoah | 166.18 | |
| Smyth | 82.75 | |
| Southampton | 87.19 | |
| Spotsylvania | 159.21 | |
| Stafford | 370.10 | |
| Suffolk | 116.56 | |
| Surry | 95.43 | |
| Sussex | 78.38 | |
| Tazewell | 77.27 | |
| Virginia Beach City | 272.49 | |
| Warren | 213.18 | |
| Washington | 142.29 | |
| Westmoreland | 105.40 | |
| Wise | 87.47 | |
| Wythe | 110.74 | |
| York | 341.60 | |
| Washington | Adams | 26.38 |
| Asotin | 24.44 | |
| Benton | 72.01 | |
| Chelan | 284.48 | |
| Clallam | 235.88 | |
| Clark | 165.26 | |
| Columbia | 30.07 | |
| Cowlitz | 165.42 | |
| Douglas | 21.80 | |
| Ferry | 9.57 | |
| Franklin | 84.88 | |
| Garfield | 29.06 | |
| Grant | 63.20 | |
| Grays Harbor | 44.24 | |
| Island | 202.81 | |
| Jefferson | 140.60 | |
| King | 651.13 | |
| Kitsap | 649.57 | |
| Kittitas | 76.24 | |
| Klickitat | 32.84 | |
| Lewis | 110.85 | |
| Lincoln | 22.57 | |
| Mason | 158.16 | |
| Okanogan | 22.30 | |
| Pacific | 63.99 | |
| Pend Oreille | 49.23 | |
| Pierce | 396.98 | |
| San Juan | 174.70 | |
| Skagit | 187.13 | |
| Skamania | 223.19 | |
| Snohomish | 357.11 | |
| Spokane | 68.87 | |
| Stevens | 28.98 | |
| Thurston | 219.46 | |
| Wahkiakum | 88.76 | |
| Walla Walla | 46.75 | |
| Whatcom | 310.23 | |
| Whitman | 32.25 | |
| Yakima | 50.89 | |
| West Virginia | Barbour | 66.22 |
| Berkeley | 151.70 | |
| Boone | 66.33 | |
| Braxton | 58.25 | |
| Brooke | 80.12 | |
| Cabell | 101.08 | |
| Calhoun | 51.70 | |
| Clay | 48.84 | |
| Doddridge | 60.38 | |
| Fayette | 82.61 | |
| Gilmer | 37.35 | |
| Grant | 74.36 | |
| Greenbrier | 73.91 | |
| Hampshire | 85.19 | |
| Hancock | 129.72 | |
| Hardy | 91.12 | |
| Harrison | 71.01 | |
| Jackson | 62.70 | |
| Jefferson | 166.56 | |
| Kanawha | 110.07 | |
| Lewis | 61.26 | |
| Lincoln | 52.27 | |
| Logan | 70.16 | |
| Marion | 84.06 | |
| Marshall | 73.37 | |
| Mason | 68.91 | |
| McDowell | 175.72 | |
| Mercer | 71.33 | |
| Mineral | 79.07 | |
| Mingo | 31.65 | |
| Monongalia | 128.47 | |
| Monroe | 75.49 | |
| Morgan | 148.44 | |
| Nicholas | 74.16 | |
| Ohio | 102.78 | |
| Pendleton | 63.81 | |
| Pleasants | 65.45 | |
| Pocahontas | 53.18 | |
| Preston | 77.91 | |
| Putnam | 81.28 | |
| Raleigh | 105.19 | |
| Randolph | 68.77 | |
| Ritchie | 51.19 | |
| Roane | 54.73 | |
| Summers | 64.43 | |
| Taylor | 87.21 | |
| Tucker | 81.19 | |
| Tyler | 54.25 | |
| Upshur | 75.01 | |
| Wayne | 56.98 | |
| Webster | 65.20 | |
| Wetzel | 54.65 | |
| Wirt | 51.27 | |
| Wood | 94.52 | |
| Wyoming | 94.92 | |
| Wisconsin | Adams | 125.67 |
| Ashland | 62.54 | |
| Barron | 95.71 | |
| Bayfield | 61.34 | |
| Brown | 237.81 | |
| Buffalo | 110.30 | |
| Burnett | 76.23 | |
| Calumet | 220.43 | |
| Chippewa | 99.63 | |
| Clark | 113.60 | |
| Columbia | 163.15 | |
| Crawford | 89.02 | |
| Dane | 230.65 | |
| Dodge | 163.60 | |
| Door | 133.17 | |
| Douglas | 54.90 | |
| Dunn | 100.81 | |
| Eau Claire | 127.85 | |
| Florence | 70.74 | |
| Fond du Lac | 203.66 | |
| Forest | 67.92 | |
| Grant | 132.05 | |
| Green | 151.93 | |
| Green Lake | 160.13 | |
| Iowa | 136.17 | |
| Iron | 95.21 | |
| Jackson | 106.38 | |
| Jefferson | 172.28 | |
| Juneau | 103.69 | |
| Kenosha | 212.06 | |
| Kewaunee | 157.33 | |
| La Crosse | 139.61 | |
| Lafayette | 167.32 | |
| Langlade | 91.60 | |
| Lincoln | 90.73 | |
| Manitowoc | 191.04 | |
| Marathon | 133.00 | |
| Marinette | 108.54 | |
| Marquette | 116.91 | |
| Menominee | 48.60 | |
| Milwaukee | 249.94 | |
| Monroe | 111.05 | |
| Oconto | 116.63 | |
| Oneida | 113.80 | |
| Outagamie | 201.76 | |
| Ozaukee | 183.48 | |
| Pepin | 108.45 | |
| Pierce | 129.34 | |
| Polk | 99.02 | |
| Portage | 114.78 | |
| Price | 68.84 | |
| Racine | 215.05 | |
| Richland | 93.95 | |
| Rock | 184.46 | |
| Rusk | 69.57 | |
| Sauk | 117.77 | |
| Sawyer | 72.59 | |
| Shawano | 130.51 | |
| Sheboygan | 184.60 | |
| St. Croix | 131.24 | |
| Taylor | 82.16 | |
| Trempealeau | 110.80 | |
| Vernon | 108.73 | |
| Vilas | 165.53 | |
| Walworth | 194.09 | |
| Washburn | 87.57 | |
| Washington | 197.45 | |
| Waukesha | 154.17 | |
| Waupaca | 126.42 | |
| Waushara | 118.45 | |
| Winnebago | 195.15 | |
| Wood | 92.69 | |
| Wyoming | Albany | 11.20 |
| Big Horn | 24.34 | |
| Campbell | 8.67 | |
| Carbon | 8.42 | |
| Converse | 8.10 | |
| Crook | 14.99 | |
| Fremont | 19.51 | |
| Goshen | 13.20 | |
| Hot Springs | 9.51 | |
| Johnson | 9.01 | |
| Laramie | 12.99 | |
| Lincoln | 28.00 | |
| Natrona | 6.95 | |
| Niobrara | 9.60 | |
| Park | 22.88 | |
| Platte | 13.45 | |
| Sheridan | 18.75 | |
| Sublette | 25.29 | |
| Sweetwater | 4.53 | |
| Teton | 62.02 | |
| Uinta | 16.42 | |
| Washakie | 17.90 | |
| Weston | 10.25 |
PART 12—SAFETY OF WATER POWER PROJECTS AND PROJECT WORKS
Subpart A—General Provisions
§ 12.1 Applicability.
(a) Except as otherwise provided in this part or ordered by the Commission or its authorized representative, the provisions of this part apply to:
(1) Any project licensed under Part I of the Federal Power Act;
(2) Any unlicensed constructed project for which the Commission has determined that an application for license must be filed under Part I of the Act; and
(3) Any project exempted from licensing under Part I of the Federal Power Act, pursuant to subparts J or K of part 4 of this chapter, to the extent that the Commission has conditioned the exemption on compliance with any particular provisions of this part.
(b) The provisions of this part apply to a project that uses a Government dam only with respect to those project works, lands, and waters specifically licensed by the Commission.
§ 12.2 Rules of construction.
(a) If any term, condition, article, or other provision in a project license is similar to any provision of this part, the licensee must comply with the relevant provision of this part, unless the Commission or the Director of the Office of Energy Projects determines that compliance with the relevant provision of the license will better protect life, health, or property.
(b) A licensee may request from the Director of the Office of Energy Projects a ruling on the applicability to its actions of any provision of its license that is similar to a provision of this part. A ruling by the Director may be appealed under § 385.207 of this chapter.
§ 12.3 Definitions.
(a) General rule. For purposes of this part, terms defined in section 3 of the Federal Power Act, 16 U.S.C. 796, have the same meaning as they have under the Act.
(b) Definitions. The following definitions apply for the purposes of this part:
(1) Applicant means any person, state, or municipality that has applied for a license for an unlicensed, constructed project and any owner of an unlicensed, constructed project for which the Commission has determined that an application for license must be filed.
(2) Owner means any person, state, or municipality, or combination thereof, that has a real property interests in a water power project sufficient to operate and maintain the project works.
(3) Authorized Commission representative means the Director of the Office of Energy Projects, the Director of the Division of Dam Safety and Inspections, the Regional Engineer, or any other member of the Commission staff whom the Commission may specifically designate.
(4) Condition affecting the safety of a project or project works means any condition, event, or action at the project which might compromise the safety, stability, or integrity of any project work or the ability of any project work to function safely for its intended purposes, including navigation, water power development, or other beneficial public uses, including recreation; or which might otherwise adversely affect life, health, or property. Conditions affecting the safety of a project or project works include, but are not limited to:
(i) Unscheduled rapid draw-down of impounded water;
(ii) Failure of, misoperation of, or failure to operate when attempted any facility that controls the release or storage of impounded water, such as a gate or a valve;
(iii) Failure or unusual movement, subsidence, or settlement of any part of a project work;
(iv) Unusual concrete deterioration or cracking, including development of new cracks or the lengthening or widening of existing cracks;
(v) Internal erosion, piping, slides, or settlements of materials in any dam, foundation, abutment, dike, or embankment;
(vi) Significant slides or settlements of materials in areas adjacent to reservoirs;
(vii) Significant damage to slope protection;
(viii) Unusual instrumentation readings;
(ix) New seepage or leakage or significant gradual increase in pre-existing seepage or leakage;
(x) Sinkholes;
(xi) Security incidents (physical and/or cyber);
(xii) Natural disasters, such as floods, earthquakes, or volcanic activity;
(xiii) Overtopping of any dam, abutment, or water conveyance;
(xiv) Any other signs of instability of any project work.
(5) Constructed project means any project with an existing dam.
(6) Dam means any structure for impounding or diverting water.
(7) Development means that part of a project comprising an impoundment and its associated dams, forebays, water conveyance facilities, power plants, and other appurtenant facilities. A project may comprise one or more developments.
(8) Modification means any activity, including repair or reconstruction, that in any way changes the physical features of the project from the state reflected in the plans or drawings or other documents filed with the Commission.
(9) Project emergency means an impending or actual sudden release of water at the project caused by natural disaster, accident, or failure of project works.
(10) Regional Engineer means the person in charge of the Commission’s regional office for the region (Atlanta, Chicago, Portland, New York, or San Francisco) where a particular project is located.
(11) Water conveyance means any canal, penstock, tunnel, flowline, flume, siphon, or other project work, constructed or natural, which facilitates the movement of water for the generation of hydropower, environmental benefit, or other purpose required by the project license.
(12) Owner’s Dam Safety Program means the written document that formalizes a licensee’s dam safety program, including, but not limited to, the licensee’s dam safety policies; objectives; expectations; responsibilities; training program; communication, coordination, and reporting; record keeping; succession planning; continuous improvement; and audits and assessments.
(13) Hazard potential for any dam or water conveyance is a classification based on the potential consequences in the event of failure or misoperation of the dam or water conveyance, and is subdivided into categories (e.g., Low, Significant, High).
(i) High hazard potential generally indicates that failure or misoperation will probably cause loss of human life.
(ii) Significant hazard potential generally indicates that failure or misoperation will probably not cause loss of human life but may have some amount of economic, environmental, or other consequences.
(iii) Low hazard potential generally indicates that failure or misoperation will probably not cause loss of human life but may have some amount of economic, environmental, or other consequences, typically limited to project facilities.
(14) Act means the Federal Power Act.
(a) Administrative responsibility. The Director of the Office of Energy Projects is responsible for administering the Commission’s project safety program and reports directly to the Chairman of the Federal Energy Regulatory Commission.
(b) Supervisory authority of the Regional Engineer or other authorized representative. (1) Any water power project and the construction, operation, maintenance, use, repair, or modification of any project works are subject to the inspection and the supervision of the Regional Engineer or any other authorized Commission representative for the purpose of:
(i) Achieving or protecting the safety, stability, security, and integrity of the project works or the ability of any project work to function safely for its intended purposes, including navigation, water power development, or other beneficial public uses; or
(ii) Otherwise protecting life, health, or property.
(2) For the purposes set forth in paragraph (b)(1) of this section, a Regional Engineer or other authorized Commission representative may:
(i) Test or inspect any water power project or project works or require that the applicant or licensee perform such tests or inspections or install monitoring instruments;
(ii) Require an applicant or a licensee to submit reports or information, regarding:
(A) The design, construction, operation, maintenance, use, repair, or modification of a water power project or project works; and
(B) Any condition affecting the safety of a project or project works or any death, serious injuries, or rescues that occur at, or might be attributable to, the water power project;
(iii) Require an applicant or a licensee to modify:
(A) Any emergency action plan filed under subpart C of this part;
(B) Any Owner’s Dam Safety Program filed under subpart F of this part;
(C) Any plan of corrective measures, including related schedules, submitted after the report of an independent consultant pursuant to § 12.36 or § 12.38 or any other inspection report; or
(D) Any public safety plan filed under § 12.52(b).
(iv) Require an applicant or licensee to take any other action with respect to the design, construction, operation, maintenance, repair, use, or modification of the project or its works that is, in the judgment of the Regional Engineer or other authorized Commission representative, necessary or desirable.
(v) Establish the time for an applicant or licensee to provide a schedule for or to perform any actions specified in this paragraph.
(c) Appeal, stay, rescission, or amendment of order or directive. (1) Any order or directive issued under this part by a Regional Engineer or other authorized Commission representative may be appealed to the Commission under § 385.207 of this chapter.
(2) Any order or directive issued under this part by a Regional Engineer or other authorized Commission representative is immediately effective and remains in effect until:
(i) The Regional Engineer or other authorized Commission representative who issued the order or directive rescinds or amends that order or directive or stays its effect; or
(ii) The Commission stays the effect of the order or directive, or amends or rescinds the order or directive on appeal.
(3) An appeal or motion for rescission, amendment, or stay of any order or directive issued under this part must contain a full explanation of why granting the appeal or the request for rescission or amendment of the order or directive, or for stay for the period requested, will not endanger life, health, or property.
(d) Failure to comply. If a licensee fails to comply with any order or directive issued under this part by the Commission, a Regional Engineer, or other authorized Commission representative, the licensee may be subject to sanctions, including, but not limited to, civil penalties, orders to cease generation, or license revocation.
§ 12.5 Responsibilities of licensee or applicant.
A licensee or applicant must use sound and prudent engineering practices in any action relating to the design, construction, operation, maintenance, use, repair, or modification of a water power project or project works.
Subpart B—Reports and Records
(a) Conditions affecting the safety of a project or its works—(1) Initial reports. An applicant or licensee must report by email or telephone to the Regional Engineer any condition affecting the safety of a project or projects works, as defined in § 12.3(b)(4). The initial report must be made as soon as practicable after that condition is discovered, preferably within 72 hours, without unduly interfering with any necessary or appropriate emergency repair, alarm, or other emergency action procedure.
(2) Written reports. Following the initial report required in paragraph (a)(1) of this section, the applicant or licensee must submit to the Regional Engineer a written report on the condition affecting the safety of the project or project works verified in accordance with § 12.13. The written report must be submitted within the time specified by the Regional Engineer and must contain any information the Regional Engineer directs, including:
(i) The causes of the condition;
(ii) A description of any unusual occurrences or operating circumstances preceding the condition;
(iii) An account of any measure taken to prevent worsening of the condition;
(iv) A detailed description of any damage to project works and the status of any repair;
(v) A detailed description of any personal injuries;
(vi) A detailed description of the nature and extent of any private property damages; and
(vii) Any other relevant information requested by the Regional Engineer.
(3) The level of detail required in any written report must be commensurate with the severity and complexity of the condition.
(b) Deaths, serious injuries, or rescues—(1) Initial reports. An applicant or licensee must report to the Regional Engineer any drowning or other incident resulting in death, serious injury, or rescue that occurs at the project works or involves project operation. The initial report must be made promptly after the incident is discovered, may be provided via email or telephone, and must include a description of the cause and location of the incident.
(2) Written reports. Following the initial report required in paragraph (b)(1), the applicant or licensee must submit to the Regional Engineer a written report.
(i) For any death, serious injury, or rescue that is considered or alleged to be project-related, or occurs at the project works, the applicant or licensee must submit to the Regional Engineer a written report that describes any remedial actions taken or proposed to avoid or reduce the chance of similar occurrences in the future. The written report must be verified in accordance with § 12.13.
(ii) For any death that is not project-related, the applicant or licensee may report the death by providing a copy of an article from print or electronic media or a report from a law enforcement agency, if available.
(iii) Serious injuries and rescues that are not project-related do not require a written report.
(3) For the purposes of this paragraph (b), project-related includes any deaths, serious injuries, or rescues that:
(i) Involve a project dam, spillway, intake, outlet works, tailrace, power canal, powerhouse, powerline, other water conveyance, or other appurtenances;
(ii) Involve changes in water levels or flows caused by generating units, project gates, or other flow regulating equipment;
(iii) Involve a licensee employee, contractor, or other person performing work at a licensed project facility and are related in whole or in part to the work being performed; or
(iv) Are otherwise attributable to project works and/or project operations.
(4) For the purposes of this paragraph (b), serious injury includes any injury that results in treatment at a medical facility or a response by licensee staff or another trained professional.
§ 12.11 Reporting modifications of the project or project works.
(a) Reporting requirement. Regardless of whether a particular modification is permitted without specific prior Commission approval, an applicant or licensee must report any modification of the project or project works to the Regional Engineer in writing, verified in accordance with § 12.13, at the time specified in paragraph (b) of this section.
(b) Time of reporting. (1) Any modification that is an emergency measure taken in response to a condition affecting the safety of the project or project works must be submitted with the report of that condition required by § 12.10(a)(2).
(2) In all other instances, the modification must be reported at least 60 days before work on the modification begins.
§ 12.12 Maintenance of records.
(a) Kinds of records—(1) General rule. Except as provided in paragraph (a)(2) of this section, the applicant or licensee must maintain as permanent project records in addition to those required in part 125 of this chapter, the following information:
(i) Engineering and geological data relating to design, construction, maintenance, repair, or modification of the project, including design memoranda and drawings, laboratory and other testing reports, geologic data (such as maps, sections, or logs of exploratory borings or trenches, foundation treatment, and excavation), plans and specifications, inspection and quality control reports, as built construction drawings, designers’ operating criteria, photographs, and any other data necessary to demonstrate that construction, maintenance, repair, or modification of the project has been performed in accordance with plans and specifications;
(ii) Instrumentation observations and data collected during construction, operation, or maintenance of the project, including continuously maintained tabular records and graphs illustrating the data collected pursuant to § 12.51; and
(iii) The operational and maintenance history of the project, including:
(A) The dates, times, nature, and causes of any complete or partial unscheduled shut-down, suspension of project operations, or reservoir filling restrictions related to the safety of the project or project works; and
(B) Any reports of project modifications, conditions affecting the safety of the project or project works, or deaths or serious injuries at the project.
(2) Exception. The applicant or licensee is not required to maintain as permanent project records any information specified in paragraph (a)(1) of this section that was or reasonably would have been prepared before the applicant or licensee acquired control of the project and that the applicant or the licensee never acquired or reasonably could have acquired.
(b) Location of records—(1) Original records. The applicant or licensee must maintain the originals of all permanent project records at a central location, such as the project site or the main business office of the applicant or licensee, secure from damage from any conceivable failure of the project works and convenient for inspection. The applicant or licensee must keep the Regional Engineer advised of the location of the permanent project records.
(2) Record copies. If the originals of the permanent project records are maintained at a central location other than the project site, the applicant or licensee must maintain at the project site copies of at least the project Exhibit G or L (design drawings), instrumentation data, and operational history that are necessary to the safe and efficient operation of the project.
(3) In accordance with the provisions of part 125 of this chapter, the applicant or licensee may select its own storage media to maintain original records or record copies at the project site, provided that appropriate equipment is available to view the records.
(c) Transfer of records. If the project is taken over by the United States at the end of a license term or the Commission issues a new license to a different licensee, the prior licensee must transfer the originals of all permanent project records to the custody of the administering Federal agency or department or to the new licensee.
(d) Provision of records. If the project is subject to subpart D of this part, or if requested by the Regional Engineer, the applicant or licensee must provide to the Regional Engineer physical and electronic copies of the documents listed in paragraph (a)(1) of this section, except as provided in paragraph (a)(2) of this section.
§ 12.13 Verification form.
If a document submitted in accordance with the provisions of this part must be verified, the form of verification attached to the document must be the following:
The undersigned, being first duly sworn, states that [he, she] has read the above document and knows the contents of it, and that all of the statements contained in that document are true and correct, to the best of [his, her] knowledge and belief.
Sworn to and subscribed before me this [day] of [month], [year].
Subpart C—Emergency Action Plans
§ 12.20 General requirements.
(a) Unless provided with a written exemption pursuant to § 12.21, every applicant or licensee must develop and file with the Regional Engineer an emergency action plan and appendices, verified in accordance with § 12.13.
(b) The emergency action plan must be:
(1) Developed in consultation and cooperation with appropriate Federal, state, and local agencies responsible for public health and safety; and
(2) Designed to provide early warning to upstream and downstream inhabitants, property owners, operators of water-related facilities, recreational users, and other persons in the vicinity who might be affected by a project emergency as defined in § 12.3(b)(9).
§ 12.21 Exemptions.
(a) Grant of exemption. Except as provided in paragraph (b), if an applicant or licensee satisfactorily demonstrates that no reasonably foreseeable project emergency would endanger life, health, or property, the Regional Engineer may exempt the applicant or licensee from filing an emergency action plan.
(b) No exemption. A licensee or applicant may not be exempted from the requirements of § 12.22(c) for a radiological response plan.
(c) Conditions of exemptions. (1) An applicant or licensee who receives an exemption from filing an emergency action plan has the continuing responsibility to review circumstances upstream and downstream from the project to determine if, as a result of changed circumstances, a project emergency might endanger life, health, or property.
(2) Promptly after the applicant or licensee learns that, as a result of any change in circumstances, a project emergency might endanger life, health, or property, the applicant or licensee must inform the Regional Engineer of that changed condition without unduly delaying the preparation and implementation of the emergency action plan.
(3) Comprehensive review of the necessity for an emergency action plan must be conducted at least once each year.
(d) Revocation of exemption. (1) The Regional Engineer may revoke an exemption granted under this section if it is determined that, as a result of any change in circumstances, a project emergency might endanger life, health, or property.
(2) If an exemption is revoked, the applicant or licensee must file an emergency action plan within the time specified by the Regional Engineer.
§ 12.22 Contents of emergency action plan.
(a) Contents—(1) The plan itself. An emergency action plan must provide:
(i) Instructions to project operators and attendants and other responsible personnel about the actions they are to take during a project emergency;
(ii) Detailed plans for notifying potentially affected persons, appropriate Federal, state, and local agencies, including public safety and law enforcement bodies, and medical units; and
(iii) Procedures for controlling the flow of water, including actions to reduce in-flows to reservoirs, such as limiting outflows from upstream dams or control structures, and actions to reduce downstream flows, such as increasing or decreasing outflows from downstream dams or control structures, on the waterway on which the project is located or its tributaries.
(2) Appendix to the plan. Each copy of the emergency action plan submitted to the Regional Engineer must be accompanied by an appendix that contains:
(i) Plans for training project operators, attendants, and other responsible personnel to respond properly during a project emergency, including instructions on the procedures to be followed throughout a project emergency and the manner in which the licensee will periodically review the knowledge and understanding that these personnel have of those procedures;
(ii) A summary of the study used for determining the upstream and downstream areas that may be affected by sudden release of water, including a summary of all criteria and assumptions used in the study and, if required by the Regional Engineer, inundation maps; and
(iii) Documentation of consultations with Federal, state, and local agencies, including public safety and law enforcement bodies, and medical units.
(b) Special factors. The applicant or licensee must take into account in its emergency action plan the time of day, particularly hours of darkness, in establishing the proper actions and procedures for use during a project emergency.
(c) Additional requirements for projects near nuclear power plants—(1) Radiological response plan. If the personnel operating any powerhouse or any spillway control facilities, such as gates or valves, of a project would be located within ten miles of a nuclear power plant reactor, the applicant or licensee must file, separately or as a supplement to any required emergency action plan, a radiological response plan that provides for emergency procedures to be taken if an accident or other incident results in the release of radioactive materials from the nuclear power plant reactor.
(2) A radiological response plan must:
(i) To the maximum extent practicable, include sufficient procedural safeguards to ensure that, during or following an accident or other incident involving the nearby nuclear power plant reactor, the project may be safely operated and, if evacuation is necessary, the project may be left unattended without danger to the safety of any project dam or to life, health, or safety upstream or downstream from the project; and
(ii) Explain the provisions, developed after consultation with the direct purchasers of project power, for cessation, curtailment, or continuation of generation of electric power at the project during or following an accident or other incident involving the nearby nuclear power plant reactor.
(3) Time of filing radiological response plan. (i) For a constructed project with an otherwise acceptable emergency action plan on file, any radiological response plan required must be filed:
(A) If an operating license for the nuclear power plant has been issued on or before March 1, 1981, not later than three months from March 1, 1981; or
(B) In all other instances, not later than three months after the date an operating license for the nuclear power plant is issued.
(ii) For any project not described in § 12.22(c)(3)(i), any radiological response plan required must be filed contemporaneously with the emergency action plan or, if the project has been exempted from filing an emergency action plan, at the time the emergency action plan would otherwise have been required to be filed pursuant to § 12.23.
§ 12.23 Time for filing emergency action plan.
(a) Unconstructed project. (1) Except as set forth in paragraph (a)(2), the emergency action plan for an unconstructed project must be filed no later than 60 days before the initial filling of the project reservoir begins.
(2) Temporary impoundment during construction. (i) For any unconstructed project, if a temporary impoundment would be created during construction, such as through construction of temporary or permanent cofferdams or large sediment control structures, and an accident to or failure of the impounding structures might endanger construction workers or otherwise endanger public health or safety, a temporary construction emergency action plan must be filed no later than 60 days before construction begins.
(ii) No later than 60 days before the initial filling of a project reservoir begins at a project for which a temporary emergency action plan has been filed the applicant or licensee must file modifications to that plan or a new plan, taking into account the differences in circumstances between the construction and post-construction periods.
(b) Unlicensed constructed project. (1) If the Commission has determined on or before March 1, 1981 that a license is required for an unlicensed constructed project, the emergency action plan for that project must be filed no later than:
(i) Six months after March 1, 1981; or
(ii) Any earlier date specified by the Commission or its authorized representative.
(2) Except as set forth in paragraph (b)(1) of this section, the emergency action plan for an unlicensed constructed project must be filed no later than the earliest of:
(i) Six months after the date that a license application is filed;
(ii) Six months after the date that the Commission issues an order determining that licensing is required; or
(iii) A date specified by the Commission or its authorized representative.
(c) Licensed constructed project. If a licensed constructed project does not have an acceptable emergency action plan on file on March 1, 1981 the emergency action plan must be filed no later than:
(1) Six months after March 1, 1981; or
(2) Any earlier date specified by the Commission or its authorized representative.
(d) For good cause shown, the Regional Engineer may grant an extension of time for filing all or any part of an emergency action plan.
§ 12.24 Review and updating of plans.
(a) The emergency action plan must be continually updated to reflect any changes in the names or titles of project operators and attendants and other personnel with specified responsibilities for actions in an emergency and any changes in names of persons to call, telephone numbers, radio call signals, or other information critical to providing notification to affected persons, Federal, state, and local agencies, and medical units.
(b) An applicant or licensee has continuing responsibility to review the adequacy of the emergency action plan in light of any significant changes in upstream or downstream circumstances which might affect water flows or the location or extent of the areas, persons, or property that might be harmed in a project emergency.
(c) Promptly after an applicant or licensee learns of any change in circumstances described in paragraph (b) of this section, the applicant or licensee must:
(1) Inform the Regional Engineer of that change in circumstances;
(2) Consult and cooperate with appropriate Federal, state, and local agencies responsible for public health and safety to determine any advisable revisions to the emergency action plan; and
(3) File with the Regional Engineer any revisions to the appropriate studies, maps, plans, procedures, or other information in the emergency action plan itself or its appendices that have changed as a result of that consultation.
(d) An applicant or licensee must conduct a comprehensive review of the adequacy of the emergency action plan at least once each year.
§ 12.25 Posting and readiness.
(a) A copy of the current emergency action plan itself must be posted in a prominent location readily accessible to the licensee’s or applicant’s operating personnel who are responsible for controlling water flows and for notifying public health and safety agencies and affected persons.
(b) Each licensee or applicant must annually test the state of training and readiness of key licensee or applicant personnel responsible for responding properly during a project emergency to ensure that they know and understand the procedures to be followed throughout a project emergency.
Subpart D—Review, Inspection, and Assessment by Independent Consultant
§ 12.30 Applicability.
This subpart D applies to any licensed project development that:
(a) Has a dam
(1) That is more than 32.8 feet (10 meters) in height above streambed, as defined in § 12.31(c); or
(2) With an impoundment gross storage capacity of more than 2,000 acre-feet (2.5 million cubic meters), as defined in § 12.31(d);
(b) Has a project work (dam or water conveyance) or any portion thereof that has a high hazard potential, as defined in § 12.3(b)(13)(i); or
(c) Is determined by the Regional Engineer or other authorized Commission representative to require inspection by an independent consultant under this subpart D.
§ 12.31 Definitions.
For purposes of this subpart D:
(a) Independent consultant means any person who:
(1) Is a licensed professional engineer;
(2) Has at least 10 years of experience and expertise in dam design and construction and in the investigation of the safety of existing dams;
(3) Is not an employee of the licensee or its affiliates;
(4) Has not been an employee of the licensee or its affiliates within two years prior to performing engineering and/or scientific services for an inspection or assessment under this subpart D; and
(5) Has not been an agent acting on behalf of the licensee or its affiliates, prior to performing engineering and/or scientific services for an inspection or assessment under this subpart D.
(b) An independent consultant team means a group of one or more people that:
(1) Includes at least one independent consultant, as defined in paragraph (a) of this section;
(2) Includes additional qualified engineering and scientific professionals as supporting team members, as needed, who meet the requirements of paragraphs (a)(3) through (5) of this section;
(3) Has demonstrable experience and expertise in dam design, construction, and the evaluation and assessment of the safety of existing dams and their appurtenances, commensurate with the scale, complexity, and relevant technical disciplines of the project and type of review, inspection, and assessment being performed (periodic inspection or comprehensive assessment, as defined in this section).
(c) Height above streambed means:
(1) For a dam with a spillway, the vertical distance from the lowest elevation of the natural streambed at the downstream toe of the dam to the maximum water storage elevation possible without any discharge from the spillway. The maximum water storage elevation is:
(i) For gated spillways, the elevation of the tops of the gates; and
(ii) For ungated spillways, the elevation of the spillway crest or the top of any flashboards, whichever is higher.
(2) For a dam without a spillway, the vertical distance from the lowest elevation of the natural streambed at the downstream tow of the dam to the lowest point on the crest of the dam.
(d) Gross storage capacity means the maximum possible volume of water impounded by a dam with zero spill, that is, without the discharge of water over the dam or a spillway.
(e) Periodic inspection means an inspection that meets the requirements of § 12.35 and is performed by an independent consultant team.
(f) Comprehensive assessment means a project review, inspection, and assessment that meets the requirements of § 12.37 and is performed by an independent consultant team.
(g) Previous Part 12D Inspection means the most recent inspection performed in accordance with the provisions of this subpart D (a periodic inspection, comprehensive assessment, or an inspection performed in accordance with the rules established by Order 122).
(h) Previous Part 12D Report means the report on the Previous Part 12D Inspection.
§ 12.32 General inspection requirement.
The project works of each development to which this subpart applies, excluding transmission and transformation facilities, must be inspected on a periodic basis by an independent consultant team to identify any actual or potential deficiencies that might endanger life, health, or property, including deficiencies that may be in the condition of those project works or in the quality or adequacy of project maintenance, safety, methods of operation, analyses, and other conditions. A report must be prepared by the independent consultant team, by or under the direction of at least one independent consultant, who may be a member of a consulting firm, to document the findings and evaluations made during their inspection. The inspection must be performed by the independent consultant team, and the report must be filed by the licensee, in accordance with the procedures in this subpart D. The licensee must ensure that the independent consultant team’s report meets all of the requirements set forth in this subpart D.
§ 12.33 Exemption.
(a) Upon written request from the licensee, the Director of the Division of Dam Safety and Inspections may grant an exemption from the requirements of this subpart D in circumstances that clearly establish good cause for exemption.
(b) Good cause for exemption may include the finding that the development in question has no dam, canal, or other water conveyance except those that meet the criteria for low hazard potential as defined in § 12.3(b)(13)(iii).
(c) The Director of the Division of Dam Safety and Inspections, for good cause shown, may rescind any exemption from this subpart D granted by the Director, and may require that a comprehensive assessment be completed prior to considering a subsequent request for exemption from the licensee.
§ 12.34 Approval of independent consultant team.
(a) The licensee must obtain written approval of the independent consultant team, and the facilitator(s) for a potential failure mode analysis or risk analysis, from the Director of the Division of Dam Safety and Inspections, prior to the performance of a periodic inspection or comprehensive assessment under this subpart D.
(b) At least 180 days prior to performing a periodic inspection or comprehensive assessment under this subpart D, the licensee must submit to the Director of the Division of Dam Safety and Inspections, with a copy to the Regional Engineer, a detailed part 12D inspection plan that includes an independent consultant team proposal that describes the technical disciplines and level of expertise required to perform the inspection.
(1) If the independent consultant team comprises one person, the detailed independent consultant team proposal must:
(i) Describe the experience of the independent consultant; and
(ii) Show that the independent consultant meets the requirements as defined in §§ 12.31(a) and 12.31(b)(3).
(2) If the independent consultant team comprises more than one person, the detailed independent consultant team proposal must:
(i) Designate one or more persons to serve as independent consultant(s);
(ii) Describe the experience of each member of the independent consultant team;
(iii) Show that each independent consultant meets the requirements as defined in § 12.31(a);
(iv) Show that each member of the independent consultant team who is not designated as an independent consultant meets the requirements as defined in § 12.31(a)(3) through (5); and
(v) Show that the independent consultant team meets the requirements as defined in § 12.31(b)(3).
(3) If any member of the independent consultant team has performed or substantially contributed to any previous investigation, analysis, or other work product that is required to be reviewed and evaluated by the independent consultant team as part of the inspection being performed, the independent consultant team proposal must include a clear delineation of roles and responsibilities that ensures no team member will be responsible for reviewing and evaluating their own previous work.
(4) If required information about any supporting team member(s) is not available at the time the independent consultant team proposal is submitted to the Director of the Division of Dam Safety and Inspections, the independent consultant team proposal must state that the information will be provided in the preliminary report required by § 12.42.
(5) The 180-day period in paragraph (b) is measured from the scheduled date of the physical field inspection, potential failure mode analysis, or risk analysis, whichever occurs first.
(c) Regardless of experience and qualifications, any independent consultant may be disapproved by the Director of the Division of Dam Safety and Inspections for good cause, such as having had one or more reports on an inspection under this subpart D rejected by the Commission within the preceding five years.
(d) The Director of the Division of Dam Safety and Inspections may, for good cause shown, grant a waiver of the 10-year requirement in § 12.31(a)(2). Any petition for waiver under this paragraph must be filed in accordance with § 385.207 of this chapter.
§ 12.35 Periodic inspection.
A periodic inspection must include:
(a) Review of prior reports. The independent consultant team must review and consider all relevant reports on the safety of the development made by or written under the direction of Federal or state agencies, submitted under Commission regulations, or made by other consultants. The licensee must provide to the independent consultant team all information and reports necessary to fulfill the requirements of this section. The independent consultant team must perform sufficient review to have, at the time of the periodic inspection, a full understanding of the design, construction, performance, condition, upstream and downstream hazard, monitoring, operation, and potential failure modes of the project works.
(b) Physical field inspection. The independent consultant team must perform a physical field inspection of accessible project works, including galleries, adits, vaults, conduits, earthen and concrete-lined spillway chutes, the exterior of water conveyances, and other non-submerged project works that may require specialized access to facilitate inspection. The inspection shall include review and assessment of all relevant data concerning:
(1) Settlement;
(2) Movement;
(3) Erosion;
(4) Seepage;
(5) Leakage;
(6) Cracking;
(7) Deterioration;
(8) Hydraulics;
(9) Hydrology;
(10) Seismicity;
(11) Internal stress and hydrostatic pressures in project structures and their foundations and abutments;
(12) The condition and performance of foundation drains, dam body drains, relief wells, and other pressure-relief systems;
(13) The condition and performance of any post-tensioned anchors installed, and other major modifications completed, to improve the stability of project works;
(14) The stability of critical slopes adjacent to a reservoir or project works; and
(15) Regional and site geological conditions.
(c) Review of surveillance and monitoring plan and data. The independent consultant team must:
(1) Review the surveillance procedures, instrumentation layout, installation details, monitoring frequency, performance history, data history and trends, and relevance to potential failure modes; and
(2) Review the frequency and scope of other surveillance activities.
(d) Review of dam and public safety programs. The independent consultant team must review the programs specified in this paragraph.
(1) Hazard potential. The independent consultant team must review the potential inundation area and document any significant changes in the magnitude and location of the population at risk since the previous inspection under this subpart D.
(2) Emergency Action Plan. If the project development is subject to subpart C of this part, the independent consultant team must review the emergency action plan, including the emergency action plan document itself, the licensee’s training program, and any related time-sensitivity assessment(s).
(3) Public Safety Program. The independent consultant team must review the public access restrictions and public safety warning signs and devices near the project works pursuant to § 12.52.
(4) Owner’s Dam Safety Program. If the project is subject to subpart F of this part, the independent consultant team must review the implementation of the licensee’s Owner’s Dam Safety Program with respect to the project development being inspected under this subpart D.
§ 12.36 Report on a periodic inspection.
(a) Scope. The report must include documentation of all the items listed in § 12.35.
(b) Specific evaluation. The report must include specific evaluation of:
(1) The history of performance of the project works through visual observations, analysis of data from monitoring instruments, and previous inspections;
(2) The quality and adequacy of maintenance, surveillance, methods of project operations, and risk reduction measures for the protection of public safety and continued project operation;
(3) Potential failure modes, including:
(i) Each identified potential failure mode associated with the project works and whether any potential failure mode is active or developing; and
(ii) Whether any inspection observations or other conditions indicate that an unidentified potential failure mode is active, developing, or is of sufficient concern to warrant development through a supplemental potential failure mode analysis;
(4) Whether any observed conditions warrant reconsideration of the current hazard potential classification; and
(5) The adequacy of the project’s:
(i) Emergency action plan;
(ii) Public safety program; and
(iii) Implementation of the Owner’s Dam Safety Program with respect to the project development being inspected under this subpart D.
(c) Changes since the previous inspection. The report must include a status update and evaluation of any changes since the Previous Part 12D Inspection concerning:
(1) Hydrology. Identify any events that may affect the conclusions of the hydrologic or hydraulic analyses of record and evaluate the effect on the safety and stability of project works.
(2) Seismicity. Identify any seismic events that may affect the conclusions of the seismicity analyses of record and evaluate the effect on the safety and stability of project works.
(3) Modifications to project works. Identify any modifications made to project works and evaluate the performance thereof with respect to the design intent.
(4) Methods of operation. Describe any changes to standard operating procedures, equipment available for project operation, and evaluate the effect on the safety and stability of project works.
(5) Results of special inspections. Summarize the findings of any special inspections (dive inspection, rope-access gate inspection, toe drain inspection, etc.), if any.
(6) Previous recommendations. List and document the status of recommendations made by the independent consultant(s) in the Previous Part 12D Report, and any earlier recommendations that remained incomplete at the time of the Previous Part 12D Report.
(7) Outstanding studies and studies completed since the previous inspection. List and document the status of any studies completed since the Previous Part 12D Inspection and those that remain outstanding at the time of the periodic inspection.
(d) Recommendations. Based on the independent consultant team’s field observations, evaluations of the project works, and the maintenance, surveillance, and methods of operation of the development, the report must contain recommendations by the independent consultant(s) regarding:
(1) Any corrective measures, described in § 12.41, necessary for the structures, maintenance or surveillance procedures, or methods of operation of the project works;
(2) A reasonable time to carry out each corrective measure; and
(3) Any new or additional monitoring instruments, periodic observations, special inspections, or other methods of monitoring project works or conditions that may be required.
(e) Dissenting views. If the inspection and report were conducted and prepared by more than one independent consultant, the report must clearly identify and describe any dissenting views concerning the evaluations or recommendations of the report that might be held by any individual consultant.
(f) List of participants. The report must identify all professional personnel who have participated in the inspection of the project or in preparation of the report and the independent consultant(s) who directed those activities.
(g) Statement of independence. Each independent consultant responsible for the report must declare that all conclusions and recommendations in the report are made independently of the licensee, its employees, and its representatives.
(h) Signature. The report must be signed and sealed, with a professional engineer’s seal, by each independent consultant responsible for the report.
§ 12.37 Comprehensive assessment.
A comprehensive assessment must include:
(a) Review of prior reports and analyses of record. The independent consultant team must review and consider all relevant reports on the safety of the development made by or written under the direction of Federal or state agencies, submitted under Commission regulations, or made by other consultants. The licensee must provide to the independent consultant team all information, reports, and analyses of record necessary to fulfill the requirements of this section.
(1) In addition to the requirements of § 12.35(a), the independent consultant team must have a full understanding of the risk associated with the project works.
(2) The independent consultant team shall perform a detailed review of the as-built drawings; monitoring data; and the methods, assumptions, calculations, results, and conclusions of the analyses of record pertaining to:
(i) Geology and seismicity;
(ii) Hydrology and hydraulics;
(iii) Stability and structural integrity of project works; and
(iv) Any other analyses relevant to the safety, stability, and operation of project works.
(b) Physical field inspection. The independent consultant team must perform a physical field inspection that complies with § 12.35(b).
(c) Review of surveillance and monitoring plan and data. The independent consultant team must perform a review of surveillance and monitoring plan and data that complies with § 12.35(c).
(d) Review of dam and public safety programs. The independent consultant team must perform a review of dam and public safety programs that complies with § 12.35(d).
(e) Supporting Technical Information Document. The comprehensive assessment shall include a review of the Supporting Technical Information Document.
(f) Potential failure mode analysis. The comprehensive assessment shall include a potential failure mode analysis.
(g) Risk analysis. The comprehensive assessment shall include a risk analysis. The Regional Engineer may, for good cause shown, grant a waiver of the requirement to complete a risk analysis. Any petition for waiver under this paragraph must be filed in accordance with § 385.207 of this chapter.
§ 12.38 Report on a comprehensive assessment.
(a) Scope. The comprehensive assessment report must include documentation of all the items listed in § 12.37.
(b) Specific evaluation. In addition to the items listed in § 12.36(b)(1) through § 12.36(b)(5), the comprehensive assessment report must evaluate:
(1) The adequacy of spillways, including the effects of overtopping of nonoverflow structures, as described in § 12.39;
(2) The structural adequacy and stability of structures under all credible loading conditions;
(3) The potential for internal erosion and/or piping of embankments, foundations, and abutments;
(4) The design and construction practices used during original construction and subsequent modifications, in comparison with the industry best practices in use at the time of the inspection under this subpart D;
(5) The adequacy of the Supporting Technical Information Document and the attached electronic records; and
(6) The adequacy and findings of the potential failure mode analysis and risk analysis report(s).
(c) Analyses of record. The comprehensive assessment report must include the independent consultant team’s evaluation of the assumptions, methods, calculations, results, and conclusions of the items listed in § 12.37(a)(2)(i) through (iv). The evaluation must:
(1) Address the accuracy, relevance, and consistency with the current state of the practice of dam engineering;
(2) Be accompanied by sufficient documentation of the independent consultant team’s rationale, including, as needed, new calculations by the independent consultant team to verify that the assumptions, methods, calculations, results, and conclusions in the analyses of record are correct; and
(3) If the independent consultant team is unable to review the analyses of record for any of the items listed in § 12.37(a)(2)(i) through (iv); or if the independent consultant team disagrees with the assumptions, methods, calculations, results, or conclusions therein; the independent consultant(s) must recommend that the licensee complete new analyses to address the identified concerns.
(d) Changes since the previous inspection. The requirements of this section are the same as described in § 12.36(c).
(e) Recommendations. The requirements of this section are the same as described in § 12.36(d).
(f) Dissenting views. The requirements of this section are the same as described in § 12.36(e).
(g) List of participants. The requirements of this section are the same as described in § 12.36(f).
(h) Statement of independence. The requirements of this section are the same as described in § 12.36(g).
(i) Signature. The requirements of this section are the same as described in § 12.36(h).
§ 12.39 Evaluation of spillway adequacy.
The adequacy of any spillway must be evaluated, as part of a comprehensive assessment or as otherwise requested by the Regional Engineer, by considering hazard potential which would result from failure of the project works during normal and flood flows.
(a) If failure would present a hazard to human life or cause significant property damage, the independent consultant team must evaluate the following for floods up to and including the probable maximum flood:
(1) The ability of project works to withstand the loading or overtopping which may occur during floods;
(2) The capacity of spillways to prevent the reservoir from rising to an elevation that would endanger the project works; and
(3) The potential for misoperation of; failure to operate; blockage of; or debilitating damage to a spillway and its appurtenances (including but not limited to structural, mechanical, and electrical components of gates, valves, chutes, and training walls); and the effect thereof on the maximum reservoir level and potential for surcharged loading or overtopping to occur during floods.
(b) If failure would not present a hazard to human life or cause significant property damage, spillway adequacy may be evaluated by means of a design flood of lesser magnitude than the probable maximum flood provided that the most recent comprehensive assessment report required by § 12.38 provides a detailed explanation of and rationale for the finding that structural failure would not present a hazard to human life or cause significant property damage.
§ 12.40 Time for inspections and reports.
(a) Projects previously inspected by independent consultant. For any project that was inspected under this subpart D prior to April 11, 2022, under the Commission’s rules in effect on January 1, 2022:
(1) A periodic inspection or comprehensive assessment must be completed, and the report on it filed, within five years of the due date of the Previous Part 12D Report.
(2) For any report due to be filed under this subpart D after October 11, 2023, the Regional Engineer may require that it be a report on a comprehensive assessment or a report on a periodic inspection.
(3) The first comprehensive assessment under this subpart must be completed, and the report on it filed, by December 31, 2038.
(b) Projects not previously inspected by independent consultant. For any project that was not inspected under this subpart D prior to April 11, 2022, under the Commission’s rules in effect on January 1, 2022:
(1) For any development that meets the criteria specified in § 12.30(a)(1) or § 12.30(a)(2), and was constructed before the date of issuance of the order licensing that development, or amending a license to include that development, the first comprehensive assessment under this subpart D must be completed, and the report on it filed, not later than two years after the date of issuance of the order licensing that development or amending the license to include that development.
(2) For any development that was constructed after the date of issuance of the order licensing that development, or amending a license to include that development, the first comprehensive assessment under this subpart D must be completed, and the report on it filed, not later than five years after the date of issuance of the order licensing that development or amending the license to include that development.
(3) For any development not set forth in either paragraph (b)(1) or (b)(2) of this section, the first comprehensive assessment under this subpart D must be completed, and the report on it filed, by a date specified by the Regional Engineer. The filing date must not be more than two years after the date of notification that a comprehensive assessment and report under this subpart D are required.
(c) Subsequent inspections and reports. For subsequent reports filed under this subpart D:
(1) A comprehensive assessment must be completed, and the report on it filed, within 10 years of the date the previous comprehensive assessment report was due to be filed.
(2) A periodic inspection must be completed, and the report on it filed, within five years of the date the previous comprehensive assessment report was due to be filed.
(d) Extension of time. For good cause shown, the Regional Engineer may extend the time for filing the report on a comprehensive assessment or periodic inspection under this subpart D.
(e) Type of Report. For good cause, the Regional Engineer may require that any report due to be filed under this subpart D be a report on a comprehensive assessment or a report on a periodic inspection, notwithstanding the type of review (periodic inspection or comprehensive assessment) scheduled to be performed under paragraphs (c)(1) and (c)(2) of this section.
§ 12.41 Corrective measures.
(a) Corrective measures. For items identified during a periodic inspection or comprehensive assessment as requiring corrective action, the following conditions apply:
(1) Corrective plan and schedule. (i) Not later than 60 days after a report on a periodic inspection or comprehensive assessment is filed with the Regional Engineer, the licensee must submit to the Regional Engineer a plan and schedule for addressing the recommendations of the independent consultant(s) and for investigating, designing, and carrying out any corrective measures that the licensee proposes to implement.
(ii) The plan and schedule may include any proposal, including taking no action, that the licensee considers a preferable alternative to any corrective measure recommended in the report of the independent consultant(s). Any proposed alternative must be accompanied by the licensee’s complete justification and detailed analysis and evaluation in support of that alternative.
(2) Carrying out the plan. The licensee must complete all corrective measures in accordance with the plan and schedule submitted to, and approved or modified by, the Regional Engineer, and on an annual basis must submit a status report on the corrective measures until all have been completed.
(3) Extension of time. For good cause shown, the Regional Engineer may extend the time for filing the plan and schedule required by this section.
(b) Emergency corrective measures. The licensee must provide that if, in the course of a periodic inspection or comprehensive assessment conducted under this subpart D, an independent consultant discovers any condition for which emergency corrective measures are advisable, such as a condition affecting the safety of a project or project works as defined in § 12.3(b)(4) of this part, the independent consultant must immediately notify the licensee and the licensee must report that condition to the Regional Engineer pursuant to § 12.10(a) of this part. Emergency corrective measures must be included in the corrective plan and schedule required by paragraph (a)(1) of this section, and are also subject to paragraphs (a)(2) and (a)(3) of this section.
§ 12.42 Preliminary reports.
At least 30 days prior to the performance of a periodic inspection or comprehensive assessment, a preliminary report prepared by the independent consultant team must be filed by the licensee with the Regional Engineer to document the initial findings, understanding, and preparation of the independent consultant team.
(a) For any periodic inspection, the 30-day period is measured from the scheduled date of the physical field inspection.
(b) For any comprehensive assessment, the 30-day period is measured from the scheduled date of the physical field inspection, potential failure mode analysis, or risk analysis, whichever occurs first.
(c) If the Regional Engineer determines that the preliminary report does not clearly demonstrate that the independent consultant team is adequately prepared for the inspection, the Regional Engineer may require the inspection to be postponed. Any such postponement shall not constitute good cause for an extension of time under § 12.40(d).
(d) If any required supporting team member information was not provided with the independent consultant team proposal required by § 12.34(b), it must be provided with the preliminary report.
Subpart E—Other Responsibilities of Applicant or Licensee
§ 12.50 Quality control programs.
(a) General rule. During any construction, repair, or modification of project works, including any corrective measures taken pursuant to § 12.41 of this part, the applicant or licensee must maintain any quality control program that may be required by the Regional Engineer, commensurate with the scope of the work and meeting any requirements or standards set by the Regional Engineer. If a quality control program is required, the construction, repair, or modification may not begin until the Regional Engineer has approved the program.
(b) If the construction, repair, or modification work is performed by a construction contractor, quality control inspection must be performed by the licensee, the design engineer, or an independent firm, other than the construction contractor, directly accountable to the licensee. This paragraph is not intended to prohibit additional quality control inspections by the construction contractor, or a firm accountable to the construction contractor, for the construction contractor’s purposes.
(c) If the construction, repair, or modification of project works is performed by the applicant’s or licensee’s own personnel, the applicant or licensee must provide for separation of authority within its organization to make certain that the personnel responsible for quality control inspection are, to the satisfaction of the Regional Engineer or other authorized Commission representative, independent from the personnel who are responsible for the construction, repair or modification.
§ 12.51 Monitoring instruments.
(a) In designing a project, a licensee must make adequate provision for installing and maintaining appropriate monitoring instrumentation whenever any physical condition that might affect the stability of a project structure has been discovered or is anticipated. The instrumentation must be satisfactory to the Regional Engineer and may include, for example, instruments to monitor movement of joints, foundation or embankment deformation, seismic effects, hydrostatic pore pressures, structural cracking, or internal stresses on the structure.
(b) If an applicant or licensee discovers any condition affecting the safety of the project or project works during the course of construction or operation, the applicant or licensee must install and maintain any monitoring devices and instruments that may be required by the Regional Engineer or other authorized Commission representative to monitor that condition.
§ 12.52 Warning and safety devices.
(a) To the satisfaction of, and within a time specified by the Regional Engineer, an applicant or licensee must install, operate, and maintain any signs, lights, sirens, barriers, or other safety devices that may reasonably be necessary or desirable to warn the public of fluctuations in flow from the project or otherwise to protect the public in the use of project lands and waters.
(b) The Regional Engineer may require the applicant or licensee to prepare, periodically update, and file with the Commission a public safety plan that formalizes the installation, operation, and maintenance of all necessary public safety devices.
§ 12.53 Power and communication lines and gas pipelines.
(a) A licensee must take all reasonable precautions, and comply with all reasonable specifications that may be provided by the Regional Engineer, to ensure that any power or communication line or gas pipeline that is located over, under, or in project waters does not obstruct navigation for recreational or commercial purposes or otherwise endanger public safety.
(b) Clearances between any power or communication line constructed after March 1, 1981 and any vessels using project waters must be at least sufficient to conform to any applicable requirements of the National Electrical Safety Code in effect at the time the power or communication line is constructed.
(c) The Regional Engineer may require a licensee or applicant to provide signs at or near power or communication lines to advise the public of the clearances for any power or communication lines located over, under, or in project waters.
§ 12.54 Testing spillway gates.
(a) General requirement. An applicant or licensee must make adequate provision, to the satisfaction of the Regional Engineer or other authorized Commission representative, to ensure that all spillway gates are operable at all times, particularly during adverse weather conditions.
(b) Annual test. (1) At least once each year, each spillway gate at a project must be operated to spill water, either during regular project operation or on a test basis.
(2) If an applicant or licensee does not operate each spillway gate on a test basis during an inspection by the Commission staff, the applicant or licensee must submit to the Regional Engineer at least once each year a written statement, verified in accordance with § 12.13, that each spillway gate has been operated at least once during the twelve months preceding the inspection.
(c) Load-test of standby power. (1) An applicant or licensee must load-test the standby emergency power for spillway gate operation at regular intervals, but not less than once during each year, and submit to the Regional Engineer, at least once each year, a written statement, verified in accordance with § 12.13, describing the intervals at which the standby emergency power was load-tested during the year preceding the inspection.
(2) The Commission staff may direct that a spillway gate be operated using standby emergency power during an inspection.
§§ 12.55-12.59 [Reserved]
Subpart F—Owner’s Dam Safety Program
§ 12.60 Applicability.
The licensee of any dam or other project work classified as having a high or significant hazard potential, as defined in § 12.3(b)(13)(i) and (ii), is required to submit an Owner’s Dam Safety Program to the Regional Engineer.
§ 12.61 Definitions.
For purposes of this subpart F:
(a) Chief Dam Safety Engineer means the designated individual, who is a licensed professional engineer with experience in dam safety, who oversees the implementation of the Owner’s Dam Safety Program and has primary responsibility for ensuring the safety of the licensee’s dam(s) and other project works.
(b) Chief Dam Safety Coordinator means the designated individual, who is not required to be a licensed professional engineer, who oversees the implementation of the Owner’s Dam Safety Program and has primary responsibility for ensuring the safety of the licensee’s dam(s) and other project works.
§ 12.62 General requirements.
(a) The Owner’s Dam Safety Program shall designate either a Chief Dam Safety Engineer or Chief Dam Safety Coordinator, as defined in § 12.61. Any Owner’s Dam Safety Program that includes one or more dams or other project works classified as having a high hazard potential, as defined in § 12.3(b)(13)(i), shall designate a Chief Dam Safety Engineer.
(b) The Owner’s Dam Safety Program must be signed by the Owner and, as applicable, the Chief Dam Safety Engineer or the Chief Dam Safety Coordinator.
(c) The Owner’s Dam Safety Program must be reviewed and updated on a periodic basis as described in § 12.64 and, if applicable, must undergo an independent external audit or peer review as described in § 12.65.
(d) The Owner may delegate to others, such as consultants, the work of establishing and implementing the Owner’s Dam Safety Program and the role of Chief Dam Safety Engineer or Chief Dam Safety Coordinator, as applicable.
(1) If the role of Chief Dam Safety Engineer or Chief Dam Safety Coordinator is delegated to an outside party who does not oversee the day-to-day implementation of the Owner’s Dam Safety Program, the Owner must designate an individual responsible for overseeing the day-to-day implementation.
(2) Any delegation made in accordance with paragraph (d) of this section must be documented in the Owner’s Dam Safety Program.
(3) The Owner retains ultimate responsibility for the safety of the dam(s) and other project works covered by the Owner’s Dam Safety Program.
§ 12.63 Contents of Owner’s Dam Safety Program.
The Owner’s Dam Safety Program shall contain, at a minimum, the following sections:
(a) Dam safety policy, objectives, and expectations;
(b) Responsibilities for dam safety;
(c) Dam safety training program;
(d) Communication, coordination, reporting, and reports;
(e) Record keeping and databases; and
(f) Continuous improvement.
§ 12.64 Annual review and update of Owner’s Dam Safety Program.
The Owner’s Dam Safety Program, and the implementation thereof, shall be reviewed at least once annually by the licensee’s dam safety staff and discussed with senior management of the Owner’s organization. The licensee shall submit the results of the annual review, including findings, analysis, corrective measures, and/or revisions to the Owner’s Dam Safety Program, to the Regional Engineer.
§ 12.65 Independent external audit and peer review.
(a) Applicability. For licensees of one or more dams or other project works classified as having a high hazard potential, as defined in § 12.3(b)(13)(i), an independent external audit or peer review of the Owner’s Dam Safety Program, and the implementation thereof, shall be performed at an interval not to exceed five years.
(b) Qualifications. A statement of qualifications for the proposed auditor(s) or peer review team that demonstrates independence from the licensee and its affiliates shall be submitted to the Regional Engineer for review, and written acceptance thereof must be obtained from the Regional Engineer prior to performing the audit or peer review.
(c) Reporting. (1) The auditor(s) or peer review team shall document their findings in a report.
(2) The report on the audit or peer review shall be reviewed by the Owner, Chief Dam Safety Engineer or Chief Dam Safety Coordinator, and management having responsibility in the area(s) audited or reviewed.
(3) The report on the audit or peer review shall be submitted to the Regional Engineer.
PART 16—PROCEDURES RELATING TO TAKEOVER AND RELICENSING OF LICENSED PROJECTS
Subpart A—General Provisions
§ 16.1 Applicability.
This part applies to the filing and processing of an application for:
(a) A new license, a nonpower license, or an exemption from licensing for a hydroelectric project with an existing license subject to the provisions of sections 14 and 15 of the Federal Power Act.
(b) A subsequent license or an exemption from licensing for a hydroelectric project with an existing minor license or minor part license not subject to the provisions of sections 14 and 15 of the Federal Power Act because those sections were waived pursuant to section 10(i) of the Federal Power Act.
(c) Any potential applicant for a new or subsequent license for which the deadline for the notice of intent required by § 16.6 falls on or after July 23, 2005 and which wishes to develop and file its application pursuant to this part, must seek Commission authorization to do so pursuant to the provisions of part 5 of this chapter.
§ 16.2 Definitions.
For purposes of this part:
(a) New license means a license, except an annual license, for a water power project that is issued under section 15(a) of the Federal Power Act after an original license expires.
(b) New license application filing deadline, as provided in section 15(c)(1) of the Federal Power Act, is the date 24 months before the expiration of an existing license.
(c) Nonpower license means a license for a nonpower project issued under section 15(b) of the Federal Power Act.
(d) Subsequent license means a license for a water power project issued under Part I of the Federal Power Act after a minor or minor part license that is not subject to sections 14 and 15 of the Federal Power Act expires.
§ 16.3 Public notice of projects under expiring licenses.
In addition to the notice of a licensee’s intent to file or not to file an application for a new license provided in § 16.6(d), the Commission will publish, in its annual report and annually in the
(a) List the licenses according to their expiration dates; and
(b) Contain the following information: license expiration date; licensee’s name; project number; type of principal project works licensed, e.g., dam and reservoir, powerhouse, transmission lines; location by state, county, and stream; location by city or nearby city when appropriate; whether the existing license is subject to sections 14 and 15 of the Federal Power Act; and plant installed capacity.
§ 16.4 Acceleration of a license expiration date.
(a) Request for acceleration. (1) A licensee may file with the Commission, in accordance with the formal filing requirements in subpart T of part 385 of this chapter, a written request for acceleration of the expiration date of its existing license, containing the statements and information specified in § 16.6(b) and a detailed explanation of the basis for the acceleration request.
(2) If the Commission grants the request for acceleration pursuant to paragraph (c), the Commission will deem the request for acceleration to be a notice of intent under § 16.6 and, unless the Commission directs otherwise, the licensee shall make available the information specified in § 16.7 no later than 90 days from the date that the Commission grants the request for acceleration.
(b) Notice of request for acceleration. (1) Upon receipt of a request for acceleration, the Commission will give notice of the licensee’s request and provide a 45-day period for comments by interested persons by:
(i) Publishing notice in the
(ii) Publishing notice once in a daily or weekly newspaper published in the county or counties in which the project or any part thereof or the lands affected thereby are situated; and
(iii) Notifying appropriate Federal, state, and interstate resource agencies and Indian tribes by mail.
(2) The notice issued pursuant to paragraphs (1) (i) and (ii) and the written notice given pursuant to paragraph (1)(iii) will be considered as fulfilling the notice provisions of § 16.6(d) should the Commission grant the acceleration request and will include an explanation of the basis for the licensee’s acceleration request.
(c) Commission order. If the Commission determines it is in the public interest, the Commission will issue an order accelerating the expiration date of the license to not less than five years and 90 days from the date of the Commission order.
§ 16.5 Site access for a competing applicant.
(a) Access. If a potential applicant for a new license, subsequent license, or nonpower license for a project has complied with the first stage consultation provisions of § 16.8(b)(1) and has notified the existing licensee in writing of the need for and extent of the access required, the existing licensee must allow the potential applicant to enter upon or into designated land, buildings, or other property in the project area at a reasonable time and under reasonable conditions, including, but not limited to, reasonable liability conditions, conditions for compensation to the existing licensee for all reasonable costs incurred in providing access, including energy generation lost as a result of modification of project operations that may be necessary to provide access, and in a manner that will not adversely affect the environment, for the purposes of:
(1) Conducting a study or gathering information required by a resource agency under § 16.8 or by the Commission pursuant to § 4.32 of this chapter;
(2) Conducting a study or gathering information not covered by paragraph (a)(1) but necessary to prepare an application for new license, subsequent license, or nonpower license; or
(3) Holding a site visit for a resource agency under § 16.8.
(b)(1) Disputes. Except as specified by paragraph (b)(2), disputes regarding the timing and conditions of access for the purposes specified in paragraphs (a) (1), (2), or (3) of this section and the need for the studies or information specified in paragraph (a)(2) may be referred to the Director of the Office of Energy Projects for resolution in the manner specified in § 16.8(b)(5) prior to the providing of access.
(2) Disputes regarding the amount of compensation to be paid the existing licensee for access may be referred to the Director of the Office of Energy Projects for resolution in the manner specified in § 16.8(b)(5) after the access has been provided.
Subpart B—Applications for Projects Subject to Sections 14 and 15 of the Federal Power Act
§ 16.6 Notification procedures under section 15 of the Federal Power Act.
(a) Applicability. This section applies to a licensee of an existing project subject to sections 14 and 15 of the Federal Power Act.
(b) Requirement to notify. In order to notify the Commission under section 15 of the Federal Power Act whether a licensee intends to file or not to file an application for new license, the licensee must file with the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov a letter, that contains the following information:
(1) The licensee’s name and address.
(2) The project number.
(3) The license expiration date.
(4) An unequivocal statement of the licensee’s intention to file or not to file an application for a new license.
(5) The type of principal project works licensed, such as dam and reservoir, powerhouse, or transmission lines.
(6) Whether the application is for a power or nonpower license.
(7) The location of the project by state, county and stream, and, when appropriate, by city or nearby city.
(8) The installed plant capacity.
(9) The location or locations of all the sites where the information required under § 16.7 is available to the public.
(10) The names and mailing addresses of:
(i) Every county in which any part of the project is located, and in which any Federal facility that is used by the project is located;
(ii) Every city, town, or similar local political subdivision:
(A) In which any part of the project is located and any Federal facility that is used by the project is located, or
(B) That has a population of 5,000 or more people and is located within 15 miles of the project dam,
(iii) Every irrigation district, drainage district, or similar special purpose political subdivision:
(A) In which any part of the project is located and any Federal facility that is used by the project is located, or
(B) That owns, operates, maintains, or uses any project facility or any Federal facility that is used by the project;
(iv) Every other political subdivision in the general area of the project that there is reason to believe would be likely to be interested in, or affected by, the notification;
(v) Affected Indian tribes.
(c) When to notify. (1) Except as provided in paragraph (c)(2) of this section, if a license expires on or after October 17, 1992, the licensee must notify the Commission as required in paragraph (b) of this section at least five years, but no more than five and one-half years, before the existing license expires.
(2) The requirement in paragraph (c)(1) of this section does not apply if a licensee filed notice more than five and one-half years before its existing license expired and before the effective date of this rule.
(d) Commission notice. Upon receipt of the notification required under paragraph (c) of this Section, the Commission will provide notice of the licensee’s intent to file or not to file an application for a new license by:
(1) If the notification is filed prior to July 23, 2005;
(i) Publishing notice in the
(ii) Publishing notice once in a daily or weekly newspaper published in the county or counties in which the project or any part thereof or the lands affected thereby are situated; and
(iii) Notifying the appropriate Federal and state resource agencies, state water quality and coastal zone management consistency certifying agencies, and Indian tribes, by electronic means if practical, otherwise by mail.
(2) If the notification is filed on or after July 23, 2005, pursuant to the provisions of § 5.8 of this chapter.
§ 16.7 Information to be made available to the public at the time of notification of intent under section 15(b) of the Federal Power Act.
(a) Applicability. This section applies to a licensee of an existing project subject to sections 14 and 15 of the Federal Power Act.
(b) Requirement to make information available. A licensee must make the information specified in paragraph (d) of this section reasonably available to the public for inspection and reproduction, from the date on which the licensee notifies the Commission pursuant to § 16.6(b) of this part until the date any relicensing proceeding for the project is terminated.
(c) Requirement to supplement information. A licensee must supplement the information it is required to make available under the provisions of paragraph (d) with any additional information developed after the filing of a notice of intent.
(d) Information to be made available. (1) A licensee for which the deadline for filing a notification of intent to seek a new or subsequent license is on or after July 23, 2005 must, at the time it files a notification of intent to seek a license pursuant to § 5.5 of this chapter, provide a copy of the pre-application document required by § 5.6 of this chapter to the entities specified in that paragraph.
(2) A licensee for which the deadline for filing a notification of intent to seek a new or subsequent license is prior to July 23, 2005, and which elects to seek a license pursuant to this part must make the following information regarding its existing project reasonably available to the public as provided in paragraph (b) of this section:
(i) The following construction and operation information:
(A) The original license application and the order issuing the license and any subsequent license application and subsequent order issuing a license for the existing project, including
(1) Approved Exhibit drawings, including as-built exhibits,
(2) Any order issuing amendments or approving exhibits,
(3) Any order issuing annual licenses for the existing project;
(B) All data relevant to whether the project is and has been operated in accordance with the requirements of each license article, including minimum flow requirements, ramping rates, reservoir elevation limitations, and environmental monitoring data;
(C) A compilation of project generation and respective outflow with time increments not to exceed one hour, unless use of another time increment can be justified, for the period beginning five years before the filing of a notice of intent;
(D) Any public correspondence related to the existing project;
(E) Any report on the total actual annual generation and annual operation and maintenance costs for the period beginning five years before the filing of a notice of intent;
(F) Any reports on original project costs, current net investment, and available funds in the amortization reserve account;
(G) A current and complete electrical single-line diagram of the project showing the transfer of electricity from the project to the area utility system or point of use; and
(H) Any bill issued to the existing licensee for annual charges under Section 10(e) of the Federal Power Act.
(ii) The following safety and structural adequacy information:
(A) The most recent emergency action plan for the project or a letter exempting the project from the emergency action plan requirement;
(B) Any independent consultant’s reports required by part 12 of this chapter and filed on or after January 1, 1981;
(C) Any report on operation or maintenance problems, other than routine maintenance, occurring within the five years preceding the filing of a notice of intent or within the most recent five-year period for which data exists, and associated costs of such problems under the Commission’s Uniform System of Accounts;
(D) Any construction report for the existing project; and
(E) Any public correspondence relating to the safety and structural adequacy of the existing project.
(iii) The following fish and wildlife resources information:
(A) Any report on the impact of the project’s construction and operation on fish and wildlife resources;
(B) Any existing report on any threatened or endangered species or critical habitat located in the project area, or affected by the existing project outside the project area;
(C) Any fish and wildlife management plan related to the project area prepared by the existing licensee or any resource agency; and
(D) Any public correspondence relating to the fish and wildlife resources within the project area.
(iv) The following recreation and land use resources information:
(A) Any report on past and current recreational uses of the project area;
(B) Any map showing recreational facilities and areas reserved for future development in the project area, designated or proposed wilderness areas in the project area; Land and Water Conservation Fund lands in the project area, and designated or proposed Federal or state wild and scenic river corridors in the project area.
(C) Any documentation listing the entity responsible for operating and maintaining any existing recreational facilities in the project area; and
(D) Any public correspondence relating to recreation and land use resources within the project area.
(v) The following cultural resources information:
(A) Except as provided in paragraph (d)(2)(v)(B) of this section, a licensee must make available:
(1) Any report concerning documented archeological resources identified in the project area;
(2) Any report on past or present use of the project area and surrounding areas by Native Americans; and
(3) Any public correspondence relating to cultural resources within the project area.
(B) A licensee must delete from any information made available under paragraph (d)(2)(v)(A) of this section, specific site or property locations the disclosure of which would create a risk of harm, theft, or destruction of archeological or Native American cultural resources or to the site at which the resources are located, or would violate any Federal law, including the Archeological Resources Protection Act of 1979, 16 U.S.C. 470w–3, and the National Historic Preservation Act of 1966, 16 U.S.C. 470hh.
(vi) The following energy conservation information under section 10(a)(2)(C) of the Federal Power Act related to the licensee’s efforts to conserve electricity or to encourage conservation by its customers including:
(A) Any plan of the licensee;
(B) Any public correspondence; and
(C) Any other pertinent information relating to a conservation plan.
(3)–(6) [Reserved]
(7)(i) If paragraph (d) of this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined in § 388.113(c) of this chapter, to any person, the applicant shall omit the CEII from the information made available and insert the following in its place:
(A) A statement that CEII is being withheld;
(B) A brief description of the omitted information that does not reveal any CEII; and
(C) This statement: “Procedures for obtaining access to Critical Energy Infrastructure Information (CEII) may be found at 18 CFR 388.113. Requests for access to CEII should be made to the Commission’s CEII Coordinator.”
(ii) The applicant, in determining whether information constitutes CEII, shall treat the information in a manner consistent with any filings that applicant has made with the Commission and shall to the extent practicable adhere to any previous determinations by the Commission or the CEII Coordinator involving the same or like information.
(iii) The procedures contained in §§ 388.112 and 388.113 of this chapter regarding designation of, and access to, CEII, shall apply in the event of a challenge to a CEII designation or a request for access to CEII. If it is determined that information is not CEII or that a requester should be granted access to CEII, the applicant will be directed to make the information available to the requester.
(iv) Nothing in this section shall be construed to prohibit any persons from voluntarily reaching arrangements or agreements calling for the disclosure of CEII.
(e) Form, place, and hours of availability, and cost of reproduction. (1) A licensee must make the information specified in paragraph (d) of this section, or the pre-application document, as applicable, available to the public for inspection:
(i) At its principal place of business or at any other location or locations that are more accessible to the public, provided that all of the information is available in at least one location;
(ii) During regular business hours; and
(iii) In a form that is readily accessible, reviewable, and reproducible.
(2) Except as provided in paragraph (d)(3) of this section, a licensee must make requested copies of the information specified in paragraph (c) of this section available either:
(i) At its principal place of business or at any other location or locations that are more accessible to the public, after obtaining reimbursement for reasonable costs of reproduction; or
(ii) Through the mail, after obtaining reimbursement for postage fees and reasonable costs of reproduction.
(3) A licensee must make requested copies of the information specified in paragraph (d) of this section available to the United States Fish and Wildlife Service, the National Marine Fisheries Service, Indian tribes, and the state agency responsible for fish and wildlife resources without charge for the costs of reproduction or postage.
(f) Unavailability of required information. Anyone may file a petition with the Commission requesting access to the information specified in paragraph (d) of this section if it believes that a licensee is not making the information reasonably available for public inspection or reproduction. The petition must describe in detail the basis for the petitioner’s belief.
(g) Public correspondence. A licensee may compile and make available in one file all the public correspondence required to be made available for inspection and reproduction by § 16.7(d)(1)(iv), (d)(2)(v), (d)(3)(iv), (d)(4)(iv), and (d)(6)(ii).
§ 16.8 Consultation requirements.
(a) Requirement to consult. (1) Before it files any application for a new license, a nonpower license, an exemption from licensing, or, pursuant to § 16.25 or § 16.26 of this part, a surrender of a project, a potential applicant must consult with the relevant Federal, State, and interstate resource agencies, including the National Marine Fisheries Service, the United States Fish and Wildlife Service, the National Park Service, the United States Environmental Protection Agency, the Federal agency administering any United States lands or facilities utilized or occupied by the project, the appropriate state fish and wildlife agencies, the appropriate State water resource management agencies, the certifying agency under section 401(a)(1) of the Federal Water Pollution Control Act (Clean Water Act), 33 U.S.C. 1341(c)(1), and any Indian tribe that may be affected by the project.
(2) Each requirement in this section to contact or consult with resource agencies or Indian tribes shall require as well that the potential Applicant contact or consult with members of the public.
(3) If the potential applicant for a new or subsequent license commences first stages pre-filing consultation under this part on or after July 23, 2005, it must file a notification of intent to file a license application pursuant to § 5.5 of this chapter and a pre-application document pursuant to the provisions of § 5.6 of this chapter.
(4) The Director of the Office of Energy Projects will, upon request, provide a list of known appropriate Federal, state, and interstate resource agencies, and Indian tribes, and local, regional, or national non-governmental organizations likely to be interested in any license application proceeding.
(5)(i) Before it files an amendment that would be considered as material under § 4.35 of this part, to any application subject to this section, an applicant must consult with the resource agencies and Indian tribes listed in paragraph (a)(1) of this section and allow such agencies and tribes at least 60 days to comment on a draft of the proposed amendment and to submit recommendations and conditions to the applicant. The amendment as filed with the Commission must summarize the consultation with the resource agencies and Indian tribes on the proposed amendment and respond to any obligations, recommendations or conditions submitted by the agencies or Indian tribes.
(ii) If an applicant has any doubt as to whether a particular amendment would be subject to the pre-filing consultation requirements of this section, the applicant may file a written request for clarification with the Director, Office of Energy Projects.
(b) First stage of consultation. (1) A potential Applicant for a new or subsequent license must, at the time it files its notification of intent to seek a license pursuant to § 5.5 of this chapter, provide a copy of the pre-application document required by § 5.6 of this chapter to the entities specified in § 5.6(a) of this chapter.
(2) A potential applicant for a nonpower license or exemption or a potential applicant which elects to use the licensing procedures of Parts 4 or 16 of this chapter prior to July 23, 2005, must promptly contact each of the appropriate resource agencies, Indian tribes, and members of the public listed in paragraph (a)(1) of this section, and the Commission with the following information:
(i) Detailed maps showing existing project boundaries, if any, proper land descriptions of the entire project area by township, range, and section, as well as by state, county, river, river mile, and closest town, and also showing the specific location of all existing and proposed project facilities, including roads, transmission lines, and any other appurtenant facilities;
(ii) A general engineering design of the existing project and any proposed changes, with a description of any existing or proposed diversion of a stream through a canal or penstock;
(iii) A summary of the existing operational mode of the project and any proposed changes;
(iv) Identification of the environment affected or to be affected, the significant resources present and the applicant’s existing and proposed environmental protection, mitigation, and enhancement plans, to the extent known at that time;
(v) Streamflow and water regime information, including drainage area, natural flow periodicity, monthly flow rates and durations, mean flow figures illustrating the mean daily streamflow curve for each month of the year at the point of diversion or impoundment, with location of the stream gauging station, the method used to generate the streamflow data provided, and copies of all records used to derive the flow data used in the applicant’s engineering calculations;
(vi) Detailed descriptions of any proposed studies and the proposed methodologies to be employed; and
(vii) Any statement required by § 4.301(a) of this chapter.
(3)(i) A potential applicant for an exemption, a new or subsequent license for which the deadline for filing a notification of intent to seek a license is prior to July 23, 2005 and which elects to commence pre-filing consultation under this part, or a new or subsequent license for which the deadline for filing a notification of intent to seek a license is on or after July 23, 2005 and which receives Commission approval to use the license application procedures of this part must:
(A) Hold a joint meeting, including an opportunity for a site visit, with all pertinent agencies, Indian tribes and members of the public to review the information and to discuss the data and studies to be provided by the potential applicant as part of the consultation process; and
(B) Consult with the resource agencies, Indian tribes and members of the public on the scheduling of the joint meeting; and provide each resource agency, Indian tribe, member of the public, and the Commission with written notice of the time and place of the joint meeting and a written agenda of the issues to be discussed at the meeting at least 15 days in advance.
(ii) The joint meeting must be held no earlier than 30 days, and no later than 60 days from, as applicable:
(A) The date of the potential applicant’s letter transmitting the information required by paragraph (b)(2) of this section, in the case of a potential exemption applicant or a potential license applicant that commences pre-filing consultation under this part prior to July 23, 2005; or
(B) The date of the Commission’s approval of the potential license applicant’s request to use the license application procedures of this part pursuant to the provisions of part 5, in the case of a potential license applicant for which the deadline for filing a notification of intent to seek a license is on or after July 23, 2005.
(4) Members of the public are invited to attend the joint meeting held pursuant to paragraph (b)(3) of this section. Members of the public attending the meeting are entitled to participate fully in the meeting and to express their views regarding resource issues that should be addressed in any application for a new license that may be filed by the potential applicant. Attendance of the public at any site visit held pursuant to paragraph (b)(3) of this section shall be at the discretion of the potential applicant. The potential applicant must make either audio recordings or written transcripts of the joint meeting, and must upon request promptly provide copies of these recordings or transcripts to the Commission and any resource agency and Indian tribe.
(5) Unless otherwise extended by the Director of Office of Energy Projects pursuant to paragraph (b)(6) of this section, not later than 60 days after the joint meeting held under paragraph (b)(3) of this section each interested resource agency, and Indian tribe, and member of the public must provide a potential applicant with written comments:
(i) Identifying its determination of necessary studies to be performed or information to be provided by the potential applicant;
(ii) Identifying the basis for its determination;
(iii) Discussing its understanding of the resource issues and its goals objectives for these resources;
(iv) Explaining why each study methodology recommended by it is more appropriate than any other available methodology alternatives, including those identified by the potential applicant pursuant to paragraph (b)(2)(vi) of this section;
(v) Documenting that the use of each study methodology recommended by it is a generally accepted practice; and
(vi) Explaining how the studies and information requested will be useful to the agency, Indian tribe, or member of the public in furthering its resource goals and objectives.
(6)(i) If a potential applicant and a resource agency, Indian tribe, or member of the public disagree as to any matter arising during the first stage of consultation or as to the need to conduct a study or gather information referenced in paragraph (c)(2) of this section, the potential applicant or resource agency, or Indian tribe, or member of the public may refer the dispute in writing to the Director of the Office of Energy Projects (Director) for resolution.
(ii) The entity referring the dispute must serve a copy of its written request for resolution on the disagreeing party at the time the request is submitted to the Director. The disagreeing party may submit to the Director a written response to the referral within 15 days of the referral’s submittal to the Director.
(iii) Written referrals to the Director and written responses thereto pursuant to paragraphs (b)(6)(i) or (b)(6)(ii) of this section must be filed with the Secretary of the Commission in accordance with the Commission’s Rules of Practice and Procedure, and must indicate that they are for the attention of the Director of the Office of Energy Projects pursuant to § 16.8(b)(6).
(iv) The Director will resolve disputes by an order directing the potential applicant to gather such information or conduct such study or studies as, in the Director’s view, is reasonable and necessary.
(v) If a resource agency, Indian tribe, or member of the public fails to refer a dispute regarding a request for a potential applicant to obtain information or conduct studies (other than a dispute regarding the information specified in paragraph (b)(1) or (b)(2) of this section, as applicable), the Commission will not entertain the dispute following the filing of the license application.
(vi) If a potential applicant fails to obtain information or conduct a study as required by the Director pursuant to paragraph (b)(6)(iv) of this section, its application will be considered deficient.
(7) Unless otherwise extended by the Director pursuant to paragraph (b)(6) of this section, the first stage of consultation ends when all participating agencies, Indian tribes, and members of the public provide the written comments required under paragraph (b)(5) of this section or 60 days after the joint meeting held under paragraph (b)(3) of this section, whichever occurs first.
(c) Second stage of consultation. (1) Unless determined otherwise by the Director of the Office of Energy Projects pursuant to paragraph (b)(6) of this section, a potential applicant must complete all reasonable and necessary studies and obtain all reasonable and necessary information requested by resource agencies and Indian tribes under paragraph (b):
(i) Prior to filing the application, if the results:
(A) Would influence the financial (e.g., instream flow study) or technical feasibility of the project (e.g., study of potential mass soil movement); or
(B) Are needed to determine the design or location of project features, reasonable alternatives to the project, the impact of the project on important natural or cultural resources (e.g., resource surveys), suitable mitigation or enhancement measures, or to minimize impact on significant resources (e.g., wild and scenic river, anadromous fish, endangered species, caribou migration routes);
(ii) After filing the application but before license issuance, if the applicant complied with the provisions of paragraph (b)(1) or (b)(2) of this section, as applicable, no later than four years prior to the expiration date of the existing license and the results:
(A) Would be those described in paragraphs (c)(1)(i) (A) or (B) of this section; and
(B) Would take longer to conduct and evaluate than the time between the conclusion of the first stage of consultation and the new license application filing deadline.
(iii) After a new license is issued, if the studies can be conducted or the information obtained only after construction or operation of proposed facilities, would determine the success of protection, mitigation, or enhancement measures (e.g., post-construction monitoring studies), or would be used to refine project operation or modify project facilities.
(2) If, after the end of the first stage of consultation as defined in paragraph (b)(7) of this section, a resource agency, Indian tribe, or member of the public requests that the potential applicant conduct a study or gather information not previously identified and specifies the basis for its request, under paragraphs (b)(5)(i)–(vi) of this section, the potential applicant will promptly initiate the study or gather the information, unless the Director of the Office of Energy Projects determines under paragraph (b)(5) of this section either that the study or information is unreasonable or unnecessary or that use of the methodology requested by a resource agency or Indian tribe for conducting the study is not a generally accepted practice.
(3) (i) The results of studies and information gathering referenced in paragraphs (c)(1)(ii) and (c)(2) of this section will be treated as additional information; and
(ii) Filing and acceptance of an application will not be delayed and an application will not be considered deficient or patently deficient pursuant to § 4.32 (e)(1) or (e)(2) of this chapter merely because the study or information gathering is not complete before the application is filed.
(4) A potential applicant must provide each resource agency and Indian tribe with:
(i) A copy of its draft application that:
(A) Indicates the type of application the potential applicant expects to file with the Commission; and
(B) Responds to any comments and recommendations made by any resource agency or Indian tribe either during the first stage of consultation or under paragraph (c)(2) of this section;
(ii) The results of all studies and information gathering either requested by that resource agency or Indian tribe in the first stage of consultation (or under paragraph (c)(2) of this section if available) or which pertains to resources of interest to that resource agency or Indian tribe and which were identified by the potential applicant pursuant to paragraph (b)(2)(vi) of this section, including a discussion of the results and any proposed protection, mitigation, or enhancement measure; and
(iii) A written request for review and comment.
(5) A resource agency or Indian tribe will have 90 days from the date of the potential applicant’s letter transmitting the paragraph (c)(4) of this section information to it to provide written comments on the information submitted by a potential applicant under paragraph (c)(4) of this section.
(6) If the written comments provided under paragraph (c)(5) of this section indicate that a resource agency or Indian tribe has a substantive disagreement with a potential applicant’s conclusions regarding resource impacts or its proposed protection, mitigation, or enhancement measures, the potential applicant will:
(i) Hold at least one joint meeting with the disagreeing resource agency or Indian tribe and other agencies with similar or related areas of interest, expertise, or responsibility not later than 60 days from the date of the disagreeing agency’s or Indian tribe’s written comments to discuss and to attempt to reach agreement on its plan for environmental protection, mitigation, or enhancement measures; and
(ii) Consult with the disagreeing agency or Indian tribe and other agencies with similar or related areas of interest, expertise, or responsibility on the scheduling of the joint meeting and provide the disagreeing resource agency or Indian tribe, other agencies with similar or related areas of interest, expertise, or responsibility, and the Commission with written notice of the time and place of each meeting and a written agenda of the issues to be discussed at the meeting at least 15 days in advance.
(7) The potential applicant and any disagreeing resource agency or Indian tribe may conclude a joint meeting with a document embodying any agreement among them regarding environmental protection, mitigation, or enhancement measures and any issues that are unresolved.
(8) The potential applicant must describe all disagreements with a resource agency or Indian tribe on technical or environmental protection, mitigation, or enhancement measures in its application, including an explanation of the basis for the applicant’s disagreement with the resource agency or Indian tribe, and must include in its application any document developed pursuant to paragraph (c)(7) of this section.
(9) A potential applicant may file an application with the Commission if:
(i) It has complied with paragraph (c)(4) of this section and no resource agency or Indian tribe has responded with substantive disagreements by the deadline specified in paragraph (c)(5) of this section; or
(ii) It has complied with paragraph (c)(6) of this section if any resource agency or Indian tribe has responded with substantive disagreements.
(10) The second stage of consultation ends:
(i) Ninety days after the submittal of information pursuant to paragraph (c)(4) of this section in cases where no resource agency or Indian tribe has responded with substantive disagreements; or
(ii) At the conclusion of the last joint meeting held pursuant to paragraph (c)(6) of this section in cases where a resource agency or Indian tribe has responded with substantive disagreements.
(d) Third stage of consultation. (1) The third stage of consultation is initiated by the filing of an application for a new license, nonpower license, exemption from licensing, or surrender of license, accompanied by a transmittal letter certifying that at the same time copies of the application are being distributed to the resource agencies, Indian tribes, and other government offices specified in paragraph (d)(2) of this section and § 16.10(f) of this part, if applicable.
(2) As soon as an applicant files such application documents with the Commission, or promptly after receipt in the case of documents described in paragraph (d)(2)(iii) of this section, as the Commission may direct, the applicant must serve on every resource agency and Indian tribe consulted, on other government offices, and, in the case of applications for surrender or nonpower license, any state, municipal, interstate, or Federal agency which is authorized to assume regulatory supervision over the land, waterways, and facilities covered by the application for surrender or nonpower license, copies of:
(i) Its application for a new license, a nonpower license, an exemption from licensing, or a surrender of the project;
(ii) Any deficiency correction, revision, supplement, response to additional information request, or amendment to the application; and
(iii) Any written correspondence from the Commission requesting the correction of deficiencies or the submittal of additional information.
(e) Resource agency or Indian tribe waiver of compliance with consultation requirement. (1) If a resource agency or Indian tribe waives in writing compliance with any requirement of this section, a potential applicant does not have to comply with that requirement as to that agency or Indian tribe.
(2) If a resource agency or Indian tribe fails to timely comply with a provision regarding a requirement of this section, a potential applicant may proceed to the next sequential requirement of this section without waiting for the resource agency or Indian tribe to comply.
(3) The failure of a resource agency or Indian tribe to timely comply with a provision regarding a requirement of this section does not preclude its participation in subsequent stages of the consultation process.
(4) Following July 23, 2003 a potential license applicant engaged in pre-filing consultation under this part may during first stage consultation request to incorporate into pre-filing consultation any element of the integrated license application process provided for in part 5 of this chapter. Any such request must be accompanied by a:
(i) Specific description of how the element of the part 5 license application would fit into the pre-filing consultation process under this part; and
(ii) Demonstration that the potential license applicant has made every reasonable effort to contact all resource agencies, Indian tribes, non-governmental organizations, and others affected by the potential applicant’s proposal, and that a consensus exists in favor of incorporating the specific element of the part 5 process into the pre-filing consultation under this part.
(f) Application requirements documenting consultation and any disagreements with resource agencies or Indian tribes. An applicant must show in Exhibit E of its application that it has met the requirements of paragraphs (b) through (d) of this section, and § 16.8(i), and must include:
(1) Any resource agency’s or Indian tribe’s letters containing comments, recommendations, and proposed terms and conditions;
(2) Any letters from the public containing comments and recommendations;
(3) Notice of any remaining disagreement with a resource agency or Indian tribe on:
(i) The need for a study or the manner in which a study should be conducted and the applicant’s reasons for disagreement, and
(ii) Information on any environmental protection, mitigation, or enhancement measure, including the basis for the applicant’s disagreement with the resource agency or Indian tribe.
(4) Evidence of any waivers under paragraph (e) of this section;
(5) Evidence of all attempts to consult with a resource agency or Indian tribe, copies of related documents showing the attempts, and documents showing the conclusion of the second stage of consultation;
(6) An explanation of how and why the project would, would not, or should not, comply with any relevant comprehensive plan as defined in § 2.19 of this chapter and a description of any relevant resource agency or Indian tribe determination regarding the consistency of the project with any such comprehensive plan;
(7) A description of how the applicant’s proposal addresses the significant resource issues raised by members of the public during the joint meeting held pursuant to paragraph (b)(2) of this section.
(g) Requests for privileged or Critical Energy Infrastructure Information treatment of pre-filing submission. If a potential applicant requests privileged treatment of any information submitted to the Commission during pre-filing consultation (except for the information specified in paragraph (b)(1) of this section), the Commission will treat the request in accordance with the provisions in § 388.112 of this chapter until the date the application is filed with the Commission.
(h) Other meetings. Prior to holding a meeting with a resource agency or Indian tribe, other than a joint meeting pursuant to paragraph (b)(3)(i) or (c)(6)(i) of this section, a potential applicant must provide the Commission and each resource agency or Indian tribe (with an area of interest, expertise, or responsibility similar or related to that of the resource agency or Indian tribe with which the potential applicant is to meet) with written notice of the time and place of each meeting and a written agenda of the issues to be discussed at the meeting at least 15 days in advance.
(i) Public participation. (1) At least 14 days in advance of the joint meeting held pursuant to paragraph (b)(3), the potential applicant must publish notice, at least once, of the purpose, location, and timing of the joint meeting, in a daily or weekly newspaper published in the county or counties in which the existing project or any part thereof or the lands affected thereby are situated. The notice shall include a copy of the written agenda of the issues to be discussed at the joint meeting prepared pursuant to paragraph (b)(3)(ii) of this section.
(2)(i) A potential applicant must make available to the public for inspection and reproduction the information specified in paragraph (b)(1) of this section from the date on which the notice required by paragraph (i)(1) of this section is first published until a final order is issued on the license application.
(ii) The provisions of § 16.7(e) shall govern the form and manner in which the information is to be made available for public inspection and reproduction.
(iii) A potential applicant must make available to the public for inspection at the joint meeting required by paragraph (b)(3) of this section the information specified in paragraph (b)(2) of this section.
(j) Critical Energy Infrastructure Information. If this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 16.7(d)(7).
§ 16.9 Applications for new licenses and nonpower licenses for projects subject to sections 14 and 15 of the Federal Power Act.
(a) Applicability. This section applies to an applicant for a new license or nonpower license for a project subject to sections 14 and 15 of the Federal Power Act.
(b) Filing requirement. (1) An applicant for a license under this section must file its application at least 24 months before the existing license expires.
(2) An application for a license under this section must meet the requirements of § 4.32 (except that the Director of the Office of Energy Projects may provide more than 90 days in which to correct deficiencies in applications) and, as appropriate, §§ 4.41, 4.51, or 4.61 of this chapter.
(3) The requirements of § 4.35 of this chapter do not apply to an application under this section, except that the Commission will reissue a public notice of the application in accordance with the provisions of § 16.9(d)(1) if an amendment described in § 4.35(f) of this chapter is filed.
(4) If the Commission rejects or dismisses an application pursuant to the provisions of § 4.32 of this chapter, the application may not be refiled after the new license application filing deadline specified in § 16.9(b)(1).
(c) Final amendments. All amendments to an application, including the final amendment, must be filed with the Commission and served on all competing applicants no later than the date specified in the notice issued under paragraph (d)(2).
(d) Commission notice. (1) Upon acceptance of an application for a new license or a nonpower license, the Commission will give notice of the application and of the dates for comment, intervention, and protests by:
(i) Publishing notice in the
(ii) Publishing notice once every week for four weeks in a daily or weekly newspaper published in the county or counties in which the project or any part thereof or the lands affected thereby are situated; and
(iii) Notifying appropriate Federal, state, and interstate resource agencies, Indian tribes, and non-governmental organizations, by electronic means if practical, otherwise by mail.
(2) Within 60 days after the new license application filing deadline, the Commission will issue a notice on the processing deadlines established under § 4.32 of this chapter, estimated dates for further processing deadlines under § 4.32 of this chapter, deadlines for complying with the provisions of § 4.36(d)(2) (ii) and (iii) of this chapter in cases where competing applications are filed, and the date for final amendments and will:
(i) Publish the notice in the
(ii) Provide the notice to appropriate Federal, state, and interstate resource agencies and Indian tribes, by electronic means if practical, otherwise by mail; and
(iii) Serve the notice on all parties to the proceedings pursuant to § 385.2010 of this chapter.
(3) Where two or more mutually exclusive competing applications have been filed for the same project, the final amendment date and deadlines for complying with the provisions of § 4.36(d)(2) (ii) and (iii) of this chapter established pursuant to the notice issued under paragraph (d)(2) of this section will be the same for all such applications.
(4) The provisions of § 4.36(d)(2)(i) of this chapter will not be applicable to applications filed pursuant to this section.
§ 16.10 Information to be provided by an applicant for new license: Filing requirements.
(a) Information to be supplied by all applicants. All applicants for a new license under this part must file the following information with the Commission:
(1) A discussion of the plans and ability of the applicant to operate and maintain the project in a manner most likely to provide efficient and reliable electric service, including efforts and plans to:
(i) Increase capacity or generation at the project;
(ii) Coordinate the operation of the project with any upstream or downstream water resource projects; and
(iii) Coordinate the operation of the project with the applicant’s or other electrical systems to minimize the cost of production.
(2) A discussion of the need of the applicant over the short and long term for the electricity generated by the project, including:
(i) The reasonable costs and reasonable availability of alternative sources of power that would be needed by the applicant or its customers, including wholesale customers, if the applicant is not granted a license for the project;
(ii) A discussion of the increase in fuel, capital, and any other costs that would be incurred by the applicant or its customers to purchase or generate power necessary to replace the output of the licensed project, if the applicant is not granted a license for the project;
(iii) The effect of each alternative source of power on:
(A) The applicant’s customers, including wholesale customers;
(B) The applicant’s operating and load characteristics; and
(C) The communities served or to be served, including any reallocation of costs associated with the transfer of a license from the existing licensee.
(3) The following data showing need and the reasonable cost and availability of alternative sources of power:
(i) The average annual cost of the power produced by the project, including the basis for that calculation;
(ii) The projected resources required by the applicant to meet the applicant’s capacity and energy requirements over the short and long term including:
(A) Energy and capacity resources, including the contributions from the applicant’s generation, purchases, and load modification measures (such as conservation, if considered as a resource), as separate components of the total resources required;
(B) A resource analysis, including a statement of system reserve margins to be maintained for energy and capacity; and
(C) If load management measures are not viewed as resources, the effects of such measures on the projected capacity and energy requirements indicated separately;
(iii) For alternative sources of power, including generation of additional power at existing facilities, restarting deactivated units, the purchase of power off-system, the construction or purchase and operation of a new power plant, and load management measures such as conservation:
(A) The total annual cost of each alternative source of power to replace project power;
(B) The basis for the determination of projected annual cost; and
(C) A discussion of the relative merits of each alternative, including the issues of the period of availability and dependability of purchased power, average life of alternatives, relative equivalent availability of generating alternatives, and relative impacts on the applicant’s power system reliability and other system operating characteristics; and
(iv) The effect on the direct providers (and their immediate customers) of alternate sources of power.
(4) If an applicant uses power for its own industrial facility and related operations, the effect of obtaining or losing electricity from the project on the operation and efficiency of such facility or related operations, its workers, and the related community.
(5) If an applicant is an Indian tribe applying for a license for a project located on the tribal reservation, a statement of the need of such tribe for electricity generated by the project to foster the purposes of the reservation.
(6) A comparison of the impact on the operations and planning of the applicant’s transmission system of receiving or not receiving the project license, including:
(i) An analysis of the effects of any resulting redistribution of power flows on line loading (with respect to applicable thermal, voltage, or stability limits), line losses, and necessary new construction of transmission facilities or upgrading of existing facilities, together with the cost impact of these effects;
(ii) An analysis of the advantages that the applicant’s transmission system would provide in the distribution of the project’s power; and
(iii) Detailed single-line diagrams, including existing system facilities identified by name and circuit number, that show system transmission elements in relation to the project and other principal interconnected system elements. Power flow and loss data that represent system operating conditions may be appended if applicants believe such data would be useful to show that the operating impacts described would be beneficial.
(7) If the applicant has plans to modify existing project facilities or operations, a statement of the need for, or usefulness of, the modifications, including at least a reconnaissance-level study of the effect and projected costs of the proposed plans and any alternate plans, which in conjunction with other developments in the area would conform with a comprehensive plan for improving or developing the waterway and for other beneficial public uses as defined in section 10(a)(1) of the Federal Power Act.
(8) If the applicant has no plans to modify existing project facilities or operations, at least a reconnaissance-level study to show that the project facilities or operations in conjunction with other developments in the area would conform with a comprehensive plan for improving or developing the waterway and for other beneficial public uses as defined in section 10(a)(1) of the Federal Power Act.
(9) A statement describing the applicant’s financial and personnel resources to meet its obligations under a new license, including specific information to demonstrate that the applicant’s personnel are adequate in number and training to operate and maintain the project in accordance with the provisions of the license.
(10) If an applicant proposes to expand the project to encompass additional lands, a statement that the applicant has notified, by certified mail, property owners on the additional lands to be encompassed by the project and governmental agencies and subdivisions likely to be interested in or affected by the proposed expansion.
(11) The applicant’s electricity consumption efficiency improvement program, as defined under section 10(a)(2)(C) of the Federal Power Act, including:
(i) A statement of the applicant’s record of encouraging or assisting its customers to conserve electricity and a description of its plans and capabilities for promoting electricity conservation by its customers; and
(ii) A statement describing the compliance of the applicant’s energy conservation programs with any applicable regulatory requirements.
(12) The names and mailing addresses of every Indian tribe with land on which any part of the proposed project would be located or which the applicant reasonably believes would otherwise be affected by the proposed project.
(b) Information to be provided by an applicant who is an existing licensee. An existing licensee that applies for a new license must provide:
(1) The information specified in paragraph (a).
(2) A statement of measures taken or planned by the licensee to ensure safe management, operation, and maintenance of the project, including:
(i) A description of existing and planned operation of the project during flood conditions;
(ii) A discussion of any warning devices used to ensure downstream public safety;
(iii) A discussion of any proposed changes to the operation of the project or downstream development that might affect the existing Emergency Action Plan, as described in subpart C of part 12 of this chapter, on file with the Commission;
(iv) A description of existing and planned monitoring devices to detect structural movement or stress, seepage, uplift, equipment failure, or water conduit failure, including a description of the maintenance and monitoring programs used or planned in conjunction with the devices; and
(v) A discussion of the project’s employee safety and public safety record, including the number of lost-time accidents involving employees and the record of injury or death to the public within the project boundary.
(3) A description of the current operation of the project, including any constraints that might affect the manner in which the project is operated.
(4) A discussion of the history of the project and record of programs to upgrade the operation and maintenance of the project.
(5) A summary of any generation lost at the project over the last five years because of unscheduled outages, including the cause, duration, and corrective action taken.
(6) A discussion of the licensee’s record of compliance with the terms and conditions of the existing license, including a list of all incidents of noncompliance, their disposition, and any documentation relating to each incident.
(7) A discussion of any actions taken by the existing licensee related to the project which affect the public.
(8) A summary of the ownership and operating expenses that would be reduced if the project license were transferred from the existing licensee.
(9) A statement of annual fees paid under Part I of the Federal Power Act for the use of any Federal or Indian lands included within the project boundary.
(c) Information to be provided by an applicant who is not an existing licensee. An applicant that is not an existing licensee must provide:
(1) The information specified in paragraph (a).
(2) A statement of the applicant’s plans to manage, operate, and maintain the project safely, including:
(i) A description of the differences between the operation and maintenance procedures planned by the applicant and the operation and maintenance procedures of the existing licensee;
(ii) A discussion of any measures proposed by the applicant to implement the existing licensee’s Emergency Action Plan, as described in subpart C of part 12 of this chapter, and any proposed changes;
(iii) A description of the applicant’s plans to continue safety monitoring of existing project instrumentation and any proposed changes; and
(iv) A statement indicating whether or not the applicant is requesting the licensee to provide transmission services under section 15(d) of the Federal Power Act.
(d) Inclusion in application. The information required to be provided by this section must be included in the application as a separate exhibit labeled “Exhibit H.”
§ 16.11 Nonpower licenses.
(a) Information to be provided by all applicants for nonpower licenses. (1) An applicant for a nonpower license must provide the following information in its application:
(i) The information required by §§ 4.51 or 4.61 of this chapter, as appropriate;
(ii) A description of the nonpower purpose for which the project is to be used;
(iii) A showing of how the nonpower use conforms with a comprehensive plan for improving or developing the waterway and for other beneficial public uses as defined in section 10(a)(1) of the Federal Power Act;
(iv) A statement of any impact that converting the project to nonpower use may have on the power supply of the system served by the project, including the additional cost of power if an alternative generating source is used to offset the loss of the project’s generation;
(v) A statement identifying the state, municipal, interstate, or Federal agency, which is authorized and willing to assume regulatory supervision over the land, waterways, and facilities to be included within the nonpower project;
(vi) Copies of written communication and documentation of oral communication that the applicant may have had with any jurisdictional agency or governmental unit authorized and willing to assume regulatory control over the project and the point of time at which the agency or unit would assume regulatory control;
(vii) A statement that demonstrates that the applicant has complied with the requirements of § 16.8(d)(2);
(viii) A proposal that shows the manner in which the applicant plans to remove or otherwise dispose of the project’s power facilities;
(ix) Any proposal to repair or rehabilitate any nonpower facilities;
(x) A statement of the costs associated with removing the project’s power facilities and with any necessary restoration and rehabilitation work; and
(xi) A statement that demonstrates that the applicant has resources to ensure the integrity and safety of the remaining project facilities and to maintain the nonpower functions of the project until the governmental unit or agency assumes regulatory control over the project.
(2) [Reserved]
(b) Termination of a proceeding for a nonpower license. The Commission may deny an application for a nonpower license and turn the project over to any agency that has jurisdiction over the land or reservations if:
(1) An existing project is located on public lands or reservations of the United States;
(2) Neither the existing licensee nor any other entity has filed an application for a new license for the project;
(3) No one has filed a recommendation to take over the project pursuant to § 16.14; and
(4) The agency that has jurisdiction over the land or reservations demonstrates that it is able and willing to:
(i) Accept immediate responsibility for the nonpower use of the project; and.
(ii) Pay the existing licensee for its net investment in the project and any severance damages specified in section 14(a) of the Federal Power Act.
(c) Termination of nonpower license. A nonpower license will be terminated by Commission order when the Commission determines that a state, municipal, interstate, or Federal agency has jurisdiction over, and is willing to assume regulatory responsibility for, the land, waterways, and facilities included within the nonpower license.
§ 16.12 Application for exemption from licensing by a licensee whose license is subject to sections 14 and 15 of the Federal Power Act.
(a) An existing licensee whose license is subject to sections 14 and 15 of the Federal Power Act may apply for an exemption for the project.
(b) An applicant for an exemption under paragraph (a) must meet the requirements of subpart K or subpart J of part 4 of this chapter, and §§ 16.5, 16.6, 16.7, 16.8, 16.9(b) (1), (2) (except the requirement to comply with §§ 4.41, 4.51, or 4.61 of this chapter), 16.9(c), 16.10(a), 16.10(b), and 16.10(d).
(c) The Commission will process an application by an existing licensee for an exemption for the project in accordance with §§ 16.9(b)(3), 16.9(b)(4), and 16.9(d).
(d) If a license application is filed in competition with an application for exemption filed by the existing licensee, the Commission will decide among the competing applications in accordance with the standards of § 16.13 and not in accordance with the provisions of § 4.37(d)(2) of this chapter.
§ 16.13 Standards and factors for issuing a new license.
(a) In determining whether a final proposal for a new license under section 15 of the Federal Power Act is best adapted to serve the public interest, the Commission will consider the factors enumerated in sections 15(a)(2) and (a)(3) of the Federal Power Act.
(b) If there are only insignificant differences between the final applications of an existing licensee and a competing applicant after consideration of the factors enumerated in section 15(a)(2) of the Federal Power Act, the Commission will determine which applicant will receive the license after considering:
(1) The existing licensee’s record of compliance with the terms and conditions of the existing license; and
(2) The actions taken by the existing licensee related to the project which affect the public.
(c) An existing licensee that files an application for a new license in conjunction with an entity or entities that are not currently licensees of all or part of the project will not be considered an existing licensee for the purpose of the insignificant differences provision of section 15(a)(2) of the Federal Power Act.
Subpart C—Takeover Provisions for Projects Subject to Sections 14 and 15 of the Federal Power Act
§ 16.14 Departmental recommendation for takeover.
(a) A Federal department or agency may file a recommendation that the United States exercise its right to take over a hydroelectric power project with a license that is subject to sections 14 and 15 of the Federal Power Act. The recommendation must:
(1) Be filed no earlier than five years before the license expires and no later than the end of the comment period specified by the Commission in:
(i) A notice of application for a new license, a nonpower license, or an exemption for the project; or
(ii) A notice of an amendment to an application for a new license, a nonpower license, or an exemption;
(2) Be filed in accordance with the formal requirements for filings in subpart T of part 385 of the Commission’s regulations and be served on each relevant Federal and state resource agency, all applicants for new license, nonpower license or exemption, and any other party to the proceeding;
(3) Specify the project works that would be taken over by the United States;
(4) Describe the proposed Federal operation of the project, including any plans for its redevelopment, and discuss the manner in which takeover would serve the public interest as fully as non-Federal development and operation;
(5) State whether the agency intends to undertake the operation of the project; and
(6) Include the information required by §§ 4.41, 4.51, or 4.61 of this chapter, as appropriate.
(b) A department or agency that files a takeover recommendation becomes a party to the proceeding.
(c) An applicant or potential applicant for a new license, a nonpower license, or an exemption that involves a takeover recommendation may file a reply to the recommendation, within 120 days from the date the takeover recommendation is filed with the Commission. The reply must be filed with the Commission in accordance with part 385 of the Commission’s regulations and a copy of such a reply must be served on the agency recommending the takeover and on any other party to the proceeding.
§ 16.15 Commission recommendation to Congress.
Upon receipt of a recommendation from any Federal department or agency, a proposal of any party, or on the Commission’s own motion, and after notice and opportunity for hearing, the Commission may determine that a project may be taken over by the United States, issue an order on its findings and recommendations, and forward a copy to Congress.
§ 16.16 Motion for stay by Federal department or agency.
(a) Within 30 days of the date on which an order granting a new license or exemption is issued, a Federal department or agency that has filed a takeover recommendation under § 16.14 may file a motion under § 385.212 of this chapter to request a stay of the effective date of the license or exemption order.
(b)(1) If a Federal department or agency files a motion under paragraph (a), the Commission will stay the effective date of the order issuing the license or exemption for two years.
(2) The stay issued under paragraph (b)(1) of this section may be terminated either:
(i) Upon motion of the department or agency that requested the stay; or
(ii) By action of Congress.
(c) The Commission will notify Congress if:
(1) An order granting a stay under paragraph (b)(1) of this section is issued;
(2) Any license or exemption order becomes effective by reason of the termination of a stay; or
(3) Any license or exemption order becomes effective by reason of the expiration of a stay.
(d) The Commission’s order granting the license or exemption will automatically become effective:
(1) Thirty days after issuance, if no request for stay is filed, provided that no appeal or rehearing is filed;
(2) When the period of the stay expires; or
(3) When the stay is terminated under paragraph (b)(2) of this section.
If Congress authorizes the takeover of a hydroelectric power project as provided under section 14 of the Federal Power Act:
(a) The Commission or the Director of the Office of Energy Projects will notify the existing licensee in writing of the authorization at least two years before the takeover occurs; and
(b) The licensee must present any claim for compensation to the Commission:
(1) Within six months of issuance of the notice of takeover; and
(2) As provided in section 14 of the Federal Power Act.
Subpart D—Annual Licenses for Projects Subject to Sections 14 and 15 of the Federal Power Act
§ 16.18 Annual licenses for projects subject to sections 14 and 15 of the Federal Power Act.
(a) This section applies to projects with licenses subject to sections 14 and 15 of the Federal Power Act.
(b) The Commission will issue an annual license to an existing licensee under the terms and conditions of the existing license upon expiration of its existing license to allow:
(1) The licensee to continue to operate the project while the Commission reviews any applications for a new license, a nonpower license, an exemption, or a surrender;
(2) The orderly removal of a project, if the United States does not take over a project and no new power or nonpower license or exemption will be issued; or
(3) The orderly transfer of a project to:
(i) The United States, if takeover is elected; or
(ii) A new licensee, if a new power or nonpower license is issued to that licensee.
(c) An annual license issued under this section will be considered renewed automatically without further order of the Commission, unless the Commission orders otherwise.
(d) In issuing an annual license, the Commission may incorporate additional or revised interim conditions if necessary and practical to limit adverse impacts on the environment.
Subpart E—Projects With Minor and Minor Part Licenses Not Subject to Sections 14 and 15 of the Federal Power Act
§ 16.19 Procedures for an existing licensee of a minor hydroelectric power project or of a minor part of a hydroelectric power project with a license not subject to sections 14 and 15 of the Federal Power Act.
(a) Applicability. This section applies to an existing licensee of a minor hydroelectric power project or of a minor part of a hydroelectric power project that is not subject to sections 14 and 15 of the Federal Power Act.
(b) Notification procedures. (1) An existing licensee with a minor license or a license for a minor part of a hydroelectric project must file a notice of intent pursuant to § 16.6(b).
(2) If the license of an existing licensee expires on or after October 17, 1994, the licensee must notify the Commission as required under § 16.6(b) at least five years before the expiration of the existing license.
(3) The Commission will give notice of a licensee’s intent to file or not to file an application for a subsequent license in accordance with § 16.6(d).
(c) Requirement to make information available. (1) Except as provided in paragraph (c)(2) of this section, a licensee must make the information described in § 16.7 available to the public for inspection and reproduction when it gives notice to the Commission under paragraph (b).
(2) The requirement of paragraph (c)(1) of this section does not apply if an applicant filed an application for a subsequent license on or before July 3, 1989.
§ 16.20 Applications for subsequent license for a project with an expiring license not subject to sections 14 and 15 of the Federal Power Act.
(a) Applicability. This section applies to an application for subsequent license for a project with an expiring license that is not subject to sections 14 and 15 of the Federal Power Act.
(b) Licensing proceeding. (1) An applicant for a license for a project with an expiring license not subject to sections 14 and 15 of the Federal Power Act must file its application under Part I of the Federal Power Act.
(2) The provisions of section 7(a) of the Federal Power Act do not apply to licensing proceedings involving an application described in paragraph (b)(1).
(c) Requirement to file. An applicant must file an application for subsequent license at least 24 months before the expiration of the existing license.
(d) Requirements for and processing of applications. An application for subsequent license must meet the requirements of, and will be processed in accordance with, §§ 16.5, 16.8, 16.9(b)(2), 16.9(b)(3), 16.9(b)(4), 16.9(c), and 16.9(d).
(e) Applicant notice. An applicant for subsequent license or exemption that proposes to expand an existing project to encompass additional lands must include in its application a statement that the applicant has notified, by certified mail, property owners on the additional lands to be encompassed by the project and governmental agencies and subdivisions likely to be interested in or affected by the proposed expansion.
§ 16.21 Operation of projects with a minor or minor part license not subject to sections 14 and 15 of the Federal Power Act after expiration of a license.
(a) A licensee of a minor or minor part project not subject to sections 14 and 15 of the Federal Power Act that has filed an application for a subsequent license or exemption may continue to operate the project in accordance with the terms and conditions of the license after the minor or minor part license expires until the Commission acts on its application.
(b) If the licensee of a minor or minor part project not subject to sections 14 and 15 of the Federal Power Act has not filed an application for a subsequent license or exemption, the Commission may issue an order requiring the licensee to continue to operate its project in accordance with the terms and conditions of the license until the Commission either acts on any applications for subsequent license timely filed by another entity or takes action pursuant to §§ 16.25 or 16.26.
§ 16.22 Application for an exemption by a licensee with a minor or minor part license for a project not subject to sections 14 and 15 of the Federal Power Act.
(a) Applicability. This section applies to an existing licensee with a license for a project not subject to sections 14 and 15 of the Federal Power Act.
(b) Information requirements. An applicant for an exemption must meet the requirements of, and will be processed in accordance with, subpart K or subpart J of part 4 of this chapter, and §§ 16.5, 16.8, 16.9(b)(2) (except the requirement to comply with §§ 4.41, 4.51, or 4.61 of this chapter), §§ 16.9(b)(3), 16.9(b)(4), 16.9(c), and 16.9(d).
(c) Standard of comparison. If an application for subsequent license is filed in competition with an application for exemption by an existing licensee, the Commission will decide among competing applications in accordance with the standards of § 16.13 and not in accordance with the provisions of § 4.37(d)(2) of this chapter.
Subpart F—Procedural Matters
§ 16.23 Failure to file timely notices of intent.
(a) An existing licensee of a water power project with a license subject to sections 14 and 15 of the Federal Power Act that fails to file a notice of intent pursuant to § 16.6(b) by the deadlines specified in § l6.6(c) shall be deemed to have filed a notice of intent indicating that it does not intend to file an application for new license, nonpower license, or exemption.
(b) An existing licensee of a water power project with a license not subject to sections 14 and 15 of the Federal Power Act that fails to file a notice of intent pursuant to § 16.6(b) by the deadlines specified in § 16.20(c) shall be deemed to have filed a notice of intent indicating that it does not intend to file an application for subsequent license or exemption.
§ 16.24 Prohibitions against filing applications for new license, nonpower license, exemption, or subsequent license.
(a) Licenses subject to sections 14 and 15 of the Federal Power Act. (1) An existing licensee with a license subject to sections 14 and 15 of the Federal Power Act that informs the Commission that it does not intend to file an application for new license, nonpower license, or exemption for a project, as required by § 16.6, may not file an application for new license, nonpower license, or exemption for the project, either individually or in conjunction with an entity or entities that are not currently licensees of the project.
(2) An existing licensee with a license subject to sections 14 and 15 of the Federal Power Act that fails to file an application for new license, nonpower license, or exemption for a project at least 24 months before the expiration of the existing license for the project may not file an application for new license, nonpower license, or exemption for the project, either individually or in conjunction with an entity or entities that are not currently licensees of the project.
(b) Licenses not subject to sections 14 and 15 of the Federal Power Act. (1) An existing licensee with a license not subject to sections 14 and 15 of the Federal Power Act that informs the Commission that it does not intend to file an application for subsequent license or exemption for a project, as required by § 16.6, may not file an application for subsequent license or exemption for the project, either individually or in conjunction with an entity or entities that are not currently licensees of the project.
(2) An existing licensee with a license not subject to sections 14 and 15 of the Federal Power Act that fails to file an application for subsequent license or exemption for a project by the deadlines specified in § 16.20(c) may not file an application for subsequent license or exemption for the project, either individually or in conjunction with an entity or entities that are not currently licensees of the project.
§ 16.25 Disposition of a project for which no timely application is filed following a notice of intent to file.
(a) If an existing licensee that indicates in the notice filed pursuant to § 16.6 that it will file an application for new license, nonpower license, subsequent license, or an exemption does not file its application individually or in conjunction with an entity or entities that are not currently licensees of the project at least 24 months before its existing license expires in the case of licenses subject to sections 14 and 15 of the Federal Power Act, or by the deadlines specified in § 16.20(c) in the case of licenses not subject to sections 14 and 15 of the Federal Power Act, and no other applicant files an application within the appropriate time or all pending applications filed before the applicable filing deadline are subsequently rejected or dismissed pursuant to § 4.32 of this chapter, the Commission will publish in the
(b) A potential applicant that files a notice of intent within 90 days from the date of the public notice issued pursuant to paragraph (a):
(1) May apply for a license under Part I of the Federal Power Act and part 4 of this chapter (except § 4.38) within 18 months of the date on which it files its notice; and
(2) Must comply with the requirements of § 16.8 and, if the project would have a total installed capacity of over 2,000 horsepower, § 16.10.
(c) The existing licensee must file a schedule for the filing of a surrender application for the project, for the approval of the Director of the Office of Energy Projects, 90 days:
(1) After the due date established for any notice of intent issued under paragraph (a), if no notices of intent were received; or
(2) After the due date for any application filed under paragraph (b)(1), if no application has been filed.
(d) Any application for surrender must be filed according to the approved schedule, must comply with the requirements of § 16.8 and part 6 of this chapter, and must provide for disposition of any project facility.
§ 16.26 Disposition of a project for which no timely application is filed following a notice of intent not to file.
(a) If an existing licensee indicates in the notice filed pursuant to § 16.6 that it will not file an application for new license, nonpower license, subsequent license, or exemption and no other applicant files an application at least 24 months before the existing license expires in the case of licenses subject to sections 14 and 15 of the Federal Power Act, or by the deadlines specified in § 16.20(c) in the case of licenses not subject to sections 14 and 15 of the Federal Power Act, the Director of the Office of Energy Projects will provide the existing licensee with written notice that no timely applications for the project have been filed.
(b) The existing licensee, within 90 days from the date of the written notice provided in paragraph (a), must file a schedule for the filing of a surrender application for the project for the approval of the Director of the Office of Energy Projects.
(c) Any application for surrender must be filed according to the approved schedule, must comply with the requirements of § 16.8 and part 6 of this chapter, and must provide for disposition of any project facility.
PART 20—AUTHORIZATION OF THE ISSUANCE OF SECURITIES BY LICENSEES AND COMPANIES SUBJECT TO SECTIONS 19 AND 20 OF THE FEDERAL POWER ACT
§ 20.1 Applicability.
(a) Without special proceeding for regulation. Every security issue within the scope of the jurisdiction conferred upon the Commission by sections 19 and 20 of the Federal Power Act shall be subject to the provisions of § 20.2, except a security issue by a person organized and operating in a State under the laws of which its security issues are regulated by a State commission, or by any one described in subsection 201(f) of the act. No other security issue within the scope of sections 19 and 20 shall be subject to § 20.2 except as provided in paragraph (b) of this section.
(b) Reservation of possibility of regulation in other cases. Not later than 10 days prior to any proposed security issuance which is within the scope of section 19 or section 20 of the act, but excepted by paragraph (a) of this section, any person or state entitled to do so under section 19 or section 20, may file a complaint or request in accordance with the applicable rules of the Commission, or the Commission upon its own motion may by order initiate a proceeding, raising the question whether issuance of such security should be subjected by Commission order to the provisions of § 20.2. After notice of such filing or order, and until such request or complaint is denied or dismissed or the proceeding initiated by such order is terminated without subjecting the issuance of the security to the provisions of § 20.2, the security in question shall not be issued except it be issued subject to and in compliance with § 20.2.
§ 20.2 Regulation of issuance of securities.
The licensee or other person issuing or proposing to issue any security subjected to this section by or pursuant to § 20.1, shall be subject to and shall comply with the same requirements as the Commission would administer to it if it were a public utility issuing the security within the meaning and subject to the requirements of section 204 of the Act and part 34 of this subchapter.
For applications for authorization of the issuance of securities or the assumption of liabilities, see part 34 of this chapter.
PART 24—DECLARATION OF INTENTION
§ 24.1 Filing.
A declaration of intention under the provisions of section 23(b) of the Act shall be filed with the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov. The declaration shall give the name and post office address of the person to whom correspondence in regard to it shall be addressed, and shall be accompanied by:
(a) A brief description of the proposed project and its purposes, including such data as maximum height of the dams, a storage capacity curve of the reservoir or reservoirs showing the maximum, average, and minimum operating pool levels, the initial and ultimate installed capacity of the project, the rated horsepower and head on the turbines, and a curve of turbine discharge versus output at average and minimum operating heads.
(b)(1) A general map (one tracing and three prints) of any convenient size and scale, showing the stream or streams to be utilized and the approximate location and the general plan of the project.
(2) Also a detailed map of the proposed project area showing all Federal lands, and lands owned by States, if any, occupied by the project.
(3) A profile of the river within the vicinity of the project showing the location of the proposed project and any existing improvements in the river.
(4) A duration curve and hydrograph for the natural and proposed regulated flows at the dam site. Furnish references to the published stream flow records used and submit copies of any unpublished records used in preparation of these curves.
(c) (1) A definite statement of the proposed method of utilizing storage or pondage seasonally, weekly and daily, during periods of low and normal flows after the plant is in operation and the system load has grown to the extent that the capacity of the plant is required to meet the load. For example, furnish:
(i) Hydrographs covering a 10–day low water period showing the natural flow of the stream and the effect thereon caused by operations of the proposed power plant:
(ii) Similar hydrographs covering a 10–day period during which the discharge of the stream approximates average recorded yearly flow, and
(iii) Similar hydrographs covering a low water year using average monthly flows.
(2) A system load curve, both daily and monthly, and the position on the load curve that the proposed project would have occupied had it been in operation.
(3) A proposed annual rule of operation for the storage reservoir or reservoirs.
PART 25—APPLICATION FOR VACATION OF WITHDRAWAL AND FOR DETERMINATION PERMITTING RESTORATION TO ENTRY
§ 25.1 Contents of application.
Any application for vacation of a reservation effected by the filing of an application for preliminary permit or license, or for a determination under the provisions of section 24 of the Act permitting restoration for location, entry, or selection under the public lands laws, or such lands reserved or classified as power sites shall, unless the subject lands are National Forest Lands, be filed with the Bureau of Land Management, Department of the Interior, at the Bureau’s office in Washington, DC or at the appropriate regional or field office of the Bureau. If the lands included in such application are National Forest Lands, the application shall be filed with the U.S. Forest Service, Department of Agriculture at the Forest Service’s office in Washington, DC, or at the appropriate regional office of the U.S. Forest Service. Such application shall contain the following data: (a) Full name of applicant; (b) post-office address; (c) description of land by legal subdivisions, including section, township, range, meridian, county, State, and river basin (both main and tributary) in which the land is located; (d) public land act under which entry is intended to be made if land is restored to entry; (e) the use to which it is proposed to put the land, and a statement as to its suitability for the intended use.
For entries subject to section 24 of the Federal Power Act, see also 43 CFR subpart 2320.
§ 25.2 Hearings.
A hearing upon such an application may be ordered by the Commission in its discretion and shall be in accordance with the provisions of subpart E of part 385 of this chapter.
On April 17, 1922, the Commission made the following general determination:
(a) That where lands of the United States have heretofore been, or hereafter may be, reserved or classified as power sites, such reservation or classification being made solely because such lands are either occupied by power transmission lines or their occupancy and use for such purposes has been applied for or authorized under appropriate laws of the United States, and such lands have otherwise no value for power purposes, and are not occupied in trespass, the Commission determines that the value of such lands so reserved or classified, or so applied for or authorized, will not be injured or destroyed for the purposes of power development by location, entry, or selection under the public land laws, subject to the reservation of section 24 of the Federal Water Power Act (41 Stat. 1075; 16 U.S.C. 818).
(b) That when notice is given to the Secretary of the Interior of reservations made under the provisions of section 24 of the Federal Water Power Act, such notice shall indicate what lands so reserved, if any, may, in accordance with the determination of the preceding paragraph, be declared open to location, entry, or selection, subject to the reservation of said section 24. Second Annual Report, page 128.
On February 16, 1937, the Commission took the following action:
Consent to Establishment of Grazing Districts, Issuance of Grazing Permits, and Leasing for Grazing Purposes Under the Act of June 28, 1934, as Amended, Government Lands Reserved for Power Purposes
Upon request under date of November 2, 1936, by the acting director, Division of Grazing, Department of the Interior, for consent of the Commission, pursuant to the act of June 28, 1934 (48 Stat. 1269), to the establishment of grazing districts and the issuance of grazing permits on lands of the United States withdrawn, classified, or otherwise reserved for power purposes, except in those instances where grazing will interfere with such purposes; and
Upon request under date of December 7, 1936, by the Acting Secretary of the Interior for consent of the Commission, pursuant to the Act of June 28, 1934 (48 Stat. 1269), as amended by the Act of June 26, 1936 (49 Stat. 1976), to the leasing under section 15 of said Act as amended, of isolated tracts of lands of the United States, withdrawn for power purposes:
The Commission upon consideration of the matter finds and determines: That the establishment of grazing districts, the issuance of grazing permits, and the leasing for grazing purposes, under said Act as amended, of lands of the United States theretofore or thereafter withdrawn, classified or otherwise reserved for power purposes, but not including lands embraced within the project area of any power project theretofore licensed by the Commission or otherwise authorized by the United States, will not injure or destroy the value of such lands for the purposes of power development nor otherwise abridge the jurisdiction of the Commission; Provided, That such grazing districts shall be established and such permits and leases for grazing permits issued subject to the following conditions:
(1) That the establishment of the grazing district or the issuance of the grazing permit or lease for grazing purposes shall in no wise diminish or affect the jurisdiction of the Commission at any time to issue permits or licenses pursuant to the provisions of the Federal Power Act (49 Stat. 838; 16 U.S.C., Sup., 791–819); and that the issuance by the Commission of a license shall immediately and automatically terminate such grazing district, permit, or lease for grazing purposes as to all lands within the project area described in such license;
(2) That the establishment of the grazing district or the issuance of the grazing permit or lease for grazing purposes involving lands withdrawn for power purposes shall in no wise diminish or affect the jurisdiction of the Commission at any time to make further determinations that the value of any such lands for the purposes of power development will not be injured or destroyed by location entry or selection, as provided by section 24 of the Act and none of such lands shall be declared open, otherwise than as hereinbefore provided, to location, entry or selection except upon such further determination by the Commission; and any such further determination shall immediately and automatically terminate such grazing district, permit, or lease for grazing purposes as to any lands involved in such further determination.
Now, therefore, the Commission consents to the establishment of such grazing districts and the issuance of grazing permits and leases for grazing purposes of lands of the United States reserved for power purposes subject to the conditions hereinabove set out;
Provided, however, That this determination and consent shall be effective for lands embraced within grazing districts, as of the date of the establishment of such districts, and for isolated tracts of lands leased for grazing purposes, it shall be in effect when such leases are issued, provided that notice thereof is received by this Commission from the Bureau of Land Management, Department of the Interior, within 30 days thereafter, such notice to include full legal description of the lands, withdrawn for power purposes which are involved.
For regulations of the Bureau of Land Management, relating to grazing, see the Index to title 43 Chapter II.
PART 32—INTERCONNECTION OF FACILITIES
Application for an Order Directing the Establishment of Physical Connection of Facilities
§ 32.1 Contents of the application.
Every application under section 202(b) of the Act shall set forth the following information:
(a) The exact legal name of the applicant and of all persons named as parties in the application.
(b) The name, title, and post office address of the person to whom correspondence in regard to the application shall be addressed.
(c) The person named in the application who is a public utility subject to the act.
(d) The State or States in which each electric utility named in the application operates, together with a brief description of the business of and territory, by counties and States, served by such utility.
(e) Description of the proposed interconnection, showing proposed location, capacity and type of construction.
(f) Reasons why the proposed connection, of facilities will be in the public interest.
(g) What steps, if any, have been taken to secure voluntary interconnection under the provisions of section 202(a) of the Act.
§ 32.2 Required exhibits.
There shall be filed with the application and as a part thereof the following exhibits:
Exhibit A. Statement of the estimated capital cost of all facilities required to establish the connection, and the estimated annual cost of operating such facilities.
Exhibit B. A general or key map on a scale not greater than 20 miles to the inch showing, in separate colors, the territory served by each utility, and the location of the facilities used for the generation and transmission of electric energy, indicating on said map the points between which connection may be established most economically.
§ 32.3 Other information.
The Commission may require additional information when it appears to be pertinent in a particular case.
§ 32.4 Filing procedure.
All applications under Part 32 must be filed with the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov.
PART 33—APPLICATIONS UNDER FEDERAL POWER ACT SECTION 203
(a) Applicability. (1) The requirements of this part will apply to any public utility seeking authorization under section 203 of the Federal Power Act to:
(i) Sell, lease, or otherwise dispose of the whole of its facilities subject to the jurisdiction of the Commission, or any part thereof of a value in excess of $10 million;
(ii) Merge or consolidate, directly or indirectly, its facilities subject to the jurisdiction of the Commission, or any part thereof, with the facilities of any other person, or any part thereof, that are subject to the jurisdiction of the Commission and have a value in excess of $10 million, by any means whatsoever;
(iii) Purchase, acquire, or take any security with a value in excess of $10 million of any other public utility; or
(iv) Purchase, lease, or otherwise acquire an existing generation facility:
(A) That has a value in excess of $10 million; and
(B) That is used in whole or in part for wholesale sales in interstate commerce by a public utility.
(2) The requirements of this part shall also apply to any holding company in a holding company system that includes a transmitting utility or an electric utility if such holding company seeks to purchase, acquire, or take any security with a value in excess of $10 million of, or, by any means whatsoever, directly or indirectly, merge or consolidate with, a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility, or an electric utility company, with a value in excess of $10 million.
(b) Definitions. For the purposes of this part, as used in section 203 of the Federal Power Act (16 U.S.C. 824b).
(1) Existing generation facility means a generation facility that is operational at or before the time the section 203 transaction is consummated. “The time the transaction is consummated” means the point in time when the transaction actually closes and control of the facility changes hands. “Operational” means a generation facility for which construction is complete (i.e., it is capable of producing power). The Commission will rebuttably presume that section 203(a) applies to the transfer of any existing generation facility unless the utility can demonstrate with substantial evidence that the generator is used exclusively for retail sales.
(2) Non-utility associate company means any associate company in a holding company system other than a public utility or electric utility company that has wholesale or retail customers served under cost-based regulation.
(3) Value when applied to:
(i) Transmission facilities, generation facilities, transmitting utilities, electric utility companies, and holding companies, means the market value of the facilities or companies for transactions between non-affiliated companies; the Commission will rebuttably presume that the market value is the transaction price. For transactions between affiliated companies, value means original cost undepreciated, as defined in the Commission’s Uniform System of Accounts prescribed for public utilities and licensees in part 101 of this chapter, or original book cost, as applicable;
(ii) Wholesale contracts, means the market value for transactions between non-affiliated companies; the Commission will rebuttably presume that the market value is the transaction price. For transactions between affiliated companies, value means total expected nominal contract revenues over the remaining life of the contract; and
(iii) Securities, means market value for transactions between non-affiliated companies; the Commission will rebuttably presume that the market value is the agreed-upon transaction price. For transactions between affiliated companies, value means market value if the securities are widely traded, in which case the Commission will rebuttably presume that market value is the market price at which the securities are being traded at the time the transaction occurs; if the securities are not widely traded, market value is determined by:
(A) Determining the value of the company that is the issuer of the equity securities based on the total undepreciated book value of the company’s assets;
(B) Determining the fraction of the securities at issue by dividing the number of equity securities involved in the transaction by the total number of outstanding equity securities for the company; and
(C) Multiplying the value determined in paragraph (b)(3)(iii)(A) of this section by the value determined in paragraph (b)(3)(iii)(B) of this section (i.e., the value of the company multiplied by the fraction of the equity securities at issue).
(4) The terms associate company, electric utility company, foreign utility company, holding company, and holding company system have the meaning given those terms in the Public Utility Holding Company Act of 2005. The term holding company does not include: A State, any political subdivision of a State, or any agency, authority or instrumentality of a State or political subdivision of a State; or an electric power cooperative.
(5) For purposes of this part, the term captive customers means any wholesale or retail electric energy customers served by a franchised public utility under cost-based regulation.
(c) Blanket Authorizations. (1) Any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to purchase, acquire, or take any security of:
(i) A transmitting utility or company that owns, operates, or controls only facilities used solely for transmission in intrastate commerce and/or sales of electric energy in intrastate commerce, provided that if any public utility within the holding company system has captive customers, or owns or provides transmission service over jurisdictional transmission facilities, the holding company must report the acquisition to the Commission, including any state actions or conditions related to the transaction, and shall provide an explanation of why the transaction does not result in cross-subsidization;
(ii) A transmitting utility or company that owns, operates, or controls only facilities used solely for local distribution and/or sales of electric energy at retail regulated by a state commission, provided that if any public utility within the holding company system has captive customers, or owns or provides transmission service over jurisdictional transmission facilities, the holding company must report the acquisition to the Commission, including any state actions or conditions related to the transaction, and shall provide an explanation of why the transaction does not result in cross-subsidization; or
(iii) An electric utility company that owns generating facilities that total 100 MW or less and are fundamentally used for its own individual load or for sales to affiliated end-users.
(2) Any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to purchase, acquire, or take:
(i) Any non-voting security (that does not convey sufficient veto rights over management actions so as to convey control) in a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility or an electric utility company; or
(ii) Any voting security in a transmitting utility, an electric utility company, or a holding company in a holding company system that includes a transmitting utility or an electric utility company if, after the acquisition, the holding company will own less than 10 percent of the outstanding voting securities; or
(iii) Any security of a subsidiary company within the holding company system.
(3) The blanket authorizations granted under paragraph (c)(2) of this section are subject to the conditions that the holding company shall not:
(i) Borrow from any electric utility company subsidiary in connection with such acquisition; or
(ii) Pledge or encumber the assets of any electric utility company subsidiary in connection with such acquisition.
(4) A holding company granted blanket authorizations in paragraph (c)(2) of this section shall provide the Commission copies of any Schedule 13D, Schedule 13G and Form 13F, at the same time and on the same basis, as filed with the Securities and Exchange Commission in connection with any securities purchased, acquired or taken pursuant to this section.
(5) Any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to acquire a foreign utility company. However, if such holding company or any of its affiliates, its subsidiaries, or associate companies within the holding company system has captive customers in the United States, or owns or provides transmission service over jurisdictional transmission facilities in the United States, the authorization is conditioned on the holding company, consistent with 18 CFR 385.2005(b), verifying by a duly authorized corporate official of the holding company that the proposed transaction:
(i) Will not have any adverse effect on competition, rates, or regulation; and
(ii) Will not result in, at the time of the transaction or in the future:
(A) Any transfer of facilities between a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, and an associate company;
(B) Any new issuance of securities by a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, for the benefit of an associate company;
(C) Any new pledge or encumbrance of assets of a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, for the benefit of an associate company; or
(D) Any new affiliate contracts between a non-utility associate company and a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, other than non-power goods and services agreements subject to review under sections 205 and 206 of the Federal Power Act.
(iii) A transaction by a holding company subject to the conditions in paragraphs (c)(5)(i) and (ii) of this section will be deemed approved only upon filing the information required in paragraphs (c)(5)(i) and (ii) of this section.
(6) Any public utility or any holding company in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under sections 203(a)(1) or 203(a)(2) of the Federal Power Act, as relevant, for internal corporate reorganizations that do not result in the reorganization of a traditional public utility that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, and that do not present cross-subsidization issues.
(7) Any public utility in a holding company system that includes a transmitting utility or an electric utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to purchase, acquire, or take any security of a public utility in connection with an intra-system cash management program, subject to safeguards to prevent cross-subsidization or pledges or encumbrances of utility assets.
(8) A person that is a holding company solely with respect to one or more exempt wholesale generators (EWGs), foreign utility companies (FUCOs), or qualifying facilities (QFs) is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to acquire the securities of additional EWGs, FUCOs, or QFs.
(9) A holding company, or a subsidiary of that company, that is regulated by the Board of Governors of the Federal Reserve Bank or by the Office of the Comptroller of the Currency, under the Bank Holding Company Act of 1956 as amended by the Gramm-Leach-Bliley Act of 1999, is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to acquire and hold an unlimited amount of the securities of holding companies that include a transmitting utility or an electric utility company if such acquisitions and holdings are in the normal course of its business and the securities are held:
(i) As a fiduciary;
(ii) As principal for derivatives hedging purposes incidental to the business of banking and it commits not to vote such securities to the extent they exceed 10 percent of the outstanding shares;
(iii) As collateral for a loan; or
(iv) Solely for purposes of liquidation and in connection with a loan previously contracted for and owned beneficially for a period of not more than two years, with the following conditions and reporting requirement: The holding does not confer a right to control, positively or negatively, through debt covenants or any other means, the operation or management of the public utility or public utility holding company, except as to customary creditors’ rights or as provided under the United States Bankruptcy Code; and the parent holding company files with the Commission on a public basis and within 45 days of the close of each calendar quarter, both its total holdings and its holdings as principal, each by class, unless the holdings within a class are less than one percent of outstanding shares, irrespective of the capacity in which they were held.
(10) Any holding company, or a subsidiary of that company, is granted a blanket authorization under section 203(a)(2) of the Federal Power Act to acquire any security of a public utility or a holding company that includes a public utility:
(i) For purposes of conducting underwriting activities, subject to the condition that holdings that the holding company or its subsidiary are unable to sell or otherwise dispose of within 45 days are to be treated as holdings as principal and thus subject to a limitation of 10 percent of the stock of any class unless the holding company or its subsidiary has within that period filed an application under section 203 of the Federal Power Act to retain the securities and has undertaken not to vote the securities during the pendency of such application; and the parent holding company files with the Commission on a public basis and within 45 days of the close of each calendar quarter, both its total holdings and its holdings as principal, each by class, unless the holdings within a class are less than one percent of outstanding shares, irrespective of the capacity in which they were held;
(ii) For purposes of engaging in hedging transactions, subject to the condition that if such holdings are 10 percent or more of the voting securities of a given class, the holding company or its subsidiary shall not vote such holdings to the extent that they are 10 percent or more.
(11) Any public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer a wholesale market-based rate contract to any other public utility affiliate that has the same ultimate upstream ownership, provided that neither affiliate is affiliated with a traditional public utility with captive customers.
(12) A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to:
(i) Any holding company granted blanket authorizations in paragraph (c)(2)(ii) of this section if, after the transfer, the holding company and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of such public utility; or
(ii) Any person other than a holding company if, after the transfer, such person and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of such public utility, and within 30 days after the end of the calendar quarter in which such transfer has occurred the public utility notifies the Commission in accordance with paragraph (c)(17) of this section.
(13) A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to any holding company granted blanket authorization in paragraph (c)(8) of this section if, after the transfer, the holding company and any of its associate or affiliate companies in aggregate will own less than 10 percent of the outstanding voting interests of such public utility.
(14) A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to any holding company granted blanket authorization in paragraph (c)(9) of this section.
(15) A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act to transfer its outstanding voting securities to any holding company granted blanket authorization in paragraph (c)(10) of this section.
(16) A public utility is granted a blanket authorization under section 203(a)(1) of the Federal Power Act for the acquisition or disposition of a jurisdictional contract where neither the acquirer nor transferor has captive customers or owns or provides transmission service over jurisdictional transmission facilities, the contract does not convey control over the operation of a generation or transmission facility, and the acquirer is a public utility.
(17) A public utility granted blanket authorization under paragraph (c)(12)(ii) of this section to transfer its outstanding voting securities shall, within 30 days after the end of the calendar quarter in which such transfer has occurred, file with the Commission a report containing the following information:
(i) The names of all parties to the transaction;
(ii) Identification of the pre- and post-transaction voting security holdings (and percentage ownership) in the public utility held by the acquirer and its associate or affiliate companies;
(iii) The date the transaction was consummated;
(iv) Identification of any public utility or holding company affiliates of the parties to the transaction; and
(v) A statement indicating that the proposed transaction will not result in, at the time of the transaction or in the future, cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company as required in § 33.2(j)(1).
§ 33.2 Contents of application—general information requirements.
Each applicant must include in its application, in the manner and form and in the order indicated, the following general information with respect to the applicant and each entity whose jurisdictional facilities or securities are involved:
(a) The exact name of the applicant and its principal business address.
(b) The name and address of the person authorized to receive notices and communications regarding the application, including phone and fax numbers, and E-mail addresses.
(c) A description of the applicant, including:
(1) All business activities of the applicant, including authorizations by charter or regulatory approval (to be identified as Exhibit A to the application);
(2) A list of all energy subsidiaries and energy affiliates, percentage ownership interest in such subsidiaries and affiliates, and a description of the primary business in which each energy subsidiary and affiliate is engaged (to be identified as Exhibit B to the application);
(3) Organizational charts depicting the applicant’s current and proposed post-transaction corporate structures (including any pending authorized but not implemented changes) indicating all parent companies, energy subsidiaries and energy affiliates unless the applicant demonstrates that the proposed transaction does not affect the corporate structure of any party to the transaction (to be identified as Exhibit C to the application);
(4) A description of all joint ventures, strategic alliances, tolling arrangements or other business arrangements, including transfers of operational control of transmission facilities to Commission approved Regional Transmission Organizations, both current, and planned to occur within a year from the date of filing, to which the applicant or its parent companies, energy subsidiaries, and energy affiliates is a party, unless the applicant demonstrates that the proposed transaction does not affect any of its business interests (to be identified as Exhibit D to the application);
(5) The identity of common officers or directors of parties to the proposed transaction (to be identified as Exhibit E to the application); and
(6) A description and location of wholesale power sales customers and unbundled transmission services customers served by the applicant or its parent companies, subsidiaries, affiliates and associate companies (to be identified as Exhibit F to the application).
(d) A description of jurisdictional facilities owned, operated, or controlled by the applicant or its parent companies, subsidiaries, affiliates, and associate companies (to be identified as Exhibit G to the application).
(e) A narrative description of the proposed transaction for which Commission authorization is requested, including:
(1) The identity of all parties involved in the transaction;
(2) All jurisdictional facilities and securities associated with or affected by the transaction (to be identified as Exhibit H to the application);
(3) The consideration for the transaction; and
(4) The effect of the transaction on such jurisdictional facilities and securities.
(f) All contracts related to the proposed transaction together with copies of all other written instruments entered into or proposed to be entered into by the parties to the transaction (to be identified as Exhibit I to the application).
(g) A statement explaining the facts relied upon to demonstrate that the proposed transaction is consistent with the public interest. The applicant must include a general explanation of the effect of the transaction on competition, rates and regulation of the applicant by the Commission and state commissions with jurisdiction over any party to the transaction. The applicant should also file any other information it believes relevant to the Commission’s consideration of the transaction. The applicant must supplement its application promptly to reflect in its analysis material changes that occur after the date a filing is made with the Commission, but before final Commission action. Such changes must be described and their effect on the analysis explained (to be identified as Exhibit J to the application).
(h) If the proposed transaction involves physical property of any party, the applicant must provide a general or key map showing in different colors the properties of each party to the transaction (to be identified as Exhibit K to the application).
(i) If the applicant is required to obtain licenses, orders, or other approvals from other regulatory bodies in connection with the proposed transaction, the applicant must identify the regulatory bodies and indicate the status of other regulatory actions, and provide a copy of each order of those regulatory bodies that relates to the proposed transaction (to be identified as Exhibit L to the application). If the regulatory bodies issue orders pertaining to the proposed transaction after the date of filing with the Commission, and before the date of final Commission action, the applicant must supplement its Commission application promptly with a copy of these orders.
(j) An explanation, with appropriate evidentiary support for such explanation (to be identified as Exhibit M to this application):
(1) Of how applicants are providing assurance, based on facts and circumstances known to them or that are reasonably foreseeable, that the proposed transaction will not result in, at the time of the transaction or in the future, cross-subsidization of a non-utility associate company or pledge or encumbrance of utility assets for the benefit of an associate company, including:
(i) Disclosure of existing pledges and/or encumbrances of utility assets; and
(ii) A detailed showing that the transaction will not result in:
(A) Any transfer of facilities between a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, and an associate company;
(B) Any new issuance of securities by a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, for the benefit of an associate company;
(C) Any new pledge or encumbrance of assets of a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, for the benefit of an associate company; or
(D) Any new affiliate contract between a non-utility associate company and a traditional public utility associate company that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, other than non-power goods and services agreements subject to review under sections 205 and 206 of the Federal Power Act; or
(2) If no such assurance can be provided, an explanation of how such cross-subsidization, pledge, or encumbrance will be consistent with the public interest.
§ 33.3 Additional information requirements for applications involving horizontal competitive impacts.
(a)(1) The applicant must file the horizontal Competitive Analysis Screen described in paragraphs (b) through (f) of this section if, as a result of the proposed transaction, a single corporate entity obtains ownership or control over the generating facilities of previously unaffiliated merging entities (for purposes of this section, merging entities means any party to the proposed transaction or its parent companies, energy subsidiaries or energy affiliates).
(2) A horizontal Competitive Analysis Screen need not be filed if the applicant:
(i) Affirmatively demonstrates that the merging entities do not currently conduct business in the same geographic markets or that the extent of the business transactions in the same geographic markets is de minimis; and
(ii) No intervenor has alleged that one of the merging entities is a perceived potential competitor in the same geographic market as the other.
(b) All data, assumptions, techniques and conclusions in the horizontal Competitive Analysis Screen must be accompanied by appropriate documentation and support.
(1) If the applicant is unable to provide any specific data required in this section, it must identify and explain how the data requirement was satisfied and the suitability of the substitute data.
(2) The applicant may provide other analyses for defining relevant markets (e.g. the Hypothetical Monopolist Test with or without the assumption of price discrimination) in addition to the delivered price test under the horizontal Competitive Analysis Screen.
(3) The applicant may use a computer model to complete one or more steps in the horizontal Competitive Analysis Screen. The applicant must fully explain, justify and document any model used and provide descriptions of model formulation, mathematical specifications, solution algorithms, as well as the annotated model code in executable form, and specify the software needed to execute the model. The applicant must explain and document how inputs were developed, the assumptions underlying such inputs and any adjustments made to published data that are used as inputs. The applicant must also explain how it tested the predictive value of the model, for example, using historical data.
(c) The horizontal Competitive Analysis Screen must be completed using the following steps:
(1) Define relevant products. Identify and define all wholesale electricity products sold by the merging entities during the two years prior to the date of the application, including, but not limited to, non-firm energy, short-term capacity (or firm energy), long-term capacity (a contractual commitment of more than one year), and ancillary services (specifically spinning reserves, non-spinning reserves, and imbalance energy, identified and defined separately). Because demand and supply conditions for a product can vary substantially over the year, periods corresponding to those distinct conditions must be identified by load level, and analyzed as separate products.
(2) Identify destination markets. Identify each wholesale power sales customer or set of customers (destination market) affected by the proposed transaction. Affected customers are, at a minimum, those entities directly interconnected to any of the merging entities and entities that have purchased electricity at wholesale from any of the merging entities during the two years prior to the date of the application. If the applicant does not identify an entity to whom the merging entities have sold electricity during the last two years as an affected customer, the applicant must provide a full explanation for each exclusion.
(3) Identify potential suppliers. The applicant must identify potential suppliers to each destination market using the delivered price test described in paragraph (c)(4) of this section. A seller may be included in a geographic market to the extent that it can economically and physically deliver generation services to the destination market.
(4) Perform delivered price test. For each destination market, the applicant must calculate the amount of relevant product a potential supplier could deliver to the destination market from owned or controlled capacity at a price, including applicable transmission prices, loss factors and ancillary services costs, that is no more than five (5) percent above the pre-transaction market clearing price in the destination market.
(i) Supplier’s presence. The applicant must measure each potential supplier’s presence in the destination market in terms of generating capacity, using economic capacity and available economic capacity measures. Additional adjustments to supplier presence may be presented; applicants must support any such adjustment.
(A) Economic capacity means the amount of generating capacity owned or controlled by a potential supplier with variable costs low enough that energy from such capacity could be economically delivered to the destination market. Prior to applying the delivered price test, the generating capacity meeting this definition must be adjusted by subtracting capacity committed under long-term firm sales contracts and adding capacity acquired under long-term firm purchase contracts (i.e., contracts with a remaining commitment of more than one year). The capacity associated with any such adjustments must be attributed to the party that has authority to decide when generating resources are available for operation. Other generating capacity may also be attributed to another supplier based on operational control criteria as deemed necessary, but the applicant must explain the reasons for doing so.
(B) Available economic capacity means the amount of generating capacity meeting the definition of economic capacity less the amount of generating capacity needed to serve the potential supplier’s native load commitments, as described in paragraph (d)(4)(i) of this section.
(C) Available transmission capacity. Each potential supplier’s economic capacity and available economic capacity (and any other measure used to determine the amount of relevant product that could be delivered to a destination market) must be adjusted to reflect available transmission capability to deliver each relevant product. The allocation to a potential supplier of limited capability of constrained transmission paths internal to the merging entities’ systems or interconnecting the systems with other control areas must recognize both the transmission capability not subject to firm reservations by others and any firm transmission rights held by the potential supplier that are not committed to long-term transactions. For each such instance where limited transmission capability must be allocated among potential suppliers, the applicant must explain the method used and show the results of such allocation.
(D) Internal interface. If the proposed transaction would cause an interface that interconnects the transmission systems of the merging entities to become transmission facilities for which the merging entities would have a “native load” priority under their open access transmission tariff (i.e., where the merging entities may reserve existing transmission capacity needed for native load growth and network transmission customer load growth reasonable forecasted within the utility’s current planning horizon), all of the unreserved capability of the interface must be allocated to the merging entities for purposes of the horizontal Competitive Analysis Screen, unless the applicant demonstrates one of the following:
(1) The merging entities would not have adequate economic capacity to fully use such unreserved transmission capability;
(2) The merging entities have committed a portion of the interface capability to third parties; or
(3) Suppliers other than the merging entities have purchased a portion of the interface capability.
(ii) [Reserved]
(5) Calculate market concentration. The applicant must calculate the market share, both pre- and post-merger, for each potential supplier, the Herfindahl-Hirschman Index (HHI) statistic for the market, and the change in the HHI statistic. (The HHI statistic is a measure of market concentration and is a function of the number of firms in a market and their respective market shares. The HHI statistic is calculated by summing the squares of the individual market shares, expressed as percentages, of all potential suppliers to the destination market.) To make these calculations, the applicant must use the amounts of generating capacity (i.e., economic capacity and available economic capacity, and any other relevant measure) determined in paragraph (c)(4)(i) of this section, for each product in each destination market.
(6) Provide historical transaction data. The applicant must provide historical trade data and historical transmission data to corroborate the results of the horizontal Competitive Analysis Screen. The data must cover the two-year period preceding the filing of the application. The applicant may adjust the results of the horizontal Competitive Analysis Screen, if supported by historical trade data or historical transmission service data. Any adjusted results must be shown separately, along with an explanation of all adjustments to the results of the horizontal Competitive Analysis Screen. The applicant must also provide an explanation of any significant differences between results obtained by the horizontal Competitive Analysis Screen and trade patterns in the last two years.
(d) In support of the delivered price test required by paragraph (c)(4) of this section, the applicant must provide the following data and information used in calculating the economic capacity and available economic capacity that a potential supplier could deliver to a destination market. The transmission data required by paragraphs (d)(7) through (d)(9) of this section must be supplied for the merging entities’ systems. The transmission data must also be supplied for other relevant systems, to the extent data are publicly available.
(1) Generation capacity. For each generating plant or unit owned or controlled by each potential supplier, the applicant must provide:
(i) Supplier name;
(ii) Name of the plant or unit;
(iii) Primary and secondary fuel-types;
(iv) Nameplate capacity;
(v) Summer and winter total capacity; and
(vi) Summer and winter capacity adjusted to reflect planned and forced outages and other factors, such as fuel supply and environmental restrictions.
(2) Variable cost. For each generating plant or unit owned or controlled by each potential supplier, the applicant must also provide variable cost components.
(i) These cost components must include at a minimum:
(A) Variable operation and maintenance, including both fuel and non-fuel operation and maintenance; and
(B) Environmental compliance.
(ii) To the extent costs described in paragraph (d)(2)(i) of this section are allocated among units at the same plant, allocation methods must be fully described.
(3) Long-term purchase and sales data. For each sale and purchase of capacity, the applicant must provide the following information:
(i) Purchasing entity name;
(ii) Selling entity name;
(iii) Duration of the contract;
(iv) Remaining contract term and any evergreen provisions;
(v) Provisions regarding renewal of the contract;
(vi) Priority or degree of interruptibility;
(vii) FERC rate schedule number, if applicable;
(viii) Quantity and price of capacity and/or energy purchased or sold under the contract; and
(ix) Information on provisions of contracts which confer operational control over generation resources to the purchaser.
(4) Native load commitments. (i) Native load commitments are commitments to serve wholesale and retail power customers on whose behalf the potential supplier, by statute, franchise, regulatory requirement, or contract, has undertaken an obligation to construct and operate its system to meet their reliable electricity needs.
(ii) The applicant must provide supplier name and hourly native load commitments for the most recent two years. In addition, the applicant must provide this information for each load level, if load-differentiated relevant products are analyzed.
(iii) If data on native load commitments are not available, the applicant must fully explain and justify any estimates of these commitments.
(5) Transmission and ancillary service prices, and loss factors. (i) The applicant must use in the horizontal Competitive Analysis Screen the maximum rates stated in the transmission providers’ tariffs. If necessary, those rates should be converted to a dollars-per-megawatt hour basis and the conversion method explained.
(ii) If a regional transmission pricing regime is in effect that departs from system-specific transmission rates, the horizontal Competitive Analysis Screen must reflect the regional pricing regime.
(iii) The following data must be provided for each transmission system that would be used to deliver energy from each potential supplier to a destination market:
(A) Supplier name;
(B) Name of transmission system;
(C) Firm point-to-point rate;
(D) Non-firm point-to-point rate;
(E) Scheduling, system control and dispatch rate;
(F) Reactive power/voltage control rate;
(G) Transmission loss factor; and
(H) Estimated cost of supplying energy losses.
(iv) The applicant may present additional alternative analysis using discount prices if the applicant can support it with evidence that discounting is and will be available.
(6) Destination market price. The applicant must provide, for each relevant product and destination market, market prices for the most recent two years. The applicant may provide suitable proxies for market prices if actual market prices are unavailable. Estimated prices or price ranges must be supported and the data and approach used to estimate the prices must be included with the application. If the applicant relies on price ranges in the analysis, such ranges must be reconciled with any actual market prices that are supplied in the application. Applicants must demonstrate that the results of the analysis do not vary significantly in response to small variations in actual and/or estimated prices.
(7) Transmission capability. (i) The applicant must provide simultaneous transfer capability data, if available, for each of the transmission paths, interfaces, or other facilities used by suppliers to deliver to the destination markets on an hourly basis for the most recent two years.
(ii) Transmission capability data must include the following information:
(A) Transmission path, interface, or facility name;
(B) Total transfer capability (TTC); and
(C) Firm available transmission capability (ATC).
(iii) Any estimated transmission capability must be supported and the data and approach used to make the estimates must be included with the application.
(8) Transmission constraints. (i) For each existing transmission facility that affects supplies to the destination markets and that has been constrained during the most recent two years or is expected to be constrained within the planning horizon, the applicant must provide the following information:
(A) Name of all paths, interfaces, or facilities affected by the constraint;
(B) Locations of the constraint and all paths, interfaces, or facilities affected by the constraint;
(C) Hours of the year when the transmission constraint is binding; and
(D) The system conditions under which the constraint is binding.
(ii) The applicant must include information regarding expected changes in loadings on transmission facilities due to the proposed transaction and the consequent effect on transfer capability.
(iii) To the extent possible, the applicant must provide system maps showing the location of transmission facilities where binding constraints have been known or are expected to occur.
(9) Firm transmission rights (Physical and Financial). For each potential supplier to a destination market that holds firm transmission rights necessary to directly or indirectly deliver energy to that market, or that holds transmission congestion contracts, the applicant must provide the following information:
(i) Supplier name;
(ii) Name of transmission path interface, or facility;
(iii) The FERC rate schedule number, if applicable, under which transmission service is provided; and
(iv) A description of the firm transmission rights held (including, at a minimum, quantity and remaining time the rights will be held, and any relevant time restrictions on transmission use, such as peak or off-peak rights).
(10) Summary table of potential suppliers’ presence. (i) The applicant must provide a summary table with the following information for each potential supplier for each destination market:
(A) Potential supplier name;
(B) The potential supplier’s total amount of economic capacity (not subject to transmission constraints); and
(C) The potential supplier’s amount of economic capacity from which energy can be delivered to the destination market (after adjusting for transmission availability).
(ii) A similar table must be provided for available economic capacity, and for any other generating capacity measure used by the applicant.
(11) Historical trade data. (i) The applicant must provide data identifying all of the merging entities’ wholesale sales and purchases of electric energy for the most recent two years.
(ii) The applicant must include the following information for each transition:
(A) Type of transaction (such as non-firm, short-term firm, long-term firm, peak, off-peak, etc.);
(B) Name of purchaser;
(C) Name of seller;
(D) Date, duration and time period of the transaction;
(E) Quantity of energy purchased or sold;
(F) Energy charge per unit;
(G) Megawatt hours purchased or sold;
(H) Price; and
(I) The delivery points used to effect the sale or purchase.
(12) Historical transmission data. The applicant must provide information concerning any transmission service denials, interruptions and curtailments on the merging entities’ systems, for the most recent two years, to the extent the information is available from OASIS data, including the following information:
(i) Name of the customer denied, interrupted or curtailed;
(ii) Type, quantity and duration of service at issue;
(iii) The date and period of time involved;
(iv) Reason given for the denial, interruption or curtailment;
(v) The transmission path; and
(vi) The reservations or other use anticipated on the affected transmission path at the time of the service denial, curtailment or interruption.
(e) Mitigation. Any mitigation measures proposed by the applicant (including, for example, divestiture or participation in a regional transmission organization) which are intended to mitigate the adverse effect of the proposed transaction must, to the extent possible, be factored into the horizontal Competitive Analysis Screen as an additional post-transaction analysis. Any mitigation commitments that involve facilities (e.g., in connection with divestiture of generation) must identify the facilities affected by the commitment, along with a timetable for implementing the commitments.
(f) Additional factors. If the applicant does not propose mitigation, the applicant must address:
(1) The potential adverse competitive effects of the transaction.
(2) The potential for entry in the market and the role that entry could play in mitigating adverse competitive effects of the transaction;
(3) The efficiency gains that reasonably could not be achieved by other means; and
(4) Whether, but for the transaction, one or more of the merging entities would be likely to fail, causing its assets to exit the market.
§ 33.4 Additional information requirements for applications involving vertical competitive impacts.
(a)(1) The applicant must file the vertical Competitive Analysis described in paragraphs (b) through (e) of this section if, as a result of the proposed transaction, a single corporate entity has ownership or control over one or more merging entities that provides inputs to electricity products and one or more merging entities that provides electric generation products (for purposes of this section, merging entities means any party to the proposed transaction or its parent companies, energy subsidiaries or energy affiliates).
(2) A vertical Competitive Analysis need not be filed if the applicant can affirmatively demonstrate that:
(i) The merging entities currently do not provide inputs to electricity products (i.e., upstream relevant products) and electricity products (i.e., downstream relevant products) in the same geographic markets or that the extent of the business transactions in the same geographic market is de minimis; and no intervenor has alleged that one of the merging entities is a perceived potential competitor in the same geographic market as the other.
(ii) The extent of the upstream relevant products currently provided by the merging entities is used to produce a de minimis amount of the relevant downstream products in the relevant destination markets, as defined in paragraph (c)(2) of § 33.3.
(b) All data, assumptions, techniques and conclusions in the vertical Competitive Analysis must be accompanied by appropriate documentation and support.
(c) The vertical Competitive Analysis must be completed using the following steps:
(1) Define relevant products—(i) Downstream relevant products. The applicant must identify and define as downstream relevant products all products sold by merging entities in relevant downstream geographic markets, as outlined in paragraph (c)(1) of § 33.3.
(ii) Upstream relevant products. The applicant must identify and define as upstream relevant products all inputs to electricity products provided by upstream merging entities in the most recent two years.
(2) Define geographic markets—(i) Downstream geographic markets. The applicant must identify all geographic markets in which it or any merging entities sell the downstream relevant products, as outlined in paragraphs (c)(2) and (c)(3) of § 33.3.
(ii) Upstream geographic markets The applicant must identify all geographic markets in which it or any merging entities provide the upstream relevant products.
(3) Analyze competitive conditions—(i) Downstream geographic market. (A) The applicant must compute market share for each supplier in each relevant downstream geographic market and the HHI statistic for the downstream market. The applicant must provide a summary table with the following information for each relevant downstream geographic market:
(1) The economic capacity of each downstream supplier (specify the amount of such capacity served by each upstream supplier);
(2) The total amount of economic capacity in the downstream market served by each upstream supplier;
(3) The market share of economic capacity served by each upstream supplier; and
(4) The HHI statistic for the downstream market.
(B) A similar table must be provided for available economic capacity and for any other measure used by the applicant.
(ii) Upstream geographic market. The applicant must provide a summary table with the following information for each upstream relevant product in each relevant upstream geographic market:
(A) The amount of relevant product provided by each upstream supplier;
(B) The total amount of relevant product in the market;
(C) The market share of each upstream supplier; and
(D) The HHI statistic for the upstream market.
(d) Mitigation. Any mitigation measures proposed by the applicant (including, for example, divestiture or participation in an Regional Transmission Organization) which are intended to mitigate the adverse effect of the proposed transaction must, to the extent possible, be factored into the vertical competitive analysis as an additional post-transaction analysis. Any mitigation measures that involve facilities must identify the facilities affected by the commitment.
(e) Additional factors. (1) If the applicant does not propose mitigation measures, the applicant must address:
(i) The potential adverse competitive effects of the transaction.
(ii) The potential for entry in the market and the role that entry could play in mitigating adverse competitive effects of the transaction;
(iii) The efficiency gains that reasonably could not be achieved by other means; and
(iv) Whether, but for the proposed transaction, one or more of the parties to the transaction would be likely to fail, causing its assets to exit the market.
(2) The applicant must address each of the additional factors in the context of whether the proposed transaction is likely to present concerns about raising rivals’ costs or anticompetitive coordination.
§ 33.5 Proposed accounting entries.
If the applicant is required to maintain its books of account in accordance with the Commission’s Uniform System of Accounts in part 101 of this chapter, the applicant must present proposed accounting entries showing the effect of the transaction with sufficient detail to indicate the effects on all account balances (including amounts transferred on an interim basis), the effect on the income statement, and the effects on other relevant financial statements. The applicant must also explain how the amount of each entry was determined.
§ 33.7 Verification.
The original application must be signed by a person or persons having authority with respect thereto and having knowledge of the matters therein set forth, and must be verified under oath.
§ 33.8 Requirements for filing applications.
The applicant must submit the application or petition to the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov.
(a) If the applicant seeks to protect any portion of the application, or any attachment thereto, from public disclosure, the applicant must make its filing in accordance with the Commission’s instructions for submission of privileged materials and Critical Energy Infrastructure Information in § 388.112 of this chapter.
(b) If required, the applicant must submit information specified in paragraphs (b), (c), (d), (e) and (f) of § 33.3 or paragraphs (b), (c), (d) and (e) of § 33.4 on electronic recorded media (i.e., CD/DVD) in accordance with § 385.2011 of this chapter, along with a printed description and summary. The printed portion of the applicant’s submission must include documentation for the electronic information, including all file names and a summary of the data contained in each file. Each column (or data item) in each separate data table or chart must be clearly labeled in accordance with the requirements of §§ 33.3 and 33.4. Any units of measurement associated with numeric entries must also be included.
§ 33.9 [Reserved]
§ 33.10 Additional information.
The Director of the Office of Energy Market Regulation, or his designee, may, by letter, require the applicant to submit additional information as is needed for analysis of an application filed under this part.
§ 33.11 Commission procedures for the consideration of applications under section 203 of the FPA.
(a) The Commission will act on a completed application for approval of a transaction (i.e., one that is consistent with the requirements of this part) not later than 180 days after the completed application is filed. If the Commission does not act within 180 days, such application shall be deemed granted unless the Commission finds, based on good cause, that further consideration is required to determine whether the proposed transaction meets the standards of section 203(a)(4) of the FPA and issues, by the 180th day, an order tolling the time for acting on the application for not more than 180 days, at the end of which additional period the Commission shall grant or deny the application.
(b) The Commission will provide for the expeditious consideration of completed applications for the approval of transactions that are not contested, do not involve mergers, and are consistent with Commission precedent.
(c) Transactions, provided that they are not contested, do not involve mergers and are consistent with Commission precedent, that will generally be subject to expedited review include:
(1) A disposition of only transmission facilities, including, but not limited to, those that both before and after the transaction remain under the functional control of a Commission-approved regional transmission organization or independent system operator; and
(2) Transactions that do not require an Appendix A analysis;
(3) Internal corporate reorganizations that result in the reorganization of a traditional public utility that has captive customers or owns or provides transmission service over jurisdictional transmission facilities, but do not present cross-subsidization issues.
§ 33.12 Notification requirement for certain transactions.
(a) Any public utility that is seeking to merge or consolidate, directly or indirectly, its facilities subject to the jurisdiction of the Commission, or any part thereof, with those of any other person, shall notify the Commission of such transaction not later than 30 days after the date on which the transaction is consummated if:
(1) The facilities, or any part thereof, to be acquired are of a value in excess of $1 million; and
(2) Such public utility is not required to secure an order of the Commission under section 203(a)(1)(B) of the Federal Power Act.
(b) Such notification shall consist of the following information:
(1) The exact name of the public utility and its principal business address; and
(2) A narrative description of the transaction, including:
(i) The identity of all parties involved in the transaction, whether such parties are affiliates, and all jurisdictional facilities associated with or affected by the transaction;
(ii) The location of such jurisdictional facilities involved in the transaction;
(iii) The date on which the transaction was consummated;
(iv) The consideration for the transaction; and
(v) The effect of the transaction on the ownership and control of such jurisdictional facilities.
PART 34—APPLICATION FOR AUTHORIZATION OF THE ISSUANCE OF SECURITIES OR THE ASSUMPTION OF LIABILITIES
For rules of practice and procedure, see part 385 of this chapter. For Approved Forms, Federal Power Act, see part 131 of this chapter. “FERC Filing No. 523” is the identification number used by the Commission and the Office of Management and Budget to reference the filing requirements in part 34.
§ 34.1 Applicability; definitions; exemptions in case of certain State regulation, certain short-term issuances and certain qualifying facilities.
(a) Applicability. This part applies to applications for authorization from the Commission to issue securities or assume an obligation or liability which are filed by:
(1) Licensees and other entities pursuant to sections 19 and 20 of the Federal Power Act (41 Stat. 1073, 16 U.S.C. 812, 813) and part 20 of the Commission’s regulations; and
(2) Public utilities pursuant to section 204 of the Federal Power Act (49 Stat. 850, 16 U.S.C. 824c).
(b) Definitions. For the purpose of this part:
(1) The term utility means a licensee, public utility or other entity seeking authorization under sections 19, 20 or 204 of the Federal Power Act;
(2) The term securities includes any note, stock, treasury stock, bond, or debenture or other evidence of interest in or indebtedness of a utility;
(3) The term issuance or placement of securities means issuance or placement of securities, or assumption of obligation or liability; and
(4) The term State means a State admitted to the Union, the District of Columbia, and any organized Territory of the United States.
(c) Exemptions. (1) If an agency of the State in which the utility is organized and operating approves or authorizes, in writing, the issuance of securities prior to their issuance, the utility is exempt from the provisions of sections 19, 20 and 204 of the Federal Power Act and the regulations under this part, with respect to such securities.
(2) This part does not apply to the issue or renewal of, or assumption of liability on, a note or draft maturing one year or less after the date of such issue, renewal, or assumption of liability, if the aggregate of such note or draft and all other then-outstanding notes and drafts of a maturity of one year or less on which the utility is primarily or secondarily liable, is not more than 5 percent of the par value of the other then-outstanding securities of the utility as of the date of issue or renewal of, or assumption of liability on, the note or draft. In the case of securities having no par value, the par value for the purpose of this part is the fair market value, as of the date of issue or renewal of, or assumption of liability on, the note or draft.
(3) For certain qualifying facilities. Any cogeneration or small power production facility which is exempt from sections 19, 20 and 204 of the Federal Power Act pursuant to § 292.601 of this chapter shall be exempt from the provisions of this part.
§ 34.2 Placement of securities.
(a) Method of issuance. Upon obtaining authorization from the Commission, utilities may issue securities by either a competitive bid or negotiated placement, provided that:
(1) Competitive bids are obtained from at least two prospective dealers, purchasers or underwriters; or
(2) Negotiated offers are obtained from at least three prospective dealers, purchasers or underwriters; and
(3) The utility:
(i) Accepts the bid or offer that provides the utility with the lowest cost of money for securities with fixed or variable interest or dividend rates, or
(ii) Accepts the bid or offer that provides the utility with the greatest net proceeds for securities with no specified interest or dividend rates, or
(iii) The utility has filed for and obtained authorization from the Commission to accept bids or offers other than those specified in paragraphs (a)(3)(i) or (a)(3)(ii) of this section.
(b) Exemptions. The provisions of paragraph (a) of this section do not apply where:
(1) The securities are to be issued to existing holders of securities on a pro rata basis;
(2) The utility receives an unsolicited offer to purchase the securities;
(3) The securities have a maturity of one year or less; or
(4) The securities are to be issued in support of or to guarantee securities issued by governmental or quasi-governmental bodies for the benefit of the utility.
(c) Prohibitions. No securities will be placed with any person who:
(1) Has performed any service or accepted any fee or compensation with respect to the proposed issuance of securities prior to submission of bids or entry into negotiations for placement of such securities; or
(2) Would be in violation of section 305(a) of the Federal Power Act with respect to the issuance.
§ 34.3 Contents of application for issuance of securities.
Each application to the Commission for authority to issue securities shall contain the information specified in this section. In lieu of filing the information required in paragraphs (e), (i) and (j) of this section, a specific reference may be made to the portion of the registration statement filed under § 34.4(f), which includes the information required in these paragraphs.
(a) The official name of the applicant and address of its principal business office.
(b) The State in which the utility is incorporated, the date of incorporation, and each State in which it operates.
(c) The name, address and telephone number of a person within the utility authorized to receive notices and communications with respect to the application.
(d) The date by which Commission action is requested.
(e) A full description of the securities proposed to be issued, including:
(1) Type and nature of securities;
(2) Amount of securities (par or stated value and number of units);
(3) Interest or dividend rate, if any;
(4) Dates of issuance and maturity;
(5) Institutional rating of the securities—or if the securities are not rated, an explanation as to why they are not rated, and if the securities will be rated, an estimate of the rating; and
(6) Any stock exchange on which the securities will be listed.
(f) The purpose for which the securities for which application is made are to be issued:
(1) If the purpose of such issuance is the construction, completion, extension, or improvement of facilities, describe in reasonable detail the construction program for which the funds were or are to be used.
(2) If the purpose for such issuance is for the refunding of obligations, describe in detail the obligations to be refunded, including the character, principal amounts, applicable discount or premium, dates of issuance and maturity, and all other material facts concerning such obligations.
(3) If the purpose for such issuance is for other than construction or refunding, explain such other purpose(s) in detail.
(g) A statement as to whether or not any application with respect to the transaction or any part thereof is required to be filed with any State regulatory body.
(h) A detailed statement of the facts relied upon by the applicant to show that the issuance:
(1) Is for some lawful object, within the corporate purposes of the applicant and compatible with the public interest, is necessary or appropriate for or consistent with the proper performances by the applicant of service as a public utility and will not impair its ability to perform that service, and
(2) Is reasonably necessary or appropriate for such purposes.
(i) A detailed statement of the bond indenture(s) or other limitations on interest and dividend coverage, and the effects of such limitations on the issuance of additional debt or equity securities.
(j) A brief summary of any rate changes which were made effective during the period for which financial statements are submitted or which became or will become effective after the period for which statements are submitted.
§ 34.4 Required exhibits.
(a) Exhibit A. The applicant must file the statement of corporate purposes from its articles of incorporation.
(b) Exhibit B. A copy of all resolutions of the applicant’s directors authorizing the issuance of securities for which the application is made; and copies of the resolution of the stockholders approving such issuance if approval of the stockholders has been obtained.
(c) Exhibit C. The Balance Sheet and attached notes for the most recent 12-month period for which financial statements have been published, provided that the 12-month period ended no more than 4 months prior to the date of the filing of the application, on both an actual basis and a pro forma basis in the form prescribed for the “Comparative Balance Sheet” of FERC Form No. 1, “Annual Report for major electric utilities, licensees and others.” Each adjustment made in determining the pro forma basis must be clearly identified.
(d) Exhibit D. The Income Statement and attached notes for the most recent 12-month period for which financial statements have been published, provided that the 12-month period ended no more than 4 months prior to the date of the filing of the application, on both an actual basis and a pro forma basis in the form prescribed for the “Statement of Income for the Year” of FERC Form No. 1, “Annual Report for major electric utilities, licensees and others.” Each adjustment made in determining the pro forma basis must be clearly identified.
(e) Exhibit E. A Statement of Cash Flows and Computation of Interest Coverage on an actual basis and a pro forma basis for the most recent 12-month period for which financial statements have been published, provided that the 12-month period ended no more than 4 months prior to the date of the filing of the application. The Statement of Cash Flows must be in the form prescribed for the “Statement of Cash Flows” of the FERC Form No. 1, Annual Report for major electric utilities, licensees and others,” followed by a computation of interest coverage, in the form of the following worksheet:
| Federal Energy Regulatory Commission worksheet for computation of interest coverage | Actual for the year ended mm-dd-yy | OMB control No. 1902–0043, pro forma for the year ended mm-dd-yy |
|---|---|---|
| Net income | ||
| Add: Interest on Long-Term Debt, Interest on Short-Term Debt, Other Interest Expense, Total Interest Expense | ||
| Federal and State Income Taxes | ||
| Income Before Interest and Income Taxes | ||
| Computation of Interest Coverage | ||
| Income Before Interest and Income Taxes ÷ Total Interest Expense = Interest Coverage |
(f) Exhibit F. A copy of registration statement and exhibits which are filed with the Securities and Exchange Commission for the proposed security issuance.
§ 34.5 Additional information.
The Commission may, in its discretion, require the filing of additional information which appears necessary to reach a determination on any particular application.
§ 34.6 Form and style.
Each application pursuant to this part 34 shall conform to the requirements of subpart T of part 385 of this chapter.
§ 34.7 Filing requirements.
Applications must be filed with the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov. If an applicant seeks to protect any portion of an application from public disclosure, the applicant must make its filing in accordance with the Commission’s instructions for filing privileged materials and critical energy infrastructure information in this chapter.
§ 34.8 Verification.
The original application shall be signed by an authorized representative of the applicant, who has knowledge of the matters set forth therein, and it shall be verified under oath.
§ 34.8 Verification.
An application verification shall be signed under oath by an authorized representative of the applicant, who has knowledge of the matters set forth therein and as provided in § 385.2005 of this chapter, and retained at the applicant’s business location until the relevant proceeding has been concluded.
§ 34.9 Reports.
The applicant must file reports under § 131.43 and § 131.50 of this chapter no later than 30 days after the sale or placement of long-term debt or equity securities or the entry into guarantees or assumptions of liabilities pursuant to authority granted under this part.
§ 34.9 Filing fee.
Each application shall be accompanied by the submission of a filing fee if one is prescribed in part 381 of this chapter.
PART 35—FILING OF RATE SCHEDULES AND TARIFFS
Subpart A—Application
§ 35.1 Application; obligation to file rate schedules, tariffs and certain service agreements.
(a) Every public utility shall file with the Commission and post, in conformity with the requirements of this part, full and complete rate schedules and tariffs and those service agreements not meeting the requirements of § 35.1(g), clearly and specifically setting forth all rates and charges for any transmission or sale of electric energy subject to the jurisdiction of this Commission, the classifications, practices, rules and regulations affecting such rates, charges, classifications, services, rules, regulations or practices, as required by section 205(c) of the Federal Power Act (49 Stat. 851; 16 U.S.C. 824d(c)). Where two or more public utilities are parties to the same rate schedule or tariff, each public utility transmitting or selling electric energy subject to the jurisdiction of this Commission shall post and file such rate schedule, or the rate schedule may be filed by one such public utility and all other parties having an obligation to file may post and file a certificate of concurrence on the form indicated in § 131.52 of this chapter: Provided, however, In cases where two or more public utilities are required to file rate schedules or certificates of concurrence such public utilities may authorize a designated representative to file upon behalf of all parties if upon written request such parties have been granted Commission authorization therefor.
(b) A rate schedule, tariff, or service agreement applicable to a transmission or sale of electric energy, other than that which proposes to supersede, cancel or otherwise change the provisions of a rate schedule, tariff, or service agreement required to be on file with this Commission, shall be filed as an initial rate in accordance with § 35.12.
(c) A rate schedule, tariff, or service agreement applicable to a transmission or sale of electric energy which proposes to supersede, cancel or otherwise change any of the provisions of a rate schedule, tariff, or service agreement required to be on file with this Commission (such as providing for other or additional rates, charges, classifications or services, or rules, regulations, practices or contracts for a particular customer or customers) shall be filed as a change in rate in accordance with § 35.13, except cancellation or termination which shall be filed as a change in accordance with § 35.15.
(d)(1) The provisions of this paragraph (d) shall apply to rate schedules, tariffs or service agreements tendered for filing on or after August 1, 1976, which are applicable to the transmission or sale of firm power for resale to an all-requirements customer, whether tendered pursuant to § 35.12 as an initial rate schedule or tendered pursuant to § 35.13 as a change in an existing rate schedule whose term has expired or whose term is to be extended.
(2) Rate schedules, tariffs or service agreements covered by the terms of paragraph (d)(1) of this section shall contain the following provision when it is the intent of the contracting parties to give the party furnishing service the unrestricted right to file unilateral rate changes under section 205 of the Federal Power Act:
Nothing contained herein shall be construed as affecting in any way the right of the party furnishing service under this rate schedule to unilaterally make application to the Federal Energy Regulatory Commission for a change in rates under section 205 of the Federal Power Act and pursuant to the Commission’s Rules and Regulations promulgated thereunder.
(3) Rate schedules, tariffs or service agreements covered by the terms of paragraph (d)(1) of this section shall contain the following provision when it is the intent of the contracting parties to withhold from the party furnishing service the right to file any unilateral rate changes under section 205 of the Federal Power Act:
The rates for service specified herein shall remain in effect for the term of __________ or until __________, and shall not be subject to change through application to the Federal Energy Regulatory Commission pursuant to the provisions of Section 205 of the Federal Power Act absent the agreement of all parties thereto.
(4) Rate schedules covered by the terms of paragraph (d)(1) of this section, but which are not covered by paragraphs (d)(2) or (d)(3) of this section, are not required to contain either of the boilerplate provisions set forth in paragraph (d)(2) or (d)(3) of this section.
(e) No public utility shall, directly or indirectly, demand, charge, collect or receive any rate, charge or compensation for or in connection with electric service subject to the jurisdiction of the Commission, or impose any classification, practice, rule, regulation or contract with respect thereto, which is different from that provided in a rate schedule required to be on file with this Commission unless otherwise specifically provided by order of the Commission for good cause shown.
(f) A rate schedule applicable to the sale of electric power by a public utility to the Bonneville Power Administration under section 5(c) of the Pacific Northwest Electric Power Planning and Conservation Act (Pub. L. No. 96–501 (1980)) shall be filed in accordance with subpart D of this part.
(g) For the purposes of paragraph (a) of this section, any service agreement that conforms to the form of service agreement that is part of the public utility’s approved tariff pursuant to § 35.10a of this chapter and any market-based rate service agreement pursuant to a tariff shall not be filed with the Commission. All agreements must, however, be retained and be made available for public inspection and copying at the public utility’s business office during regular business hours and provided to the Commission or members of the public upon request. Any individually executed service agreement for transmission, cost-based power sales, or other generally applicable services that deviates in any material respect from the applicable form of service agreement contained in the public utility’s tariff and all unexecuted agreements under which service will commence at the request of the customer, are subject to the filing requirements of this part.
§ 35.2 Definitions.
(a) Electric service. The term electric service as used herein shall mean the transmission of electric energy in interstate commerce or the sale of electric energy at wholesale for resale in interstate commerce, and may be comprised of various classes of capacity and energy sales and/or transmission services. Electric service shall include the utilization of facilities owned or operated by any public utility to effect any of the foregoing sales or services whether by leasing or other arrangements. As defined herein, electric service is without regard to the form of payment or compensation for the sales or services rendered whether by purchase and sale, interchange, exchange, wheeling charge, facilities charge, rental or otherwise.
(b) Rate schedule. The term rate schedule as used herein shall mean a statement of (1) electric service as defined in paragraph (a) of this section, (2) rates and charges for or in connection with that service, and (3) all classifications, practices, rules, or regulations which in any manner affect or relate to the aforementioned service, rates, and charges. This statement shall be in writing and may take the physical form of a contract, purchase or sale or other agreement, lease of facilities, or other writing. Any oral agreement or understanding forming a part of such statement shall be reduced to writing and made a part thereof. A rate schedule is designated with a Rate Schedule number.
(c)(1) Tariff. The term tariff as used herein shall mean a statement of (1) electric service as defined in paragraph (a) of this section offered on a generally applicable basis, (2) rates and charges for or in connection with that service, and (3) all classifications, practices, rules, or regulations which in any manner affect or relate to the aforementioned service, rates, and charges. This statement shall be in writing. Any oral agreement or understanding forming a part of such statement shall be reduced to writing and made a part thereof. A tariff is designated with a Tariff Volume number.
(2) Service agreement. The term service agreement as used herein shall mean an agreement that authorizes a customer to take electric service under the terms of a tariff. A service agreement shall be in writing. Any oral agreement or understanding forming a part of such statement shall be reduced to writing and made a part thereof. A service agreement is designated with a Service Agreement number.
(d) Filing date. The term filing date as used herein shall mean the date on which a rate schedule, tariff or service agreement filing is completed by the receipt in the office of the Secretary of all supporting cost and other data required to be filed in compliance with the requirements of this part, unless such rate schedule is rejected as provided in § 35.5. If the material submitted is found to be incomplete, the Director of the Office of Energy Market Regulation will so notify the filing utility within 60 days of the receipt of the submittal.
(e) Posting (1) The term posting as used in this part shall mean:
(i) Keeping a copy of every rate schedule, service agreement, or tariff of a public utility as currently on file, or as tendered for filing, with the Commission open and available during regular business hours for public inspection in a convenient form and place at the public utility’s principal and district or division offices in the territory served, and/or accessible in electronic format, and
(ii) Serving each purchaser under a rate schedule, service agreement, or tariff either electronically or by mail in accordance with the service regulations in Part 385 of this chapter with a copy of the rate schedule, service agreement, or tariff. Posting shall include, in the event of the filing of increased rates or charges, serving either electronically or by mail in accordance with the service regulations in Part 385 of this chapter each purchaser under a rate schedule, service agreement or tariff proposed to be changed and to each State Commission within whose jurisdiction such purchaser or purchasers distribute and sell electric energy at retail, a copy of the rate schedule, service agreement or tariff showing such increased rates or charges, comparative billing data as required under this part, and, if requested by a purchaser or State Commission, a copy of the supporting data required to be submitted to this Commission under this part. Upon direction of the Secretary, the public utility shall serve copies of rate schedules, service agreements, or tariffs, and supplementary data, upon designated parties other than those specified herein.
(2) Unless it seeks a waiver of electronic service, each customer, State Commission, or other party entitled to service under this paragraph (e) must notify the public utility of the e-mail address to which service should be directed. A customer, State Commission, or other party may seek a waiver of electronic service by filing a waiver request under Part 390 of this chapter providing good cause for its inability to accept electronic service.
(f) Effective date. As used herein the effective date of a rate schedule, tariff or service agreement shall mean the date on which a rate schedule filed and posted pursuant to the requirements of this part is permitted by the Commission to become effective as a filed rate schedule. The effective date shall be 60 days after the filing date, or such other date as may be specified by the Commission.
(g) Frequency regulation. The term frequency regulation as used in this part will mean the capability to inject or withdraw real power by resources capable of responding appropriately to a system operator’s automatic generation control signal in order to correct for actual or expected Area Control Error needs.
§ 35.3 Notice requirements.
(a)(1) Rate schedules or tariffs. All rate schedules or tariffs or any part thereof shall be tendered for filing with the Commission and posted not less than sixty days nor more than one hundred-twenty days prior to the date on which the electric service is to commence and become effective under an initial rate schedule or tariff or the date on which the filing party proposes to make any change in electric service and/or rate, charge, classification, practice, rule, regulation, or contract effective as a change in rate schedule or tariff, except as provided in paragraph (b) of this section, or unless a different period of time is permitted by the Commission. Nothing herein shall be construed as in any way precluding a public utility from entering into agreements which, under this section, may not be filed at the time of execution thereof by reason of the aforementioned sixty to one hundred-twenty day prior filing requirements. The proposed effective date of any rate schedule or tariff filing having a filing date in accordance with § 35.2(d) may be deferred by the public utility making a filing requesting deferral prior to the rate schedule or tariff’s acceptance by the Commission.
(2) Service agreements. Service agreements that are required to be filed and posted authorizing a customer to take electric service under the terms of a tariff, or any part thereof, shall be tendered for filing with the Commission and posted not more than 30 days after electric service has commenced or such other date as may be specified by the Commission.
(b) Construction of facilities. Rate schedules, tariffs or service agreements predicated on the construction of facilities may be tendered for filing and posted no more than one hundred-twenty days prior to the date set by the parties for the contract to go into effect. The Commission, upon request, may permit a rate schedule or service agreement or part thereof to be tendered for filing and posted more than one hundred-twenty days before it is to become effective.
§ 35.4 Permission to become effective is not approval.
The fact that the Commission permits a rate schedule or tariff, tariff or service agreement or any part thereof or any notice of cancellation to become effective shall not constitute approval by the Commission of such rate schedule or tariff, tariff or service agreement or part thereof or notice of cancellation.
§ 35.5 Rejection of material submitted for filing.
(a) The Secretary, pursuant to the Commission’s rules of practice and procedure and delegation of Commission authority, shall reject any material submitted for filing with the Commission which patently fails to substantially comply with the applicable requirements set forth in this part, or the Commission’s rules of practice and procedure.
(b) A rate filing that fails to comply with this Part may be rejected by the Director of the Office of Energy Market Regulation pursuant to the authority delegated to the Director in § 375.307(a)(1)(ii) of this chapter.
§ 35.6 Submission for staff suggestions.
Any public utility may submit a rate schedule, tariff or service agreement or any part thereof or any material relating thereto for the purpose of receiving staff suggestions and comments thereon prior to filing with the Commission.
(a) General rule. All filings made in proceedings initiated under this part must be made electronically, including tariffs, rate schedules and service agreements, or parts thereof, and material that relates to or bears upon such documents, such as cancellations, amendments, withdrawals, termination, or adoption of tariffs.
(b) Requirement for signature. All filings must be signed in compliance with the following:
(1) The signature on a filing constitutes a certification that: the contents are true and correct to the best knowledge and belief of the signer; and that the signer possesses full power and authority to sign the filing.
(2) A filing must be signed by one of the following:
(i) The person on behalf of whom the filing is made;
(ii) An officer, agent, or employee of the company, governmental authority, agency, or instrumentality on behalf of which the filing is made; or,
(iii) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.
(3) All signatures on the filing or any document included in the filing must comply, where applicable, with the requirements in Part 385 of this chapter with respect to sworn declarations or statements and electronic signatures.
(c) Format requirements for electronic filing. The requirements and formats for electronic filing are listed in instructions for electronic filing and for each form. These formats are available through the Commission’s website, https://www.ferc.gov.
(d) Only filings filed and designated as filings with statutory action dates in accordance with these electronic filing requirements and formats will be considered to have statutory action dates. Filings not properly filed and designated as having statutory action dates will not become effective, pursuant to the Federal Power Act, should the Commission not act by the requested action date.
§ 35.8 Protests and interventions by interested parties.
Unless the notice issued by the Commission provides otherwise, any protest or intervention to a rate filing made pursuant to this part must be filed in accordance with §§ 385.211 and 385.214 of this chapter, on or before 21 days after the subject rate filing. A protest must state the basis for the objection. A protest will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make the protestant a party to the proceeding. A person wishing to become a party to the proceeding must file a motion to intervene.
§ 35.9 Requirements for filing rate schedules, tariffs or service agreements.
(a) Rate schedules, tariffs, and service agreements may be filed either by dividing the rate schedule, tariff, or service agreements into individual sheets or sections, or as an entire document except as provided in paragraphs (b) and (c) of this section.
(b) Open Access Transmission Tariffs (OATT) filed by utilities that are not Independent System Operators or Regional Transmission Organizations must be filed either as individual sheets or sections. If filed as sections, the sections must be no larger than the 1.0 level, although each schedule or attachment may be a single section. Individual service agreements that are entered into pursuant to the OATT may be filed as entire documents.
(c) OATT and other open access documents filed by Independent System Operators or Regional Transmission Organizations must be filed either as individual sheets or sections. If filed as sections, the sections must be no larger than the 1.1 level, including schedules or attachments. Individual service agreements that are part entered into pursuant to the OATT may be filed as entire documents.
§ 35.10 Form and style of rate schedules, tariffs and service agreements.
(a) Every rate schedule, tariff or service agreement offered for filing with the Commission under this part, shall show on a title page, which shall be otherwise blank, (1) the name of the filing public utility, (2) the names of other utilities rendering or receiving service under the rate schedule, tariff or service agreement ; and (3) a brief description of the service to be provided under the rate schedule, tariff or service agreement .
(b) At the time a public utility files with the Commission and posts under this part to supersede or change the provisions of a rate schedule, tariff, or service agreement previously filed with the Commission under this part, in addition to the other requirements of this part, it must list in the transmittal letter the sheets or sections revised, and file a marked version of the rate schedule, tariff or service agreement sheets or sections showing additions and deletions. New language must be marked by either highlighting, background shading, bold text, or underlined text. Deleted language must be marked by strike-through.
(c) In any filing to supersede or change the provisions of a rate schedule, tariff, or service agreement previously filed with the Commission under this part, only those revisions appropriately designated and marked under paragraph (b) of this section constitute the filing. Revisions to unmarked portions of the rate schedule, tariff or service agreement are not considered part of the filing nor will any acceptance of the filing by the Commission constitute acceptance of such unmarked changes.
§ 35.10a Forms of service agreements.
(a) To the extent a public utility adopts a standard form of service agreement for a service other than market-based power sales, the public utility shall include as part of its applicable tariff(s) an unexecuted standard service agreement approved by the Commission for each category of generally applicable service offered by the public utility under its tariff(s). The standard format for each generally applicable service must reference the service to be rendered and where it is located in its tariff(s). The standard format must provide spaces for insertion of the name of the customer, effective date, expiration date, and term. Spaces may be provided for the insertion of receipt and delivery points, contract quantity, and other specifics of each transaction, as appropriate.
(b) Forms of service agreement submitted under this section shall be filed electronically as prescribed in § 35.7 for the filing of rate schedules.
§ 35.10b Electric Quarterly Reports.
Each public utility as well as each non-public utility with more than a de minimis market presence shall file an updated Electric Quarterly Report with the Commission covering all services it provides pursuant to this part, for each of the four calendar quarters of each year, in accordance with the following schedule: for the period from January 1 through March 31, file by April 30; for the period from April 1 through June 30, file by July 31; for the period July 1 through September 30, file by October 31; and for the period October 1 through December 31, file by January 31. Electric Quarterly Reports must be prepared in conformance with the Commission’s guidance posted on the FERC Web site (http://www.ferc.gov).
(a) For purposes of this section, the term “non-public utility” means any market participant that is exempted from the Commission’s jurisdiction under 16 U.S.C. 824(f).
The term does not include an entity that engages in purchases or sales of wholesale electric energy or transmission services within the Electric Reliability Council of Texas or any entity that engages solely in sales of wholesale electric energy or transmission services in the states of Alaska or Hawaii.
(b) For purposes of this section, the term “de minimis market presence” means any non-public utility that makes 4,000,000 megawatt hours or less of annual wholesale sales, based on the average annual sales for resale over the preceding three years as published by the Energy Information Administration’s Form 861.
(c) For purposes of this section, the following wholesale sales made by a non-public utility with more than a de minimis market presence are excluded from the EQR filing requirement:
(1) Sales by a non-public utility, such as a cooperative or joint action agency, to its members; and
(2) Sales by a non-public utility under a long-term, cost-based agreement required to be made to certain customers under Federal or state statute.
§ 35.11 Waiver of notice requirement.
Upon application and for good cause shown, the Commission may, by order, provide that a rate schedule or tariff, tariff or service agreement, or part thereof, shall be effective as of a date prior to the date of filing or prior to the date the rate schedule or tariff, tariff or service agreement would become effective in accordance with these rules. Application for waiver of the prior notice requirement shall show (a) how and the extent to which the filing public utility and purchaser(s) under such rate schedule or tariff, tariff or service agreement, or part thereof, would be affected if the notice requirement is not waived, and (b) the effects of the waiver, if granted, upon purchasers under other rate schedules. The filing public utility requesting such waiver of notice shall serve copies of its request therefor upon all purchasers.
Subpart B—Documents To Be Submitted With a Filing
§ 35.12 Filing of initial rate schedules and tariffs.
(a) The letter of a public utility transmitting to the Commission for filing an initial rate schedule or tariff shall list the documents submitted with the filing; give the date on which the service under that rate schedule or tariff is expected to commence; state the names and addresses of those to whom the rate schedule or tariff has been mailed; contain a brief description of the kinds of services to be furnished at the rates specified therein; and summarize the circumstances which show that all requisite agreement to the rate schedule or tariff or the filing thereof, including any contract embodied therein, has in fact been obtained. In the case of coordination and interchange arrangements in the nature of power pooling transactions, all supporting data required to be submitted in support of a rate schedule or tariff filing shall also be submitted by parties filing certificates of concurrence, or a representative to file supporting data on behalf of all parties may be designated as provided in § 35.1.
(b) In addition, the following material shall be submitted:
(1) Estimates of the transactions and revenues under an initial rate schedule. This shall include estimates, by months and for the year, of the quantities of services to be rendered and of the revenues to be derived therefrom during the 12 months immediately following the month in which those services will commence. Such estimates should be subdivided by classes of service, customers, and delivery points and shall show all billing determinants, e.g., kw, kwh, fuel adjustment, power factor adjustment. These estimates will not be required where they cannot be made with relative accuracy as, for example, in cases of interconnection arrangements containing schedules of rates for emergency energy, spinning reserve or economy energy or in cases of coordination and integration of hydroelectric generating resources whose output cannot be predicted quantitatively due to water conditions.
(2)(i) Basis of the rate or charge proposed in an initial rate schedule or tariff and an explanation of how the proposed rate or charge was derived. For example, is it a standard rate of the filing public utility; is it a special rate arrived at through negotiations and, if so, were unusual customer requirements or competitive factors involved; and is it designed to produce a return substantially equal to the filing public utility’s overall rate of return or is it essentially an increment cost plus a share of the savings rate? Were special cost of service studies prepared in connection with the derivation of the rate?
(ii) A summary statement of all cost (whether fully distributed, incremental or other) computations involved in arriving at the derivation of the level of the rate, in sufficient detail to justify the rate, shall be submitted with the filing, except that if the filing includes nothing more than service to one or more added customers under an established rate of the utility for a particular class of service, such summary statement of cost computations is not required. In all cases, the Secretary is authorized to require the submission of the complete cost studies as part of the filing and each filing public utility shall submit the same upon request by the Secretary in such form as he or she shall direct.
(3) A comparison of the proposed initial rate with other rates of the filing public utility for similar wholesale for resale and transmission services.
(4) If any facilities are installed or modified in order to supply the service to be furnished under the proposed rate schedule or tariff, the filing public utility shall show on an appropriate available map (or sketch) and single line diagram the additions or changes to be made.
(5) In support of the design of the proposed rate, the filing public utility shall submit the same material required to be furnished pursuant to § 35.13(h)(37) Statement BL. In addition to the summary cost analysis required by Statement BL, the public utility shall also submit a complete explanation as to the method used in arriving at the cost of service allocated to the sales and service for which the rate or charge is proposed, and showing the principal determinants used for allocation purposes. In connection therewith, the following data should be submitted:
(i) In the event the filing public utility considers certain special facilities as being devoted entirely to the service involved, it shall show the cost of service related to such special facilities.
(ii) Computations showing the energy responsibility of the service, based upon considerations of energy sales under the proposed rate schedule or tariff and the kWh delivered from the filing public utility’s supply system.
(iii) Computations showing the demand responsibility of the service, and explaining the considerations upon which such responsibility was determined (e.g., coincident or non-coincident peak demands, etc.).
§ 35.13 Filing of changes in rate schedules, tariffs or service agreements.
(a) General rule. Every public utility shall file the information required by this section, as applicable, at the time it files with the Commission under § 35.1 all or part of a rate schedule, tariff or service agreement to supersede or otherwise change the provisions of a rate schedule, tariff or service agreement filed with the Commission under § 35.1. Any petition filed under § 385.207 of this chapter for waiver of any provision of this section shall specifically identify the requirement that the applicant wishes the Commission to waive.
(1) Filing for any rate schedule change or tariff not otherwise excepted. Except as provided in paragraph (a)(2) of this section, any utility that files a rate schedule, tariff, or service agreement change shall submit with its filing the information specified in paragraphs (b), (c), (d), (e), and (h) of this section, in accordance with paragraph (g) of this section.
(2) Abbreviated filing requirements—(i) For certain small rate increases. Any utility that files a rate increase for power or transmission services not covered by paragraph (a)(2)(ii) of this section may elect to file under this paragraph instead of paragraph (a)(1) of this section, if the proposed increase for the Test Period, as defined in paragraph (a)(2)(i)(A) of this section, is equal to or less than $200,000, regardless of customer consent, or equal to or less than $1 million if all wholesale customers that belong to the affected rate class consent.
(A) Definition: The Test Period, for purposes of paragraph (a)(2)(i) of this section, means the most recent calendar year for which actual data are available, the last day of which is no more than fifteen months before the date of tender for filing under § 35.1 of the notice of rate schedule.
(B) Any utility that elects to file under this subparagraph must file the following information, conforming its submission to any rule of general applicability and to any Commission order specifically applicable to such utility:
(1) A complete cost of service analysis for the Test Period, consistent with the requirements of paragraph (h)(36), Statement BK, of this section.
(2) A complete derivation and explanation of all allocation factors and special assignments, consistent with the information required in § 35.12(b)(5).
(3) A complete calculation of revenues for the Test Period and for the first 12 months after the proposed effective date, consistent with the requirements of paragraph (c)(1) of this section.
(4) If the proposed rates contain a fuel cost or purchased economic power adjustment clause, as defined in § 35.14, the company must provide the derivation of its base cost of fuel (Fb) and its monthly fuel factors (Fm) for the Test Period and the resulting fuel adjustment clause revenues. If any pro forma adjustments affect the fuel clause in any way, the company must show the impact on Fm, kWh sales in the base period (Sm), Fb and kWh sales in the current period (Sb), as well as on fuel adjustment clause revenues.
(5) Rate design calculations and narrative consistent with the information required in paragraph (h)(37) of this section and in § 35.12(b)(5).
(6) The information required in paragraphs (b), (c)(2) and (c)(3) of this section and in § 35.12(b)(2).
(C) Data shall be reconciled with the utility’s most recent FERC Form 1. If the utility has not yet submitted Form 1 for the Test Period, the utility shall submit the relevant Form 1 pages in draft form.
(D) The utility may make pro forma adjustments for post-Test Period changes that occur before the proposed effective date and that are known and measurable at the time of filing. The utility shall provide a narrative statement explaining all pro forma adjustments.
(E) If the utility models its filing in whole or in part on retail rate decisions or settlements, the utility must provide detailed calculations and a narrative statement showing how all retail rate treatments are factored into the cost of service.
(F) If the Commission sets the filing for hearing, the Commission will allow the company a specific time period in which to file testimony, exhibits, and supplemental workpapers to complete its case-in-chief. While not required under this subpart, a utility may elect to submit Statements AA through BM for the Test Period in accord with the requirements of paragraphs (d), (g) and (h) of this section.
(ii) Rate increases for service of short duration or for interchange or coordination service. Any utility that files a rate increase for any service of short duration and of a type for which the need and usage cannot be reasonably forecasted (such as emergency or short-term power), or for service that is an integral part of a coordination and interchange arrangement, may submit with its filing only the information required in paragraphs (b), (c) and (h)(37) of this section and in § 35.12(b)(2) and (b)(5), conforming its submission to any rule of general applicability and to any Commission order specifically applicable to such utility.
(iii) For rate schedule, tariff, or service agreement changes other than rate increases. Any utility that files a rate change that does not provide for a rate increase or that provides for a rate increase that is based solely on a change in delivery points, a change in delivery voltage, or a similar change in service, must submit with its filing only the information required in paragraphs (b) and (c) of this section.
(iv) Computing rate increases. For purposes of this subparagraph and paragraph (d)(2)(ii) of this section, the amount of any rate increase shall be the difference between the total revenues to be recovered under the rate change and the total revenues recovered or recoverable under the rate to be superseded or supplemented and shall be determined by:
(A) applying the components of the rate to be superseded or supplemented to the billing determinants for the twelve months of Period I;
(B) Applying the components of the rate change to the billing determinants for the twelve months of Period I; and
(C) Subtracting the total revenues under subclause (A) from the total revenues under subclause (B).
(3) Cost of service data required by letter. The Director of the Office of Energy Market Regulation may, by letter, require a utility that is not required under paragraph (a)(1) of this section to submit cost of service data to submit such specified cost of service data as are needed for Commission analysis of the rate schedule change.
(b) General information. Any utility subject to paragraph (a) of this section shall file the following general information:
(1) A list of documents submitted with the rate change;
(2) The date on which the utility proposes to make the rate change effective;
(3) The names and addresses of persons to whom a copy of the rate change has been posted;
(4) A brief description of the rate change;
(5) A statement of the reasons for the rate change;
(6) A showing that all requisite agreement to the rate change, or to the filing of the rate change, including any agreement required by contract, has in fact been obtained;
(7) A statement showing any expenses or costs included in the cost of service statements for Period I or Period II, as defined in paragraph (d)(3) of this section, that have been alleged or judged in any administrative or judicial proceeding to be illegal, duplicative, or unnecessary costs that are demonstrably the product of discriminatory employment practices; and
(c) Information relating to the effect of the rate change. Any utility subject to paragraph (a) of this section shall also file the following information or materials:
(1) A table or statement comparing sales and services and revenues from sales and services under the rate schedule, tariff, or service agreement to be superseded and under the rate change, by applying the components of each such rate schedule or tariff to the billing determinants for each class of service, for each customer, and for each delivery point or set of delivery points that constitutes a billing unit:
(i) Except as provided in clause (ii), for each of the twelve months immediately before and each of the twelve months immediately after the proposed effective date of the rate change, and the total for each of the two twelve month periods; or
(ii) At the election of the utility:
(A) If the utility files Statements BG and BH under paragraph (h) for Period I, for each of the twelve months of Period I instead of for the twelve months immediately before the proposed effective date of the rate change; and
(B) If Period II is the test period, for each of the twelve months of Period II instead of for the twelve months immediately after the proposed effective date of the rate change;
(2) A comparison of the rate change and the utility’s other rates for similar wholesale for resale and transmission services; and
(3) If any specifically assignable facilities have been or will be installed or modified in order to supply service under the rate change, an appropriate map or sketch and single line diagram showing the additions or changes to be made.
(d) Cost of service information—(1) Filing of Period I data. Any utility that is required under paragraph (a)(1) of this section to submit cost of service information, or that is subject to the exceptions in paragraphs (a)(2)(i) and (a)(2)(ii) of this section but elects to file such information, shall submit Statements AA through BM under paragraph (h) of this section using:
(i) Unadjusted Period I data; or
(ii) Period I data adjusted to reflect changes that affect revenues and costs prior to the proposed effective date of the rate change and that are known and measurable with reasonable accuracy at the time the rate schedule change is filed, if such utility:
(A) Is not required to and does not file Period II data;
(B) Adjusts all Period I data to reflect such changes; and
(C) Fully supports the adjustments in the appropriate cost of service statements.
(2) Filing of Period II data. (i) Except as provided in clause (ii) of this subparagraph, any utility that is required under paragraph (a)(1) of this section to submit cost of service information shall submit Statements AA through BM described in paragraph (h) using estimated costs and revenues for Period II;
(ii) A utility may elect not to file Period II data if:
(A) The utility files a rate increase that is less than one million dollars for Period I; or
(B) All wholesale customers that belong to the affected rate class have consented to the rate increase.
(3) Definitions. For purposes of this section:
(i) Period I means the most recent twelve consecutive months, or the most recent calendar year, for which actual data are available, the last day of which is no more than fifteen months before the date of tender for filing under § 35.1 of the notice of rate change;
(ii) Period II means any period of twelve consecutive months after the end of Period I that begins:
(A) No earlier than nine months before the date on which the rate change is proposed to become effective; and
(B) No later than three months after the date on which the rate change is proposed to become effective.
(4) Test period. If Period II data are not submitted for Statements AA through BM, Period I shall be the test period. If Period II data are submitted for Statements AA through BM, Period II shall be the test period.
(5) Work papers. A utility that files adjusted Period I data or that files Period II data shall submit all work papers relating to such data. The utility shall provide a comprehensive explanation of the bases for the adjustments or estimates and, if such adjustments or estimates are based on a regularly prepared corporate budget, shall include relevant excerpts from such budget. Work papers and documents containing additional explanatory material shall be provided in electronic format, shall be legible, shall be assigned page numbers, and shall be marked, organized and indexed according to:
(A) Subject matter;
(B) The cost of service statements to which they apply; and
(C) Witness.
(6) Attestation. A utility shall include in its filing an attestation by its chief accounting officer or another of its officers that, to the best of that officer’s knowledge, information, and belief, the cost of service statements and supporting data submitted under this paragraph are true, accurate, and current representations of the utility’s books, budgets, or other corporate documents.
(e) Testimony and exhibits—(1) Filing requirements. (i) A utility subject to paragraph (a)(1) of this section shall file Statements AA through BM under paragraph (h) as exhibits with its rate change and may file any other exhibits in support of its rate schedule change.
(ii) A utility subject to paragraph (a)(1) of this section shall file prepared testimony. Such testimony shall include an explanation of all exhibits, including Statements AA through BM, and shall include support for all adjustments to book or budgeted data relied on in preparing the exhibits.
(iii) To the extent that testimony and exhibits other than Statements AA through BM duplicate information required to be submitted in such statements, the testimony and exhibits may incorporate such information by referencing the specific statement containing such material.
(2) Case in chief. In order to avoid delay in processing rate filings, such cost of service statements, testimony, and other exhibits described in paragraph (e)(1) of this section shall be the utility’s case in chief in the event the matter is set for hearing.
(3) Burden of proof. Any utility that files a rate increase shall be prepared to go forward at a hearing on reasonable notice on the data submitted under this section, to sustain the burden of proof under the Federal Power Act of establishing that the rate increase is just and reasonable and not unduly discriminatory or preferential or otherwise unlawful within the meaning of the Act.
(f) Filing by parties concurring in coordination and interchange arrangements. For coordination and interchange arrangements in the nature of power pooling transactions, all information required to be submitted in support of a rate change under paragraphs (a)(1), (2), and (3) of this section shall be submitted by each party filing a certificate of concurrence under § 35.1. If a representative is designated and authorized in accordance with § 35.1 to file supporting information on behalf of all parties to a rate change, such filing shall fulfill the requirement in this paragraph for individual submittals by each party.
(g) Commission precedents and policy. If a utility submits cost of service data under paragraph (d) of this section, it shall conform all such submissions to any rule of general applicability and to any Commission order specifically applicable to such utility.
(h) Cost of service statements. Any utility subject to paragraph (a)(1) of this section shall submit the following Statements AA through BM in accordance with the requirements of paragraphs (d) and (g) of this section.
(1) Statement AA—Balance sheets. Statement AA consists of balance sheets as of the beginning and the end of both Period I and Period II, and the most recently available balance sheet, including any applicable notes, and an explanation of any significant accounting changes since the most recent filing by the utility under this section that involves the same wholesale customer rate class. Balance sheets shall be constructed in accordance with the annual report form for electric utilities specified in part 141.
(2) Statement AB—Income statements. Statement AB consists of income statements for both Period I and Period II, and the most recently available income statement, including any applicable notes, and an explanation of any significant accounting changes since the most recent filing by the utility under this section that involves the same wholesale customer rate class. Income statements shall be prepared in accordance with the annual report form for electric utilities specified in part 141.
(3) Statement AC—Retained earnings statements. Statement AC consists of retained earnings statements for both Period I and Period II, and the most recently available retained earnings statement, including any notes applicable thereto. Retained earnings statements shall be prepared in accordance with the annual report form for electric utilities specified in part 141.
(4) Statement AD—Cost of plant. Statement AD is a statement of the original cost of total electric plant in service according to functional classification for Period I and Period II. If the plant functions and subfunctions for Period I and Period II are different, the utility shall explain and justify the differences.
(i) For each separately identified function and subfunction of production plant or transmission plant, the utility shall state the original cost as of the beginning of the first month and the end of each month of both Period I and Period II, with an average of the thirteen balances for each period. If any of the Period I or Period II thirteen monthly balances is not available or is unrepresentative of the current plan of the utility for plant in service, the utility shall provide an explanation of the relevant circumstances.
(ii) For each separately identified function and subfunction of plant other than production or transmission, the utility shall state the original cost as of the beginning and the end of both Period I and Period II, with an average of the beginning and end balances for each period. If any of the Period I or Period II balances is not available or is unrepresentative of the current plan of the utility for plant in service, the utility shall provide an explanation of the relevant circumstances.
(iii) The utility shall show the electric plant in service in accordance with each of the following five major functional classifications:
(A) Production;
(B) Transmission;
(C) Distribution;
(D) General and Intangible; and
(E) Common and Other.
(iv) To the extent feasible, the utility shall show completed construction not classified in accordance with clause (iii) in accordance with tentative classification to major functional accounts. If this is not feasible, the utility shall describe such facilities as other plant under clause (iii)(E).
(v) If a utility designs its rate change so that subdivision of the major functional classifications is necessary to support the changed rate, the utility shall supply the original cost information for any of the five major functional plant classifications in clause (iii) that are divided into subfunctional categories. If subfunctional original cost information is provided, the utility shall explain the importance of providing such information to support the changed rate. The utility shall describe each subfunctional category in substantive terms, such as steam electric production or high voltage transmission.
(vi) The utility shall select any subfunctional categories, as appropriate, under the following criteria:
(A) Production plant categories shall be established as necessary to segregate costs for production services with special characteristics, such as base, intermediate or peaking load. The utility shall provide a description of each such service and shall list a brief descriptive title for each corresponding subfunctional category.
(B) Transmission plant categories shall be chosen to reflect the extent to which the facilities are proposed to be allocated on a common basis among all or specific segments of utility services. For descriptive purposes, plant may also be categorized according to accounting or engineering terminology, such as high voltage overhead lines. The utility shall provide brief descriptive transmission category titles and explain the basis for the titles. If a utility allocates all transmission plant among utility services on the basis of a single set of allocation data, the utility may show original cost in total without subfunctionalization.
(C) Distribution plant categories shall be selected according to engineering or use characteristics meaningful for allocations or assignments to wholesale services such as substations, overhead lines, meters, or non-wholesale. The utility shall provide brief descriptive distribution category titles and shall explain the basis for the titles.
(D) If the utility divides any general, intangible, common, and other plant functional classifications into subfunctional categories, the subfunctional categories shall be chosen to group together facilities that share a common basis for allocation between wholesale and other electric services. The utility shall provide a brief descriptive title for each general and intangible subfunctional category, and for each common and other subfunctional category, with an explanation of the basis of each category selection. A utility need not divide the functional classifications of plant into subfunctional categories if these functions of plant are allocated in Statement BK on the basis of utility labor expenses.
(E) A separate category shall be provided for each specific assignment of plant reported in Statement BE. Such assignments are applicable principally but not necessarily exclusively to distribution facilities. The utility shall provide brief descriptive titles consistent with Statement BE.
(F) A separate category shall be provided for each exclusive-use commitment of major power supply facilities as required to be reported at Statement BF. The utility shall provide brief descriptive titles consistent with Statement BF.
(5) Statement AE—Accumulated depreciation and amortization. Statement AE is a statement of the accumulated provision for depreciation and amortization of electric plant for Period I and Period II, provided according to major functional classifications selected by the utility in Statement AD under paragraph (h)(4) and divided into the subfunctional categories selected by the utility in Statement AD, to the extent that subfunctionalized data are available.
(i) For each function and subfunction of electric production and transmission plant in service identified in Statement AD, the utility shall set forth the accumulated depreciation and amortization as of the beginning of the first month and the end of each month of both Period I and Period II. The utility shall state an average for each period computed as the average of the thirteen balances.
(ii) For each function and subfunction of electric plant in service other than production or transmission, identified in Statement AD, the utility shall state the accumulated depreciation and amortization as of the beginning and the end of Period I and Period II, with an average of the beginning and end balances for each period.
(iii) If any of the Period I or Period II balances is not available or is unrepresentative of the current plan of the utility for depreciation reserves, the utility shall provide an explanation of the relevant circumstances.
(iv) If accumulated depreciation and amortization data are not available for any subfunction selected in Statement AD, the utility shall:
(A) Provide a comparison of the current depreciation rate of the major functional classification and the depreciation rate estimated to be appropriate to the subfunctional category; and
(B) State and explain the estimation techniques which the utility proposes to utilize in the absence of subfunctional data, such as the proration of accumulated depreciation and amortization data among the subfunctional categories according to the data for electric plant in service in Statement AD. If any of the proposed estimation techniques require data that are not provided elsewhere in the cost of service statements in paragraph (h) of this section, the utility shall supply the necessary data in Statement AE.
(6) Statement AF—Specified deferred credits. Statement AF consists of balances of specified accounts and items which are to be considered in the determination of the net original cost rate base. All required balances are to be stated as of the beginning and end of both Period I and Period II, with an average of the beginning and end balances for each period. If any of the Period I and Period II balances is not available or is unrepresentative of the current operating plan of the utility, the utility shall include an explanation of the relevant circumstances. If subaccounts are maintained to reflect differences in ratemaking treatment among regulatory authorities that have jurisdiction, balances shall be provided in accordance with such subaccounts, with detailed explanations of the bases upon which the subaccounts were established and are maintained. The balances of deferred credits required to be filed in this statement are described in paragraph (h)(6) (i) through (v) of this section. All references to numbered accounts refer to the Commission’s Uniform System of Accounts, 18 CFR part 101.
(i) The utility shall state total electric balances for accumulated deferred investment tax credits Account 255, and shall separate the credits into balances applicable to pre-1971 and post-1970 qualifying property additions. If the utility maintains records to show Account 255 component balances according to the major functional classifications identified in Statement AD under paragraph (h)(4), the utility shall provide the component balances by function. If the data are not available by function, the utility shall describe the procedure by which the utility believes it can reasonably estimate the portion of the total electric balances for each major functional classification. The utility may show by function the component balances obtained by applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements in this paragraph, the utility shall supply in Statement AF the necessary data, such as historical functional patterns of plant additions eligible for the tax credits. The utility shall state whether the Internal Revenue Code General Rule, § 46(f)(1), is applicable with respect to restrictions on credit treatment for ratemaking purposes. If the General Rule is not applicable, the utility shall state which election it has made with respect to special rules for ratable or immediate flow-through for ratemaking purposes.
(ii) The utility shall state the total electric component balances for accumulated deferred income tax Account 281 pertaining to accelerated amortization property. The utility shall show separate components for defense, pollution control, and other facilities. The utility shall show balances for each component and totaled for the electric utility department. If the utility maintains records to show Account 281 component balances according to the major functional classifications identified in Statement AD under paragraph (h)(4), the utility shall provide such component balances. If data are not available by function, the utility shall describe the procedure by which the utility believes it can reasonably estimate the portion of the total electric balances for each major functional classification. The utility may show by function the component balances obtained by applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements in this paragraph, the utility shall supply in Statement AF the necessary data.
(iii) The utility shall state the total electric component balances for accumulated deferred income tax Account 282 pertaining to electric utility property other than accelerated amortization property. The utility shall itemize the balances in Account 282, to the extent data are available, in detail sufficient to identify the specific major properties involved and shall list the balances according to the accounting entries, such as liberalized depreciation, for which interperiod tax allocation was used and included in this account. Component balances shall be shown individually and in total for the electric utility department. If the utility maintains records to show account 282 component balances according to the major functional classifications identified in Statement AD under paragraph (h)(4), the utility shall provide such component balances by function. If the data are not available by function, the utility shall describe the procedure by which the utility believes it can reasonably estimate the portion of the total electric balances for each major functional classification. The utility may show by function the component balances obtained by applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements in this paragraph, the utility shall supply in Statement AF the necessary data, such as historical functional patterns of plant additions.
(iv) The utility shall state the total electric component balances for accumulated deferred income tax Account 283 pertaining to interperiod income tax allocations not related to property. The utility shall itemize in detail balances in Account 283, to the extent data are available, and shall list the balances according to the accounting entries for which interperiod tax allocation was used and included in this account. Component balances shall be shown individually and in total for the electric utility department. If the utility maintains records to show Account 283 component balances according to the major functional classifications identified in Statement AD under paragraph (h)(4), the utility shall provide such component balances by function. If the data are not available by function, the utility shall describe the procedure by which the utility believes it can reasonably estimate the portion of the total electric balances for each major functional classification. The utility may show by function the component balances obtained by applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements in this paragraph, the filing shall supply in Statement AF the necessary data.
(v) The utility shall show electric utility balances for every other item that the utility believes should be included in Statement AF. The utility shall explain the reasons for inclusion of each item.
(7) Statement AG—Specified plant accounts (other than plant in service) and deferred debits. Statement AG is a statement of balances of specified accounts and items that are to be considered in the determination of the net original cost rate base. Except as prescribed in clause (ii), the utility shall state all required balances as of the beginning and the end of Period I and Period II, with an average of the beginning and end balances for each period. If any of the Period I or Period II balances is not available or is unrepresentative of the current operating plan of the utility, the utility shall provide a full explanation of the relevant circumstances. If subaccounts are maintained to reflect differences in ratemaking treatment among regulatory authorities having jurisdiction, the utility shall provide balances in accordance with such subaccounts, with detailed explanations of the bases upon which the subaccounts were established and are maintained. The balances required to be submitted under Statement AG are described in clauses (7)(i) through (vi).
(i) For each separately identified major functional classification selected by the utility in Statement AD, the utility shall state the electric utility land and land rights balances for electric plant held for future use in account 105. If itemized in detail, balances shall be totaled for each major functional classification.
(ii) The utility shall state the electric utility component balances in Accounts 107 and 120.1, individually and in total, for each item of construction work in progress for pollution control facilities, fuel conversion facilities, or any other facilities that qualify for inclusion in rate base under § 35.26. The utility shall state such balances for each major functional and subfunctional classification under Statement AD as of the beginning of the first month and the end of each month of Period I and Period II with an average of the 13 balances for each period.
(iii) For each major functional classification under Statement AD and with respect to property otherwise includable in plant in service, the utility shall state the balances for extraordinary property losses Account 182. If itemized in detail, balances shall be totaled for each major functional classification. The utility shall provide information about Commission authorization for any loss included in Account 182 and shall state when the loss was claimed for tax purposes.
(iv) The utility shall state the total electric component balances for accumulated deferred income taxes Account 190. The component balances in Account 190 shall be itemized in detail and listed according to the accounting entries for which interperiod tax allocation was used. Component balances shall be shown individually and in total for the electric utility department. If the utility maintains records to show Account 190 component balances according to the major functional classifications identified in Statement AD under paragraph (h)(4), the utility shall provide such component balances by function. If the data are not available by function, the filing utility shall describe the procedure by which the utility believes it can reasonably estimate the portion of the total electric balances for each major functional classification. The utility may show by function the component balances obtained by applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements in this paragraph, the utility shall supply in Statement AG the necessary data.
(v) Balances shall be shown for every other item that the utility believes should be included in Statement AG. The utility shall provide support for inclusion of each item, and a brief descriptive title for each such item.
(8) Statement AH—Operation and maintenance expenses. Statement AH is a statement of electric utility operation and maintenance expenses for Period I and Period II provided according to the accounts prescribed by the Commission’s Uniform System of Accounts, 18 CFR part 101.
(i) For Period I and Period II, the utility shall itemize and subtotal all operation and maintenance expenses according to the major functional classifications of Statement AD in paragraph (h)(4) and the subfunctional categories of those classifications. The utility shall further divide the operation and maintenance expenses itemized under the production classification and each of its subfunctional categories to reflect expenses relating to the energy component (list each item by account number and compute fuel costs on an as-burned basis), the demand component, and any other production expenses.
(ii) For Period I and Period II, the utility shall report production operation and maintenance expenses according to appropriate account numbers. The utility shall apply the following principles in developing Period I and Period II production operation and maintenance data for this statement:
(A) Total production operation and maintenance expenses shall be segregated into energy, demand, and other components. The utility shall specifically state and support its criteria for classifications between energy and demand, and for use of the production other classification, such as specific assignments related to sales from particular generating units.
(B) Fuel expense for cost of service purposes shall be the total as-burned expense incurred. If the utility defers a portion of such expense for accounting purposes, the deferral amount shall be separately stated and accompanied by material that shows computational detail in support of such amount. If claimed nuclear fuel expense reflects a change in the estimated net salvage value of nuclear fuel, the utility shall show the amounts involved and explain the relevant circumstances.
(C) If the amount of production fuel expense is significantly affected by abnormal Period I water availability for hydroelectric generation, the utility shall explain how water availability was taken into account in developing projected Period II production fuel expenses.
(iii) For Period I and Period II, the utility shall report operation and maintenance expenses attributable to the transmission and distribution functions according to appropriate account numbers. If Period II transmission and distribution plant data are not provided by subfunctional category in Statement AD, the utility need only provide for Period II total operation and maintenance expenses for each function.
(iv) For Period I and Period II, the utility shall report in total for each period, operation and maintenance expenses incurred under each of the categories of customer accounting, customer service and information, and sales.
(v) For Period I and Period II, the utility shall itemize administrative and general expenses by groups that are directly assignable, such as regulatory Commission expenses, or that are related to selected plant or expense items for which an allocation to wholesale services is independently determinable, such as items related to labor expense or to a category of production plant in service. Administrative and general expenses shall include a detailed itemization of the general advertising Account 930.1 and the miscellaneous general expenses Account 930.2. If Account 930 data are not projected on a detailed basis for Period II, the utility shall provide its best estimate of the Account 930.1 expense items and a descriptive list of expense items anticipated as miscellaneous general expenses in Account 930.2. Where applicable, separate items shall be shown for general plant maintenance, and for common and other plant maintenance.
(vi) In addition to annual production data for Period I and Period II, the utility shall provide monthly expense data by accounts for fuel in Accounts 501, 518, and 547 and purchased power in Account 555. For each type of transaction, such as firm power or economy interchange power, monthly purchased power expense data shall be subtotaled separately for interchange receipts and deliveries. For monthly fuel Accounts 501, 518, and 547, and for each type of purchased power transaction, the monthly data shall identify components to be claimed under the fuel adjustment clause of the utility.
(9) Statement AI—Wages and salaries. Statement AI consists of statements of the electric utility wages and salaries, for Period I and Period II, that are included in operation and maintenance expenses reported in Statement AH.
(i) For Period I and Period II, the utility shall show the distribution of wages and salaries by function according to the form prescribed for operation and maintenance expenses by the Commission’s Uniform System of Accounts, 18 CFR part 101. The statement shall also include by function additional wages and salaries attributable to common and other plant classifications identified in Statement AD in paragraph (h)(4).
(ii) For Period I and Period II, the utility shall show total production wages and salaries, itemized and subtotaled into energy and demand related components in accordance with classifications of Statement AH operation and maintenance production expenses of which production wages and salaries are a part.
(10) Statement AJ—Depreciation and amortization expenses. Statement AJ consists of statements of depreciation and amortization expenses for Period I and Period II.
(i) For Period I and Period II, the utility shall show the depreciation and amortization expenses and the depreciable plant balances of the filing utility, in accordance with major functional classifications selected by the utility in Statement AD under paragraph (h)(4).
(ii) The utility shall divide the major functional classifications of depreciation and amortization expenses shown in clause (i) into the subfunctional categories selected by the utility for electric plant in service in Statement AD, to the extent such data are available.
(iii) If depreciation and amortization expense data are not available for any subfunctional category selected in Statement AD, the utility shall:
(A) Provide a comparison of the current depreciation rate of the major functional classification and the depreciation rate estimated to be appropriate to the subfunctional category; and
(B) State and explain the estimation techniques that the utility utilized in developing each estimated subfunctional depreciation rate. If utilization of such estimation techniques requires data that are not provided elsewhere in the cost of service statements in this paragraph, the utility shall supply such data in Statement AJ.
(iv) For Period I and Period II, the utility shall show the annual depreciation rate applicable to each function and subfunction for which depreciation expense is reported. The utility shall indicate the bases upon which the depreciation rates were established. If the depreciation rates used for Period I or Period II data differ from those employed to support the utility’s prior approved jurisdictional electric rate, the utility shall include in or append to Statement AJ detailed studies in support of such changes. These detailed studies shall include:
(A) Copies of any reports or analyses prepared by any independent consultant or utility personnel to support the proposed depreciation rates; and
(B) A detailed capital recovery study showing by primary account the depreciation base, accumulated provision for depreciation, cost of removal, net salvage, estimated service life, attained age of survivors, accrual rate, and annual depreciation expense.
(11) Statement AK—Taxes other than income taxes. Statement AK consists of statements of taxes other than income taxes for Period I and Period II.
(i) For Period I and Period II, the utility shall itemize and total any taxes other than income taxes according to clauses (i) (A) through (D).
(A) Revenue taxes. The utility shall show total revenue taxes levied by each taxing authority and identify the revenue taxes, under both the present and changed rate, applicable to wholesale services for which a rate change is filed. The utility shall identify revenue taxes associated with each revenue credit item reported in Statement AU under paragraph (h)(21).
(B) Real estate and property taxes. The utility shall itemize and total all real estate and property taxes. If the utility maintains records to show tax component balances according to the major functional classifications identified in Statement AD under paragraph (h)(4), the utility shall supply the component balances by function. If the data are not available by function, the utility shall describe the procedure by which the utility believes it can reasonably estimate the portion of the total electric balances for each major functional classification. The utility may show by function the component balances obtained by applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements in this paragraph, the utility shall supply the necessary data in Statement AK.
(C) Payroll taxes. The utility shall itemize and total all payroll taxes. If the utility maintains records to show tax component balances according to the major functional classifications identified in Statement AD in paragraph (h)(4), the utility shall provide the component balances by function. If the data are not available by function, the utility shall describe the procedure by which the utility believes it can reasonably estimate the portion of the total electric balances for each major functional classification. The utility may show by function the component balances obtained by applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements in this paragraph, the utility shall provide the necessary data in Statement AK.
(D) Miscellaneous taxes. The utility shall itemize and total all miscellaneous taxes which are directly assignable or which are related to any selected plant or expense item for which an allocation to wholesale services is independently determinable, such as items related to transmission plant in service or to net distribution plant.
(ii) If any of the taxes itemized under clause (11)(i) are levied by a taxing authority that is a customer, or is related to a customer, whose services would be affected by the changed rate schedule, the utility shall show amounts of such taxes according to the taxing authority, identify the related customer, and provide an explanation of the relevant circumstances.
(12) Statement AL—Working capital. Statement AL consists of statements for Period I and Period II designed to establish the need for working capital to maintain adequate levels of operating supplies, to meet required prepayments, and to meet ongoing cash disbursements that must be made at a time different than related revenue receipts for utility services rendered.
(i) Supplies and prepayments. The utility shall supply statements to show monthly balances of operating supplies and prepayments itemized under clauses (i) (A) through (C). The utility shall state all required balances as of the beginning of the first month and the end of each month of both Period I and Period II, with an average of the thirteen balances for each period. If any of the Period I or Period II balances is not available or is unrepresentative of the current operating plan of the utility for supplies or prepayments, the utility shall include an explanation of the relevant circumstances. Operating supply and prepayment balances shall be itemized under the following categories:
(A) Fuel supplies. The utility shall state the fuel supply balances for each type of electric utility production plant, except hydraulic. The utility shall describe its overall fossil fuel supply objectives for Period I and Period II, in terms of projected average days of burn for major fossil fuel generating stations, if feasible. The utility shall explain substantial differences, if any, between actual Period I inventories and the target objectives, or between Period II objectives and Period I objectives. Nuclear fuel balances shall include fuel in stock, fuel in the reactor and spent fuel in the process of cooling in Accounts 120.2, 120.3, 120.4, less accumulated provisions for amortization of nuclear fuel assemblies in Account 120.5.
(B) Plant materials and operating supplies. The utility shall state materials and operating supply balances for each of the major electric utility operating functions of production, transmission, and distribution, and for each significant type of miscellaneous operating supplies. Miscellaneous supplies shall be grouped to facilitate suitable allocations or assignments among utility services.
(C) Prepayments. The utility shall indicate prepayment balances for each major prepayment item, with a brief description of the item. Balances shall be grouped and subtotaled to facilitate suitable allocations or assignments among utility services.
(ii) Cash working capital. The utility shall indicate average monthly working cash requirements that reflect the extent to which day-to-day operational utility service revenues are received later or earlier than cash disbursements necessary to provide the services, with an explanation of how such requirements are derived.
(13) Statement AM—Construction work in progress. Statement AM is a statement of the amount of construction work in progress described according to functional classification for Period I and Period II. For production plant and transmission plant, the utility shall state the balances as of the beginning of the first month and the end of each month of both Period I and Period II, with an average of the 13 balances for each period. For each function of plant identified in Statement AD other than production or transmission, the utility shall state the balances as of the beginning and the end of both Period I and Period II, with an average of the beginning and end balances for each period. If any Period I or Period II balance is not available, the utility shall include monthly estimates and an explanation of the relevant circumstances. Pollution control facilities, fuel conversion facilities, or other construction amounts reported in Statement AG shall be excluded from amounts reported in this Statement.
(14) Statement AN—Notes payable. Statement AN is a statement of the electric utility portion of average notes payable for Period I and Period II. The utility shall indicate balances as of the beginning of the first month and the end of each month of both Period I and Period II, with an average of the thirteen balances for each period. If any of the Period I or Period II balances is not available or is unrepresentative of the current financing plan of the utility, the utility shall provide an explanation of the relevant circumstances. If a utility has operations other than electric, the utility shall also show allocations between electric and other utility departments on an appropriate basis, such as the average amount of construction work in progress and net plant.
(15) Statement AO—Rate for allowance for funds used during construction. Statement AO is a statement of the basis of the rate for computing the allowance for funds used during construction (AFUDC) for Period I and Period II.
(i) The utility shall show the computations of the maximum rates for the construction allowances computed in accordance with plant instructions of the Commission’s Uniform System of Accounts, 18 CFR part 101. The utility shall show the rates computed annually, and shall provide the rates for each annual period that includes any part of Period I or Period II. If the utility proposes to use a net-of-tax rate, the utility shall show the derivation for both the gross-of-tax and net-of-tax rates.
(ii) If the book allowance amounts of AFUDC do not reflect the maximum rates for allowances for funds computed in accordance with clause (i), the utility shall show the derivation for the actual rates utilized in computing AFUDC, including derivation of any net-of-tax rate utilized by the utility.
(16) Statement AP—Federal income tax deductions—interest. Statement AP is a statement of electric utility interest charges for Period I and Period II. For each period, the utility shall state the total electric utility interest in terms of three or more component items described in clauses (i) through (iv).
(i) The utility shall state the allowance for borrowed funds used for electric utility construction Account 432 as a separate component. The utility shall show supporting detail, including computation of the amounts on the basis of AFUDC rates claimed in Statement AO.
(ii) The utility shall state interest for borrowed funds used for electric utility construction Account 431 as a separate component. If applicable, the utility shall also show all elements of Account 431 related to purposes other than electric utility construction, with detailed supporting material, such as a computation of allocations between electric and other utility departments with explanatory material to support the bases of such allocations.
(iii) The utility shall state the interest on long-term debt required for electric rate base investment as a separate component. The interest amount shall be consistent with that shown and utilized in Statement BK under paragraph (h)(36) of this section.
(iv) The utility shall show other interest items appropriate in the determination of net taxable income allocable to the wholesale services at issue. The utility shall describe and support each item and shall accompany each item with a statement of the basis on which the item is allocable to the wholesale services. The utility shall also list a short descriptive title for each item.
(17) Statement AQ—Federal income tax deductions—other than interest. Statement AQ is a statement of other deductions from net operating income before Federal income taxes, for Period I and Period II, which deductions are appropriate in determining the net taxable income allocable to the wholesale services subject to the changed rate. The utility shall show unallowable deductions as negative entries in this statement. The utility shall itemize deductions in accordance with clause (i) through (iii) and individually identify each by a brief descriptive title.
(i) The utility shall report, as a separate component of this statement, the difference between tax and book depreciation, in total, or in individual amounts based on the Internal Revenue Code provisions that permit the utility to use various methods of computing depreciation for tax purposes, such as liberalized depreciation or the asset depreciation range. If the utility reports the differences in total only, it shall list the specific Internal Revenue Code provisions that result in the difference.
(ii) The utility shall state taxes and pensions capitalized as a separate component.
(iii) The utility shall describe and support other deduction items appropriate in the determination of net taxable income allocable to the wholesale services. Each item shall be accompanied by a brief explanation of the basis on which the item is allocable to the wholesale services.
(18) Statement AR—Federal tax adjustments. Statement AR is a statement of adjustments to Federal income taxes for Period I and Period II. If subaccounts are maintained to reflect differences in ratemaking treatment among regulatory authorities having jurisdiction, the utility shall provide adjustment amounts in accordance with such subaccounts. The utility shall report detailed explanations of the bases upon which the subaccounts were established and are maintained.
(i) For each major function of plant identified in Statement AD under paragraph (h)(4), the utility shall state the electric utility component adjustment for the Federal portions of the provision for deferred income tax Account 410.1. If the data are not available by function, the utility shall state the amounts for the total electric utility and shall describe the procedure by which the utility believes it can reasonably estimate the portion of the total electric balances for each major functional classification. The utility may show by function the component balances obtained by applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements in this paragraph, the utility shall supply in Statement AR the necessary data. The utility shall provide the adjustment amounts for total electric and, to the extent available for each such major functional component, accompanied by summary totals segregated in accordance with related balance sheet Accounts 281, 282, 283, and 190 [see Statements AF and AG]. Account 190 items require a negative sign for entries in Statement AR. The utility shall identify the summarized items by account number.
(ii) The utility shall provide for the Federal portions of the provision for deferred income tax-credit Account 411.1 the data required by clause (i) for Account 410.1.
(iii) For each major functional classification of plant identified in Statement AD under paragraph (h)(4), the utility shall provide the electric utility component for investment tax credits generated for Period I and Period II, credits utilized for each period, and the allocations to current income for each period. If the data are not available by function, the utility shall state the amounts for total electric utility and shall describe the procedure by which the utility believes it can reasonably estimate the portion of the total electric balances for each major functional classification. The utility may show by function the component balance obtained by applying the procedure. If such estimation requires data that are not provided elsewhere in the cost of service statements in this paragraph, the utility shall supply in Statement AR the necessary data. If itemized in detail, balances shall be subtotaled for each major function, and totaled for the electric utility department. Detailed data shall be consistent with that provided in Statement AF under paragraph (h)(6) of this section.
(iv) The utility shall list and designate as other adjustment items any additional Federal income tax adjustments and shall provide a brief descriptive title for each item. The utility shall explain the reasons for inclusion of each item, and shall indicate the basis on which each will be assigned or allocated to the wholesale services subject to the changed rate and to the other electric utility services.
(19) Statement AS—Additional state income tax deductions. Statement AS is a listing of state income tax deductions for Period I and Period II, in addition to those listed at Statements AP and AQ for Federal tax purposes. The utility shall explain the reasons for inclusion of each item. The utility shall indicate the basis on which each item is to be assigned or allocated to the wholesale services at issue and to the other electric utility services. If applicable, the utility shall show unallowable deductions as negative entries in this statement. The utility shall provide the percentage of Federal income tax payable which is deductible for state income tax purposes, if applicable. [See also Statement AY, dealing with tax rate data.]
(20) Statement AT—State tax adjustments. Statement AT is a statement of adjustments to state income taxes for Period I and Period II. The utility shall prepare and present the data in statement AT as prescribed for Federal tax adjustments in Statement AR. The utility shall annotate Statement At data as necessary to identify state tax adjustments that are not properly deductible for Federal tax purposes.
(21) Statement AU—Revenue credits. Statement AU is, for Period I and Period II, a statement of the operating revenue balances in Accounts 450 through 456, and other revenue items, such as short-term sales in Account 447, that are appropriately credited to the cost of service for determinations of costs allocable to the wholesale services subject to the changed rate. The utility shall include revenue credits proposed for exclusive-use commitment of major power supply facilities according to instructions for preparation of Statement BF under paragraph (h)(31) of this section. When applicable, the utility shall state revenue taxes for each revenue credit item. The utility shall explain the reasons for inclusion of each item, and shall indicate the basis for assigning or allocating each item to the wholesale services subject to the changed rate and to the other electric utility services.
(22) Statement AV—Rate of return. Statement AV is a statement and explanation of the percentage rate of return requested by the utility. The utility shall provide the complete capital structure, including ratios, component costs and weighted component costs claimed by the utility. The utility shall submit additional data where any component of the capital of the utility is not primarily obtained through its own financing, but is primarily obtained from a company by which the utility is controlled, as defined in the Commission’s Uniform System of Accounts, 18 CFR part 101. The utility shall submit the additional data, if required with respect to the debt capital, preferred stock capital and common stock capital of such controlling company or any intermediate company through which such funds have been secured.
(i) General. The utility shall show, based on the capitalization of the utility, the cost of debt capital and preferred stock capital, the claimed rate of return on the common equity of the utility and the resulting overall rate of return requested.
(A) For Period I and, if applicable, Period II, the utility shall show in tabular form the following:
(1) Cost of each capital element, including claimed rate of return on equity capital;
(2) Capitalization amounts and ratios;
(3) Weighted cost of each capital element; and
(4) Overall claimed rate of return.
(B) When a Period II filing is submitted the utility shall provide:
(1) A full explanation of, and supporting work papers for, the pro forma adjustments to the actual capitalization data to arrive at the Period II capitalization; and
(2) The pro forma adjustment to Period I data to arrive at the Period II amount for unappropriated undistributed subsidiary earnings in Account 216.1.
(C) If not included elsewhere in the filing, the utility shall submit the amount for Account 216.1 for Period I as part of this statement.
(ii) Debt capital. (A) The utility shall show the weighted cost for all issues of long-term debt capital as of the end of Period I, as expected on the date the changed rate is filed, and, if applicable, as estimated for the end of Period II. The weighted cost is calculated by: (1) Multiplying the cost of money for each issue under clause (B)(6) below by the principal amount outstanding for each issue, which yields the annualized cost for each issue; and (2) adding the annual cost of each issue to obtain the total for all issues, which is divided by the total principal amount outstanding for all issues to obtain the weighted cost for all issues.
(B) The utility shall show the following for each class and series of long-term debt outstanding as of the end of Period I, as expected on the date the changed rate is filed, and, if applicable, as estimated to be outstanding as of the end of Period II.
(1) Title;
(2) Date of offering and date of maturity;
(3) Interest rate;
(4) Principal amount of issue;
(5) Net proceeds to the utility;
(6) Cost of money, which is the yield to maturity at issuance based on the interest rate and net proceeds to the utility determined by reference to any generally accepted table of bond yields;
(7) Principal amount outstanding;
(8) Name and relationship of issuer and if the debt issue was issued by an affiliate; and
(9) If the utility has acquired at a discount or premium some part of the outstanding debt which could be used in meeting sinking fund requirements, or for some other reason, the annual amortization of the discount or premium for each issue of debt from the date of the reacquisition over the remaining life of the debt being retired. The utility shall show separately the total discount and premium to be amortized, and the amortized amount applicable to Period I and, if applicable, Period II.
(C) The utility shall show the before-tax interest coverage, for the twelve months of Period I based on the indenture requirements. The utility shall provide a copy of the work papers used to make the calculations, with explanations appropriate to understand the calculations.
(iii) Preferred stock and preference stock capital. (A) This statement shall show the weighted cost for all issues of preferred and preference stock capital as of the end of Period I, as expected on the date the changed rate is filed, and, if applicable, as estimated for the end of Period II. The weighted cost is calculated by: (1) Multiplying the cost of money for each issue under clause (B)(9) by the par amount outstanding for each issue, which yields the annualized cost for each issue; and (2) adding the annual cost of each issue to obtain the total for all issues, which is divided by the total par amount outstanding for all issues to obtain the weighted cost for all issues.
(B) The statement shall show for each class and issue of preferred and preference stock outstanding as of the end of Period I, as expected on the date the changed rate is filed, and, if applicable, as estimated to be outstanding as of the end of Period II:
(1) Title;
(2) Date of offering;
(3) If callable, call price;
(4) If convertible, terms of conversion;
(5) Dividend rate;
(6) Par or stated amount of issue;
(7) Net proceeds to the filing utility;
(8) Ratio of net proceeds to gross proceeds received by the filing utility;
(9) Cost of money (dividend rate divided by the ratio of net proceeds to gross proceeds for each issue);
(10) Par or stated amount outstanding; and
(11) If issue is owned by an affiliate, name and relationship of owner.
(iv) Common stock capital. This statement shall show the following information for each sale of common stock during the five-year period preceding the date of the balance sheet for the end of Period I and for each sale of common stock between the end of Period I and the date that the changed rate is filed:
(A) Number of shares offered;
(B) Date of offering;
(C) Gross proceeds at offering price;
(D) Underwriters’ commissions;
(E) Dividends per share;
(F) Net proceeds to company;
(G) Issuance expenses; and
(H) Whether issue was offered to stockholders through subscription rights or to the public and whether common stock was issued for property or for capital stock of others.
(v) Supplementary financial data. The utility shall submit a statement indicating the sources and uses of funds for Period I and as estimated for Period II and a copy of the utility’s most recent annual report to the stockholders. The utility shall also supply a prospectus for its most recent issue of securities and a copy of the latest prospectus issued by any subsidiary of the filing utility or by any holding company of which the filing utility is a subsidiary.
(23) Statement AW—Cost of short-term debt. In Statement AW, the utility shall provide a statement of the cost of capital rate for short-term debt of the utility as of the end of Period I, as expected on the date the proposed rate is filed, and, if applicable, as estimated for the end of Period II, with details supporting each stated cost. The short-term debt rate shown in Statement AW shall include only the short-term debt that appears on the income statement as interest expense and shall not include nominal forms of financing, such as trust agreements.
(24) Statement AX—Other recent and pending rate changes. Statement AX is a statement describing the extent to which operating revenues are subject to refund for Period I and, if applicable, Period II, for each rate change filed with any Federal, state, or other regulatory body that has jurisdiction. The utility shall list and submit any orders in which applications for a rate increase have been acted on by any regulatory body during Period I, Period II, or the interval between Period I and Period II, and a copy of each transmittal letter or equivalent written document by which a utility summarized and submitted any pending applications that have not been acted on. Statement AX shall reflect information available at the time of submittal under this paragraph. Notwithstanding any other provision of this section, Statement AX is required to be filed only if the proposed rate design tracks retail rates.
(25) Statement AY—Income and revenue tax rate data. (i) Statement AY is a statement of tax rate data for Period I and Period II arranged as follows:
(A) Nominal Federal income tax rate;
(B) Nominal state income tax rate;
(C) Proportion of Federal income taxes payable which is deductible for state income tax purposes. If an allowable deduction is stated in other terms, the utility shall provide an estimate of the effective deduction as a percentage of Federal tax payable; and
(D) Revenue tax rate. If the revenue tax rate is scaled, the utility shall show approximate weighted average rates for relevant revenue levels and full supporting data.
(ii) If the utility serves in more than one jurisdiction for revenue or state income tax purposes, the utility shall state the appropriate tax rates for each wholesale customer group at issue and for all other customers as a composite group. [See, Statement BA under paragraph (h)(26) for wholesale customer grouping criteria.] If there are any changes in tax rates that occur in Period I or that may occur in Period II, the utility shall describe such changes and the effective date of the changes.
(26) Statement BA—Wholesale customer rate groups. (i) Statement BA is a list of wholesale customers by group for the purpose of:
(A) Allocating the allowable costs of the utility to such customer groups on the basis of electric utility services rendered; and
(B) Comparing proposed revenues from each customer group with the cost of service as allocated to that group.
(ii) The utility shall limit the number of wholesale customer groups listed to the minimum required under the following criteria:
(A) At least one customer group shall be specified for each separate wholesale rate subject to the changed rate filing.
(B) In general, all customers proposed to be served on the same rate shall be included in a common group. If the utility believes that there are significant differences in services provided under the same rate, the utility shall subdivide the common group served by the same rate into separate customer groups characterized by the type of service provided each group and shall demonstrate whether the common rate is cost-based by means of cost-justification for each service group. Certain customer groupings, such as cooperatives or municipals, may also be utilized to facilitate purchaser evaluations of the changed rate.
(C) In all cases, the utility shall select customer groupings on a basis consistent with rate design information provided in Statement BL under paragraph (h)(37) of this section.
(iii) The utility shall enumerate all wholesale customer rate groups, together with a brief descriptive title for each group. For example:
Group 1. Full Requirements Tariff
Group 2. Partial Requirements Tariff PR–1.
(27) Statement BB—Allocation demand and capability data. Statement BB is a statement of electric utility demand and capability data for Period I and Period II to be considered as a basis for allocating related costs to the wholesale services subject to the changed rate.
(i) For each month of Period I and Period II, with an average for each period, the utility shall show the maximum peak firm kilowatt demand on the power supply system of the utility, and the kilowatt demands of the wholesale services that coincide with the system monthly maximum power supply demand, including for Period I the date and hour for such coincidental peak demands. The utility shall state these kilowatt demands in terms of 60-minute intervals or other intervals adjusted to the equivalent of 60 minutes. The utility shall not include in the data the demands associated with interruptible power supply services, firm or nonfirm transmission wheeling services, or demands associated with other services the revenues from which are shown as revenue credits in Statement AU under paragraph (h)(21). The utility shall provide wholesale service demand data as follows:
(A) The wholesale service data for each individual customer delivery point or set of delivery points that constitutes an individual wholesale customer billing unit shall include demands at delivery. The individual customer wholesale service data shall be summarized and subtotaled in accordance with Statement BA customer groupings.
(B) The data supplied for each wholesale customer group under clause (A) shall be adjusted for losses to reflect demand at the power supply level. The data shall be totaled to show total customer group demand at power supply level for each month of Period I and Period II.
(ii) To the extent such data are available, the utility shall state Period I and Period II monthly maximum demand data for interruptible power supply services, firm wheeling services, and nonfirm wheeling services. The utility shall also provide, to the extent data are available, firm wheeling demand data for any of the 60-minute periods that coincide with the times of power supply peak demands shown under clause (i). The utility shall indicate the basis of all demands, such as metered demands or contract demands, reported under this clause. For interruptible services, the utility shall provide a description of the conditions under which service may be interrupted or curtailed. The utility shall include available information on actual interruptions or curtailments during a three-year period that includes Period I. If any of the wholesale rates at issue are for interruptible or curtailable service, the utility shall provide any demand data specifically relevant to such service.
(iii) If a utility establishes plant categories in Statement AD under paragraph (h)(4) of this section for the purpose of supporting wholesale rates for firm power supply services with special characteristics, such as base load, intermediate, or peaking, the utility shall provide in Statement BB the demand data required by clause (i) in total and in separate corresponding demand values consistent with the service characteristics. Corresponding values shall be stated for the system demand of the utility, and for each applicable wholesale service group.
(iv) If a utility establishes plant categories in Statement AD under paragraph (h)(4) of this section for the purpose of supporting wholesale rates for nonfirm power supply services, such as capacity sales, the utility shall include in Statement BB for each month of Period I and Period II the monthly capability data relied on by the utility in developing costs allocable to such rates, with an explanation of the underlying cost allocation rationale.
(v) If a utility establishes production plant categories in Statement AD under paragraph (h)(4) of this section for the purpose of supporting wholesale rates based on specialized ratemaking theories such as marginal cost pricing, time-of-day pricing, or base, intermediate, and peaking characteristics, the utility shall include in Statement BB all demand and capability data relied on by the utility in developing support on a cost of service basis, with appropriate explanatory material.
(vi) For each month of Period I and Period II, the utility shall provide any additional demand data that the utility believes to be relevant to the allocation of electric utility costs to the wholesale services at issue. The utility shall fully support all such data and shall explain the rationale and the specific application proposed.
(vii) Based upon information reported in Statements BB and BC, the utility shall list selected months that are normally the months of greatest significance in determining the need of the utility for power supply capability throughout the year. All twelve months may be selected, if appropriate. In its selection, the utility shall take into account any effects of local weather seasons and, particularly, the extent to which peak demands may tend to be similar in magnitude in two or more months of a weather season. The utility shall explain the reasons for the selections and describe the significance for the selections of seasonal variations in the weather.
(28) Statement BC—Reliability data. Statement BC is a statement relating to reference standards of the filing utility for electric power supply reliability, and to information designed to reflect monthly availability of generating capacity reserves.
(i) For Period II, Period I, and each of the three calendar years preceding Period I, the utility shall state and briefly explain its objective reference standard of production power supply reliability and the rationale underlying its choice of a reliability standard, including whether it participates with other electric utilities in the selection of a common standard on an area or pool basis. The utility shall identify any such participating utilities, and provide a general explanation of the basis upon which the reliability standard was jointly developed.
(ii) The utility shall describe how its objective standard for production power supply reliability affects its electric generating facility construction planning and purchased power planning.
(iii) For the peak day of each month of Period II, Period I, and, to the extent data are available, for the peak day of each month of the three calendar years preceding Period I, the utility shall include tabular schedules designed to show the following:
(A) Net peak load in megawatts, itemized to show:
(1) Gross peak firm load, including all firm sales assured available by the reserve capacity of the utility;
(2) All firm purchases assured available by the reserve capacity of the supplier; and
(3) Net peak load, computed as gross peak load under clause (1) minus all firm purchases under clause (2).
(B) Net available dependable capacity, that is, the load-carrying ability of the electric production facilities determined for the purpose of scheduling capacity in day-to-day operations, provided in megawatts and itemized to show:
(1) The owned dependable capacity of the utility for each production plant category selected in Statement AD under paragraph (h)(4);
(2) Scheduled maintenance of owned dependable capacity of the utility;
(3) Purchased dependable capacity of the utility;
(4) Scheduled maintenance of purchased dependable capacity of the utility; and
(5) Net available dependable capacity, computed as the owned dependable capacity under clause (1), minus scheduled maintenance of owned capacity under clause (2), plus purchased dependable capacity under clause (3), minus scheduled maintenance of purchased capacity under clause (4).
(C) Available reserves in megawatts, which is the net available dependable capacity under clause (iii)(B) minus net peak load under clause (iii)(A).
(D) Available reserves as a percent of peak load, which is the available reserves under clause (iii)(C) divided by net peak load under clause (iii)(A).
(29) Statement BD—Allocation energy and supporting data. Statement BD is a statement of electric utility energy data for Period I and Period II to be considered as bases for allocating related costs to the wholesale services subject to the changed rate.
(i) For each month of Period I and Period II, and as totaled for the twelve months of each period, the utility shall show the megawatt-hours of firm power supply energy required by the system of the utility and the megawatt-hour energy requirements of the wholesale customer groups whose services will be subject to the changed rate. The wholesale service data for each individual customer delivery point or set of delivery points that constitutes an individual wholesale customer billing unit shall include megawatt-hours at delivery. The utility shall summarize and subtotal these individual customer data in accordance with Statement BA customer groupings under paragraph (h)(26). The utility shall show a loss adjustment for each wholesale customer group to reflect energy at the power supply level. The utility shall total the data to show total customer group energy requirements at power supply level for each month of Period I and Period II.
(ii) Data provided under clause (i) shall not include energy associated with interruptible or curtailable services, or energy associated with other services, the revenues from which are shown as revenue credits in Statement AU under paragraph (h)(21) of this section. The utility shall separately state Period I and Period II monthly and total energy data for any such services provided by the utility. If any of the proposed wholesale rates at issue are for interruptible or curtailable service, the utility shall provide descriptive material and energy data specifically relevant to such services.
(iii) If a utility selects subfunctional categories in Statement AD under paragraph (h)(4) of this section for the purpose of supporting any changed wholesale rate for firm power supply services with special characteristics, such as base load, intermediate, and peaking services, the utility shall separate the energy data required by clause (i) into corresponding energy values consistent with the service characteristics and consistent with energy-related expense categories utilized in Statement AH under paragraph (h)(8) of this section. The utility shall state the corresponding values for the utility’s system energy and for each applicable wholesale service group.
(iv) If a utility establishes plant categories in Statement AD under paragraph (h)(4) of this section for the purpose of supporting any changed wholesale rate for nonfirm production services, or the changed wholesale rate based on specialized ratemaking theories [see paragraph (h)(27)(v) of this section], the utility shall include in Statement BD all energy data relied on by the utility in developing the support on a cost of service basis and relevant explanatory material. Energy data provided under this clause shall be consistent with related expense categories utilized in Statement AH under paragraph (h)(8) of this section.
(v) For each month of Period I and Period II, and as totaled for the twelve months of each period, the utility shall show the megawatt-hours generated, itemized in accordance with Statement AD production subfunctional categories, and the megawatt-hours purchased or interchanged, itemized to show each type of transaction, such as firm energy or economy interchanged energy. The utility shall quantitatively reconcile such data with the system allocation energy reported in this statement, and with energy data underlying the fuel and purchased power expense reported in Statement AH.
(30) Statement BE—Specific assignment data. (i) Statement BE is a statement of specific components of the electric costs of service of the utility for Period I and Period II. Statement BE costs of service are those apportioned among wholesale services subject to the rate change and other utility services, on a basis other than:
(A) Demand, capability, or energy data provided in Statements BB and BD;
(B) A proportional relationship based on a selected plant category or expense item for which an allocation to wholesale services is to be independently determined; or
(C) Exclusive-use commitment in Statement BF under paragraph (h)(31) of this section.
(ii) The utility shall include specific assignments considered appropriate by the utility. Typical cost of service components that could be specifically assigned are distribution plant [see examples listed in Statement AD under paragraph (h)(4) of this section], certain total electric wages and salaries provided in Statement AI under paragraph (h)(9) of this section, such as wages and salaries for customer accounting and for customer service and information, and certain administrative and general expense items. [See examples listed in Statement AH under paragraph (h)(8) of this section.]
(iii) The utility shall limit specific assignments to the minimum required to adequately provide for costs not otherwise appropriately allocable.
(iv) For each specific assignment, the utility shall include at least the following information:
(A) Brief descriptive component title, such as distribution substations or rate case expenses;
(B) Total electric amount in dollars;
(C) Wholesale customer group dollar amounts stated individually for each wholesale customer rate group identified in Statement BA under paragraph (h)(26), and stated in total for all such groups; and
(D) Explanation of the basis on which assignments were made, accompanied by supporting detailed computations.
(31) Statement BF—Exclusive-use commitments of major power supply facilities. Statement BF is a statement describing and justifying the commitment to exclusive-use for particular services of all or a stated portion of electric utility generation units or plants, or major transmission facilities.
(i) For Period I and Period II, the utility shall list each transaction in which all or a stated portion of the output of a specified filing utility-owned generating unit or group of units was committed exclusively to a particular customer or group of customers, or to a power pool or similar power supply entity. For each such transaction, the utility shall provide the following information:
(A) Brief descriptive title for each commitment;
(B) Name of plant and unit designation;
(C) Name of the purchaser or power pool or other similar power supply entity;
(D) Duration of the transaction;
(E) Basis of rates or charges, stated in terms of whether a transaction reflects marginal, incremental, or fully distributed costs, the specific overall and common equity rates of return included in costs, provided on both a claimed and earned basis to the extent such information is available, the approximate date of the cost analysis on which the rates and charges were based, and any other considerations significant to the transaction;
(F) Revenue received for each month of Period I and Period II or, if applicable, monthly quantities of power and energy received or available from power pools as consideration for commitment to a pool; and
(G) Proposed treatment in the cost of service determinations for the wholesale services at issue. For example, a credit of revenue to the total electric cost of service, in Statement AU under paragraph (h)(21), could be proposed to account for unit capacity sales based upon incremental capital costs. The utility shall include explanatory material and support for the proposed procedures.
(ii) For Period I and Period II, the utility shall list each transaction in which all, or a portion, of a major transmission facility owned by the filing utility was committed exclusively to a particular customer or group of customers. For each such transaction, the utility shall provide information similar to that required by clause (i).
(32) Statement BG—Revenue data to reflect changed rates. Statement BG is a statement of revenues for Period I and Period II, including those under the changed rate for the wholesale services at issue.
(i) For each month of Period I and Period II, and in total for each of the two periods, the utility shall show all billing determinants and metered quantities for each delivery point or set of delivery points that constitutes an individual wholesale customer billing unit, and the result of applying each specific rate component to the billing determinants for each billing unit stated with the total of the computed monthly bill for the customer. If the rates include a fuel clause, the utility shall compute and total the revenues under the fuel clause to reflect fuel costs incurred during each month of Period I and Period II. That is, the fuel clause revenues for the first month of Period I shall reflect fuel costs incurred for that month, and so on for each month of Period I and Period II. In computing fuel clause revenues, the utility shall determine fuel cost according to § 35.14 of this chapter.
(ii) If the form of the proposed fuel clause would produce revenues different from those computed in accordance with clause (i), the utility shall separately compute and state such fuel clause revenues for each customer for each month of Period I and Period II.
(iii) The utility shall summarize separately revenue data computed in accordance with clauses (i) and (ii) above for each month and in total for Period I and Period II, in accordance with wholesale rate groups specified in Statement BA under paragraph (h)(26) of this section. The utility shall show total electric department revenues for each period to include revenues under the changed rate for all such wholesale customer rate groups.
(iv) For Period I and as estimated for Period II, the utility shall summarize all billing determinants and revenues received from interruptible or curtailable services. Billing determinants and revenue data shall be consistent with interruptible demand and energy data in Statements BB and BD. The utility shall include an explanation of the extent to which interruptible or curtailable service revenues are or are not included in revenue credits in Statement AU under paragraph (h)(21) of this section.
(33) Statement BH—Revenue data to reflect present rates. Statement BH is a statement of revenues for Period I and Period II, including those under present rates for wholesale services at issue, and for total electric service to reflect such revenues for wholesale services. The utility shall prepare this statement to include data consistent with criteria specified for presentation of revenue under the changed rate in Statement BG under paragraph (h)(32) of this section.
(34) Statement BI—Fuel cost adjustment factors. Statement BI is a statement of monthly fuel cost adjustment factors under the changed rate and under the present rates, for Period I and Period II.
(i) If the changed rate schedule embodies a fuel cost adjustment clause, the utility shall show detailed derivations of fuel cost adjustment factors computed to reflect fuel cost incurred during each month of Period I and Period II. Fuel cost adjustment factors are those required for revenue determinations in accordance with paragraph (h)(32)(i) of Statement BG.
(ii) If additional proposed fuel clause revenue data are reported in accordance with paragraph (h)(32)(ii) of Statement BG, the utility shall show detailed derivation of applicable monthly fuel adjustment factors.
(iii) If the present rate includes a fuel cost adjustment change, the utility shall show detailed derivations of fuel cost adjustment factors for each month of Period I and Period II. The utility shall include in Statement BI derivations for all monthly factors required in the computation of present fuel clause revenues reported in Statement BH. The utility shall provide an explanation of the differences between the present and proposed fuel clauses.
(iv) All fuel cost adjustment factors shall be cost-based. The utility shall make a computational showing that shall develop adjustment factors in a manner consistent with the requirements of § 35.14 of this chapter. The utility shall provide supporting detail on cost by type of fuel, and shall show separately the allowable fuel clause cost component of purchased or interchanged energy. All fuel cost data shall be consistent with that included in operation and maintenance expenses in Statement AH under paragraph (h)(8) of this section.
(35) Statement BJ—Summary data tables. Statement BJ is a tabular summary of portions of Period I and Period II data from specific cost of service statements in this paragraph. The utility shall summarize under descriptive titles the Period I and Period II data from the cost of service provisions listed in this subparagraph. The utility shall supply the data in the manner described for each cost of service statement and in this subparagraph.
(i) If a utility provides in Statement BK information that is substantially equivalent to the information required in this statement, the utility may fulfill the requirements of this statement by specifically referring to the location in Statement BK of the information required in this subparagraph.
(ii) The utility shall provide the information in the following statements as average total electric department monthly balances for each function and subfunction of plant:
(A) Statement AD—(h)(4)(i) and (ii);
(B) Statement AE—(h)(5)(i) and (ii);
(C) Statement AF—(h)(6)(i) through (v);
(D) Statement AG—(h)(7)(i) through (vi);
(E) Statement AL—(h)(12)(i) and (ii);
(F) Statement AM—(h)(13); and
(G) Statement AN—(h)(14).
(iii) The utility shall provide the information in the following statements as total electric department annual revenue and expense amounts:
(A) Statement AH—(h)(8)(i), (iv) and (v);
(B) Statement AI—(h)(9)(i) and (ii);
(C) Statement AJ—(h)(10)(i);
(D) Statement AK—(h)(11)(i);
(E) Statement AP—(h)(16)(i) through (iv);
(F) Statement AQ—(h)(17)(i) through (iii);
(G) Statement AR—(h)(18)(i) through (iv);
(H) Statement AS—(h)(19);
(I) Statement AT—(h)(20); and
(J) Statement AU—(h)(21).
(iv) The utility shall provide all cost of capital amounts in the following statements.
(A) Statement AV—(h)(22)(i)(A); and
(B) Statement AW—(h)(23);
(v) The utility shall provide all tax rate data in Statement AY, paragraph (h)(25)(i) of this section.
(vi) The utility shall provide the information in the following statements as appropriate, for total electric department values and individual customer group values:
(A) Statement BB—(h)(27)(i) through (vi);
(B) Statement BD—(h)(29)(i) through (iv);
(C) Statement BE—(h)(30)(iv) (A), (B), and (C);
(D) Statement BG—(h)(32)(iii); and
(E) Statement BH—(h)(33).
(36) Statement BK—Electric utility department cost of service, total and as allocated. Statement BK is a statement of the claimed fully allocated cost of service of the utility developed and shown for Period I and Period II. The utility shall include analytical support for each rate proposed to be differentiated on a time-of-use basis. The utility shall also provide any marginal or incremental cost information that is required to support the changed rate developed on a marginal or incremental cost basis. The utility shall show allocations of fully distributed costs to the wholesale services subject to the changed rate accompanied by a comparison of allocated costs with revenues under the changed rate. Nothing in this subparagraph shall preclude use by any utility of any cost of service technique it believes reasonable and that is consistent with the requirements of paragraph (g) of this section.
(i) The utility shall base the fully distributed cost of service and the allocations thereof upon data provided in the accompanying detailed statements required under this section and additional data which the utility may submit and support in connection with this statement. The cost of service data of the utility shall conform to the following requirements:
(A) The total electric rate base and cost of service shall be itemized and summarized by major functions and in a format designed to facilitate review and analysis.
(B) Based on the total electric rate base and cost of service, and on allocated or assigned component elements, the cost of service for each Statement BA wholesale customer rate group under paragraph (h)(26) shall be itemized and summarized by major functions in a format consistent with that shown for total electric.
(C) The costs of service data for total electric and for each of the wholesale customer groups shall include data that show the return and the income taxes by components and in total, based upon the rate of return claimed by the utility in Statement AV under paragraph (h)(22). Individual components of income taxes shall include income taxes payable, provision for deferred income tax—debits and deferred income tax—credits, investment tax credits, or other adjustments.
(D) The fully distributed cost of service study of the utility shall disclose the principal determinants for allocation of total electric costs among the wholesale customer groups, including but not limited to the following:
(1) Computations showing the energy responsibilities of the wholesale services, with supporting detail;
(2) Computations showing the demand responsibilities of the wholesale services, with supporting detail; and
(3) Computations showing the specific assignment responsibilities of the wholesale services, with supporting detail.
(ii) For the total electric service and for each wholesale customer rate group, the utility shall compare the fully distributed cost of service with the revenues under the changed rate. Based on the comparison, the utility shall show the revenue excess or deficiency and the earned rate of return computed for the total electric service and for each wholesale customer rate group.
(iii) For any filing that contains Period II data, the utility shall supply any work papers and additional explanatory material necessary to support Statement BK, indexed, referenced and paginated as provided in paragraph (d)(5) of this section.
(iv) The utility shall provide a tabular comparison of Period II total electric fully distributed cost items with those of Period I. The comparisons shall show item amounts for each of the two periods, and also shall show Period II item amounts as percentages of equivalent items for Period I. Comparisons shall include at least the following items, accompanied by explanatory notes with respect to significant variations among the comparative percentages:
(A) Rate base;
(B) Production expenses;
(C) Transmission expenses;
(D) Customer accounting, customer service and information, and sales expenses;
(E) Depreciation expenses;
(F) Taxes except income and revenue;
(G) Income taxes;
(H) Revenue taxes; and
(I) Return claimed.
(37) Statement BL—Rate design information. In support of the design of the changed rate, the utility shall submit the following material:
(i) A narrative statement describing and justifying the objectives of the design of the changed rate. If the purpose of the rate design is to reflect costs, the utility shall state how that objective is achieved, and shall accompany it with a summary cost analysis that would justify the rate design, including any discounts or surcharges based on delivery voltage level or other specific considerations. Such summary cost analysis shall be consistent with, derived from, and cross-referenced to the data in cost of service Statement BK. If the rate design is not intended to reflect costs, whether fully distributed, marginal, incremental, or other, the utility shall provide a statement to justify the departure from cost-based rates.
(ii) If the billing determinants, such as quantities of demand, energy, or delivery points, are on different bases than the cost allocation determinants supporting such charges, the utility shall submit an explanation setting forth the economic or other considerations that warrant such departure. The information shall include at least the following:
(A) If the individual rate for the demand, energy and customer charges do not correspond to the comparable cost classifications supporting such charges, a detailed explanation stating the reasons for the differences.
(B) If the changed rate contains more than one demand or energy block, a detailed explanation indicating the rationale for the blocking and the considerations upon which such blocking is based, including adequate cost support for the specified blocking.
(38) Statement BM—Construction program statement. Statement BM is a summary of data and supporting assumptions relating to the economics of any construction program to replace or expand the utility’s power supply that shall be filed if the utility is filing for construction work in progress in rate base under § 35.26(c)(3) of this chapter. The filing utility shall describe generally its program for providing reliable and economic power for the period beginning with the date of the filing and ending with the tenth year after the test period. The statement shall include an assessment of the relative costs of adopting alternative strategies including an analysis of alternative production plant, e.g., cogeneration, small power production, heightened load management and conservation efforts, additions to transmission plant or increased purchases of power, and an explanation of why the program adopted is prudent and consistent with a least-cost energy supply program.
Subpart C—Other Filing Requirements
§ 35.14 Fuel cost and purchased economic power adjustment clauses.
(a) Fuel adjustment clauses (fuel clause) which are not in conformity with the principles set out below are not in the public interest. These regulations contemplate that the filing of proposed rate schedules, tariffs or service agreements which embody fuel clauses failing to conform to the following principles may result in suspension of those parts of such rate schedules, tariffs, or service agreements:
(1) The fuel clause shall be of the form that provides for periodic adjustments per kWh of sales equal to the difference between the fuel and purchased economic power costs per kWh of sales in the base period and in the current period:
(2) Fuel and purchased economic power costs (F) shall be the cost of:
(i) Fossil and nuclear fuel consumed in the utility’s own plants, and the utility’s share of fossil and nuclear fuel consumed in jointly owned or leased plants.
(ii) The actual identifiable fossil and nuclear fuel costs associated with energy purchased for reasons other than identified in paragraph (a)(2)(iii) of this section.
(iii) The total cost of the purchase of economic power, as defined in paragraph (a)(11) of this section, if the reserve capacity of the buyer is adequate independent of all other purchases where non-fuel charges are included in either F
(iv) Energy charges for any purchase if the total amount of energy charges incurred for the purchase is less than the buyer’s total avoided variable cost;
(v) And less the cost of fossil and nuclear fuel recovered through all inter-system sales.
(3) Sales (S) must be all kWh’s sold, excluding inter-system sales. Where for any reason, billed system sales cannot be coordinated with fuel costs for the billing period, sales may be equated to the sum of: (i) Generation, (ii) purchases, (iii) exchange received, less (iv) energy associated with pumped storage operations, less (v) inter-system sales referred to in paragraph (a)(2)(iv) of this section, less (vi) total system losses.
(4) The adjustment factor developed according to this procedure shall be modified to properly allow for losses (estimated if necessary) associated only with wholesale sales for resale.
(5) The adjustment factor developed according to this procedure may be further modified to allow the recovery of gross receipts and other similar revenue based tax charges occasioned by the fuel adjustment revenues.
(6) The cost of fossil fuel shall include no items other than those listed in Account 151 of the Commission’s Uniform System of Accounts for Public Utilities and Licensees. The cost of nuclear fuel shall be that as shown in Account 518, except that if Account 518 also contains any expense for fossil fuel which has already been included in the cost of fossil fuel, it shall be deducted from this account. (Paragraph C of Account 518 includes the cost of other fuels used for ancillary steam facilities.)
(7) Where the cost of fuel includes fuel from company-owned or controlled
(8) All rate filings which contain a proposed new fuel clause or a change in an existing fuel clause shall conform such clauses with the regulations. Within one year of the effectiveness of this rulemaking, all public utilities with rate schedules that contain a fuel clause should conform such clauses with the regulations. Recognizing that individual public utilities may have special operating characteristics that may warrant granting temporary delays in the implementation of the regulations, the Commission may, upon showing of good cause, waive the requirements of this section of the regulations for an additional one-year period so as to permit the public utilities sufficient time to adjust to the requirements.
(9) All rate filings containing a proposed new fuel clause or change in an existing fuel clause shall include:
(i) A description of the fuel clause with detailed cost support for the base cost of fuel and purchased economic power or energy.
(ii) Full cost of service data unless the utility has had the rate approved by the Commission within a year, provided that such cost of service may not be required when an existing fuel cost adjustment clause is being modified to conform to the Commission’s regulations.
(10) Whenever particular circumstances prevent the use of the standards provided for herein, or the use thereof would result in an undue burden, the Commission may, upon application under § 385.207 of this chapter and for good cause shown, permit deviation from these regulations.
(11) For the purpose of paragraph (a)(2)(iii) of this section, the following definitions apply:
(i) Economic power is power or energy purchased over a period of twelve months or less where the total cost of the purchase is less than the buyer’s total avoided variable cost.
(ii) Total cost of the purchase is all charges incurred in buying economic power and having such power delivered to the buyer’s system. The total cost includes, but is not limited to, capacity or reservation charges, energy charges, adders, and any transmission or wheeling charges associated with the purchase.
(iii) Total avoided variable cost is all identified and documented variable costs that would have been incurred by the buyer had a particular purchase not been made. Such costs include, but are not limited to, those associated with fuel, start-up, shut-down or any purchases that would have been made in lieu of the purchase made.
(12) For the purpose of paragraph (a)(2)(iii) of this section, the following procedures and instructions apply:
(i) A utility proposing to include purchase charges other than those for fuel or energy in fuel and purchased economic power costs (F) under paragraph (a)(2)(iii) of this section shall amend its fuel cost adjustment clause so that it is consistent with paragraphs (a)(1) and (a)(2)(iii) of this section. Such amendment shall state the system reserve capacity criteria by which the system operator decides whether a reliability purchase is required. Where the utility filing the statement is required by a State or local regulatory body (including a plant site licensing board) to file a capacity criteria statement with that body, the system reserve capacity criteria in the statement filed with the Commission shall be identical to those contained in the statement filed with the State or local regulatory body. Any utility that changes its reserve capacity criteria shall, within 45 days of such change, file an amended fuel cost and purchased economic power adjustment clause to incorporate the new criteria.
(ii) Reserve capacity shall be deemed adequate if, at the time a purchase was initiated, the buyer’s system reserve capacity criteria were projected to be satisfied for the duration of the purchase without the purchase at issue.
(iii) The total cost of the purchase must be projected to be less than total avoided variable cost, at the time a purchase was initiated, before any non-fuel purchase charge may be included in F
(iv) The purchasing utility shall make a credit to F
(v) If a purchase is made of more capacity than is needed to satisfy the buyer’s system reserve capacity criteria because the total costs of the extra capacity and associated energy are less than the buyer’s total avoided variable costs for the duration of the purchase, the charges associated with the non-reliability portion of the purchase may be included in F.
§ 35.15 Notices of cancellation or termination.
(a) General rule. When a rate schedule, tariff or service agreement or part thereof required to be on file with the Commission is proposed to be cancelled or is to terminate by its own terms and no new rate schedule, tariff or service agreement or part thereof is to be filed in its place, a filing must be made to cancel such rate schedule, tariff or service agreement or part thereof at least sixty days but not more than one hundred-twenty days prior to the date such cancellation or termination is proposed to take effect. A copy of such notice to the Commission shall be duly posted. With such notice, each filing party shall submit a statement giving the reasons for the proposed cancellation or termination, and a list of the affected purchasers to whom the notice has been provided. For good cause shown, the Commission may by order provide that the notice of cancellation or termination shall be effective as of a date prior to the date of filing or prior to the date the filing would become effective in accordance with these rules.
(b) Applicability. (1) The provisions of paragraph (a) of this section shall apply to all contracts for unbundled transmission service and all power sale contracts:
(i) Executed prior to July 9, 1996; or
(ii) If unexecuted, filed with the Commission prior to July 9, 1996.
(2) Any power sales contract executed on or after July 9, 1996 that is to terminate by its own terms shall not be subject to the provisions of paragraph (a) of this section.
(c) Notice. Any public utility providing jurisdictional services under a power sales contract that is not subject to the provisions of paragraph (a) of this section shall notify the Commission of the date of the termination of such contract within 30 days after such termination takes place.
§ 35.16 Notice of succession.
Whenever the name of a public utility is changed, or its operating control is transferred to another public utility in whole or in part, or a receiver or trustee is appointed to operate any public utility, the exact name of the public utility, receiver, or trustee which will operate the property thereafter shall be filed within 30 days thereafter with the Commission with a tariff consistent with the electronic filing requirements in § 35.7 of this part.
§ 35.17 Withdrawals and amendments of rate schedule, tariff or service agreement filings.
(a) Withdrawals of rate schedule, tariff or service agreement filings prior to Commission action. (1) A public utility may withdraw in its entirety a rate schedule, tariff or service agreement filing that has not become effective and upon which no Commission or delegated order has been issued by filing a withdrawal motion with the Commission. Upon the filing of such motion, the proposed rate schedule, tariff or service agreement sections will not become effective under section 205(d) of the Federal Power Act in the absence of Commission action making the rate schedule, tariff or service agreement filing effective.
(2) The withdrawal motion will become effective, and the rate schedule, tariff or service agreement filing will be deemed withdrawn, at the end of 15 days from the date of filing of the withdrawal motion, if no answer in opposition to the withdrawal motion is filed within that period and if no order disallowing the withdrawal is issued within that period. If an answer in opposition is filed within the 15 day period, the withdrawal is not effective until an order accepting the withdrawal is issued.
(b) Amendments or modifications to rate schedule, tariff or service agreement sections prior to Commission action on the filing. A public utility may file to amend or modify, and may file a settlement that would amend or modify, a rate schedule, tariff or service agreement section contained in a rate schedule, tariff or service agreement filing that has not become effective and upon which no Commission or delegated order has yet been issued. Such filing will toll the notice period in section 205(d) of the Federal Power Act for the original filing, and establish a new date on which the entire filing will become effective, in the absence of Commission action, no earlier than 61 days from the date of the filing of the amendment or modification.
(c) Withdrawal of suspended rate schedules, tariffs, or service agreements, or parts thereof. Where a rate schedule, tariff, or service agreement, or part thereof has been suspended by the Commission, it may be withdrawn during the period of suspension only by special permission of the Commission granted upon application therefor and for good cause shown. If permitted to be withdrawn, any such rate schedule, tariff, or service agreement may be refiled with the Commission within a one-year period thereafter only with special permission of the Commission for good cause shown.
(d) Changes in suspended rate schedules, tariffs, or service agreements, or parts thereof. A public utility may not, within the period of suspension, file any change in a rate schedule, tariff, or service agreement, or part thereof, which has been suspended by order of the Commission except by special permission of the Commission granted upon application therefor and for good cause shown.
(e) Changes in rate schedules or tariffs or parts thereof continued in effect and which were proposed to be changed by the suspended filing. A public utility may not, within the period of suspension, file any change in a rate schedule or tariff or part thereof continued in effect by operation of an order of suspension and which was proposed to be changed by the suspended filing, except by special permission of the Commission granted upon application therefor and for good cause shown.
§ 35.18 Asset retirement obligations.
(a) A public utility that files a rate schedule, tariff or service agreement under § 35.12 or § 35.13 and has recorded an asset retirement obligation on its books must provide a schedule, as part of the supporting work papers, identifying all cost components related to the asset retirement obligations that are included in the book balances of all accounts reflected in the cost of service computation supporting the proposed rates. However, all cost components related to asset retirement obligations that would impact the calculation of rate base, such as electric plant and related accumulated depreciation and accumulated deferred income taxes, may not be reflected in rates and must be removed from the rate base calculation through a single adjustment.
(b) A public utility seeking to recover nonrate base costs related to asset retirement costs in rates must provide, with its filing under § 35.12 or § 35.13, a detailed study supporting the amounts proposed to be collected in rates.
(c) A public utility that has recorded asset retirement obligations on its books, but is not seeking recovery of the asset retirement costs in rates, must remove all asset-retirement-obligations-related cost components from the cost of service supporting its proposed rates.
§ 35.19 Submission of information by reference.
If all or any portion of the information called for in this part has already been submitted to the Commission, substantially in the form prescribed above, specific reference thereto may be made in lieu of re-submission in response to the requirements of this part.
§ 35.19a Refund requirements under suspension orders.
(a) Refunds. (1) The public utility whose proposed increased rates or charges were suspended shall refund at such time in such amounts and in such manner as required by final order of the Commission the portion of any increased rates or charges found by the Commission in that suspension proceeding not to be justified, together with interest as required in paragraph (a)(2) of this section.
(2) Interest shall be computed from the date of collection until the date refunds are made as follows:
(i) At a rate of seven percent simple interest per annum on all excessive rates or charges held prior to October 10, 1974;
(ii) At a rate of nine percent simple interest per annum on all excessive rates or charges held between October 10, 1974, and September 30, 1979; and
(iii)(A) At an average prime rate for each calendar quarter on all excessive rates or charges held (including all interest applicable to such rates or charges) on or after October 1, 1979. The applicable average prime rate for each calendar quarter shall be the arithmetic mean, to the nearest one-hundredth of one percent, of the prime rate values published in the Federal Reserve Bulletin, or in the Federal Reserve’s “Selected Interest Rates” (Statistical Release H. 15), for the fourth, third, and second months preceding the first month of the calendar quarter.
(B) The interest required to be paid under clause (iii)(A) shall be compounded quarterly.
(3) Any public utility required to make refunds pursuant to this section shall bear all costs of such refunding.
(b) Reports. Any public utility whose proposed increased rates or charges were suspended and have gone into effect pending final order of the Commission pursuant to section 205(e) of the Federal Power Act shall keep accurate account of all amounts received under the increased rates or charges which became effective after the suspension period, for each billing period, specifying by whom and in whose behalf such amounts are paid.
§ 35.21 Applicability to licensees and others subject to section 19 or 20 of the Federal Power Act.
Upon further order of this Commission issued upon its own motion or upon complaint or request by any person or State within the meaning of sections 19 or 20 of the Federal Power Act, the provisions of §§ 35.1 through 35.19 shall be operative as to any licensee or others who are subject to this Commission’s jurisdiction in respect to services and the rates and charges of payment therefor by reason of the requirements of sections 19 or 20 of the Federal Power Act. The requirement of this section for compliance with the provisions of §§ 35.1 through 35.19 shall be in addition to and independent of any obligation for compliance with those regulations by reason of the provisions of sections 205 and 206 of the Federal Power Act. For purposes of applying this section Electric Service as otherwise defined in § 35.2(a) shall mean: Services to customers or consumers of power within the meaning of sections 19 or 20 of the Federal Power Act which may be comprised of various classes of capacity and energy and/or transmission services subject to the jurisdiction of this Commission. Electric Service shall include the utilization of facilities owned or operated by any licensee or others to effect any of the foregoing sales or services whether by leasing or other arrangements. As defined herein Electric Service is without regard to the form of payment or compensation for the sales or services rendered, whether by purchase and sale, interchange, exchange, wheeling charge, facilities charge, rental or otherwise. For purposes of applying this section, Rate Schedule as otherwise defined in § 35.2(b) shall mean: A statement of
(1) Electric service as defined in this § 35.21,
(2) Rates and charges for or in connection with that service, and
(3) All classifications, practices, rules, regulations, or contracts which in any manner affect or relate to the aforementioned service, rates and charges. This statement shall be in writing and may take the physical form of a contractual document, purchase or sale agreement, lease of facilities, tariff
§ 35.22 Limits for percentage adders in rates for transmission services; revision of rate schedules, tariffs or service agreements.
(a) Applicability. This section applies to all electric rate schedules, tariffs or service agreements required to be filed under this part that are used for transactions in which the utility or system performs a transmission or purchase and resale function.
(b) Definition. For purposes of this section, purchased power price means the amount paid by a utility or system that performs a transmission or purchase and resale function for electric power generated by another utility or system.
(c) General rule. (1) If a utility or system uses a rate component that recovers revenues computed wholly or in part as a percentage of the purchased power price, the utility or system shall establish a limit on the revenues recovered by such rate component in any transaction, in accordance with paragraph (d) of this section.
(2) The limit established under this paragraph shall be stated in mills per kilowatt-hour.
(d) Cost support information. (1) A utility or system shall submit cost support information to justify any revenue limit established under paragraph (c) of this section, except as provided in paragraph (e) of this section.
(2) The information submitted under this section shall consist of those costs, other than the purchased power price, incurred by a utility or system as a result of a transmission or purchase and resale transaction, which costs are not recovered under any other rate component.
(e) Exception. A utility or system need not submit the cost support information required under paragraph (d) of this section if the limit established under paragraph (c) of this section is not more than one mill per kilowatt-hour.
(f) Revision of rate schedules, tariffs or service agreements. Every utility or system shall:
(1) Amend any rate schedule, tariffs or service agreements to indicate any limit established pursuant to this section, not later than 60 days after the effective date of this rule; and
(2) Hereafter conform any rate or rate change filed under this part to the requirements of this section.
§ 35.23 General provisions.
(a) Applicability. This subpart applies to any wholesale sale of electric energy in a coordination transaction by a public utility if that sale requires the use of an emissions allowance.
(b) Implementation Procedures. (1) If a public utility has a coordination rate schedule on file that expressly provides for the recovery of all incremental or out-of-pocket costs, such utility may make an abbreviated rate filing detailing how it will recover emissions allowance costs. Such filing must include the following: the index or combination of indices to be used; the method by which the emission allowance amounts will be calculated; timing procedures; how inconsistencies, if any, with dispatch criteria will be reconciled; and how any other rate impacts will be addressed. In addition, a utility making an abbreviated filing must:
(i) Clearly identify the filing as being limited to an amendment to a coordination rate to reflect the cost of emissions allowances, in the first paragraph of the letter of transmittal accompanying the filing;
(ii) Submit the revisions in accordance with § 35.7; and
(iii) Identify each rate schedule to which the amendment applies.
(2) The abbreviated filing must apply consistent treatment to all coordination rate schedules. If the filing does not apply consistent rate treatment, the public utility must explain why it does not do so.
(3) If a public utility wants to charge incremental costs for emissions allowances, but its rate schedule on file with the Commission does not provide for the recovery of all incremental costs, the selling public utility may submit an abbreviated filing if all customers agree to the rate change. If customers do not agree, the selling public utility must tender its emissions allowance proposal in a separate section 205 rate filing, fully justifying its proposal.
§ 35.24 Tax normalization for public utilities.
(a) Applicability. (1) Except as provided in subparagraph (2) of this paragraph, this section applies, with respect to rate schedules filed under §§ 35.12 and 35.13 of this part, to the ratemaking treatment of the tax effects of all transactions for which there are timing differences.
(2) This section does not apply to the following timing differences:
(i) Differences that result from the use of accelerated depreciation;
(ii) Differences that result from the use of Class Life Asset Depreciation Range (ADR) provisions of the Internal Revenue Code;
(iii) Differences that result from the use of accelerated amortization provisions on certified defense and pollution control facilities;
(iv) Differences that arise from recognition of extraordinary property losses as a current expense for tax purposes but as a deferred and amortized expense for book purposes;
(v) Differences that arise from recognition of research, development, and demonstration expenditures as a current expense for tax purposes but as a deferred and amortized expense for book purposes;
(vi) Differences that result from different tax and book reporting of deferred gains or losses from disposition of utility plant;
(vii) Differences that result from the use of the Asset Guideline Class “Repair Allowance” provision of the Internal Revenue Code;
(viii) Differences that result from recognition of purchased gas costs as a current expense for tax purposes but as a deferred expense for book purposes.
(b) General rules—(1) Tax normalization required. (i) A public utility must compute the income tax component of its cost of service by using tax normalization for all transactions to which this section applies.
(ii) Except as provided in paragraph (c) of this section, application of tax normalization by a public utility under this section to compute the income tax component will not be subject to case-by-case adjudication.
(2) Reduction of, and addition to, rate base. (i) The rate base of a public utility using tax normalization under this section must be reduced by the balances that are properly recordable in Account 281, “Accumulated deferred income taxes-accelerated amortization property;” Account 282, “Accumulated deferred income taxes—other property;” and Account 283, “Accumulated deferred income taxes—other.” Balances that are properly recordable in Account 190, “Accumulated deferred income taxes,” must be treated as an addition to rate base.
(ii) Such rate base reductions or additions must be limited to deferred taxes related to rate base, construction or other jurisdictional activities.
(iii) If a public utility uses an approved purchased gas adjustment clause or a research, development and demonstration tracking clause, the rate base reductions or additions required under this subparagraph must apply only to the extent that the balances in Account 190 and Accounts 281 through 283 are not used, for purposes of calculating carrying charges, as an offset to balances properly recordable in Account 188, “Research development and demonstration expenditures,” or Account 191, “Unrecovered purchased gas costs.”
(c) Special rules. (1) This paragraph applies:
(i) If the public utility has not provided deferred taxes in the same amount that would have accrued had tax normalization been applied for the tax effects of timing difference transactions originating at any time prior to the test period; or
(ii) If, as a result of changes in tax rates, the accumulated provision for deferred taxes becomes deficient in or in excess of amounts necessary to meet future tax liabilities as determined by application of the current tax rate to all timing difference transactions originating in the test period and prior to the test period.
(2) The public utility must compute the income tax component in its cost of service by making provision for any excess or deficiency in deferred taxes described in subparagraphs (1)(i) or (1)(ii) of this paragraph.
(3) The public utility must apply a Commission-approved ratemaking method made specifically applicable to the public utility for determining the cost of service provision described in subparagraph (2) of this paragraph. If no Commission-approved ratemaking method has been made specifically applicable to the public utility, then the public utility must use some ratemaking method for making such provision, and the appropriateness of this method will be subject to case-by-case determination.
(d) Definitions. For purposes of this section, the term:
(1) Tax normalization means computing the income tax component as if the amounts of timing difference transactions recognized in each period for ratemaking purposes were also recognized in the same amount in each such period for income tax purposes.
(2) Timing differences means differences between amounts of expenses or revenues recognized for income tax purposes and amounts of expenses or revenues recognized for ratemaking purposes, which differences arise in one time period and reverse in one or more other time periods so that the total amounts of expenses or revenues recognized for income tax purposes and for ratemaking purposes are equal.
(3) Commission-approved ratemaking method means a ratemaking method approved by the Commission in a final decision including approval of a settlement agreement containing a ratemaking method only if such settlement agreement applies that method beyond the effective term of the settlement agreement.
(4) Income tax purposes means for the purpose of computing income tax under the provisions of the Internal Revenue Code or the income tax provisions of the laws of a State or political subdivision of a State (including franchise taxes).
(5) Income tax component means that part of the cost of service that covers income tax expenses allowable by the Commission.
(6) Ratemaking purposes means for the purpose of fixing, modifying, approving, disapproving or rejecting rates under the Federal Power Act or the Natural Gas Act.
(7) Tax effect means the tax reduction or addition associated with a specific expense or revenue transaction.
(8) Transaction means an activity or event that gives rise to an accounting entry that is used in determining revenues or expenses.
§ 35.25 Construction work in progress.
(a) Applicability. This section applies to any rate schedule filed under this part by any public utility as defined in subsection 201(e) of the Federal Power Act.
(b) Definitions. For purposes of this section:
(1) Constuction work in progress or CWIP means any expenditure for public utility plant in process of construction that is properly included in Accounts 107 (construction work in progress) and 120.1 (nuclear fuel in process of refinement, conversion, enrichment, and fabrication) of part 101 of this chapter, the Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act (Major and Nonmajor), that would otherwise be eligible for allowance for funds used during construction (AFUDC) treatment.
(2) Double whammy means a situation which may arise when a wholesale electric rate customer embarks upon its own or participates in a construction program to supply itself with all or a portion of its future power needs, thereby reducing its future dependence on the CWIP of the rate applicant, but is simultaneously forced to pay to the CWIP public utility rate applicant the CWIP portion of the wholesale rates that reflects existing levels of service or a different anticipated service level.
(3) Fuel conversion facility means any addition to public utility plant that enables a natural gas-burning plant to convert to the use of other fuels, or that enables an oil-burning plant to convert to the use of other fuels, other than natural gas. Such facilities include those that alter internal plant workings, such as oil or coal burners, soot blowers, bottom ash removal systems and concomitant air pollution control facilities, and any facility needed for receiving and storing the fuel to which the plant is being converted, which facility would not be necessary if the plant continued to burn gas or oil.
(4) Pollution control facility means an identifiable structure or portions of a structure that is designed to reduce the amount of pollution produced by the power plant, but does not include any facility that reduces pollution by substituting a different method of generation or that generates the additional power necessitated by the operation of a pollution control facility.
(c) General rule. For purposes of any initial rate schedule or any rate schedule change filed under § 35.12 or § 35.13 of this part, a public utility may include in its rate base any costs of construction work in progress (CWIP), including allowance for funds used during construction (AFUDC), as provided in this section.
(1) Pollution control facilities—(i) General rule. Any CWIP for pollution control facilities allocable to electric power sales for resale may be included in the rate base of the public utility.
(ii) Qualification as a pollution control facility. In determining whether a facility is a pollution control facility for purposes of this section, the Commission will consider:
(A) Whether such facility is the type facility described in the Internal Revenue Service laws, 26 U.S.C. 169(d)(1), as follows:
“A new identifiable treatment facility which is used * * * to abate or control water or atmospheric pollution or contamination by removing, altering, disposing, storing, or preventing the creation or emission of pollutants, contaminants, wastes or heat”;
(B) Whether such facility has been certified by a local, state, or federal agency as being in conformity with, or required by, a program of pollution control;
(C) Other evidence showing that such facilities are for pollution control.
(2) Fuel conversion facilities. Any CWIP for fuel conversion facilities allocable to electric power sales for resale may be included in the rate base of the public utility.
(3) Non-pollution control of fuel conversion (non-PC/FC) CWIP. No more than 50 percent of any CWIP allocable to electric power sales for resale not otherwise included in rate base under paragraphs (c) (1) and (2) of this section, may be included in the rate base of the public utility.
(4) Forward looking allocation ratios. Every test period CWIP project requested for wholesale rate base treatment pursuant to § 35.26(c)(1), (2), and (3) of this part will be allocated to the customer classes on the basis of forward looking allocation ratios reflecting the anticipated average annual use the wholesale customers will make of the system over the estimated service life of the project. Supporting documentation, as required by §§ 35.12 and 35.13 of this part, must be in sufficient detail to permit examination and verification of the forward looking allocation ratio’s recognition of each wholesale customer’s plans, if any, for future alternative or supplementary power supplies. For the purpose of preventing anticompetitive effects, including CWIP-induced price squeeze and double whammy, sufficient recognition of such plans may require the public utility applicant to provide for separate customer groups or provide for a rate design incorporating selected CWIP project credits.
(d) Effective date. If a public utility proposes in its filed rates to include CWIP in rate base under this section, that portion of the rate related to CWIP is collectible at the time the general rates become effective pursuant to Commission order, whether or not subject to refund, except as provided in paragraph (g) of this section.
(e) Discontinuance of AFUDC. On the date that any proposed rate that includes CWIP in rate base becomes effective, a public utility that has included CWIP in rate base must discontinue the capitalization of any AFUDC related to those amounts of CWIP is rate base.
(f) Accounting procedures. When a public utility files to include CWIP in its rate base pursuant to this section, it must propose accounting procedures in that rate schedule filing that:
(1) Ensure that wholesale customers will not be charged for both capitalized AFUDC and corresponding amounts of CWIP proposed to be included in rate base; and
(2) Ensure that wholesale customers will not be charged for any corresponding AFUDC capitalized as a result of different accounting or ratemaking treatments accorded CWIP by state or local regulatory authorities.
(g) Anticompetitive procedures—(1) Filing requirements. In order to facilitate Commission review of the anticompetitive effects of applications for CWIP pursuant to § 35.26(c)(3), a public utility applying for rates based upon inclusion of such CWIP in rate base must include the following information in its filing:
(i) The percentage of the proposed increase in the jurisdictional rate level attributable to non-pollution control/fuel conversion CWIP and the percentage of non-pollution control/fuel conversion CWIP supporting the proposed rate level;
(ii) The percentage of non-pollution control/fuel conversion CWIP permitted by the state or local commission supporting the current retail rates of the public utility against which the relevant wholesale customers compete; and
(iii) Individual earned rate of return analyses of each of the competing retail rates developed on a basis fully consistent with the wholesale cost of service for the same test period if the requested percentage of wholesale non-pollution control/fuel conversion CWIP exceeds that permitted by the relevant state or local authority to support the currently competing retail rates.
(2) Preliminary relief. (i) If an intervenor in its initial pleading alleges that a price squeeze will occur as a direct result of the public utility’s request for CWIP pursuant to § 35.26(c)(3), makes a showing that it is likely to incur harm if such CWIP is allowed subject to refund, and makes a showing of how the harm to the intervenor would be mitigated or eliminated by the types of preliminary relief requested, the Commission will consider preliminary relief at the suspension stage of the case pursuant to paragraph (g)(4) of this section. In determining whether to grant preliminary relief, the Commission will balance the following public interest considerations:
(A) The harm to the intervenor if it is not granted preliminary relief from the requested CWIP;
(B) The harm to the public utility if, during the interim period of preliminary relief, the public utility is required to recover its financing charges later through AFUDC rather than immediately through CWIP; and
(C) Mitigating bias against investment in new plants, ensuring accurate price signals, and fostering rate stability.
(ii) Whether or not preliminary relief is granted at the suspension stage will not preclude consideration of further interim or final remedies later in the proceedings, if warranted.
(3) If the Commission makes a final determination that a price squeeze due solely to allowance of a lower percentage of non-pollution control/fuel conversion CWIP in the public utility’s retail rate base than allowed by this Commission, the Commission will consider an adjustment to non-pollution control/fuel conversion CWIP in order to eliminate or mitigate the price squeeze.
(4) If an intervenor meets the requirements of paragraph (g)(2) of this section, the Commission, depending on the type of showing made including the likelihood, immediacy, and severity of any anticompetitive harm, may:
(i) Suspend the entire rate increase or all or a portion of the non-pollution control/fuel conversion CWIP component for up to five months;
(ii) Allow all or a portion of the non-pollution control/fuel conversion CWIP only prospectively from the issuance of the Commission’s final order on rehearing on the matter; or
(iii) Take such other action as is proper under the circumstances.
§ 35.26 Recovery of stranded costs by public utilities and transmitting utilities.
(a) Purpose. This section establishes the standards that a public utility or transmitting utility must satisfy in order to recover stranded costs.
(b) Definitions. (1) Wholesale stranded cost means any legitimate, prudent and verifiable cost incurred by a public utility or a transmitting utility to provide service to:
(i) A wholesale requirements customer that subsequently becomes, in whole or in part, an unbundled wholesale transmission services customer of such public utility or transmitting utility; or
(ii) A retail customer that subsequently becomes, either directly or through another wholesale transmission purchaser, an unbundled wholesale transmission services customer of such public utility or transmitting utility.
(2) Wholesale requirements customer means a customer for whom a public utility or transmitting utility provides by contract any portion of its bundled wholesale power requirements.
(3) Wholesale transmission services means the transmission of electric energy sold, or to be sold, at wholesale in interstate commerce or ordered pursuant to section 211 of the Federal Power Act (FPA).
(4) Wholesale requirements contract means a contract under which a public utility or transmitting utility provides any portion of a customer’s bundled wholesale power requirements.
(5) Retail stranded cost means any legitimate, prudent and verifiable cost incurred by a public utility to provide service to a retail customer that subsequently becomes, in whole or in part, an unbundled retail transmission services customer of that public utility.
(6) Retail transmission services means the transmission of electric energy sold, or to be sold, in interstate commerce directly to a retail customer.
(7) New wholesale requirements contract means any wholesale requirements contract executed after July 11, 1994, or extended or renegotiated to be effective after July 11, 1994.
(8) Existing wholesale requirements contract means any wholesale requirements contract executed on or before July 11, 1994.
(c) Recovery of wholesale stranded costs—(1) General requirement. A public utility or transmitting utility will be allowed to seek recovery of wholesale stranded costs only as follows:
(i) No public utility or transmitting utility may seek recovery of wholesale stranded costs if such recovery is explicitly prohibited by a contract or settlement agreement, or by any power sales or transmission rate schedule or tariff.
(ii) No public utility or transmitting utility may seek recovery of stranded costs associated with a new wholesale requirements contract if such contract does not contain an exit fee or other explicit stranded cost provision.
(iii) If wholesale stranded costs are associated with a new wholesale requirements contract containing an exit fee or other explicit stranded cost provision, and the seller under the contract is a public utility, the public utility may seek recovery of such costs, in accordance with the contract, through rates for electric energy under sections 205–206 of the FPA. The public utility may not seek recovery of such costs through any transmission rate for FPA section 205 or 211 transmission services.
(iv) If wholesale stranded costs are associated with a new wholesale requirements contract, and the seller under the contract is a transmitting utility but not also a public utility, the transmitting utility may not seek an order from the Commission allowing recovery of such costs.
(v) If wholesale stranded costs are associated with an existing wholesale requirements contract, if the seller under such contract is a public utility, and if the contract does not contain an exit fee or other explicit stranded cost provision, the public utility may seek recovery of stranded costs only as follows:
(A) If either party to the contract seeks a stranded cost amendment pursuant to a section 205 or section 206 filing under the FPA made prior to the expiration of the contract, and the Commission accepts or approves an amendment permitting recovery of stranded costs, the public utility may seek recovery of such costs through FPA section 205–206 rates for electric energy.
(B) If the contract is not amended to permit recovery of stranded costs as described in paragraph (c)(1)(v)(A) of this section, the public utility may file a proposal, prior to the expiration of the contract, to recover stranded costs through FPA section 205–206 or section 211–212 rates for wholesale transmission services to the customer.
(vi) If wholesale stranded costs are associated with an existing wholesale requirements contract, if the seller under such contract is a transmitting utility but not also a public utility, and if the contract does not contain an exit fee or other explicit stranded cost provision, the transmitting utility may seek recovery of stranded costs through FPA section 211–212 transmission rates.
(vii) If a retail customer becomes a legitimate wholesale transmission customer of a public utility or transmitting utility, e.g., through municipalization, and costs are stranded as a result of the retail-turned-wholesale customer’s access to wholesale transmission, the utility may seek recovery of such costs through FPA section 205–206 or section 211–212 rates for wholesale transmission services to that customer.
(2) Evidentiary demonstration for wholesale stranded cost recovery. A public utility or transmitting utility seeking to recover wholesale stranded costs in accordance with paragraphs (c)(1) (v) through (vii) of this section must demonstrate that:
(i) It incurred costs to provide service to a wholesale requirements customer or retail customer based on a reasonable expectation that the utility would continue to serve the customer;
(ii) The stranded costs are not more than the customer would have contributed to the utility had the customer remained a wholesale requirements customer of the utility, or, in the case of a retail-turned-wholesale customer, had the customer remained a retail customer of the utility; and
(iii) The stranded costs are derived using the following formula: Stranded Cost Obligation = (Revenue Stream Estimate—Competitive Market Value Estimate) × Length of Obligation (reasonable expectation period).
(3) Rebuttable presumption. If a public utility or transmitting utility seeks recovery of wholesale stranded costs associated with an existing wholesale requirements contract, as permitted in paragraph (c)(1) of this section, and the existing wholesale requirements contract contains a notice provision, there will be a rebuttable presumption that the utility had no reasonable expectation of continuing to serve the customer beyond the term of the notice provision.
(4) Procedure for customer to obtain stranded cost estimate. A customer under an existing wholesale requirements contract with a public utility seller may obtain from the seller an estimate of the customer’s stranded cost obligation if it were to leave the public utility’s generation supply system by filing with the public utility a request for an estimate at any time prior to the termination date specified in its contract.
(i) The public utility must provide a response within 30 days of receiving the request. The response must include:
(A) An estimate of the customer’s stranded cost obligation based on the formula in paragraph (c)(2)(iii) of this section;
(B) Supporting detail indicating how each element in the formula was derived;
(C) A detailed rationale justifying the basis for the utility’s reasonable expectation of continuing to serve the customer beyond the termination date in the contract;
(D) An estimate of the amount of released capacity and associated energy that would result from the customer’s departure; and
(E) The utility’s proposal for any contract amendment needed to implement the customer’s payment of stranded costs.
(ii) If the customer disagrees with the utility’s response, it must respond to the utility within 30 days explaining why it disagrees. If the parties cannot work out a mutually agreeable resolution, they may exercise their rights to Commission resolution under the FPA.
(5) A customer must be given the option to market or broker a portion or all of the capacity and energy associated with any stranded costs claimed by the public utility.
(i) To exercise the option, the customer must so notify the utility in writing no later than 30 days after the public utility files its estimate of stranded costs for the customer with the Commission.
(A) Before marketing or brokering can begin, the utility and customer must execute an agreement identifying, at a minimum, the amount and the price of capacity and associated energy the customer is entitled to schedule, and the duration of the customer’s marketing or brokering of such capacity and energy.
(ii) If agreement over marketing or brokering cannot be reached, and the parties seek Commission resolution of disputed issues, upon issuance of a Commission order resolving the disputed issues, the customer may reevaluate its decision in paragraph (c)(5)(i) of this section to exercise the marketing or brokering option. The customer must notify the utility in writing within 30 days of issuance of the Commission’s order resolving the disputed issues whether the customer will market or broker a portion or all of the capacity and energy associated with stranded costs allowed by the Commission.
(iii) If a customer undertakes the brokering option, and the customer’s brokering efforts fail to produce a buyer within 60 days of the date of the brokering agreement entered into between the customer and the utility, the customer shall relinquish all rights to broker the released capacity and associated energy and will pay stranded costs as determined by the formula in paragraph (c)(2)(iii) of this section.
(d) Recovery of retail stranded costs—(1) General requirement. A public utility may seek to recover retail stranded costs through rates for retail transmission services only if the state regulatory authority does not have authority under state law to address stranded costs at the time the retail wheeling is required.
(2) Evidentiary demonstration necessary for retail stranded cost recovery. A public utility seeking to recover retail stranded costs in accordance with paragraph (d)(1) of this section must demonstrate that:
(i) It incurred costs to provide service to a retail customer that obtains retail wheeling based on a reasonable expectation that the utility would continue to serve the customer; and
(ii) The stranded costs are not more than the customer would have contributed to the utility had the customer remained a retail customer of the utility.
§ 35.27 Authority of State commissions.
Nothing in this part—
(a) Shall be construed as preempting or affecting any jurisdiction a State commission or other State authority may have under applicable State and Federal law, or
(b) Limits the authority of a State commission in accordance with State and Federal law to establish
(1) Competitive procedures for the acquisition of electric energy, including demand-side management, purchased at wholesale, or
(2) Non-discriminatory fees for the distribution of such electric energy to retail consumers for purposes established in accordance with State law.
§ 35.28 Non-discriminatory open access transmission tariff.
(a) Applicability. This section applies to any public utility that owns, controls or operates facilities used for the transmission of electric energy in interstate commerce and to any non-public utility that seeks voluntary compliance with jurisdictional transmission tariff reciprocity conditions.
(b) Definitions—(1) Requirements service agreement means a contract or rate schedule under which a public utility provides any portion of a customer’s bundled wholesale power requirements.
(2) Economy energy coordination agreement means a contract, or service schedule thereunder, that provides for trading of electric energy on an “if, as and when available” basis, but does not require either the seller or the buyer to engage in a particular transaction.
(3) Non-economy energy coordination agreement means any non-requirements service agreement, except an economy energy coordination agreement as defined in paragraph (b)(2) of this section.
(4) Demand response means a reduction in the consumption of electric energy by customers from their expected consumption in response to an increase in the price of electric energy or to incentive payments designed to induce lower consumption of electric energy.
(5) Demand response resource means a resource capable of providing demand response.
(6) An operating reserve shortage means a period when the amount of available supply falls short of demand plus the operating reserve requirement.
(7) Market Monitoring Unit means the person or entity responsible for carrying out the market monitoring functions that the Commission has ordered Commission-approved independent system operators and regional transmission organizations to perform.
(8) Market Violation means a tariff violation, violation of a Commission-approved order, rule or regulation, market manipulation, or inappropriate dispatch that creates substantial concerns regarding unnecessary market inefficiencies.
(9) Electric storage resource as used in this section means a resource capable of receiving electric energy from the grid and storing it for later injection of electric energy back to the grid.
(10) Distributed energy resource as used in this section means any resource located on the distribution system, any subsystem thereof or behind a customer meter.
(11) Distributed energy resource aggregator as used in this section means the entity that aggregates one or more distributed energy resources for purposes of participation in the capacity, energy and/or ancillary service markets of the regional transmission organizations and/or independent system operators.
(12) Ambient-adjusted rating means a transmission line rating that applies to a time period of not greater than one hour; reflects an up-to-date forecast of ambient air temperature across the time period to which the rating applies; reflects the absence of solar heating during nighttime periods where the local sunrise/sunset times used to determine daytime and nighttime periods are updated at least monthly, if not more frequently; and is calculated at least each hour, if not more frequently.
(13) Emergency rating means a transmission line rating that reflects operation for a specified, finite period, rather than reflecting continuous operation. An emergency rating may assume an acceptable loss of equipment life or other physical or safety limitations for the equipment involved.
(14) Dynamic line rating means a transmission line rating that applies to a time period of not greater than one hour and reflects up-to-date forecasts of inputs such as (but not limited to) ambient air temperature, wind, solar heating intensity, transmission line tension, or transmission line sag.
(15) Energy Management System (EMS) means a computer control system used by electric utility dispatchers to monitor the real-time performance of the various elements of an electric system and to dispatch, schedule, and/or control generation and transmission facilities.
(16) Supervisory Control and Data Acquisition (SCADA) means a computer system that allows an electric system operator to remotely monitor and control elements of an electric system.
(c) Non-discriminatory open access transmission tariffs. (1) Every public utility that owns, controls, or operates facilities used for the transmission of electric energy in interstate commerce must have on file with the Commission an open access transmission tariff of general applicability for transmission services, including ancillary services, over such facilities. Such tariff must be the pro forma tariff promulgated by the Commission, as amended from time to time, or such other tariff as may be approved by the Commission consistent with the principles set forth in Commission rulemaking proceedings promulgating and amending the pro forma tariff.
(i) Subject to the exceptions in paragraphs (c)(1)(ii), (c)(1)(iii), (c)(1)(iv), and (c)(1)(v) of this section, the open access transmission tariff, which tariff must be the pro forma tariff required by Commission rulemaking proceedings promulgating and amending the pro forma tariff, and accompanying rates must be filed no later than 60 days prior to the date on which a public utility would engage in a sale of electric energy at wholesale in interstate commerce or in the transmission of electric energy in interstate commerce.
(ii) If a public utility owns, controls, or operates facilities used for the transmission of electric energy in interstate commerce, it must file the revisions to its open access transmission tariff required by Commission rulemaking proceedings promulgating and amending the pro forma tariff, pursuant to section 206 of the FPA and accompanying rates pursuant to section 205 of the FPA in accordance with the procedures set forth in Commission rulemaking proceedings promulgating and amending the pro forma tariff.
(iii) If a public utility owns, controls, or operates transmission facilities used for the transmission of electric energy in interstate commerce, such facilities are jointly owned with a non-public utility, and the joint ownership contract prohibits transmission service over the facilities to third parties, the public utility with respect to access over the public utility’s share of the jointly owned facilities must file the revisions to its open access transmission tariff required by Commission rulemaking proceedings promulgating and amending the pro forma tariff pursuant to section 206 of the FPA and accompanying rates pursuant to section 205 of the FPA in accordance with the procedures set forth in Commission rulemaking proceedings promulgating and amending the pro forma tariff.
(iv) Any public utility whose transmission facilities are under the independent control of a Commission-approved ISO or RTO may satisfy its obligation under paragraph (c)(1) of this section, with respect to such facilities, through the open access transmission tariff filed by the ISO or RTO.
(v) If a public utility obtains a waiver of the tariff requirement pursuant to paragraph (d) of this section, it does not need to file the open access transmission tariff required by this section.
(vi) Any public utility that seeks a deviation from the pro forma tariff promulgated by the Commission, as amended from time to time, must demonstrate that the deviation is consistent with the principles set forth in Commission rulemaking proceedings promulgating and amending the pro forma tariff.
(vii) Each public utility’s open access transmission tariff must include the standards incorporated by reference in part 38 of this chapter.
(2) Subject to the exceptions in paragraphs (c)(2)(i) and (c)(3)(iii) of this section, every public utility that owns, controls, or operates facilities used for the transmission of electric energy in interstate commerce, and that uses those facilities to engage in wholesale sales and/or purchases of electric energy, or unbundled retail sales of electric energy, must take transmission service for such sales and/or purchases under the open access transmission tariff filed pursuant to this section.
(i) For sales of electric energy pursuant to a requirements service agreement executed on or before July 9, 1996, this requirement will not apply unless separately ordered by the Commission. For sales of electric energy pursuant to a bilateral economy energy coordination agreement executed on or before July 9, 1996, this requirement is effective on December 31, 1996. For sales of electric energy pursuant to a bilateral non-economy energy coordination agreement executed on or before July 9, 1996, this requirement will not apply unless separately ordered by the Commission.
(ii) [Reserved]
(3) Every public utility that owns, controls, or operates facilities used for the transmission of electric energy in interstate commerce, and that is a member of a power pool, public utility holding company, or other multi-lateral trading arrangement or agreement that contains transmission rates, terms or conditions, must have on file a joint pool-wide or system-wide open access transmission tariff, which tariff must be the pro forma tariff promulgated by the Commission, as amended from time to time, or such other open access transmission tariff as may be approved by the Commission consistent with the principles set forth in Commission rulemaking proceedings promulgating and amending the pro forma tariff.
(i) For any power pool, public utility holding company or other multi-lateral arrangement or agreement that contains transmission rates, terms or conditions and that is executed after October 11, 2011, this requirement is effective on the date that transactions begin under the arrangement or agreement.
(ii) For any power pool, public utility holding company or other multi-lateral arrangement or agreement that contains transmission rates, terms or conditions and that is executed on or before May 14, 2007, a public utility member of such power pool, public utility holding company or other multi-lateral arrangement or agreement that owns, controls, or operates facilities used for the transmission of electric energy in interstate commerce must file the revisions to its joint pool-wide or system-wide open access transmission tariff required by Commission rulemaking proceedings promulgating and amending the pro forma tariff pursuant to section 206 of the FPA and accompanying rates pursuant to section 205 of the FPA in accordance with the procedures set forth in Commission rulemaking proceedings promulgating and amending the pro forma tariff.
(iii) A public utility member of a power pool, public utility holding company or other multi-lateral arrangement or agreement that contains transmission rates, terms or conditions and that is executed on or before July 9, 1996 must take transmission service under a joint pool-wide or system-wide open access transmission tariff filed pursuant to this section for wholesale trades among the pool or system members.
(4) Consistent with paragraph (c)(1) of this section, every Commission-approved ISO or RTO must have on file with the Commission an open access transmission tariff of general applicability for transmission services, including ancillary services, over such facilities. Such tariff must be the pro forma tariff promulgated by the Commission, as amended from time to time, or such other tariff as may be approved by the Commission consistent with the principles set forth in Commission rulemaking proceedings promulgating and amending the pro forma tariff.
(i) Subject to paragraph (c)(4)(ii) of this section, a Commission-approved ISO or RTO must file the revisions to its open access transmission tariff required by Commission rulemaking proceedings promulgating and amending the pro forma tariff pursuant to section 206 of the FPA and accompanying rates pursuant to section 205 of the FPA in accordance with the procedures set forth in Commission rulemaking proceedings promulgating and amending the pro forma tariff.
(ii) If a Commission-approved ISO or RTO can demonstrate that its existing open access transmission tariff is consistent with or superior to the pro forma tariff promulgated by the Commission, as amended from time to time, the Commission-approved ISO or RTO may instead set forth such demonstration in its filing pursuant to section 206 in accordance with the procedures set forth in Commission rulemaking proceedings promulgating and amending the pro forma tariff.
(5) Any public utility that owns transmission facilities that are not under the public utility’s control must, consistent with the pro forma tariff required by paragraph (c)(1) of this section, share with the public utility that controls such facilities (and its Market Monitoring Unit(s), if applicable):
(i) Transmission line ratings for each period for which transmission line ratings are calculated for such facilities (with updated ratings shared each time ratings are calculated); and
(ii) Written transmission line rating methodologies used to calculate the transmission line ratings for such facilities provided under subparagraph (i).
(d) Waivers. (1) A public utility subject to the requirements of this section and 18 CFR parts 37 (Open Access Same-Time Information System) and 358 (Standards of Conduct for Transmission Providers) may file a request for waiver of all or part of such requirements for good cause shown. Except as provided in paragraph (f) of this section, an application for waiver must be filed no later than 60 days prior to the time the public utility would have to comply with the requirement.
(2) The requirements of this section, 18 CFR parts 37 (Open Access Same-Time Information System) and 358 (Standards of Conduct for Transmission Providers) are waived for any public utility that is or becomes subject to such requirements solely because it owns, controls, or operates Interconnection Customer’s Interconnection Facilities, in whole or in part, as that term is defined in the standard generator interconnection procedures and agreements referenced in paragraph (f) of this section, or comparable jurisdictional interconnection facilities that are the subject of interconnection agreements other than the standard generator interconnection procedures and agreements referenced in paragraph (f) of this section, if the entity that owns, operates, or controls such facilities either sells electric energy, or files a statement with the Commission that it commits to comply with and be bound by the obligations and procedures applicable to electric utilities under section 210 of the Federal Power Act.
(i) The waivers referenced in this paragraph (d)(2) shall be deemed to be revoked as of the date the public utility ceases to satisfy the qualifications of this paragraph (d)(2), and may be revoked by the Commission if the Commission determines that it is in the public interest to do so. After revocation of its waivers, the public utility must comply with the requirements that had been waived within 60 days of revocation.
(ii) Any eligible entity that seeks interconnection or transmission services with respect to the interconnection facilities for which a waiver is in effect pursuant to this paragraph (d)(2) may follow the procedures in sections 210, 211, and 212 of the Federal Power Act, 18 CFR 2.20, and 18 CFR part 36. In any proceeding pursuant to this paragraph (d)(2)(ii):
(A) The Commission will consider it to be in the public interest to grant priority rights to the owner and/or operator of interconnection facilities specified in this paragraph (d)(2) to use capacity thereon when such owner and/or operator can demonstrate that it has specific plans with milestones to use such capacity to interconnect its or its affiliate’s future generation projects.
(B) For the first five years after the commercial operation date of the interconnection facilities specified in this paragraph (d)(2), the Commission will apply the rebuttable presumption that the owner and/or operator of such facilities has definitive plans to use the capacity thereon, and it is thus in the public interest to grant priority rights to the owner and/or operator of such facilities to use capacity thereon.
(e) Non-public utility procedures for tariff reciprocity compliance. (1) A non-public utility may submit an open access transmission tariff and a request for declaratory order that its voluntary transmission tariff meets the requirements of Commission rulemaking proceedings promulgating and amending the pro forma tariff.
(i) Any submittal and request for declaratory order submitted by a non-public utility will be provided an NJ (non-jurisdictional) docket designation.
(ii) If the submittal is found to be an acceptable open access transmission tariff, an applicant in a Federal Power Act (FPA) section 211 or 211A proceeding against the non-public utility shall have the burden of proof to show why service under the open access transmission tariff is not sufficient and why a section 211 or 211A order should be granted.
(2) A non-public utility may file a request for waiver of all or part of the reciprocity conditions contained in a public utility open access transmission tariff, for good cause shown. An application for waiver may be filed at any time.
(f) Standard generator interconnection procedures and agreements. (1) Every public utility that is required to have on file a non-discriminatory open access transmission tariff under this section must amend such tariff by adding the standard interconnection procedures and agreement and the standard small generator interconnection procedures and agreement required by Commission rulemaking proceedings promulgating and amending such interconnection procedures and agreements, or such other interconnection procedures and agreements as may be required by Commission rulemaking proceedings promulgating and amending the standard interconnection procedures and agreement and the standard small generator interconnection procedures and agreement.
(i) Any public utility that seeks a deviation from the standard interconnection procedures and agreement or the standard small generator interconnection procedures and agreement required by Commission rulemaking proceedings promulgating and amending such interconnection procedures and agreements, must demonstrate that the deviation is consistent with the principles set forth in Commission rulemaking proceedings promulgating and amending such interconnection procedures and agreements.
(ii) Any public utility that conducts interconnection studies shall be liable for and eligible to appeal certain penalties under the interconnection procedures and agreements adopted by the Commission-approved independent system operator or regional transmission organization under paragraph (f)(1) of this section following that public utility’s failure to complete an interconnection study by the appropriate deadline.
(iii)–(iv) [Reserved]
(2) The non-public utility procedures for tariff reciprocity compliance described in paragraph (e) of this section are applicable to the standard interconnection procedures and agreements.
(3) A public utility subject to the requirements of this paragraph (f) may file a request for waiver of all or part of the requirements of this paragraph (f), for good cause shown.
(g) Tariffs and operations of Commission-approved independent system operators and regional transmission organizations—(1) Demand response and pricing—(i) Ancillary services provided by demand response resources. (A) Every Commission-approved independent system operator or regional transmission organization that operates organized markets based on competitive bidding for energy imbalance, spinning reserves,supplemental reserves, reactive power and voltage control, or regulation and frequency response ancillary services (or its functional equivalent in the Commission-approved independent system operator’s or regional transmission organization’s tariff) must accept bids from demand response resources in these markets for that product on a basis comparable to any other resources, if the demand response resource meets the necessary technical requirements under the tariff, and submits a bid under the Commission-approved independent system operator’s or regional transmission organization’s bidding rules at or below the market-clearing price, unless not permitted by the laws or regulations of the relevant electric retail regulatory authority.
(B) Each Commission-approved independent system operator or regional transmission organization must allow providers of a demand response resource to specify the following in their bids:
(1) A maximum duration in hours that the demand response resource may be dispatched;
(2) A maximum number of times that the demand response resource may be dispatched during a day; and
(3) A maximum amount of electric energy reduction that the demand response resource may be required to provide either daily or weekly.
(ii) Removal of deviation charges. A Commission-approved independent system operator or regional transmission organization with a tariff that contains a day-ahead and a real-time market may not assess charge to a purchaser of electric energy in its day-ahead market for purchasing less power in the real-time market during a real-time market period for which the Commission-approved independent system operator or regional transmission organization declares an operating reserve shortage or makes a generic request to reduce load to avoid an operating reserve shortage.
(iii) Aggregation of retail customers. Each Commission-approved independent system operator and regional transmission organization must accept bids from an aggregator of retail customers that aggregates the demand response of the customers of utilities that distributed more than 4 million megawatt-hours in the previous fiscal year, and the customers of utilities that distributed 4 million megawatt-hours or less in the previous fiscal year, where the relevant electric retail regulatory authority permits such customers’ demand response to be bid into organized markets by an aggregator of retail customers. An independent system operator or regional transmission organization must not accept bids from an aggregator of retail customers that aggregates the demand response of the customers of utilities that distributed more than 4 million megawatt-hours in the previous fiscal year, where the relevant electric retail regulatory authority prohibits such customers’ demand response to be bid into organized markets by an aggregator of retail customers, or the customers of utilities that distributed 4 million megawatt-hours or less in the previous fiscal year, unless the relevant electric retail regulatory authority permits such customers’ demand response to be bid into organized markets by an aggregator of retail customers.
(iv) Price formation during periods of operating reserve shortage. (A) Each Commission-approved independent system operator and regional transmission organization must modify its market rules to allow the market-clearing price during periods of operating reserve shortage to reach a level that rebalances supply and demand so as to maintain reliability while providing sufficient provisions for mitigating market power. Each Commission-approved independent system operator and regional transmission organization must trigger shortage pricing for any interval in which a shortage of energy or operating reserves is indicated during the pricing of resources for that interval.
(B) A Commission-approved independent system operator or regional transmission organization may phase in this modification of its market rules.
(v) Demand response compensation in energy markets. Each Commission-approved independent system operator or regional transmission organization that has a tariff provision permitting demand response resources to participate as a resource in the energy market by reducing consumption of electric energy from their expected levels in response to price signals must:
(A) Pay to those demand response resources the market price for energy for these reductions when these demand response resources have the capability to balance supply and demand and when payment of the market price for energy to these resources is cost-effective as determined by a net benefits test accepted by the Commission;
(B) Allocate the costs associated with demand response compensation proportionally to all entities that purchase from the relevant energy market in the area(s) where the demand response reduces the market price for energy at the time when the demand response resource is committed or dispatched.
(vi) Settlement intervals. Each Commission-approved independent system operator and regional transmission organization must settle energy transactions in its real-time markets at the same time interval it dispatches energy, must settle operating reserves transactions in its real-time markets at the same time interval it prices operating reserves, and must settle intertie transactions at the same time interval it schedules intertie transactions.
(2) Long-term power contracting in organized markets. Each Commission-approved independent system operator or regional transmission organization must provide a portion of its Web site for market participants to post offers to buy or sell power on a long-term basis.
(3) Market monitoring policies. (i) Each Commission-approved independent system operator or regional transmission organization must modify its tariff provisions governing its Market Monitoring Unit to reflect the directives provided in Order No. 719, including the following:
(A) Each Commission-approved independent system operator or regional transmission organization must include in its tariff a provision to provide its Market Monitoring Unit access to Commission-approved independent system operator and regional transmission organization market data, resources and personnel to enable the MarketMonitoring Unit to carry out its functions.
(B) The tariff provision must provide the Market Monitoring Unit complete access to the Commission-approved independent system operator’s and regional transmission organization’s databases of market information.
(C) The tariff provision must provide that any data created by the Market Monitoring Unit, including, but not limited to, reconfiguring of the Commission-approved independent system operator’s and regional transmission organization’s data, will be kept within the exclusive control of the Market Monitoring Unit.
(D) The Market Monitoring Unit must report to the Commission-approved independent system operator’s or regional transmission organization’s board of directors, with its management members removed, or to an independent committee of the Commission-approved independent system operator’s or regional transmission organization’s board of directors. A Commission-approved independent system operator or regional transmission organization that has both an internal Market Monitoring Unit and an external Market Monitoring Unit may permit the internal Market Monitoring Unit to report to management and the external Market Monitoring Unit to report to the Commission-approved independent system operator’s or regional transmission organization’s board of directors with its management members removed, or to an independent committee of the Commission-approved independent system operator or regional transmission organization board of directors. If the internal market monitor is responsible for carrying out any or all of the core Market Monitoring Unit functions identified in paragraph (g)(3)(ii) of this section, the internal market monitor must report to the independent system operator’s or regional transmission organization’s board of directors.
(E) A Commission-approved independent system operator or regional transmission organization may not alter the reports generated by the Market Monitoring Unit, or dictate the conclusions reached by the Market Monitoring Unit.
(F) Each Commission-approved independent system operator or regional transmission organization must consolidate the core Market Monitoring Unit provisions into one section of its tariff. Each independent system operator or regional transmission organization must include a mission statement in the introduction to the Market Monitoring Unit provisions that identifies the Market Monitoring Unit’s goals, including the protection of consumers and market participants by the identification and reporting of market design flaws and market power abuses.
(ii) Core Functions of Market Monitoring Unit. The Market Monitoring Unit must perform the following core functions:
(A) Evaluate existing and proposed market rules, tariff provisions and market design elements and recommend proposed rule and tariff changes to the Commission-approved independent system operator or regional transmission organization, to the Commission’s Office of Energy Market Regulation staff and to other interested entities such as state commissions and market participants, provided that:
(1) The Market Monitoring Unit is not to effectuate its proposed market design itself, and
(2) The Market Monitoring Unit must limit distribution of its identifications and recommendations to the independent system operator or regional transmission organization and to Commission staff in the event it believes broader dissemination could lead to exploitation, with an explanation of why further dissemination should be avoided at that time.
(B) Review and report on the performance of the wholesale markets to the Commission-approved independent system operator or regional transmission organization, the Commission, and other interested entities such as state commissions and market participants, on at least a quarterly basis and submit a more comprehensive annual state of the market report. The Market Monitoring Unit may issue additional reports as necessary.
(C) Identify and notify the Commission’s Office of Enforcement staff of instances in which a market participant’s or the Commission-approved independent system operator’s or regional transmission organization’s behavior may require investigation, including, but not limited to, suspected Market Violations.
(iii) Tariff administration and mitigation (A) A Commission-approved independent system operator or regional transmission organization may not permit its Market Monitoring Unit, whether internal or external, to participate in the administration of the Commission-approved independent system operator’s or regional transmission organization’s tariff or, except as provided in paragraph (g)(3)(iii)(D) of this section, to conduct prospective mitigation.
(B) A Commission-approved independent system operator or regional transmission organization may permit its Market Monitoring Unit to provide the inputs required for the Commission-approved independent system operator or regional transmission organization to conduct prospective mitigation, including, but not limited to, reference levels, identification of system constraints, and cost calculations.
(C) A Commission-approved independent system operator or regional transmission organization may allow its Market Monitoring Unit to conduct retrospective mitigation.
(D) A Commission-approved independent system operator or regional transmission organization with a hybrid Market Monitoring Unit structure may permit its internal market monitor to conduct prospective and/or retrospective mitigation, in which case it must assign to its external market monitor the responsibility and the tools to monitor the quality and appropriateness of the mitigation.
(E) Each Commission-approved independent system operator or regional transmission organization must identify in its tariff the functions the Market Monitoring Unit will perform and the functions the Commission-approved independent system operator or regional transmission organization will perform.
(iv) Protocols on Market Monitoring Unit referrals to the Commission of suspected violations. (A) A Market Monitoring Unit is to make a non-public referral to the Commission in all instances where the Market Monitoring Unit has reason to believe that a Market Violation has occurred. While the Market Monitoring Unit need not be able to prove that a Market Violation has occurred, the Market Monitoring Unit is to provide sufficient credible information to warrant further investigation by the Commission. Once the Market Monitoring Unit has obtained sufficient credible information to warrant referral to the Commission, the Market Monitoring Unit is to immediately refer the matter to the Commission and desist from independent action related to the alleged Market Violation. This does not preclude the Market Monitoring Unit from continuing to monitor for any repeated instances of the activity by the same or other entities, which would constitute new Market Violations. The Market Monitoring Unit is to respond to requests from the Commission for any additional information in connection with the alleged Market Violation it has referred.
(B) All referrals to the Commission of alleged Market Violations are to be in writing, whether transmitted electronically, by fax, mail, or courier. The Market Monitoring Unit may alert the Commission orally in advance of the written referral.
(C) The referral is to be addressed to the Commission’s Director of the Office of Enforcement, with a copy also directed to both the Director of the Office of Energy Market Regulation and the General Counsel.
(D) The referral is to include, but need not be limited to, the following information.
(1) The name[s] of and, if possible, the contact information for, the entity[ies] that allegedly took the action[s] that constituted the alleged Market Violation[s];
(2) The date[s] or time period during which the alleged Market Violation[s] occurred and whether the alleged wrongful conduct is ongoing;
(3) The specific rule or regulation, and/or tariff provision, that was allegedly violated, or the nature of any inappropriate dispatch that may have occurred;
(4) The specific act[s] or conduct that allegedly constituted the Market Violation;
(5) The consequences to the market resulting from the acts or conduct, including, if known, an estimate of economic impact on the market;
(6) If the Market Monitoring Unit believes that the act[s] or conduct constituted a violation of the anti-manipulation rule of Part 1c, a description of the alleged manipulative effect on market prices, market conditions, or market rules;
(7) Any other information the Market Monitoring Unit believes is relevant and may be helpful to the Commission.
(E) Following a referral to the Commission, the Market Monitoring Unit is to continue to notify and inform the Commission of any information that the Market Monitoring Unit learns of that may be related to the referral, but the Market Monitoring Unit is not to undertake any investigative steps regarding the referral except at the express direction of the Commission or Commission Staff.
(v) Protocols on Market Monitoring Unit Referrals to the Commission of Perceived Market Design Flaws and Recommended Tariff Changes. (A) A Market Monitoring Unit is to make a referral to the Commission in all instances where the Market Monitoring Unit has reason to believe market design flaws exist that it believes could effectively be remedied by rule or tariff changes. The Market Monitoring Unit must limit distribution of its identifications and recommendations to the independent system operator or regional transmission organization and to the Commission in the event it believes broader dissemination could lead to exploitation, with an explanation of why further dissemination should be avoided at that time.
(B) All referrals to the Commission relating to perceived market design flaws and recommended tariff changes are to be in writing, whether transmitted electronically, by fax, mail, or courier. The Market Monitoring Unit may alert the Commission orally in advance of the written referral.
(C) The referral should be addressed to the Commission’s Director of the Office of Energy Market Regulation, with copies directed to both the Director of the Office of Enforcement and the General Counsel.
(D) The referral is to include, but need not be limited to, the following information.
(1) A detailed narrative describing the perceived market design flaw[s];
(2) The consequences of the perceived market design flaw[s], including, if known, an estimate of economic impact on the market;
(3) The rule or tariff change(s) that the Market Monitoring Unit believes could remedy the perceived market design flaw;
(4) Any other information the Market Monitoring Unit believes is relevant and may be helpful to the Commission.
(E) Following a referral to the Commission, the Market Monitoring Unit is to continue to notify and inform the Commission of any additional information regarding the perceived market design flaw, its effects on the market, any additional or modified observations concerning the rule or tariff changes that could remedy the perceived design flaw, any recommendations made by the Market Monitoring Unit to the regional transmission organization or independent system operator, stakeholders, market participants or state commissions regarding the perceived design flaw, and any actions taken by the regional transmission organization or independent system operator regarding the perceived design flaw.
(vi) Market Monitoring Unit ethics standards. Each Commission-approved independent system operator or regional transmission organization must include in its tariff ethical standards for its Market Monitoring Unit and the employees of its Market Monitoring Unit. At a minimum, the ethics standards must include the following requirements:
(A) The Market Monitoring Unit and its employees must have no material affiliation with any market participant or affiliate.
(B) The Market Monitoring Unit and its employees must not serve as an officer, employee, or partner of a market participant.
(C) The Market Monitoring Unit and its employees must have no material financial interest in any market participant or affiliate with potential exceptions for mutual funds and non-directed investments.
(D) The Market Monitoring Unit and its employees must not engage in any market transactions other than the performance of their duties under the tariff.
(E) The Market Monitoring Unit and its employees must not be compensated, other than by the Commission-approved independent system operator or regional transmission organization that retains or employs it, for any expert witness testimony or other commercial services, either to the Commission-approved independent system operator or regional transmission organization or to any other party, in connection with any legal or regulatory proceeding or commercial transaction relating to the Commission-approved independent system operator or regional transmission organization or to the Commission-approved independent system operator’s or regional transmission organization’s markets.
(F) The Market Monitoring Unit and its employees may not accept anything of value from a market participant in excess of a de minimis amount.
(G) The Market Monitoring Unit and its employees must advise a supervisor in the event they seek employment with a market participant, and must disqualify themselves from participating in any matter that would have an effect on the financial interest of the market participant.
(4) Electronic delivery of data. Each Commission-approved regional transmission organization and independent system operator must electronically deliver to the Commission, on an ongoing basis and in a form and manner consistent with its own collection of data and in a form and manner acceptable to the Commission, data related to the markets that the regional transmission organization or independent system operator administers.
(5) Offer and bid data. (i) Unless a Commission-approved independent system operator or regional transmission organization obtains Commission approval for a different period, each Commission-approved independent system operator and regional transmission organization must release its offer and bid data within three months.
(ii) A Commission-approved independent system operator or regional transmission organization must mask the identity of market participants when releasing offer and bid data. The Commission-approved independent system operators and regional transmission organization may propose a time period for eventual unmasking.
(6) Responsiveness of Commission-approved independent system operators and regional transmission organizations. Each Commission-approved independent system operator or regional transmission organization must adopt business practices and procedures that achieve Commission-approved independent system operator and regional transmission organization board of directors’ responsiveness to customers and other stakeholders and satisfy the following criteria:
(i) Inclusiveness. The business practices and procedures must ensure that any customer or other stakeholder affected by the operation of the Commission-approved independent system operator or regional transmission organization, or its representative, is permitted to communicate the customer’s or other stakeholder’s views to the independent system operator’s or regional transmission organization’s board of directors;
(ii) Fairness in balancing diverse interests. The business practices and procedures must ensure that the interests of customers or other stakeholders are equitably considered, and that deliberation and consideration of Commission-approved independent system operator’s and regional transmission organization’s issues are not dominated by any single stakeholder category;
(iii) Representation of minority positions. The business practices and procedures must ensure that, in instances where stakeholders are not in total agreement on a particular issue, minority positions are communicated to the Commission-approved independent system operator’s and regional transmission organization’s board of directors at the same time as majority positions; and
(iv) Ongoing responsiveness. The business practices and procedures must provide for stakeholder input into the Commission-approved independent system operator’s or regional transmission organization’s decisions as well as mechanisms to provide feedback to stakeholders to ensure that information exchange and communication continue over time.
(7) Compliance filings. All Commission-approved independent system operators and regional transmission organizations must make a compliance filing with the Commission as described in Order No. 719 under the following schedule:
(i) The compliance filing addressing the accepting of bids from demand response resources in markets for ancillary services on a basis comparable to other resources, removal of deviation charges, aggregation of retail customers, shortage pricing during periods of operating reserve shortage, long-term power contracting in organized markets, Market Monitoring Units, Commission-approved independent system operators’ and regional transmission organizations’ board of directors’ responsiveness, and reporting on the study of the need for further reforms to remove barriers to comparable treatment of demand response resources must be submitted on or before April 28, 2009.
(ii) A public utility that is approved as a regional transmission organization under § 35.34, or that is not approved but begins to operate regional markets for electric energy or ancillary services after December 29, 2008, must comply with Order No. 719 and the provisions of paragraphs (g)(1) through (g)(5) of this section before beginning operations.
(8) Frequency regulation compensation in ancillary services markets. Each Commission-approved independent system operator or regional transmission organization that has a tariff that provides for the compensation for frequency regulation service must provide such compensation based on the actual service provided, including a capacity payment that includes the marginal unit’s opportunity costs and a payment for performance that reflects the quantity of frequency regulation service provided by a resource when the resource is accurately following the dispatch signal.
(9) Electric storage resources. (i) Each Commission-approved independent system operator and regional transmission organization must have tariff provisions providing a participation model for electric storage resources that:
(A) Ensures that a resource using the participation model for electric storage resources in an independent system operator or regional transmission organization market is eligible to provide all capacity, energy, and ancillary services that it is technically capable of providing;
(B) Enables a resource using the participation model for electric storage resources to be dispatched and ensures that such a dispatchable resource can set the wholesale market clearing price as both a wholesale seller and wholesale buyer consistent with rules that govern the conditions under which a resource can set the wholesale price;
(C) Accounts for the physical and operational characteristics of electric storage resources through bidding parameters or other means; and
(D) Establishes a minimum size requirement for resources using the participation model for electric storage resources that does not exceed 100 kW.
(ii) The sale of electric energy from an independent system operator or regional transmission organization market to an electric storage resource that the resource then resells back to that market must be at the wholesale locational marginal price.
(10) Transparency—(i) Uplift reporting. Each Commission-approved independent system operator or regional transmission organization must post two reports, at minimum, regarding uplift on a publicly accessible portion of its website. First, each Commission-approved independent system operator or regional transmission organization must post uplift, paid in dollars, and categorized by transmission zone, day, and uplift category. Transmission zone shall be defined as the geographic area that is used for the local allocation of charges. Transmission zones with fewer than four resources may be aggregated with one or more neighboring transmission zones, until each aggregated zone contains at least four resources, and reported collectively. This report shall be posted within 20 calendar days of the end of each month. Second, each Commission-approved independent system operator or regional transmission organization must post the resource name and the total amount of uplift paid in dollars aggregated across the month to each resource that received uplift payments within the calendar month. This report shall be posted within 90 calendar days of the end of each month.
(ii) Reporting Operator-Initiated Commitments. Each Commission-approved independent system operator or regional transmission organization must post a report of each operator-initiated commitment listing the size of the commitment, transmission zone, commitment reason, and commitment start time on a publicly accessible portion of its website within 30 calendar days of the end of each month. Transmission zone shall be defined as a geographic area that is used for the local allocation of charges. Commitment reasons shall include, but are not limited to, system-wide capacity, constraint management, and voltage support.
(iii) Transmission constraint penalty factors. Each Commission-approved independent system operator or regional transmission organization must include, in its tariff, its transmission constraint penalty factor values; the circumstances, if any, under which the transmission constraint penalty factors can set locational marginal prices; and the procedure, if any, for temporarily changing the transmission constraint penalty factor values. Any procedure for temporarily changing transmission constraint penalty factor values must provide for notice of the change to market participants.
(11) A resource’s incremental energy offer must be capped at the higher of $1,000/MWh or that resource’s cost-based incremental energy offer. For the purpose of calculating Locational Marginal Prices, Regional Transmission Organizations and Independent System Operators must cap cost-based incremental energy offers at $2,000/MWh. The actual or expected costs underlying a resource’s cost-based incremental energy offer above $1,000/MWh must be verified before that offer can be used for purposes of calculating Locational Marginal Prices. If a resource submits an incremental energy offer above $1,000/MWh and the actual or expected costs underlying that offer cannot be verified before the market clearing process begins, that offer may not be used to calculate Locational Marginal Prices and the resource would be eligible for a make-whole payment if that resource is dispatched and the resource’s actual costs are verified after-the-fact. A resource would also be eligible for a make-whole payment if it is dispatched and its verified cost-based incremental energy offer exceeds $2,000/MWh. All resources, regardless of type, are eligible to submit cost-based incremental energy offers in excess of $1,000/MWh.
(12) Distributed energy resource aggregators. (i) Each independent system operator and regional transmission organization must have tariff provisions that allow distributed energy resource aggregations to participate directly in the independent system operator or regional transmission organization markets.
(ii) Each regional transmission organization and independent system operator, to accommodate the participation of distributed energy resource aggregations, must establish market rules that address:
(A) Eligibility to participate in the independent system operator or regional transmission organization markets through a distributed energy resource aggregation;
(B) Locational requirements for distributed energy resource aggregations;
(C) Distribution factors and bidding parameters for distributed energy resource aggregations;
(D) Information and data requirements for distributed energy resource aggregations;
(E) Modification to the list of resources in a distributed energy resource aggregation;
(F) Metering and telemetry system requirements for distributed energy resource aggregations;
(G) Coordination between the regional transmission organization or independent system operator, the distributed energy resource aggregator, the distribution utility, and the relevant electric retail regulatory authorities; and
(H) Market participation agreements for distributed energy resource aggregators.
(iii) Each regional transmission organization and independent system operator must establish a minimum size requirement for distributed energy resource aggregations that does not exceed 100 kW.
(iv) Each regional transmission organization and independent system operator must accept bids from a distributed energy resource aggregator if its aggregation includes distributed energy resources that are customers of utilities that distributed more than 4 million megawatt-hours in the previous fiscal year. An independent system operator or regional transmission organization must not accept bids from a distributed energy resource aggregator if its aggregation includes distributed energy resources that are customers of utilities that distributed 4 million megawatt-hours or less in the previous fiscal year, unless the relevant electric retail regulatory authority permits such customers to be bid into RTO/ISO markets by a distributed energy resource aggregator.
(13) Transmission line ratings. (i) Each Commission-approved independent system operator or regional transmission organization must establish and maintain systems and procedures necessary to allow any public utility whose transmission facilities are under the independent control of the independent system operator or regional transmission organization to electronically update transmission line ratings for such facilities (for each period for which transmission line ratings are calculated) at least hourly, with such data submitted by those public utility transmission owners directly into the independent system operator’s or regional transmission organization’s EMS through SCADA or related systems.
(ii) [Reserved]
§ 35.29 Treatment of special assessments levied under the Atomic Energy Act of 1954, as amended by Title XI of the Energy Policy Act of 1992.
The costs that public utilities incur relating to special assessments under the Atomic Energy Act of 1954, as amended by the Energy Policy Act of 1992, are costs that may be reflected in jurisdictional rates. Public utilities seeking to recover the costs incurred relating to special assessments shall comply with the following procedures.
(a) Fuel adjustment clauses. In computing the Account 518 cost of nuclear fuel pursuant to § 35.14(a)(6), utilities seeking to recover the costs of special assessments through their fuel adjustment clauses shall:
(1) Deduct any expenses associated with special assessments included in Account 518;
(2) Add to Account 518 one-twelfth of any payments made for special assessments within the 12-month period ending with the current month; and
(3) Deduct from Account 518 one-twelfth of any refunds of payments made for special assessments received within the 12-month period ending with the current month that is received from the Federal government because the public utility has contested a special assessment or overpaid a special assessment.
(b) Cost of service data requirements. Public utilities filing rate applications under §§ 35.12 or 35.13 (regardless of whether the utility elects the abbreviated, unadjusted Period I, adjusted Period I, or Period II cost support requirements) must submit cost data that is computed in accordance with the requirements specified in paragraphs (a) (1), (2) and (3) of this section.
(c) Formula rates. Public utilities with formula rates on file that provide for the automatic recovery of nuclear fuel costs must reflect the costs of special assessments in accordance with the requirements specified in paragraphs (a) (1), (2) and (3) of this section.
Subpart D—Procedures and Requirements for Public Utility Sales of Power to Bonneville Power Administration Under Northwest Power Act
§ 35.30 General provisions.
(a) Applicability. This subpart applies to any sales of electric power subject to the Commission’s jurisdiction under Part II of the Federal Power Act from public utilities to the Administrator of the Bonneville Power Administration (BPA) at the average system cost (ASC) of that utility’s resources (electric power generation by the utility) pursuant to section 5(c) of the Pacific Northwest Electric Power Planning and Conservation Act, 16 U.S.C. 830–839h. The ASC is determined by BPA in accordance with 18 CFR part 301.
(b) Effectiveness of rates. (1) During the period between the date of BPA’s determination of ASC and the date of the final order issued by the Commission, the utility may charge the rate based on the ASC determined by BPA, subject to § 35.31(c) of this part.
(2) Except as otherwise provided under this section, the ASC ordered by the Commission will be deemed in effect from the beginning of the relevant exchange period, as defined in § 301.1(b)(95) of this chapter. For any initial exchange period after the Commission approves a new ASC methodology, the ASC will be effective retroactively under this paragraph only if the utility files its new ASC within the time allowed under BPA procedures. Any utility that files a revised ASC with BPA in accordance with this paragraph must promptly file with the Commission a notice of timely filing of the new ASC.
(c) Filing requirements. Within 15 business days of the date of issuance of the BPA report on a utility’s ASC, the utility must file with the Commission the ASC determined by BPA, the BPA written report, the utility’s ASC schedules, material necessary to comply with 18 CFR 35.13(c), and any other material requested by the Commission or its staff.
§ 35.31 Commission review.
(a) Procedures. Filings under this subpart are subject to the procedures applicable to other filings under section 205 of the Federal Power Act, as the Commission deems appropriate.
(b) Commission standard. With respect to any filing under this subpart, the Commission will determine whether the ASC set by BPA for the applicable exchange period was determined in accordance with the ASC methodology set forth at 18 CFR 301.1. If the ASC is not in accord with the methodology, the Commission will order that BPA amend the ASC to conform with the methodology. If the ASC is in accord with the methodology, the rate is deemed just and reasonable.
(c) Refunds and adjustments. (1) Any ASC-based rate charged by a public utility under this subpart pending Commission order is subject to refund or to adjustment that increases the ASC-based rate.
(2) Any interest on refunds ordered by the Commission under this subpart is computed in accordance with 18 CFR 35.19a. Interest on any increase ordered by the Commission will be at the rate charged to BPA by the U.S. Treasury during that period, unless the Commission orders another interest rate.
Subpart E—Regulations Governing Nuclear Plant Decommissioning Trust Funds
§ 35.32 General provisions.
(a) If a public utility has elected to provide for the decommissioning of a nuclear power plant through a nuclear plant decommissioning trust fund (Fund), the Fund must meet the following criteria:
(1) The Fund must be an external trust fund in the United States, established pursuant to a written trust agreement, that is independent of the utility, its subsidiaries, affiliates or associates. If the trust fund includes monies collected both in Commission-jurisdictional rates and in non-Commission-jurisdictional rates, then a separate account of the Commission-jurisdictional monies shall be maintained.
(2) The utility may provide overall investment policy to the Trustee or Investment Manager, but it may do so only in writing, and neither the utility nor its subsidiaries, affiliates or associates may serve as Investment Manager or otherwise engage in day-to-day management of the Fund or mandate individual investment decisions.
(3) The Fund’s Investment Manager must exercise the standard of care, whether in investing or otherwise, that a prudent investor would use in the same circumstances. The term “prudent investor” means a prudent investor as described in Restatement of the Law (Third), Trusts § 227, including general comments and reporter’s notes, pages 8–101. St. Paul, MN: American Law Institute Publishers, (1992). ISBN 0–314–84246–2. This incorporation by reference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Law Institute, 4025 Chestnut Street, Philadelphia, PA 19104, and are also available in local law libraries. Copies may be inspected at the Federal Energy Regulatory Commission’s Library, Room 95–01, 888 First Street, NE. Washington, DC or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202–741–6030, or go to: http://www.archives.gov/federal_register/code_of_federal_regulations/ibr_locations.html.
(4) The Trustee shall have a net worth of at least $100 million. In calculating the $100 million net worth requirement, the net worth of the Trustee’s parent corporation and/or affiliates may be taken into account only if such entities guarantee the Trustee’s responsibilities to the Fund.
(5) The Trustee or Investment Manager shall keep accurate and detailed accounts of all investments, receipts, disbursements and transactions of the Fund. All accounts, books and records relating to the Fund shall be open to inspection and audit at reasonable times by the utility or its designee or by the Commission or its designee. The utility or its designee must notify the Commission prior to performing any such inspection or audit. The Commission may direct the utility to conduct an audit or inspection.
(6) Absent the express authorization of the Commission, no part of the assets of the Fund may be used for, or diverted to, any purpose other than to fund the costs of decommissioning the nuclear power plant to which the Fund relates, and to pay administrative costs and other incidental expenses, including taxes, of the Fund.
(7) If the Fund balances exceed the amount actually expended for decommissioning after decommissioning has been completed, the utility shall return the excess jurisdictional amount to ratepayers, in a manner the Commission determines.
(8) Except for investments tied to market indexes or other mutual funds, the Investment Manager shall not invest in any securities of the utility for which it manages the funds or in that utility’s subsidiaries, affiliates, or associates or their successors or assigns.
(9) The utility and the Fiduciary shall seek to obtain the best possible tax treatment of amounts collected for nuclear plant decommissioning. In this regard, the utility and the Fiduciary shall take maximum advantage of tax deductions and credits, when it is consistent with sound business practices to do so.
(10) Each utility shall deposit in the Fund at least quarterly all amounts included in Commission-jurisdictional rates to fund nuclear power plant decommissioning.
(b) The establishment, organization, and maintenance of the Fund shall not relieve the utility or its subsidiaries, affiliates or associates of any obligations it may have as to the decommissioning of the nuclear power plant. It is not the responsibility of the Fiduciary to ensure that the amount of monies that a Fund contains are adequate to pay for a nuclear unit’s decommissioning.
(c) A utility may establish both qualified and non-qualified Funds with respect to a utility’s interest in a specific nuclear plant. This section applies to both “qualified” (under the Internal Revenue Code, 26 U.S.C. 468A, or any successor section) and non-qualified Funds.
(d) A utility must regularly supply to the Fund’s Investment Manager, and regularly update, essential information about the nuclear unit covered by the Trust Fund Agreement, including its description, location, expected remaining useful life, the decommissioning plan the utility proposes to follow, the utility’s liquidity needs once decommissioning begins, and any other information that the Fund’s Investment Manager would need to construct and maintain, over time, a sound investment plan.
(e) A utility should monitor the performance of all Fiduciaries of the Fund and, if necessary, replace them if they are not properly performing assigned responsibilities.
§ 35.33 Specific provisions.
(a) In addition to the general provisions of § 35.32, the Trustee must observe the provisions of this section.
(b) The Trustee may use Fund assets only to:
(1) Satisfy the liability of a utility for decommissioning costs of the nuclear power plant to which the Fund relates as provided by § 35.32; and
(2) Pay administrative costs and other incidental expenses, including taxes, of the Fund as provided by § 35.32.
(c) To the extent that the Trustee does not currently require the assets of the Fund for the purposes described in paragraphs (b)(1) and (b)(2) of this section, the Investment Manager, when investing Fund assets, must exercise the same standard of care that a reasonable person would exercise in the same circumstances. In this context, a “reasonable person” means a prudent investor as described in Restatement of the Law (Third), Trusts § 227, including general comments and reporter’s notes, pages 8–101. St. Paul, MN: American Law Institute Publishers, 1992. ISBN 0–314–84246–2. This incorporation by reference was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. Copies may be obtained from the American Law Institute, 4025 Chestnut Street, Philadelphia, PA 19104, and are also available in local law libraries. Copies may be inspected at the Federal Energy Regulatory Commission, 888 First Street, NE. Washington, DC or at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, call 202–741–6030, or go to: http://www.archives.gov/federal-register/cfr/ibr-locations.html.
(d) The utility must submit to the Commission by March 31 of each year, one original and three conformed copies of the financial report furnished to the utility by the Fund’s Trustee that shows for the previous calendar year:
(1) Fund assets and liabilities at the beginning of the period;
(2) Activity of the Fund during the period, including amounts received from the utility, a summary amount for purchases of fund investments and a summary amount for sales of fund investments, gains and losses from investment activity, disbursements from the Fund for decommissioning activity and payment of Fund expenses, including taxes; and
(3) Fund assets and liabilities at the end of the period. The report should not include the liability for decommissioning.
(4) Public utilities owning nuclear plants must maintain records of individual purchase and sales transactions until after decommissioning has been completed and any excess jurisdictional amounts have been returned to ratepayers in a manner that the Commission determines. The public utility need not include these records in the financial report that it furnishes to the Commission by March 31 of each year.
(e) The utility must also mail a copy of the financial report provided to the Commission pursuant to paragraph (d) of this section to anyone who requests it.
(f) If an independent public accountant has expressed an opinion on the report or on any portion of the report, then that opinion must accompany the report.
Subpart F—Procedures and Requirements Regarding Regional Transmission Organizations
§ 35.34 Regional Transmission Organizations.
(a) Purpose. This section establishes required characteristics and functions for Regional Transmission Organizations for the purpose of promoting efficiency and reliability in the operation and planning of the electric transmission grid and ensuring non-discrimination in the provision of electric transmission services. This section further directs each public utility that owns, operates, or controls facilities used for the transmission of electric energy in interstate commerce to make certain filings with respect to forming and participating in a Regional Transmission Organization.
(b) Definitions. (1) Regional Transmission Organization means an entity that satisfies the minimum characteristics set forth in paragraph (j) of this section, performs the functions set forth in paragraph (k) of this section, and accommodates the open architecture condition set forth in paragraph (l) of this section.
(2) Market participant means:
(i) Any entity that, either directly or through an affiliate, sells or brokers electric energy, or provides ancillary services to the Regional Transmission Organization, unless the Commission finds that the entity does not have economic or commercial interests that would be significantly affected by the Regional Transmission Organization’s actions or decisions; and
(ii) Any other entity that the Commission finds has economic or commercial interests that would be significantly affected by the Regional Transmission Organization’s actions or decisions.
(3) Affiliate means the definition given in section 2(a)(11) of the Public Utility Holding Company Act (15 U.S.C. 79b(a)(11)).
(4) Class of market participants means two or more market participants with common economic or commercial interests.
(c) General rule. Except for those public utilities subject to the requirements of paragraph (h) of this section, every public utility that owns, operates or controls facilities used for the transmission of electric energy in interstate commerce as of March 6, 2000 must file with the Commission, no later than October 15, 2000, one of the following:
(1) A proposal to participate in a Regional Transmission Organization consisting of one of the types of submittals set forth in paragraph (d) of this section; or
(2) An alternative filing consistent with paragraph (g) of this section.
(d) Proposal to participate in a Regional Transmission Organization. For purposes of this section, a proposal to participate in a Regional Transmission Organization means:
(1) Such filings, made individually or jointly with other entities, pursuant to sections 203, 205 and 206 of the Federal Power Act (16 U.S.C. 824b, 824d, and 824e), as are necessary to create a new Regional Transmission Organization;
(2) Such filings, made individually or jointly with other entities, pursuant to sections 203, 205 and 206 of the Federal Power Act (16 U.S.C. 824b, 824d, and 824e), as are necessary to join a Regional Transmission Organization approved by the Commission on or before the date of the filing; or
(3) A petition for declaratory order, filed individually or jointly with other entities, asking whether a proposed transmission entity would qualify as a Regional Transmission Organization and containing at least the following:
(i) A detailed description of the proposed transmission entity, including a description of the organizational and operational structure and the intended participants;
(ii) A discussion of how the transmission entity would satisfy each of the characteristics and functions of a Regional Transmission Organization specified in paragraphs (j), (k) and (l) of this section;
(iii) A detailed description of the Federal Power Act section 205 rates that will be filed for the Regional Transmission Organization; and
(iv) A commitment to make filings pursuant to sections 203, 205 and 206 of the Federal Power Act (16 U.S.C. 824b, 824d, and 824e), as necessary, promptly after the Commission issues an order in response to the petition.
(4) Any proposal filed under this paragraph (d) must include an explanation of efforts made to include public power entities and electric power cooperatives in the proposed Regional Transmission Organization.
(e) [Reserved]
(f) Transfer of operational control. Any public utility’s proposal to participate in a Regional Transmission Organization filed pursuant to paragraph (c)(1) of this section must propose that operational control of that public utility’s transmission facilities will be transferred to the Regional Transmission Organization on a schedule that will allow the Regional Transmission Organization to commence operating the facilities no later than December 15, 2001.
The requirement in paragraph (f) of this section may be satisfied by proposing to transfer to the Regional Transmission Organization ownership of the facilities in addition to operational control.
(g) Alternative filing. Any filing made pursuant to paragraph (c)(2) of this section must contain:
(1) A description of any efforts made by that public utility to participate in a Regional Transmission Organization;
(2) A detailed explanation of the economic, operational, commercial, regulatory, or other reasons the public utility has not made a filing to participate in a Regional Transmission Organization, including identification of any existing obstacles to participation in a Regional Transmission Organization; and
(3) The specific plans, if any, the public utility has for further work toward participation in a Regional Transmission Organization, a proposed timetable for such activity, an explanation of efforts made to include public power entities in the proposed Regional Transmission Organization, and any factors (including any law, rule or regulation) that may affect the public utility’s ability or decision to participate in a Regional Transmission Organization.
(h) Public utilities participating in approved transmission entities. Every public utility that owns, operates or controls facilities used for the transmission of electric energy in interstate commerce as of March 6, 2000, and that has filed with the Commission on or before March 6, 2000 to transfer operational control of its facilities to a transmission entity that has been approved or conditionally approved by the Commission on or before March 6, 2000 as being in conformance with the eleven ISO principles set forth in Order No. 888, FERC Statutes and Regulations, Regulations Preamble January 1991–June 1996 ¶ 31,036 (Final Rule on Open Access and Stranded Costs; see 61 FR 21540, May 10, 1996), must, individually or jointly with other entities, file with the Commission, no later than January 15, 2001:
(1) A statement that it is participating in a transmission entity that has been so approved;
(2) A detailed explanation of the extent to which the transmission entity in which it participates has the characteristics and performs the functions of a Regional Transmission Organization specified in paragraphs (j) and (k) of this section and accommodates the open architecture conditions in paragraph (l) of this section; and
(3) To the extent the transmission entity in which the public utility participates does not meet all the requirements of a Regional Transmission Organization specified in paragraphs (j), (k), and (l) of this section,
(i) A proposal to participate in a Regional Transmission Organization that meets such requirements in accordance with paragraph (d) of this section,
(ii) A proposal to modify the existing transmission entity so that it conforms to the requirements of a Regional Transmission Organization, or
(iii) A filing containing the information specified in paragraph (g) of this section addressing any efforts, obstacles, and plans with respect to conformance with those requirements.
(i) Entities that become public utilities with transmission facilities. An entity that is not a public utility that owns, operates or controls facilities used for the transmission of electric energy in interstate commerce as of March 6, 2000, but later becomes such a public utility, must file a proposal to participate in a Regional Transmission Organization in accordance with paragraph (d) of this section, or an alternative filing in accordance with paragraph (g) of this section, by October 15, 2000 or 60 days prior to the date on which the public utility engages in any transmission of electric energy in interstate commerce, whichever comes later. If a proposal to participate in accordance with paragraph (d) of this section is filed, it must propose that operational control of the applicant’s transmission system will be transferred to the Regional Transmission Organization within six months of filing the proposal.
(j) Required characteristics for a Regional Transmission Organization. A Regional Transmission Organization must satisfy the following characteristics when it commences operation:
(1) Independence. The Regional Transmission Organization must be independent of any market participant. The Regional Transmission Organization must include, as part of its demonstration of independence, a demonstration that it meets the following:
(i) The Regional Transmission Organization, its employees, and any non-stakeholder directors must not have financial interests in any market participant.
(ii) The Regional Transmission Organization must have a decision making process that is independent of control by any market participant or class of participants.
(iii) The Regional Transmission Organization must have exclusive and independent authority under section 205 of the Federal Power Act (16 U.S.C. 824d), to propose rates, terms and conditions of transmission service provided over the facilities it operates.
Transmission owners retain authority under section 205 of the Federal Power Act (16 U.S.C. 824d) to seek recovery from the Regional Transmission Organization of the revenue requirements associated with the transmission facilities that they own.
(iv)(A) The Regional Transmission Organization must provide:
(1) With respect to any Regional Transmission Organization in which market participants have an ownership interest, a compliance audit of the independence of the Regional Transmission Organization’s decision making process under paragraph (j)(1)(ii) of this section, to be performed two years after approval of the Regional Transmission Organization, and every three years thereafter, unless otherwise provided by the Commission.
(2) With respect to any Regional Transmission Organization in which market participants have a role in the Regional Transmission Organization’s decision making process but do not have an ownership interest, a compliance audit of the independence of the Regional Transmission Organization’s decision making process under paragraph (j)(1)(ii) of this section, to be performed two years after its approval as a Regional Transmission Organization.
(B) The compliance audits under paragraph (j)(1)(iv)(A) of this section must be performed by auditors who are not affiliated with the Regional Transmission Organization or transmission facility owners that are members of the Regional Transmission Organization.
(2) Scope and regional configuration. The Regional Transmission Organization must serve an appropriate region. The region must be of sufficient scope and configuration to permit the Regional Transmission Organization to maintain reliability, effectively perform its required functions, and support efficient and non-discriminatory power markets.
(3) Operational authority. The Regional Transmission Organization must have operational authority for all transmission facilities under its control. The Regional Transmission Organization must include, as part of its demonstration of operational authority, a demonstration that it meets the following:
(i) If any operational functions are delegated to, or shared with, entities other than the Regional Transmission Organization, the Regional Transmission Organization must ensure that this sharing of operational authority will not adversely affect reliability or provide any market participant with an unfair competitive advantage. Within two years after initial operation as a Regional Transmission Organization, the Regional Transmission Organization must prepare a public report that assesses whether any division of operational authority hinders the Regional Transmission Organization in providing reliable, non-discriminatory and efficiently priced transmission service.
(ii) The Regional Transmission Organization must be the security coordinator for the facilities that it controls.
(4) Short-term reliability. The Regional Transmission Organization must have exclusive authority for maintaining the short-term reliability of the grid that it operates. The Regional Transmission Organization must include, as part of its demonstration with respect to reliability, a demonstration that it meets the following:
(i) The Regional Transmission Organization must have exclusive authority for receiving, confirming and implementing all interchange schedules.
(ii) The Regional Transmission Organization must have the right to order redispatch of any generator connected to transmission facilities it operates if necessary for the reliable operation of these facilities.
(iii) When the Regional Transmission Organization operates transmission facilities owned by other entities, the Regional Transmission Organization must have authority to approve or disapprove all requests for scheduled outages of transmission facilities to ensure that the outages can be accommodated within established reliability standards.
(iv) If the Regional Transmission Organization operates under reliability standards established by another entity (e.g., a regional reliability council), the Regional Transmission Organization must report to the Commission if these standards hinder it from providing reliable, non-discriminatory and efficiently priced transmission service.
(k) Required functions of a Regional Transmission Organization. The Regional Transmission Organization must perform the following functions. Unless otherwise noted, the Regional Transmission Organization must satisfy these obligations when it commences operations.
(1) Tariff administration and design. The Regional Transmission Organization must administer its own transmission tariff and employ a transmission pricing system that will promote efficient use and expansion of transmission and generation facilities. As part of its demonstration with respect to tariff administration and design, the Regional Transmission Organization must satisfy the standards listed in paragraphs (k)(1)(i) and (ii) of this section, or demonstrate that an alternative proposal is consistent with or superior to satisfying such standards.
(i) The Regional Transmission Organization must be the only provider of transmission service over the facilities under its control, and must be the sole administrator of its own Commission-approved open access transmission tariff. The Regional Transmission Organization must have the sole authority to receive, evaluate, and approve or deny all requests for transmission service. The Regional Transmission Organization must have the authority to review and approve requests for new interconnections.
(ii) Customers under the Regional Transmission Organization tariff must not be charged multiple access fees for the recovery of capital costs for transmission service over facilities that the Regional Transmission Organization controls.
(2) Congestion management. The Regional Transmission Organization must ensure the development and operation of market mechanisms to manage transmission congestion. As part of its demonstration with respect to congestion management, the Regional Transmission Organization must satisfy the standards listed in paragraph (k)(2)(i) of this section, or demonstrate that an alternative proposal is consistent with or superior to satisfying such standards.
(i) The market mechanisms must accommodate broad participation by all market participants, and must provide all transmission customers with efficient price signals that show the consequences of their transmission usage decisions. The Regional Transmission Organization must either operate such markets itself or ensure that the task is performed by another entity that is not affiliated with any market participant.
(ii) The Regional Transmission Organization must satisfy the market mechanism requirement no later than one year after it commences initial operation. However, it must have in place at the time of initial operation an effective protocol for managing congestion.
(3) Parallel path flow. The Regional Transmission Organization must develop and implement procedures to address parallel path flow issues within its region and with other regions. The Regional Transmission Organization must satisfy this requirement with respect to coordination with other regions no later than three years after it commences initial operation.
(4) Ancillary services. The Regional Transmission Organization must serve as a provider of last resort of all ancillary services required by Order No. 888, FERC Statutes and Regulations, Regulations Preamble January 1991–June 1996 ¶ 31,036 (Final Rule on Open Access and Stranded Costs; see 61 FR 21540, May 10, 1996), and subsequent orders. As part of its demonstration with respect to ancillary services, the Regional Transmission Organization must satisfy the standards listed in paragraphs (k)(4)(i) through (iii) of this section, or demonstrate that an alternative proposal is consistent with or superior to satisfying such standards.
(i) All market participants must have the option of self-supplying or acquiring ancillary services from third parties subject to any restrictions imposed by the Commission in Order No. 888, FERC Statutes and Regulations, Regulations Preamble January 1991–June 1996 ¶ 31,036 (Final Rule on Open Access and Stranded Costs), and subsequent orders.
(ii) The Regional Transmission Organization must have the authority to decide the minimum required amounts of each ancillary service and, if necessary, the locations at which these services must be provided. All ancillary service providers must be subject to direct or indirect operational control by the Regional Transmission Organization. The Regional Transmission Organization must promote the development of competitive markets for ancillary services whenever feasible.
(iii) The Regional Transmission Organization must ensure that its transmission customers have access to a real-time balancing market. The Regional Transmission Organization must either develop and operate this market itself or ensure that this task is performed by another entity that is not affiliated with any market participant.
(5) OASIS and Total Transmission Capability (TTC) and Available Transmission Capability (ATC). The Regional Transmission Organization must be the single OASIS site administrator for all transmission facilities under its control and independently calculate TTC and ATC.
(6) Market monitoring. To ensure that the Regional Transmission Organization provides reliable, efficient and not unduly discriminatory transmission service, the Regional Transmission Organization must provide for objective monitoring of markets it operates or administers to identify market design flaws, market power abuses and opportunities for efficiency improvements, and propose appropriate actions. As part of its demonstration with respect to market monitoring, the Regional Transmission Organization must satisfy the standards listed in paragraphs (k)(6)(i) through (k)(6)(iii) of this section, or demonstrate that an alternative proposal is consistent with or superior to satisfying such standards.
(i) Market monitoring must include monitoring the behavior of market participants in the region, including transmission owners other than the Regional Transmission Organization, if any, to determine if their actions hinder the Regional Transmission Organization in providing reliable, efficient and not unduly discriminatory transmission service.
(ii) With respect to markets the Regional Transmission Organization operates or administers, there must be a periodic assessment of how behavior in markets operated by others (e.g., bilateral power sales markets and power markets operated by unaffiliated power exchanges) affects Regional Transmission Organization operations and how Regional Transmission Organization operations affect the efficiency of power markets operated by others.
(iii) Reports on opportunities for efficiency improvement, market power abuses and market design flaws must be filed with the Commission and affected regulatory authorities.
(7) Planning and expansion. The Regional Transmission Organization must be responsible for planning, and for directing or arranging, necessary transmission expansions, additions, and upgrades that will enable it to provide efficient, reliable and non-discriminatory transmission service and coordinate such efforts with the appropriate state authorities. As part of its demonstration with respect to planning and expansion, the Regional Transmission Organization must satisfy the standards listed in paragraphs (k)(7)(i) and (ii) of this section, or demonstrate that an alternative proposal is consistent with or superior to satisfying such standards.
(i) The Regional Transmission Organization planning and expansion process must encourage market-driven operating and investment actions for preventing and relieving congestion.
(ii) The Regional Transmission Organization’s planning and expansion process must accommodate efforts by state regulatory commissions to create multi-state agreements to review and approve new transmission facilities. The Regional Transmission Organization’s planning and expansion process must be coordinated with programs of existing Regional Transmission Groups (See § 2.21 of this chapter) where appropriate.
(iii) If the Regional Transmission Organization is unable to satisfy this requirement when it commences operation, it must file with the Commission a plan with specified milestones that will ensure that it meets this requirement no later than three years after initial operation.
(8) Interregional coordination. The Regional Transmission Organization must ensure the integration of reliability practices within an interconnection and market interface practices among regions.
(l) Open architecture. (1) Any proposal to participate in a Regional Transmission Organization must not contain any provision that would limit the capability of the Regional Transmission Organization to evolve in ways that would improve its efficiency, consistent with the requirements in paragraphs (j) and (k) of this section.
(2) Nothing in this regulation precludes an approved Regional Transmission Organization from seeking to evolve with respect to its organizational design, market design, geographic scope, ownership arrangements, or methods of operational control, or in other appropriate ways if the change is consistent with the requirements of this section. Any future filing seeking approval of such changes must demonstrate that the proposed changes will meet the requirements of paragraphs (j), (k) and (l) of this section.
Subpart G—Transmission Infrastructure Investment Provisions
§ 35.35 Transmission infrastructure investment.
(a) Purpose. This section establishes rules for incentive-based (including performance-based) rate treatments for transmission of electric energy in interstate commerce by public utilities for the purpose of benefiting consumers by ensuring reliability and reducing the cost of delivered power by reducing transmission congestion.
(b) Definitions. (1) Transco means a stand-alone transmission company that has been approved by the Commission and that sells transmission services at wholesale and/or on an unbundled retail basis, regardless of whether it is affiliated with another public utility.
(2) Transmission Organization means a Regional Transmission Organization, Independent System Operator, independent transmission provider, or other transmission organization finally approved by the Commission for the operation of transmission facilities.
(c) General rule. All rates approved under the rules of this section, including any revisions to the rules, are subject to the filing requirements of sections 205 and 206 of the Federal Power Act and to the substantive requirements of sections 205 and 206 of the Federal Power Act that all rates, charges, terms and conditions be just and reasonable and not unduly discriminatory or preferential.
(d) Incentive-based rate treatments for transmission infrastructure investment. The Commission will authorize any incentive-based rate treatment, as discussed in this paragraph (d), for transmission infrastructure investment, provided that the proposed incentive-based rate treatment is just and reasonable and not unduly discriminatory or preferential. A public utility’s request for one or more incentive-based rate treatments, to be made in a filing pursuant to section 205 of the Federal Power Act, or in a petition for a declaratory order that precedes a filing pursuant to section 205, must include a detailed explanation of how the proposed rate treatment complies with the requirements of section 219 of the Federal Power Act and a demonstration that the proposed rate treatment is just, reasonable, and not unduly discriminatory or preferential. The applicant must demonstrate that the facilities for which it seeks incentives either ensure reliability or reduce the cost of delivered power by reducing transmission congestion consistent with the requirements of section 219, that the total package of incentives is tailored to address the demonstrable risks or challenges faced by the applicant in undertaking the project, and that resulting rates are just and reasonable. For purposes of this paragraph (d), incentive-based rate treatment means any of the following:
(1) For purposes of this paragraph (d), incentive-based rate treatment means any of the following:
(i) A rate of return on equity sufficient to attract new investment in transmission facilities;
(ii) 100 percent of prudently incurred Construction Work in Progress (CWIP) in rate base;
(iii) Recovery of prudently incurred pre-commercial operations costs;
(iv) Hypothetical capital structure;
(v) Accelerated depreciation used for rate recovery;
(vi) Recovery of 100 percent of prudently incurred costs of transmission facilities that are cancelled or abandoned due to factors beyond the control of the public utility;
(vii) Deferred cost recovery; and
(viii) Any other incentives approved by the Commission, pursuant to the requirements of this paragraph, that are determined to be just and reasonable and not unduly discriminatory or preferential.
(2) In addition to the incentives in § 35.35(d)(1), the Commission will authorize the following incentive-based rate treatments for Transcos, provided that the proposed incentive-based rate treatment is just and reasonable and not unduly discriminatory or preferential:
(i) A return on equity that both encourages Transco formation and is sufficient to attract investment; and
(ii) An adjustment to the book value of transmission assets being sold to a Transco to remove the disincentive associated with the impact of accelerated depreciation on federal capital gains tax liabilities.
(e) Incentives for joining a Transmission Organization. The Commission will authorize an incentive-based rate treatment, as discussed in this paragraph (e), for public utilities that join a Transmission Organization, if the applicant demonstrates that the proposed incentive-based rate treatment is just and reasonable and not unduly discriminatory or preferential. Applicants for the incentive-based rate treatment must make a filing with the Commission under section 205 of the Federal Power Act. For purposes of this paragraph (e), an incentive-based rate treatment means a return on equity that is higher than the return on equity the Commission might otherwise allow if the public utility did not join a Transmission Organization. The Commission will also permit transmitting utilities or electric utilities that join a Transmission Organization the ability to recover prudently incurred costs associated with joining the Transmission Organization, either through transmission rates charged by transmitting utilities or electric utilities or through transmission rates charged by the Transmission Organization that provides services to such utilities.
(f) Approval of prudently-incurred costs. The Commission will approve recovery of prudently-incurred costs necessary to comply with the mandatory reliability standards pursuant to section 215 of the Federal Power Act, provided that the proposed rates are just and reasonable and not unduly discriminatory or preferential.
(g) Approval of prudently incurred costs related to transmission infrastructure development. The Commission will approve recovery of prudently-incurred costs related to transmission infrastructure development pursuant to section 216 of the Federal Power Act, provided that the proposed rates are just and reasonable and not unduly discriminatory or preferential.
(h) FERC–730, Report of transmission investment activity. Public utilities that have been granted incentive rate treatment for specific transmission projects must file FERC–730 on an annual basis beginning with the calendar year incentive rate treatment is granted by the Commission. Such filings are due by April 18 of the following calendar year and are due April 18 each year thereafter. The following information must be filed:
(1) In dollar terms, actual transmission investment for the most recent calendar year, and projected, incremental investments for the next five calendar years;
(2) For all current and projected investments over the next five calendar years, a project by project listing that specifies for each project the most up-to-date, expected completion date, percentage completion as of the date of filing, and reasons for delays. Exclude from this listing projects with projected costs less than $20 million; and
(3) For good cause shown, the Commission may extend the time within which any FERC–730 filing is to be filed or waive the requirements applicable to any such filing.
(i) Rebuttable presumption. (1) The Commission will apply a rebuttable presumption that an applicant has demonstrated that its project is needed to ensure reliability or reduces the cost of delivered power by reducing congestion for:
(i) A transmission project that results from a fair and open regional planning process that considers and evaluates projects for reliability and/or congestion and is found to be acceptable to the Commission; or
(ii) A project that has received construction approval from an appropriate state commission or state siting authority.
(2) To the extent these approval processes do not require that a project ensures reliability or reduce the cost of delivered power by reducing congestion, the applicant bears the burden of demonstrating that its project satisfies these criteria.
(j) Commission authorization to site electric transmission facilities in interstate commerce. If the Commission pursuant to its authority under section 216 of the Federal Power Act and its regulations thereunder has issued one or more permits for the construction or modification of transmission facilities in a national interest electric transmission corridor designated by the Secretary, such facilities shall be deemed to either ensure reliability or reduce the cost of delivered power by reducing congestion for purposes of section 219(a).
Subpart H—Wholesale Sales of Electric Energy, Capacity and Ancillary Services at Market-Based Rates
§ 35.36 Generally.
(a) For purposes of this subpart:
(1) Seller means any person that has authorization to or seeks authorization to engage in sales for resale of electric energy, capacity or ancillary services at market-based rates under section 205 of the Federal Power Act.
(2) Category 1 Seller means a Seller that:
(i) Is either a wholesale power marketer that controls or is affiliated with 500 MW or less of generation in aggregate per region or a wholesale power producer that owns, controls or is affiliated with 500 MW or less of generation in aggregate in the same region as its generation assets;
(ii) Does not own, operate or control transmission facilities other than limited equipment necessary to connect individual generating facilities to the transmission grid (or has been granted waiver of the requirements of Order No. 888, FERC Stats. & Regs. ¶ 31,036);
(iii) Is not affiliated with anyone that owns, operates or controls transmission facilities in the same region as the Seller’s generation assets;
(iv) Is not affiliated with a franchised public utility in the same region as the Seller’s generation assets; and
(v) Does not raise other vertical market power issues.
(3) Category 2 Sellers means any Sellers not in Category 1.
(4) Inputs to electric power production means intrastate natural gas transportation, intrastate natural gas storage or distribution facilities; physical coal supply sources and ownership of or control over who may access transportation of coal supplies;
(5) Franchised public utility means a public utility with a franchised service obligation under State law.
(6) Captive customers means any wholesale or retail electric energy customers served by a franchised public utility under cost-based regulation.
(7) Market-regulated power sales affiliate means any power seller affiliate other than a franchised public utility, including a power marketer, exempt wholesale generator, qualifying facility or other power seller affiliate, whose power sales are regulated in whole or in part on a market-rate basis.
(8) Market information means non-public information related to the electric energy and power business including, but not limited to, information regarding sales, cost of production, generator outages, generator heat rates, unconsummated transactions, or historical generator volumes. Market information includes information from either affiliates or non-affiliates.
(9) Affiliate of a specified company means:
(i) Any person that directly or indirectly owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of the specified company;
(ii) Any company 10 percent or more of whose outstanding voting securities are owned, controlled, or held with power to vote, directly or indirectly, by the specified company;
(iii) Any person or class of persons that the Commission determines, after appropriate notice and opportunity for hearing, to stand in such relation to the specified company that there is liable to be an absence of arm’s-length bargaining in transactions between them as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that the person be treated as an affiliate; and
(iv) Any person that is under common control with the specified company.
(v) For purposes of paragraph (a)(9), owning, controlling or holding with power to vote, less than 10 percent of the outstanding voting securities of a specified company creates a rebuttable presumption of lack of control.
(10) Ultimate upstream affiliate means the furthest upstream affiliate(s) in the ownership chain. The term “upstream affiliate” means any entity described in § 35.36(a)(9)(i).
(b) The provisions of this subpart apply to all Sellers authorized, or seeking authorization, to make sales for resale of electric energy, capacity or ancillary services at market-based rates unless otherwise ordered by the Commission.
§ 35.37 Market power analysis required.
(a)(1) In addition to other requirements in subparts A and B, a Seller must submit a market power analysis in the following circumstances: When seeking market-based rate authority; for Category 2 Sellers, every three years, according to the schedule posted on the Commission’s website; or any other time the Commission directs a Seller to submit one. Failure to timely file an updated market power analysis will constitute a violation of Seller’s market-based rate tariff. The market power analysis must be preceded by a submission of information into a relational database that will include a list of the Seller’s own assets, the assets of its non-market-based rate affiliate(s) and identification of its ultimate upstream affiliate(s). The relational database submission will also include information necessary to generate the indicative screens, if necessary, as discussed in paragraph (c)(1) of this section. When seeking market-based rate authority, the relational database submission must also include other market-based information concerning category status, operating reserves authorization, mitigation, and other limitations.
(2) When submitting a market power analysis, whether as part of an initial application or an update, a Seller must include a description of its ownership structure that identifies all ultimate upstream affiliate(s). With respect to any investors or owners that a Seller represents to be passive, the Seller must affirm in its narrative that the ownership interests consist solely of passive rights that are necessary to protect the passive investors’ or owners’ investments and do not confer control. The Seller must also include an appendix of assets and, if necessary, indicative screens as discussed in paragraph (c)(1) of this section. A Seller must include all supporting materials referenced in the indicative screens. The appendix of assets and indicative screens are derived from the information submitted by a Seller and its affiliates into the relational database and retrievable in conformance with the instructions posted on the Commission’s website.
(b) A market power analysis must address whether a Seller has horizontal and vertical market power.
(c)(1) There will be a rebuttable presumption that a Seller lacks horizontal market power with respect to sales of energy, capacity, energy imbalance service, generation imbalance service, and primary frequency response service if it passes two indicative market power screens: a pivotal supplier analysis based on annual peak demand of the relevant market, and a market share analysis applied on a seasonal basis. There will be a rebuttable presumption that a Seller lacks horizontal market power with respect to sales of operating reserve-spinning and operating reserve-supplemental services if the Seller passes these two indicative market power screens and demonstrates in its market-based rate application how the scheduling practices in its region support the delivery of operating reserve resources from one balancing authority area to another. There will be a rebuttable presumption that a Seller possesses horizontal market power with respect to sales of energy, capacity, energy imbalance service, generation imbalance service, operating reserve-spinning service, operating reserve-supplemental service, and primary frequency response service if it fails either screen.
(2) Sellers and intervenors may also file alternative evidence to support or rebut the results of the indicative screens. Sellers may file such evidence at the time they file their indicative screens. Intervenors may file such evidence in response to a Seller’s submissions.
(3) If a Seller does not pass one or both screens, the Seller may rebut a presumption of horizontal market power by submitting a Delivered Price Test analysis. A Seller that does not rebut a presumption of horizontal market power or that concedes market power, is subject to mitigation, as described in § 35.38.
(4) In lieu of submitting the indicative market power screens, Sellers studying regional transmission organization (RTO) or independent system operator (ISO) markets that operate RTO/ISO-administered energy, ancillary services, and capacity markets may state that they are relying on Commission-approved market monitoring and mitigation to address potential horizontal market power Sellers may have in those markets.
(5) In lieu of submitting the indicative market power screens, Sellers studying RTO or ISO markets that operate RTO/ISO-administered energy and ancillary services markets, but not capacity markets, may state that they are relying on Commission-approved market monitoring and mitigation to address potential horizontal market power that Sellers may have in energy and ancillary services. However, Sellers studying such RTOs/ISOs would need to submit indicative market power screens if they wish to obtain market-based rate authority for wholesale sales of capacity in these markets.
(6) Sellers submitting simultaneous transmission import limit studies must file Submittal 1, and, if applicable, Submittal 2, in the electronic spreadsheet format provided on the Commission’s Web site.
(d) To demonstrate a lack of vertical market power, a Seller that owns, operates or controls transmission facilities, or whose affiliates own, operate or control transmission facilities, must have on file with the Commission an Open Access Transmission Tariff, as described in § 35.28; provided, however, that a Seller whose foreign affiliate(s) own, operate or control transmission facilities outside of the United States that can be used by competitors of the Seller to reach United States markets must demonstrate that such affiliate either has adopted and is implementing an Open Access Transmission Tariff as described in § 35.28, or otherwise offers comparable, non-discriminatory access to such transmission facilities.
(e) To demonstrate a lack of vertical market power in wholesale energy markets through the affiliation, ownership or control of inputs to electric power production, such as the transportation or distribution of the inputs to electric power production, a Seller must provide the following information:
(1) A description of its ownership or control of, or affiliation with an entity that owns or controls, intrastate natural gas transportation, intrastate natural gas storage or distribution facilities;
(2) Physical coal supply sources and ownership or control over who may access transportation of coal supplies; and
(3) A Seller must ensure that this information is included in the record of each new application for market-based rates and each updated market power analysis. In addition, a Seller is required to make an affirmative statement that it and its affiliates have not erected barriers to entry into the relevant market and will not erect barriers to entry into the relevant market.
(f) If the Seller seeks to protect any portion of a filing from public disclosure, the Seller must make its filing in accordance with the Commission’s instructions for filing privileged materials and critical energy infrastructure information in § 388.112 of this chapter.
§ 35.38 Mitigation.
(a) A Seller that has been found to have market power in generation or ancillary services, or that is presumed to have horizontal market power in generation or ancillary services by virtue of failing or foregoing the relevant market power screens, as described in 35.37(c), may adopt the default mitigation detailed in paragraph (b) of this section for sales of energy or capacity or paragraph (c) of this section for sales of ancillary services or may propose mitigation tailored to its own particular circumstances to eliminate its ability to exercise market power. Mitigation will apply only to the market(s) in which the Seller is found, or presumed, to have market power.
(b) Default mitigation for sales of energy or capacity consists of three distinct products:
(1) Sales of power of one week or less priced at the Seller’s incremental cost plus a 10 percent adder;
(2) Sales of power of more than one week but less than one year priced at no higher than a cost-based ceiling reflecting the costs of the unit(s) expected to provide the service; and
(3) New contracts filed for review under section 205 of the Federal Power Act for sales of power for one year or more priced at a rate not to exceed embedded cost of service.
(c) Default mitigation for sales of ancillary services consist of: (1) A cap based on the relevant OATT ancillary service rate of the purchasing transmission operator; or (2) the results of a competitive solicitation that meets the Commission’s requirements for transparency, definition, evaluation, and competitiveness.
§ 35.39 Affiliate restrictions.
(a) General affiliate provisions. As a condition of obtaining and retaining market-based rate authority, the conditions provided in this section, including the restriction on affiliate sales of electric energy and all other affiliate provisions, must be satisfied on an ongoing basis, unless otherwise authorized by Commission rule or order. Failure to satisfy these conditions will constitute a violation of the Seller’s market-based rate tariff.
(b) Restriction on affiliate sales of electric energy or capacity. As a condition of obtaining and retaining market-based rate authority, no wholesale sale of electric energy or capacity may be made between a franchised public utility with captive customers and a market-regulated power sales affiliate without first receiving Commission authorization for the transaction under section 205 of the Federal Power Act. All authorizations to engage in affiliate wholesale sales of electric energy or capacity must be listed in a Seller’s market-based rate tariff.
(c) Separation of functions. (1) For the purpose of this paragraph, entities acting on behalf of and for the benefit of a franchised public utility with captive customers (such as entities controlling or marketing power from the electrical generation assets of the franchised public utility) are considered part of the franchised public utility. Entities acting on behalf of and for the benefit of the market-regulated power sales affiliates of a franchised public utility with captive customers are considered part of the market-regulated power sales affiliates.
(2) (i) To the maximum extent practical, the employees of a market-regulated power sales affiliate must operate separately from the employees of any affiliated franchised public utility with captive customers.
(ii) Franchised public utilities with captive customers are permitted to share support employees, and field and maintenance employees with their market-regulated power sales affiliates. Franchised public utilities with captive customers are also permitted to share senior officers and boards of directors with their market-regulated power sales affiliates; provided, however, that the shared officers and boards of directors must not participate in directing, organizing or executing generation or market functions.
(iii) Notwithstanding any other restrictions in this section, in emergency circumstances affecting system reliability, a market-regulated power sales affiliate and a franchised public utility with captive customers may take steps necessary to keep the bulk power system in operation. A franchised public utility with captive customers or the market-regulated power sales affiliate must report to the Commission and disclose to the public on its Web site, each emergency that resulted in any deviation from the restrictions of section 35.39, within 24 hours of such deviation.
(d) Information sharing. (1) A franchised public utility with captive customers may not share market information with a market-regulated power sales affiliate if the sharing could be used to the detriment of captive customers, unless simultaneously disclosed to the public.
(2) Permissibly shared support employees, field and maintenance employees and senior officers and board of directors under §§ 35.39(c)(2)(ii) may have access to information covered by the prohibition of § 35.39(d)(1), subject to the no-conduit provision in § 35.39(g).
(e) Non-power goods or services. (1) Unless otherwise permitted by Commission rule or order, sales of any non-power goods or services by a franchised public utility with captive customers, to a market-regulated power sales affiliate must be at the higher of cost or market price.
(2) Unless otherwise permitted by Commission rule or order, sales of any non-power goods or services by a market-regulated power sales affiliate to an affiliated franchised public utility with captive customers may not be at a price above market.
(f) Brokering of power. (1) Unless otherwise permitted by Commission rule or order, to the extent a market-regulated power sales affiliate seeks to broker power for an affiliated franchised public utility with captive customers:
(i) The market-regulated power sales affiliate must offer the franchised public utility’s power first;
(ii) The arrangement between the market-regulated power sales affiliate and the franchised public utility must be non-exclusive; and
(iii) The market-regulated power sales affiliate may not accept any fees in conjunction with any brokering services it performs for an affiliated franchised public utility.
(2) Unless otherwise permitted by Commission rule or order, to the extent a franchised public utility with captive customers seeks to broker power for a market-regulated power sales affiliate:
(i) The franchised public utility must charge the higher of its costs for the service or the market price for such services;
(ii) The franchised public utility must market its own power first, and simultaneously make public (on the Internet) any market information shared with its affiliate during the brokering; and
(iii) The franchised public utility must post on the Internet the actual brokering charges imposed.
(g) No conduit provision. A franchised public utility with captive customers and a market-regulated power sales affiliate are prohibited from using anyone, including asset managers, as a conduit to circumvent the affiliate restrictions in §§ 35.39(a) through (g).
(h) Franchised utilities without captive customers. If necessary, any affiliate restrictions regarding separation of functions, power sales or non-power goods and services transactions, or brokering involving two or more franchised public utilities, one or more of whom has captive customers and one or more of whom does not have captive customers, will be imposed on a case-by-case basis.
§ 35.40 Ancillary services.
A Seller may make sales of ancillary services at market-based rates only if it has been authorized by the Commission and only in specific geographic markets as the Commission has authorized.
§ 35.41 Market behavior rules.
(a) Unit operation. Where a Seller participates in a Commission-approved organized market, Seller must operate and schedule generating facilities, undertake maintenance, declare outages, and commit or otherwise bid supply in a manner that complies with the Commission-approved rules and regulations of the applicable market. A Seller is not required to bid or supply electric energy or other electricity products unless such requirement is a part of a separate Commission-approved tariff or is a requirement applicable to Seller through Seller’s participation in a Commission-approved organized market.
(b) Communications. A Seller must provide accurate and factual information and not submit false or misleading information, or omit material information, in any communication with the Commission, Commission-approved market monitors, Commission-approved regional transmission organizations, Commission-approved independent system operators, or jurisdictional transmission providers, unless Seller exercises due diligence to prevent such occurrences.
(c) Price reporting. To the extent a Seller engages in reporting of transactions to publishers of electric or natural gas price indices, Seller must provide accurate and factual information, and not knowingly submit false or misleading information or omit material information to any such publisher, by reporting its transactions in a manner consistent with the procedures set forth in the Policy Statement on Natural Gas and Electric Price Indices, issued by the Commission in Docket No. PL03–3–000, and any clarifications thereto. Seller must identify as part of its Electric Quarterly Report filing requirement in § 35.10b of this chapter the publishers of electricity and natural gas indices to which it reports its transactions. In addition, Seller must adhere to any other standards and requirements for price reporting as the Commission may order.
(d) Records retention. A Seller must retain, for a period of five years, all data and information upon which it billed the prices it charged for the electric energy or electric energy products it sold pursuant to Seller’s market-based rate tariff, and the prices it reported for use in price indices.
§ 35.42 Change in status reporting requirement.
(a) As a condition of obtaining and retaining market-based rate authority, a Seller must timely report to the Commission any change in status that would reflect a departure from the characteristics the Commission relied upon in granting market-based rate authority. A change in status includes, but is not limited to, the following:
(1) Ownership or control of generation capacity or long-term firm purchases of capacity and/or energy that results in cumulative net increases (i.e., the difference between increases and decreases in affiliated generation capacity) of 100 MW or more of capacity based on nameplate or seasonal capacity ratings, or, for solar photovoltaic facilities, nameplate capacity, or, for other energy-limited resources, nameplate or five-year average capacity factors, in any individual relevant geographic market, or of inputs to electric power production, or ownership, operation or control of transmission facilities; or
(2) Affiliation with any entity not disclosed in the application for market-based rate authority that:
(i) Owns or controls generation facilities or has long-term firm purchases of capacity and/or energy that results in cumulative net increases (i.e., the difference between increases and decreases in affiliated generation capacity) of 100 MW or more of capacity based on nameplate or seasonal capacity ratings, or, for solar photovoltaic facilities, nameplate capacity, or, for other energy-limited resources, nameplate or five-year average capacity factors, in any individual relevant geographic market;
(ii) Owns or controls inputs to electric power production;
(iii) Owns, operates or controls transmission facilities;
(iv) Has a franchised service area; or
(v) Is an ultimate upstream affiliate.
(b) Any change in status subject to paragraph (a) of this section must be filed quarterly. Power sales contracts with future delivery are reportable once the physical delivery has begun. Sellers shall file change in status in accordance with the following schedule: For the period from January 1 through March 31, file by April 30; for the period from April 1 through June 30, file by July 31; for the period July 1 through September 30, file by October 31; and for the period October 1 through December 31, file by January 31. Failure to timely file a change in status constitutes a tariff violation.
(c) Changes in status must be prepared in conformance with the instructions posted on the Commission’s website.
(d) A Seller must report on a monthly basis changes to its previously-submitted relational database information, excluding updates to the horizontal market power screens. These submissions must be made by the 15th day of the month following the change. The submission must be prepared in conformance with the instructions posted on the Commission’s website.
Subpart I—Cross-Subsidization Restrictions on Affiliate Transactions
§ 35.43 Generally.
(a) For purposes of this subpart:
(1) Affiliate of a specified company means:
(i) For any person other than an exempt wholesale generator:
(A) Any person that directly or indirectly owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of the specified company;
(B) Any company 10 percent or more of whose outstanding voting securities are owned, controlled, or held with power to vote, directly or indirectly, by the specified company;
(C) Any person or class of persons that the Commission determines, after appropriate notice and opportunity for hearing, to stand in such relation to the specified company that there is liable to be an absence of arm’s-length bargaining in transactions between them as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that the person be treated as an affiliate; and
(D) Any person that is under common control with the specified company.
(E) For purposes of paragraph (a)(1)(i) of this section, owning, controlling or holding with power to vote, less than 10 percent of the outstanding voting securities of a specified company creates a rebuttable presumption of lack of control.
(ii) For any exempt wholesale generator (as defined under § 366.1 of this chapter), consistent with section 214 of the Federal Power Act (16 U.S.C. 824m), which provides that “affiliate” will have the same meaning as provided in section 2(a) of the Public Utility Holding Company Act of 1935 (15 U.S.C. 79b(a)(11)):
(A) Any person that directly or indirectly owns, controls, or holds with power to vote, 5 percent or more of the outstanding voting securities of the specified company;
(B) Any company 5 percent or more of whose outstanding voting securities are owned, controlled, or held with power to vote, directly or indirectly, by the specified company;
(C) Any individual who is an officer or director of the specified company, or of any company which is an affiliate thereof under paragraph (a)(1)(ii)(A) of this section; and
(D) Any person or class of persons that the Commission determines, after appropriate notice and opportunity for hearing, to stand in such relation to the specified company that there is liable to be an absence of arm’s-length bargaining in transactions between them as to make it necessary or appropriate in the public interest or for the protection of investors or consumers that the person be treated as an affiliate.
(2) Captive customers means any wholesale or retail electric energy customers served by a franchised public utility under cost-based regulation.
(3) Franchised public utility means a public utility with a franchised service obligation under state law.
(4) Market-regulated power sales affiliate means any power seller affiliate other than a franchised public utility, including a power marketer, exempt wholesale generator, qualifying facility or other power seller affiliate, whose power sales are regulated in whole or in part on a market-rate basis.
(5) Non-utility affiliate means any affiliate that is not in the power sales or transmission business, other than a local gas distribution company or an interstate natural gas pipeline.
(b) The provisions of this subpart apply to all franchised public utilities that have captive customers or that own or provide transmission service over jurisdictional transmission facilities.
§ 35.44 Protections against affiliate cross-subsidization.
(a) Restriction on affiliate sales of electric energy. No wholesale sale of electric energy may be made between a franchised public utility with captive customers and a market-regulated power sales affiliate without first receiving Commission authorization for the transaction under section 205 of the Federal Power Act. This requirement does not apply to energy sales from a qualifying facility, as defined by 18 CFR 292.101, made under market-based rate authority granted by the Commission.
(b) Non-power goods or services. (1) Unless otherwise permitted by Commission rule or order, and except as permitted by paragraph (b)(4) of this section, sales of any non-power goods or services by a franchised public utility that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, including sales made to or through its affiliated exempt wholesale generators or qualifying facilities, to a market-regulated power sales affiliate or non-utility affiliate must be at the higher of cost or market price.
(2) Unless otherwise permitted by Commission rule or order, and except as permitted by paragraphs (b)(3) and (b)(4) of this section, a franchised public utility that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, may not purchase or receive non-power goods and services from a market-regulated power sales affiliate or a non-utility affiliate at a price above market.
(3) A franchised public utility that has captive customers or that owns or provides transmission service over jurisdictional transmission facilities, may only purchase or receive non-power goods and services from a centralized service company at cost.
(4) A company in a single-state holding company system, as defined in § 366.3(c)(1) of this chapter, may provide general administrative and management non-power goods and services to, or receive such goods and services from, other companies in the same holding company system, at cost, provided that the only parties to transactions involving these non-power goods and services are affiliates or associate companies, as defined in § 366.1 of this chapter, of a holding company in the holding company system.
(c) Exemption for price under fuel adjustment clause regulations. Where the price of fuel from a company-owned or controlled source is found or presumed under § 35.14 to be reasonable and includable in the adjustment clause, transactions involving that fuel shall be exempt from the affiliate price restrictions in § 35.44(b).
Subpart J—Credit Practices In Organized Wholesale Electric Markets
§ 35.45 Applicability.
This subpart establishes credit practices for organized wholesale electric markets for the purpose of minimizing risk to market participants.
§ 35.46 Definitions.
As used in this subpart:
(a) Market Participant means an entity that qualifies as a Market Participant under § 35.34.
(b) Organized Wholesale Electric Market includes an independent system operator and a regional transmission organization.
(c) Regional Transmission Organization means an entity that qualifies as a Regional Transmission Organization under 18 CFR 35.34.
(d) Independent System Operator means an entity operating a transmission system and found by the Commission to be an Independent System Operator.
§ 35.47 Tariff provisions regarding credit practices in organized wholesale electric markets.
Each organized wholesale electric market must have tariff provisions that:
(a) Limit the amount of unsecured credit extended by an organized wholesale electric market to no more than $50 million for each market participant; where a corporate family includes more than one market participant participating in the same organized wholesale electric market, the limit on the amount of unsecured credit extended by that organized wholesale electric market shall be no more than $50 million for the corporate family.
(b) Adopt a billing period of no more than seven days and allow a settlement period of no more than seven days.
(c) Eliminate unsecured credit in financial transmission rights markets and equivalent markets.
(d) Establish a single counterparty to all market participant transactions, or require each market participant in an organized wholesale electric market to grant a security interest to the organized wholesale electric market in the receivables of its transactions, or provide another method of supporting netting that provides a similar level of protection to the market and is approved by the Commission. In the alternative, the organized wholesale electric market shall not net market participants’ transactions and must establish credit based on market participants’ gross obligations.
(e) Limit to no more than two days the time period provided to post additional collateral when additional collateral is requested by the organized wholesale electric market.
(f) Require minimum participation criteria for market participants to be eligible to participate in the organized wholesale electric market.
(g) Provide a list of examples of circumstances when a market administrator may invoke a “material adverse change” as a justification for requiring additional collateral; this list does not limit a market administrator’s right to invoke such a clause in other circumstances.
(h)(1) Subject to paragraph (h)(2) of this section:
(i) Permit organized wholesale electric markets to share market participant credit-related information with, and receive market participant credit-related information from, other organized wholesale electric markets for the purpose of credit risk management and mitigation; and
(ii) Permit the receiving organized wholesale electric market to use credit-related information received from another organized wholesale electric market to the same extent and for the same purposes that the receiving organized wholesale electric market may use credit-related information collected from its own market participants.
(2) Require the receiving organized wholesale electric market to treat credit-related information an organized wholesale electric market receives from another organized wholesale electric market as confidential under the terms set forth in the tariff or other governing document of the receiving organized wholesale electric market.
Subpart K—Cybersecurity Investment Provisions
§ 35.48 Cybersecurity investment.
(a) Purpose. This section establishes rules for incentive-based rate treatments for utilities with rates on file with the Commission that voluntarily make cybersecurity investments as described in this section.
(b) Definitions. As used in this section:
Advanced Cybersecurity Technology means any technology, operational capability, or service, including computer hardware, software, or a related asset, that enhances the security posture of public utilities through improvements in the ability to protect against, detect, respond to, or recover from a cybersecurity threat (as defined in section 102 of the Cybersecurity Act of 2015 (6 U.S.C. 1501)).
Advanced Cybersecurity Technology Information means information relating to Advanced Cybersecurity Technology or proposed Advanced Cybersecurity Technology that is generated by or provided to the Commission or another Federal agency. Pursuant to FPA section 219A(g), Advanced Cybersecurity Technology Information is considered to be Critical Electric Infrastructure Information.
Critical Energy/Electric Infrastructure Information (CEII) has the same meaning as defined in 18 CFR 388.113.
Electric Reliability Organization has the same meaning as defined in § 39.1 of this subchapter.
Reliability Standard has the same meaning as defined in § 39.1 of this subchapter.
(c) Incentive-based rate treatment for cybersecurity investment. The Commission will authorize incentive-based rate treatment for a utility that voluntarily makes an investment in Advanced Cybersecurity Technology and for a utility that voluntarily participates in a cybersecurity threat information sharing program under this section, provided that the utility meets the requirements of this section and the utility demonstrates that the resulting rate is just and reasonable and not unduly discriminatory or preferential, as required by sections 205 and 206 of the Federal Power Act. Incentive-based rate treatment is available to both public and non-public utilities that have or will have a rate on file with the Commission. A utility may request a single incentive-based rate treatment as specified in paragraph (f) of this section for an eligible cybersecurity investment that meets the eligibility criteria set forth in paragraph (d) of this section.
(d) Eligibility criteria. Pursuant to paragraphs (e) through (j) of this section, a utility may receive incentive-based rate treatment for a cybersecurity investment that:
(1) Materially improves cybersecurity through either Advanced Cybersecurity Technology or participation in a cybersecurity threat information sharing program; and
(2) Is not already mandated by the Reliability Standards as maintained by the Electric Reliability Organization, or otherwise mandated by local, State, or Federal law, decision, or directive; otherwise legally mandated; or an action taken in response to a Federal or State agency merger condition, consent decree from Federal or State agency, or settlement agreement that resolves a dispute between a utility and a public or private party.
(e) Demonstrating satisfaction of the eligibility criteria. A utility shall demonstrate to the Commission that a proposed cybersecurity investment satisfies the eligibility criteria in paragraph (d) of this section. Such demonstration shall show that the cybersecurity investment fulfills at least one of the provisions in the following paragraphs (e)(1) through (3):
(1) A utility shall demonstrate that a cybersecurity investment qualifies as one or more of the pre-qualified cybersecurity investments. The Commission shall rebuttably presume that pre-qualified cybersecurity investments satisfy the eligibility criteria. The Commission shall maintain a list on its website of pre-qualified cybersecurity investments and shall update such list from time to time either subject to notice and comment procedures or in a rulemaking.
(2) A utility shall demonstrate that a cybersecurity investment satisfies each of the eligibility criteria in paragraph (d) of this section. The Commission shall not presume that such demonstration satisfies the eligibility criteria.
(3) A utility shall demonstrate that it will make cybersecurity investments to comply with a Reliability Standard that is approved by the Commission but has not yet taken effect as approved by the Commission. The Commission shall not presume that such demonstration satisfies the eligibility criteria. Any incentives authorized by the Commission pursuant to this section shall terminate when the Reliability Standard takes effect.
(f) Types of incentive-based rate treatment for cybersecurity investment. For purposes of this section, incentive-based rate treatment shall mean deferral of expenses as a regulatory asset.
(g) Incentive duration. (1) A deferred Advanced Cybersecurity Technology regulatory asset whose costs are typically expensed shall be:
(i) Amortized over a period of up to five years;
(ii) Limited to expenses incurred in the first five years following Commission approval of the incentive;
(iii) Limited to ongoing expenses that the applicable utility was not already undertaking more than three months prior to filing an incentive request; and
(iv) Terminated when the cybersecurity investment or activity that serves as the basis of that incentive becomes mandatory.
(2) An incentive granted for participation in a qualified cybersecurity threat information sharing program will not be subject to the five-year duration limitation provisions of paragraph (g)(1)(ii) of this section for as long as the utility participates in the qualified cybersecurity threat information sharing program and such participation is not mandatory as to the utility. A utility participating in a qualified cybersecurity threat information sharing program is eligible to continue deferring expenses associated with such participation, which for each year would be amortized over the next five years.
(h) Incentive applications. For the purpose of this section, a utility’s request for incentive based-rate treatments for one or more cybersecurity investments must be made in a filing pursuant to section 205 of the Federal Power Act, or in a petition for a declaratory order that precedes a filing pursuant to section 205 of the Federal Power Act. Utilities may file such a request either as a part of a general rate request or on a single-issue basis. Such a request shall include a detailed explanation to include the following information:
(1) A demonstration that the cybersecurity investment satisfies the eligibility criteria, which includes an attestation that cybersecurity investment is not mandatory, as required by paragraph (d)(2) of this section, and that the resulting rate is just and reasonable and not unduly discriminatory or preferential;
(2) A detailed description of relevant cybersecurity expenses, including whether such cybersecurity expenses are:
(i) Associated with third-party provision of hardware, software, computing networking services, and/or cybersecurity monitoring services;
(ii) For training to implement network analysis and monitoring programs, and/or other cybersecurity protocols; and/or
(iii) Other cybersecurity expenses;
(3) Estimates of the cost of such cybersecurity expenses;
(4) When the cybersecurity expenses are expected to be incurred; and
(5) An attestation that the utility either has not already been undertaking duplicative or materially the same expenses for more than three months or that the utility is participating in a cybersecurity threat information-sharing program for the expense at issue. In the case of cybersecurity investments made to comply with a Reliability Standard that is approved by the Commission but has not yet taken effect as approved by the Commission pursuant to paragraph (e)(3) of this section, the utility must attest that it has not already been undertaking duplicative or materially the same expenses for more than three months prior to the date that the Commission’s approval of the Reliability Standard becomes effective.
(i) Reporting requirements. A utility that has received Commission approval for incentive-based rate treatment under this section shall make an annual informational filing on June 1, provided that the utility has received such Commission approval at least 60 days prior to June 1 of that year. A utility that receives Commission approval of an incentive-based rate treatment under this section later than 60 days prior to June 1 shall submit an annual informational filing beginning on June 1 of the following year. The annual filing shall detail the specific cybersecurity investments that were made pursuant to the Commission’s approval and the corresponding FERC account used. The annual informational filing shall describe the deferred expenses in sufficient detail to demonstrate that such expenses are specifically related to the cybersecurity investment granted incentives and not for ongoing services including system maintenance, surveillance, and other labor costs. Utilities shall provide a detailed description of any material changes in the nature of such expenses from prior year informational filings.
(j) Transmittal of CEII in incentive applications and annual reports. As appropriate, any CEII submitted to the Commission in a utility’s incentive application made pursuant to paragraph (h) of this section or contained in its reporting requirements made pursuant to paragraph (i) of this section shall be filed consistent with part 388 of this title.
PART 36—RULES CONCERNING APPLICATIONS FOR TRANSMISSION SERVICES UNDER SECTION 211 OF THE FEDERAL POWER ACT
§ 36.1 Notice provisions applicable to applications for transmission services under section 211 of the Federal Power Act.
(a) Definitions. (1) Affected party means each affected electric utility, each affected State regulatory authority, and each affected Federal power marketing agency.
(2) Affected electric utility means each electric utility that has made arrangements for the sale or purchase of electric energy to be transmitted pursuant to the particular application for transmission services, and each transmitting utility, as defined in section 3(23) of the Federal Power Act, 16 U.S.C. 796(23), being requested to transmit such electric energy.
(3) Affected State regulatory authority means a State regulatory authority, as defined in section 3(21) of the Federal Power Act, 16 U.S.C. 796(21), regulating the rates and charges of each affected electric utility.
(4) Affected Federal power marketing agency means a Federal power marketing agency that operates in the service area of each affected electric utility.
(b) Additional filing requirements. Any person filing an application for transmission services pursuant to section 211 of the Federal Power Act, 16 U.S.C. 824j, shall include the following:
(1) The applicant must include a form of notice of the application suitable for publication in the
(2) A sworn statement that actual notice, including the applicant’s name, the date of the application, the names of the affected parties, and a brief description of the transmission services sought (including the proposed dates for initiating and terminating the requested transmission services, the total amount of transmission capacity requested, a brief description of the character and nature of the transmission services being requested, and whether the transmission services requested are firm or non-firm) has been served, pursuant to Rule 2010 of the Commission’s Rules of Practice and Procedure, § 385.2010 of this chapter, on each affected party. Such statement shall enumerate each person so served.
(c) Other filing requirements. All other filing requirements of the Commission’s Rules of Practice and Procedure remain in effect for applications under this section.
PART 37—OPEN ACCESS SAME-TIME INFORMATION SYSTEMS
§ 37.1 Applicability.
This part applies to any public utility that owns, operates, or controls facilities used for the transmission of electric energy in interstate commerce and to transactions performed under the pro forma tariff required in part 35 of this chapter.
§ 37.2 Purpose.
(a) The purpose of this part is to ensure that potential customers of open access transmission service receive access to information that will enable them to obtain transmission service on a non-discriminatory basis from any Transmission Provider. These rules provide standards of conduct and require the Transmission Provider (or its agent) to create and operate an Open Access Same-time Information System (OASIS) that gives all users of the open access transmission system access to the same information.
(b) The OASIS will provide information by electronic means about available transmission capability for point-to-point service and will provide a process for requesting transmission service. OASIS will enable Transmission Providers and Transmission Customers to communicate promptly requests and responses to buy and sell available transmission capacity offered under the Transmission Provider’s tariff.
§ 37.3 Definitions.
(a) Transmission Provider means any public utility that owns, operates, or controls facilities used for the transmission of electric energy in interstate commerce.
(b) Transmission Customer means any eligible customer (or its designated agent) that can or does execute a transmission service agreement or can or does receive transmission service.
(c) Responsible party means the Transmission Provider or an agent to whom the Transmission Provider has delegated the responsibility of meeting any of the requirements of this part.
(d) Reseller means any Transmission Customer who offers to sell transmission capacity it has purchased.
(e) Wholesale merchant function means the sale for resale of electric energy in interstate commerce.
(f) Affiliate means:
(1) For any exempt wholesale generator, as defined under section 32(a) of the Public Utility Holding Company Act of 1935, as amended, the same as provided in section 214 of the Federal Power Act; and
(2) For any other entity, the term affiliate has the same meaning as given in § 161.2(a) of this chapter.
§ 37.4 [Reserved]
§ 37.5 Obligations of Transmission Providers and Responsible Parties.
(a) Each Transmission Provider is required to provide for the operation of an OASIS, either individually or jointly with other Transmission Providers, in accordance with the requirements of this Part. The Transmission Provider may delegate this responsibility to a Responsible Party such as another Transmission Provider, an Independent System Operator, a Regional Transmission Group, or a Regional Reliability Council.
(b) A Responsible Party must provide access to an OASIS providing standardized information relevant to the availability of transmission capacity, prices, and other information (as described in this part) pertaining to the transmission system for which it is responsible.
(c) A Responsible Party may not deny or restrict access to an OASIS user merely because that user makes automated computer-to-computer file transfers or queries, or extensive requests for data.
(d) In the event that an OASIS user’s grossly inefficient method of accessing an OASIS node or obtaining information from the node seriously degrades the performance of the node, a Responsible Party may limit a user’s access to the OASIS node without prior Commission approval. The Responsible Party must immediately contact the OASIS user to resolve the problem. Notification of the restriction must be made to the Commission within two business days of the incident and include a description of the problem. A closure report describing how the problem was resolved must be filed with the Commission within one week of the incident.
(e) In the event that an OASIS user makes an error in a query, the Responsible Party can block the affected query and notify the user of the nature of the error. The OASIS user must correct the error before making any additional queries. If there is a dispute over whether an error has occurred, the procedures in paragraph (d) of this section apply.
(f) Transmission Providers must provide “read only” access to the OASIS to Commission staff and the staffs of State regulatory authorities, at no cost, after such staff members have complied with the requisite registration procedures.
§ 37.6 Information to be posted on the OASIS.
(a) The information posted on the OASIS must be in such detail and the OASIS must have such capabilities as to allow Transmission Customers to:
(1) Make requests for transmission services offered by Transmission Providers, Resellers and other providers of ancillary services, request the designation of a network resource, and request the termination of the designation of a network resource;
(2) View and download in standard formats, using standard protocols, information regarding the transmission system necessary to enable prudent business decision making;
(3) Post, view, upload and download information regarding available products and desired services;
(4) Clearly identify the degree to which transmission service requests or schedules were denied or interrupted;
(5) Obtain access, in electronic format, to information to support available transmission capability calculations and historical transmission service requests and schedules for various audit purposes; and
(6) Make file transfers and automated computer-to-computer file transfers and queries as defined by the Standards and Communications Protocols Document.
(b) Posting transfer capability. The available transfer capability on the Transmission Provider’s system (ATC) and the total transfer capability (TTC) of that system shall be calculated and posted for each Posted Path as set out in this section.
(1) Definitions. For purposes of this section the terms listed below have the following meanings:
(i) Posted path means any control area to control area interconnection; any path for which service is denied, curtailed or interrupted for more than 24 hours in the past 12 months; and any path for which a customer requests to have ATC or TTC posted. For this last category, the posting must continue for 180 days and thereafter until 180 days have elapsed from the most recent request for service over the requested path. For purposes of this definition, an hour includes any part of an hour during which service was denied, curtailed or interrupted.
(ii) Constrained posted path means any posted path having an ATC less than or equal to 25 percent of TTC at any time during the preceding 168 hours or for which ATC has been calculated to be less than or equal to 25 percent of TTC for any period during the current hour or the next 168 hours.
(iii) Unconstrained posted path means any posted path not determined to be a constrained posted path.
(iv) The word interconnection, as used in the definition of “posted path”, means all facilities connecting two adjacent systems or control areas.
(v) Available transfer capability or ATC means the transfer capability remaining in the physical transmission network for further commercial activity over and above already committed uses, or such definition as contained in Commission-approved Reliability Standards.
(vi) Total transfer capability or TTC means the amount of electric power that can be moved or transferred reliably from one area to another area of the interconnected transmission systems by way of all transmission lines (or paths) between those areas under specified system conditions, or such definition as contained in Commission-approved Reliability Standards.
(vii) Capacity Benefit Margin or CBM means the amount of TTC preserved by the Transmission Provider for load-serving entities, whose loads are located on that Transmission Provider’s system, to enable access by the load-serving entities to generation from interconnected systems to meet generation reliability requirements, or such definition as contained in Commission-approved Reliability Standards.
(viii) Transmission Reliability Margin or TRM means the amount of TTC necessary to provide reasonable assurance that the interconnected transmission network will be secure, or such definition as contained in Commission-approved Reliability Standards.
(2) Calculation methods, availability of information, and requests. (i) Information used to calculate any posting of ATC and TTC must be dated and time-stamped and all calculations shall be performed according to consistently applied methodologies referenced in the Transmission Provider’s transmission tariff and shall be based on Commission-approved Reliability Standards, business practice and electronic communication standards, and related implementation documents, as well as current industry practices, standards and criteria. Such calculations shall be conducted in a manner that is transparent, consistent with anticipated system conditions and outages for the relevant timeframe, and not unduly discriminatory or preferential.
(ii) On request, the Responsible Party must make all data used to calculate ATC, TTC, CBM, and TRM for any constrained posted paths publicly available (including the limiting element(s) and the cause of the limit (e.g., thermal, voltage, stability), as well as load forecast assumptions) in electronic form within one week of the posting. The information is required to be provided only in the electronic format in which it was created, along with any necessary decoding instructions, at a cost limited to the cost of reproducing the material. This information is to be retained for six months after the applicable posting period.
(iii) System planning studies, facilities studies, and specific network impact studies performed for customers or the Transmission Provider’s own network resources are to be made publicly available in electronic form on request and a list of such studies shall be posted on the OASIS. A study is required to be provided only in the electronic format in which it was created, along with any necessary decoding instructions, at a cost limited to the cost of reproducing the material. These studies are to be retained for five years.
(3) Posting. The ATC, TTC, CBM, and TRM for all Posted Paths must be posted in megawatts by specific direction and in the manner prescribed in this subsection.
(i) Constrained posted paths—(A) For firm ATC and TTC.
(1) The posting shall show ATC, TTC, CBM, and TRM for a 30-day period. For this period postings shall be: by the hour, for the current hour and the 168 hours next following; and thereafter, by the day. If the Transmission Provider charges separately for on-peak and off-peak periods in its tariff, ATC, TTC, CBM, and TRM will be posted daily for each period.
(2) Postings shall also be made by the month, showing for the current month and the 12 months next following.
(3) If planning and specific requested transmission studies have been done, seasonal capability shall be posted for the year following the current year and for each year following to the end of the planning horizon but not to exceed 10 years.
(B) For non-firm ATC and TTC. The posting shall show ATC, TTC, CBM and TRM for a 30-day period by the hour and days prescribed under paragraph (b)(3)(i)(A)(1) of this section and, if so requested, by the month and year as prescribed under paragraph (b)(3)(i)(A) (2) and (3) of this section. The posting of non-firm ATC and TTC shall show CBM as zero.
(C) Updating posted information for constrained paths.
(1) The capability posted under paragraphs (b)(3)(i)(A) and (B) of this section must be updated when transactions are reserved or service ends or whenever the estimate for the path changes by more than 10 percent.
(2) All updating of hourly information shall be made on the hour.
(3) When the monthly and yearly capability posted under paragraphs (b)(3)(i)(A) and (B) of this section are updated because of a change in TTC by more than 10 percent, the Transmission Provider shall post a brief, but specific, narrative explanation of the reason for the update. This narrative should include, the specific events which gave rise to the update (e.g., scheduling of planned outages and occurrence of forced transmission outages, de-ratings of transmission facilities, scheduling of planned generation outages and occurrence of forced generation outages, changes in load forecast, changes in new facilities’ in-service dates, or other events or assumption changes) and new values for ATC on the path (as opposed to all points on the network).
(4) When the monthly and yearly capability posted under paragraphs (b)(3)(i)(A) and (B) of this section remain unchanged at a value of zero for a period of six months, the Transmission Provider shall post a brief, but specific, narrative explanation of the reason for the unavailability of ATC.
(ii) Unconstrained posted paths.
(A) Postings of firm and nonfirm ATC, TTC, CBM, and TRM shall be posted separately by the day, showing for the current day and the next six days following and thereafter, by the month for the 12 months next following. If the Transmission Provider charges separately for on-peak and off-peak periods in its tariff, ATC, TTC, CBM, and TRM will be posted separately for the current day and the next six days following for each period. These postings are to be updated whenever the ATC changes by more than 20 percent of the Path’s TTC.
(B) If planning and specific requested transmission studies have been done, seasonal capability shall be posted for the year following the current year and for each year following until the end of the planning horizon but not to exceed 10 years.
(iii) Calculation of CBM.
(A) The Transmission Provider must reevaluate its CBM needs at least every year.
(B) The Transmission Provider must post its practices for reevaluating its CBM needs.
(iv) Daily load. The Transmission Provider must post on a daily basis, its load forecast, including underlying assumptions, and actual daily peak load for the prior day.
(c) Posting Transmission Service Products and Prices. (1) Transmission Providers must post prices and a summary of the terms and conditions associated with all transmission products offered to Transmission Customers.
(2) Transmission Providers must provide a downloadable file of their complete tariffs in the same electronic format as the tariff that is filed with the Commission. Transmission Providers also must provide a link to all of the rules, standards and practices that relate to transmission services posted on the Transmission Providers’ public Web sites.
(3) Any offer of a discount for any transmission service made by the Transmission Provider must be announced to all potential customers solely by posting on the OASIS.
(4) For any transaction for transmission service agreed to by the Transmission Provider and a customer, the Transmission Provider (at the time when ATC must be adjusted in response to the transaction), must post on the OASIS (and make available for download) information describing the transaction (including: price; quantity; points of receipt and delivery; length and type of service; identification of whether the transaction involves the Transmission Provider’s wholesale merchant function or any affiliate; identification of what, if any, ancillary service transactions are associated with this transmission service transaction; and any other relevant terms and conditions) and shall keep such information posted on the OASIS for at least 30 days. A record of the transaction must be retained and kept available as part of the audit log required in § 37.7.
(5) Customers choosing to use the OASIS to offer for resale transmission capacity they have purchased must post relevant information to the same OASIS as used by the Transmission Provider from whom the Reseller purchased the transmission capacity. This information must be posted on the same display page, using the same tables, as similar capability being sold by the Transmission Provider, and the information must be contained in the same downloadable files as the Transmission Provider’s own available capability.
(d) Posting Ancillary Service Offerings and Prices. (1) Any ancillary service required to be provided or offered under the pro forma tariff prescribed by part 35 of this chapter must be posted with the price of that service.
(2) Any offer of a discount for any ancillary service made by the Transmission Provider must be announced to all potential customers solely by posting on the OASIS.
(3) For any transaction for ancillary service agreed to by the Transmission Provider and a customer, the Transmission Provider (at the time when ATC must be adjusted in response to an associated transmission service transaction, if any), must post on the OASIS (and make available for download) information describing the transaction (including: date and time when the agreement was entered into; price; quantity; length and type of service; identification of whether the transaction involves the Transmission Provider’s wholesale merchant function or any affiliate; identification of what, if any, transmission service transactions are associated with this ancillary service transaction; and any other relevant terms and conditions) and shall keep such information posted on the OASIS for at least 30 days. A record of the transaction must be retained and kept available as part of the audit log required in § 37.7.
(4) Any other interconnected operations service offered by the Transmission Provider may be posted, with the price for that service.
(5) Any entity offering an ancillary service shall have the right to post the offering of that service on the OASIS if the service is one required to be offered by the Transmission Provider under the pro forma tariff prescribed by part 35 of this chapter. Any entity may also post any other interconnected operations service voluntarily offered by the Transmission Provider. Postings by customers and third parties must be on the same page, and in the same format, as postings of the Transmission Provider.
(e) Posting specific transmission and ancillary service requests and responses—(1) General rules. (i) All requests for transmission and ancillary service offered by Transmission Providers under the pro forma tariff, including requests for discounts, and all requests to designate or terminate a network resource, must be made on the OASIS and posted prior to the Transmission Provider responding to the request, except as discussed in paragraphs (e)(1)(ii) and (iii) of this section. The Transmission Provider must post all requests for transmission service, for ancillary service, and for the designation or termination of a network resource comparably. Requests for transmission service, ancillary service, and to designate and terminate a network resource, as well as the responses to such requests, must be conducted in accordance with the Transmission Provider’s tariff, the Federal Power Act, and Commission regulations.
(ii) The requirement in paragraph (e)(1)(i) of this section, to post requests for transmission and ancillary service offered by Transmission Providers under the pro forma tariff, including requests for discounts, prior to the Transmission Provider responding to the request, does not apply to requests for next-hour service made during Phase I.
(iii) In the event that a discount is being requested for ancillary services that are not in support of basic transmission service provided by the Transmission Provider, such request need not be posted on the OASIS.
(iv) In processing a request for transmission or ancillary service, the Responsible Party shall post the same information as required in paragraphs (c)(4) and (d)(3) of this section, and the following information: the date and time when the request is made, its place in any queue, the status of that request, and the result (accepted, denied, withdrawn). In processing a request to designate or terminate the designation of a network resource, the Responsible Party shall post the date and time when the request is made.
(v) For any request to designate or terminate a network resource, the Transmission Provider (at the time when the request is received), must post on the OASIS (and make available for download) information describing the request (including: name of requestor, identification of the resource, effective time for the designation or termination, identification of whether the transaction involves the Transmission Provider’s wholesale merchant function or any affiliate; and any other relevant terms and conditions) and shall keep such information posted on the OASIS for at least 30 days. A record of the transaction must be retained and kept available as part of the audit log required in § 37.7.
(vi) The Transmission Provider shall post a list of its current designated network resources and all network customers’ current designated network resources on OASIS. The list of network resources should include the name of the resource, its geographic and electrical location, its total installed capacity, and the amount of capacity to be designated as a network resource.
(2) Posting when a request for transmission service is denied. (i) When a request for service is denied, the Responsible Party must provide the reason for that denial as part of any response to the request.
(ii) Information to support the reason for the denial, including the operating status of relevant facilities, must be maintained for five years and provided, upon request, to the potential Transmission Customer and the Commission’s Staff.
(iii) Any offer to adjust operation of the Transmission Provider’s System to accommodate the denied request must be posted and made available to all Transmission Customers at the same time.
(3) Posting when a transaction is curtailed or interrupted. (i) When any transaction is curtailed or interrupted, the Transmission Provider must post notice of the curtailment or interruption on the OASIS, and the Transmission Provider must state on the OASIS the reason why the transaction could not be continued or completed.
(ii) Information to support any such curtailment or interruption, including the operating status of the facilities involved in the constraint or interruption, must be maintained and made available upon request, to the curtailed or interrupted customer, the Commission’s Staff, and any other person who requests it, for five years.
(iii) Any offer to adjust the operation of the Transmission Provider’s system to restore a curtailed or interrupted transaction must be posted and made available to all curtailed and interrupted Transmission Customers at the same time.
(f) Posting Transmission Service Schedules Information. Information on transmission service schedules must be recorded by the entity scheduling the transmission service and must be available on the OASIS for download. Transmission service schedules must be posted no later than seven calendar days from the start of the transmission service.
(g) Posting Other Transmission-Related Communications. (1) The posting of other communications related to transmission services must be provided for by the Responsible Party. These communications may include “want ads” and “other communications” (such as using the OASIS as a Transmission-related conference space or to provide transmission-related messaging services between OASIS users). Such postings carry no obligation to respond on the part of any market participant.
(2) The Responsible Party is responsible for posting other transmission-related communications in conformance with the instructions provided by the third party on whose behalf the communication is posted. It is the responsibility of the third party requesting such a posting to ensure the accuracy of the information to be posted.
(3) Notices of transfers of personnel shall be posted as described in § 358.4(c). The posting requirements are the same as those provided in § 37.7 for audit data postings.
(4) Logs detailing the circumstances and manner in which a Transmission Provider or Responsible Party exercised its discretion under any terms of the tariff shall be posted as described in § 358.5(c)(4). The posting requirements are the same as those provided in § 37.7 for audit data postings.
(h) Posting information summarizing the time to complete transmission service request studies. (1) For each calendar quarter, the Responsible Party must post the set of measures detailed in paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section related to the Responsible Party’s processing of transmission service request system impact studies and facilities studies. The Responsible Party must calculate and post the measures in paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section for requests for short-term firm point-to-point transmission service, requests for long-term firm point-to-point transmission service, and requests to designate a new network resource or network load. When calculating the measures in paragraph (h)(1)(i) through paragraph (h)(1)(iv) of this section, the Responsible Party may aggregate requests for short-term firm point-to-point service and requests for long-term firm point-to-point service, but must calculate and post measures separately for transmission service requests from Affiliates and transmission service requests from Transmission Customers who are not Affiliates. The Responsible Party is required to include in the calculations of the measures in paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section all studies the Responsible Party conducts of transmission service requests on another Transmission Provider’s OASIS.
(i) Process time from initial service request to offer of system impact study agreement.
(A) Number of new system impact study agreements delivered during the reporting quarter to entities that request transmission service,
(B) Number of new system impact study agreements delivered during the reporting quarter to entities that request transmission service more than thirty (30) days after the Responsible Party received the request for transmission service,
(C) Mean time (in days), for all requests acted on by the Responsible Party during the reporting quarter, from the date when the Responsible Party received the request for transmission service to when the Responsible Party changed the transmission service request status to indicate that the Responsible Party could offer transmission service or needed to perform a system impact study,
(D) Mean time (in days), for all system impact study agreements delivered by the Responsible Party during the reporting quarter, from the date when the Responsible Party received the request for transmission service to the date when the Responsible Party delivered a system impact study agreement, and
(E) Number of new system impact study agreements executed during the reporting quarter.
(ii) System impact study processing time.
(A) Number of system impact studies completed by the Responsible Party during the reporting quarter,
(B) Number of system impact studies completed by the Responsible Party during the reporting quarter more than 60 days after the Responsible Party received an executed system impact study agreement,
(C) For all system impact studies completed more than 60 days after receipt of an executed system impact study agreement, average number of days study was delayed due to transmission customer’s actions (e.g., delays in providing needed data),
(D) Mean time (in days), for all system impact studies completed by the Responsible Party during the reporting quarter, from the date when the Responsible Party received the executed system impact study agreement to the date when the Responsible Party provided the system impact study to the entity who executed the system impact study agreement, and
(E) Mean cost of system impact studies completed by the Responsible Party during the reporting quarter.
(iii) Transmission service requests withdrawn from the system impact study queue.
(A) Number of transmission service requests withdrawn from the Responsible Party’s system impact study queue during the reporting quarter,
(B) Number of transmission service requests withdrawn from the Responsible Party’s system impact study queue during the reporting quarter more than 60 days after the Responsible Party received the executed system impact study agreement, and
(C) Mean time (in days), for all transmission service requests withdrawn from the Responsible Party’s system impact study queue during the reporting quarter, from the date the Responsible Party received the executed system impact study agreement to date when request was withdrawn from the Responsible Party’s system impact study queue.
(iv) Process time from completed system impact study to offer of facilities study.
(A) Number of new facilities study agreements delivered during the reporting quarter to entities that request transmission service,
(B) Number of new facilities study agreements delivered during the reporting quarter to entities that request transmission service more than thirty (30) days after the Responsible Party completed the system impact study,
(C) Mean time (in days), for all facilities study agreements delivered by the Responsible Party during the reporting quarter, from the date when the Responsible Party completed the system impact study to the date when the Responsible Party delivered a facilities study agreement, and
(D) Number of new facilities study agreements executed during the reporting quarter.
(v) Facilities study processing time.
(A) Number of facilities studies completed by the Responsible Party during the reporting quarter,
(B) Number of facilities studies completed by the Responsible Party during the reporting quarter more than 60 days after the Responsible Party received an executed facilities study agreement,
(C) For all facilities studies completed more than 60 days after receipt of an executed facilities study agreement, average number of days study was delayed due to transmission customer’s actions (e.g., delays in providing needed data),
(D) Mean time (in days), for all facilities studies completed by the Responsible Party during the reporting quarter, from the date when the Responsible Party received the executed facilities study agreement to the date when the Responsible Party provided the facilities study to the entity who executed the facilities study agreement,
(E) Mean cost of facilities studies completed by the Responsible Party during the reporting quarter, and
(F) Mean cost of upgrades recommended in facilities studies completed during the reporting quarter.
(vi) Service requests withdrawn from facilities study queue.
(A) Number of transmission service requests withdrawn from the Responsible Party’s facilities study queue during the reporting quarter,
(B) Number of transmission service requests withdrawn from the Responsible Party’s facilities study queue during the reporting quarter more than 60 days after the Responsible Party received the executed facilities study agreement, and
(C) Mean time (in days), for all transmission service requests withdrawn from the Responsible Party’s facilities study queue during the reporting quarter, from the date the Responsible Party received the executed facilities study agreement to date when request was withdrawn from the Responsible Party’s facilities study queue.
(2) The Responsible Party is required to post the measures in paragraph (h)(1)(i) through paragraph (h)(1)(vi) of this section for each calendar quarter within 15 days of the end of the calendar quarter. The Responsible Party will keep the quarterly measures posted on OASIS for three calendar years.
(3) The Responsible Party will be required to post on OASIS the measures in paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this section in the event the Responsible Party, for two consecutive calendar quarters, completes more than twenty (20) percent of the studies associated with requests for transmission service from entities that are not Affiliates of the Responsible Party more than sixty (60) days after the Responsible Party delivers the appropriate study agreement. The Responsible Party will have to post the measures in paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this section until it processes at least ninety (90) percent of all studies within 60 days after it has received the appropriate executed study agreement. For the purposes of calculating the percent of studies completed more than sixty (60) days after the Responsible Party delivers the appropriate study agreement, the Responsible Party should aggregate all system impact studies and facilities studies that it completes during the reporting quarter.
(i) Mean, across all system impact studies the Responsible Party completes during the reporting quarter, of the employee-hours expended per system impact study the Responsible Party completes during reporting period;
(ii) Mean, across all facilities studies the Responsible Party completes during the reporting quarter, of the employee-hours expended per facilities study the Responsible Party completes during reporting period;
(iii) The number of employees the Responsible Party has assigned to process system impact studies;
(iv) The number of employees the Responsible Party has assigned to process facilities studies.
(4) The Responsible Party is required to post the measures in paragraph (h)(3)(i) through paragraph (h)(3)(iv) of this section for each calendar quarter within 15 days of the end of the calendar quarter. The Responsible Party will keep the quarterly measures posted on OASIS for five calendar years.
(i) Posting data related to grants and denials of service. The Responsible Party is required to post data each month listing, by path or flowgate, the number of transmission service requests that have been accepted and the number of transmission service requests that have been denied during the prior month. This posting must distinguish between the length of the service request (e.g., short-term or long-term requests) and between the type of service requested (e.g., firm point-to-point, non-firm point-to-point or network service). The posted data must show:
(1) The number of non-Affiliate requests for transmission service that have been rejected,
(2) The total number of non-Affiliate requests for transmission service that have been made,
(3) The number of Affiliate requests for transmission service, including requests by the transmission provider’s merchant function to designate a network resource or to procure secondary network service, that have been rejected, and
(4) The total number of Affiliate requests for transmission service, including requests by the transmission provider’s merchant function to designate, or terminate the designation of, a network resource or to procure secondary network service, that have been made.
(j) Posting redispatch data.
(1) The Transmission Provider must allow the posting on OASIS of any third party offer to relieve a specified congested transmission facility.
(2) The Transmission Provider must post on OASIS (i) its monthly average cost of planning and reliability redispatch, for which it invoices customers, at each internal transmission facility or interface over which it provides redispatch service and (ii) a high and low redispatch cost for the month for each of these same transmission facilities. The transmission provider must post this data on OASIS as soon as practical after the end of each month, but no later than when it sends invoices to transmission customers for redispatch-related services.
(k) Posting of historical area control error data. The Transmission Provider must post on OASIS historical one-minute and ten-minute area control error data for the most recent calendar year, and update this posting once per year.
§ 37.7 Auditing Transmission Service Information.
(a) All OASIS database transactions, except other transmission-related communications provided for under § 37.6(g)(2), must be stored, dated, and time stamped.
(b) Audit data must remain available for download on the OASIS for 90 days, except ATC/TTC postings that must remain available for download on the OASIS for 20 days. The audit data are to be retained and made available upon request for download for five years from the date when they are first posted in the same electronic form as used when they originally were posted on the OASIS.
§ 37.8 Obligations of OASIS users.
Each OASIS user must notify the Responsible Party one month in advance of initiating a significant amount of automated queries. The OASIS user must also notify the Responsible Party one month in advance of expected significant increases in the volume of automated queries.
PART 38—STANDARDS FOR PUBLIC UTILITY BUSINESS OPERATIONS AND COMMUNICATIONS
§ 38.1 Incorporation by reference of North American Energy Standards Board Wholesale Electric Quadrant standards.
(a) Any public utility that owns, operates, or controls facilities used for the transmission of electric energy in interstate commerce or for the sale of electric energy at wholesale in interstate commerce and any non-public utility that seeks voluntary compliance with jurisdictional transmission tariff reciprocity conditions must comply with the business practice and electronic communication standards and models promulgated by the North American Energy Standards Board (NAESB) Wholesale Electric Quadrant (WEQ) that are incorporated by reference in paragraph (b) of this section. The requirements and formats for electronic filing are listed in instructions for electronic filing and for each form. These formats are available through the Commission’s website, https://www.ferc.gov.
(b) The material listed in this paragraph (b) is incorporated by reference into this section with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. All approved material is available for inspection at the Federal Energy Regulatory Commission (the Commission) and at the National Archives and Records Administration (NARA). Contact the Commission at: https://www.ferc.gov, email at [email protected] or via phone call at (202) 502–8371. For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations or email [email protected]. The material may be obtained from the North American Energy Standards Board, 801 Travis Street, Suite 1675, Houston, TX 77002, Phone: (713) 356–0060; https://www.naesb.org/.
(1) WEQ–000, Abbreviations, Acronyms, and Definition of Terms (WEQ Version 003.1, September 30, 2015) (including only the definitions of Interconnection Time Monitor, Time Error, and Time Error Correction);
(2) WEQ–000, Abbreviations, Acronyms, and Definition of Terms (WEQ Version 003.3, March 30, 2020);
(3) WEQ–001, Open Access Same-Time Information Systems (OASIS), (WEQ Version 003.3, March 30, 2020);
(4) WEQ–002, Open Access Same-Time Information Systems (OASIS) Business Practice Standards and Communication Protocols (S&CP), (WEQ Version 003.3, March 30, 2020);
(5) WEQ–003, Open Access Same-Time Information Systems (OASIS) Data Dictionary, (WEQ Version 003.3, March 30, 2020);
(6) WEQ–004, Coordinate Interchange (WEQ Version 003.3, March 30, 2020);
(7) WEQ–005, Area Control Error (ACE) Equation Special Cases (WEQ Version 003.3, March 30, 2020);
(8) WEQ–006, Manual Time Error Correction (WEQ Version 003.1, Sept. 30, 2015);
(9) WEQ–007, Inadvertent Interchange Payback (WEQ Version 003.3, March 30, 2020);
(10) WEQ–008, Transmission Loading Relief (TLR)—Eastern Interconnection (WEQ Version 003.3, March 30, 2020);
(11) WEQ–011, Gas/Electric Coordination (WEQ Version 003.3, March 30, 2020);
(12) WEQ–012, Public Key Infrastructure (PKI) (WEQ Version 003.3, March 30, 2020);
(13) WEQ–013, Open Access Same-Time Information Systems (OASIS) Implementation Guide, (WEQ Version 003.3, March 30, 2020);
(14) WEQ–015, Measurement and Verification of Wholesale Electricity Demand Response (WEQ Version 003.3, March 30, 2020);
(15) WEQ–021, Measurement and Verification of Energy Efficiency Products (WEQ Version 003.3, March 30, 2020);
(16) WEQ–022, Electric Industry Registry (WEQ Version 003.3, March 30, 2020); and
(17) WEQ–023, Modeling (WEQ Version 003.3, March 30, 2020).
§ 38.2 Communication and information sharing among public utilities and pipelines.
(a) Any public utility that owns, operates, or controls facilities used for the transmission of electric energy in interstate commerce is authorized to share non-public, operational information with a pipeline, as defined in § 284.12(b)(4) of this chapter, or another public utility covered by this section for the purpose of promoting reliable service or operational planning.
(b) Except as permitted in paragraph (a) of this section, a public utility, as defined in this section, and its employees, contractors, consultants, and agents are prohibited from disclosing, or using anyone as a conduit for the disclosure of, non-public, operational information received from a pipeline pursuant to § 284.12(b)(4) of this chapter to a third party or to its marketing function employees as that term is defined in § 358.3(d) of this chapter.
PART 39—RULES CONCERNING CERTIFICATION OF THE ELECTRIC RELIABILITY ORGANIZATION; AND PROCEDURES FOR THE ESTABLISHMENT, APPROVAL, AND ENFORCEMENT OF ELECTRIC RELIABILITY STANDARDS
§ 39.1 Definitions.
As used in this part:
Bulk-Power System means facilities and control systems necessary for operating an interconnected electric energy transmission network (or any portion thereof), and electric energy from generating facilities needed to maintain transmission system reliability. The term does not include facilities used in the local distribution of electric energy.
Cross-Border Regional Entity means a Regional Entity that encompasses a part of the United States and a part of Canada or Mexico.
Cybersecurity Incident means a malicious act or suspicious event that disrupts, or was an attempt to disrupt, the operation of those programmable electronic devices and communications networks including hardware, software and data that are essential to the Reliable Operation of the Bulk-Power System.
Electric Reliability Organization or “ERO” means the organization certified by the Commission under § 39.3 the purpose of which is to establish and enforce Reliability Standards for the Bulk-Power System, subject to Commission review.
Electric Reliability Organization Rule means, for purposes of this part, the bylaws, a rule of procedure or other organizational rule or protocol of the Electric Reliability Organization.
Interconnection means a geographic area in which the operation of Bulk-Power System components is synchronized such that the failure of one or more of such components may adversely affect the ability of the operators of other components within the system to maintain Reliable Operation of the facilities within their control.
Regional Advisory Body means an entity established upon petition to the Commission pursuant to section 215(j) of the Federal Power Act that is organized to advise the Electric Reliability Organization, a Regional Entity, or the Commission regarding certain matters in accordance with § 39.13.
Regional Entity means an entity having enforcement authority pursuant to § 39.8.
Regional Entity Rule means, for purposes of this part, the bylaws, a rule of procedure or other organizational rule or protocol of a Regional Entity.
Reliability Standard means a requirement approved by the Commission under section 215 of the Federal Power Act, to provide for Reliable Operation of the Bulk-Power System. The term includes requirements for the operation of existing Bulk-Power System facilities, including cybersecurity protection, and the design of planned additions or modifications to such facilities to the extent necessary to provide for Reliable Operation of the Bulk-Power System, but the term does not include any requirement to enlarge such facilities or to construct new transmission capacity or generation capacity.
Reliable Operation means operating the elements of the Bulk-Power System within equipment and electric system thermal, voltage, and stability limits so that instability, uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance, including a Cybersecurity Incident, or unanticipated failure of system elements.
Transmission Organization means a regional transmission organization, independent system operator, independent transmission provider, or other transmission organization finally approved by the Commission for the operation of transmission facilities.
§ 39.2 Jurisdiction and applicability.
(a) Within the United States (other than Alaska and Hawaii), the Electric Reliability Organization, any Regional Entities, and all users, owners and operators of the Bulk-Power System, including but not limited to entities described in section 201(f) of the Federal Power Act, shall be subject to the jurisdiction of the Commission for the purposes of approving Reliability Standards established under section 215 of the Federal Power Act and enforcing compliance with section 215 of the Federal Power Act.
(b) All entities subject to the Commission’s reliability jurisdiction under paragraph (a) of this section shall comply with applicable Reliability Standards, the Commission’s regulations, and applicable Electric Reliability Organization and Regional Entity Rules made effective under this part.
(c) Each user, owner and operator of the Bulk-Power System within the United States (other than Alaska and Hawaii) shall register with the Electric Reliability Organization and the Regional Entity for each region within which it uses, owns or operates Bulk-Power System facilities, in such manner as prescribed in the Rules of the Electric Reliability Organization and each applicable Regional Entity.
(d) Each user, owner or operator of the Bulk-Power System within the United States (other than Alaska and Hawaii) shall provide the Commission, the Electric Reliability Organization and the applicable Regional Entity such information as is necessary to implement section 215 of the Federal Power Act as determined by the Commission and set out in the Rules of the Electric Reliability Organization and each applicable Regional Entity. The Electric Reliability Organization and each Regional Entity shall provide the Commission such information as is necessary to implement section 215 of the Federal Power Act.
§ 39.3 Electric Reliability Organization certification.
(a) Any person may submit an application to the Commission for certification as the Electric Reliability Organization no later than April 4, 2006. Such application shall comply with the requirements for filings in proceedings before the Commission in part 385 of this chapter.
(b) After notice and an opportunity for public comment, the Commission may certify one such applicant as an Electric Reliability Organization, if the Commission determines such applicant:
(1) Has the ability to develop and enforce, subject to § 39.7, Reliability Standards that provide for an adequate level of reliability of the Bulk-Power System, and
(2) Has established rules that:
(i) Assure its independence of users, owners and operators of the Bulk-Power System while assuring fair stakeholder representation in the selection of its directors and balanced decisionmaking in any Electric Reliability Organization committee or subordinate organizational structure;
(ii) Allocate equitably reasonable dues, fees and charges among end users for all activities under this part;
(iii) Provide fair and impartial procedures for enforcement of Reliability Standards through the imposition of penalties in accordance with § 39.7, including limitations on activities, functions, operations, or other appropriate sanctions or penalties;
(iv) Provide reasonable notice and opportunity for public comment, due process, openness, and balance of interests in developing Reliability Standards, and otherwise exercising its duties; and
(v) Provide appropriate steps, after certification by the Commission as the Electric Reliability Organization, to gain recognition in Canada and Mexico.
(c) The Electric Reliability Organization shall submit an assessment of its performance three years from the date of certification by the Commission, and every five years thereafter. After receipt of the assessment, the Commission will establish a proceeding with opportunity for public comment in which it will review the performance of the Electric Reliability Organization.
(1) The Electric Reliability Organization’s assessment of its performance shall include:
(i) An explanation of how the Electric Reliability Organization satisfies the requirements of § 39.3(b);
(ii) Recommendations by Regional Entities, users, owners, and operators of the Bulk-Power System, and other interested parties for improvement of the Electric Reliability Organization’s operations, activities, oversight and procedures, and the Electric Reliability Organization’s response to such recommendations; and
(iii) The Electric Reliability Organization’s evaluation of the effectiveness of each Regional Entity, recommendations by the Electric Reliability Organization, users, owners, and operators of the Bulk-Power System, and other interested parties for improvement of the Regional Entity’s performance of delegated functions, and the Regional Entity’s response to such evaluation and recommendations.
(2) The Commission will issue an order finding that the Electric Reliability Organization meets the statutory and regulatory criteria or directing the Electric Reliability Organization or a Regional Entity to come into compliance with or improve its compliance with the requirements of this part. If the ERO fails to comply adequately with the Commission order, the Commission may institute a proceeding to enforce its order, including, if necessary and appropriate, a proceeding to consider decertification of the ERO consistent with § 39.9. The Commission will issue an order finding that each Regional Entity meets the statutory and regulatory criteria or directing the Regional Entity to come into compliance with or improve its compliance with the requirements of this part. If a Regional Entity fails to comply adequately with the Commission order, the Commission may institute a proceeding to enforce its order, including, if necessary and appropriate, a proceeding to consider rescission of its approval of the Regional Entity’s delegation agreement.
§ 39.4 Funding of the Electric Reliability Organization.
(a) Any person who submits an application for certification as the Electric Reliability Organization shall include in its application a formula or method for the allocation and assessment of Electric Reliability Organization dues, fees and charges. The certified Electric Reliability Organization may subsequently file with the Commission a request to modify the formula or method.
(b) The Electric Reliability Organization shall file with the Commission its proposed entire annual budget for statutory and any non-statutory activities, including the entire annual budget for statutory and any non-statutory activities of each Regional Entity, with supporting materials, including the ERO’s and each Regional Entity’s complete business plan and organization chart, explaining the proposed collection of all dues, fees and charges and the proposed expenditure of funds collected in sufficient detail to justify the requested funding collection and budget expenditures 130 days in advance of the beginning of each Electric Reliability Organization fiscal year. The annual Electric Reliability Organization budget shall include line item budgets for the activities of each Regional Entity that are delegated or assigned to each Regional Entity pursuant to § 39.8.
(c) The Commission, after public notice and opportunity for hearing, will issue an order either accepting, rejecting, remanding or modifying the proposed Electric Reliability Organization budget and business plan no later than sixty (60) days in advance of the beginning of the Electric Reliability Organization’s fiscal year.
(d) On a demonstration of unforeseen and extraordinary circumstances requiring additional funds prior to the next Electric Reliability Organization fiscal year, the Electric Reliability Organization may file with the Commission for authorization to collect a special assessment. Such filing shall include supporting materials explaining the proposed collection in sufficient detail to justify the requested funding, including any departure from the approved funding formula or method. After notice and an opportunity for hearing, the Commission will approve, disapprove, remand or modify such request.
(e) All entities within the Commission’s jurisdiction as set forth in section 215(b) of the Federal Power Act shall pay any Electric Reliability Organization assessment of dues, fees and charges as approved by the Commission, in a timely manner reasonably as designated by the Electric Reliability Organization.
(f) Any person who submits an application for certification as the Electric Reliability Organization may include in the application a plan for a transitional funding mechanism that would allow such person, if certified as the Electric Reliability Organization, to continue existing operations without interruption as it transitions from one method of funding to another. Any proposed transitional funding plan should terminate no later than eighteen (18) months from the date of Electric Reliability Organization certification.
(g) The Electric Reliability Organization or a Regional Entity may not engage in any activity or receive revenues from any person that, in the judgment of the Commission represents a significant distraction from, or a conflict of interest with, its responsibilities under this part.
§ 39.5 Reliability Standards.
(a) The Electric Reliability Organization shall file each Reliability Standard or modification to a Reliability Standard that it proposes to be made effective under this part with the Commission. The filing shall include a concise statement of the basis and purpose of the proposed Reliability Standard, either a summary of the Reliability Standard development proceedings conducted by the Electric Reliability Organization or a summary of the Reliability Standard development proceedings conducted by a Regional Entity together with a summary of the Reliability Standard review proceedings of the Electric Reliability Organization, and a demonstration that the proposed Reliability Standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest.
(b) The Electric Reliability Organization shall rebuttably presume that a proposal for a Reliability Standard or a modification to a Reliability Standard to be applicable on an Interconnection-wide basis is just, reasonable, not unduly discriminatory or preferential, and in the public interest, if such proposal is from a Regional Entity organized on an Interconnection-wide basis.
(c) The Commission may approve by rule or order a proposed Reliability Standard or a proposed modification to a Reliability Standard if, after notice and opportunity for public hearing, it determines that the proposed Reliability Standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest.
(1) The Commission will give due weight to the technical expertise of the Electric Reliability Organization with respect to the content of a proposed Reliability Standard or a proposed modification to a Reliability Standard,
(2) The Commission will give due weight to the technical expertise of a Regional Entity organized on an Interconnection-wide basis with respect to a proposed Reliability Standard or a proposed modification to a Reliability Standard to be applicable within that Interconnection, and
(3) The Commission will not defer to the Electric Reliability Organization or a Regional Entity with respect to the effect of a proposed Reliability Standard or a proposed modification to a Reliability Standard on competition.
(d) An approved Reliability Standard or modification to a Reliability Standard shall take effect as approved by the Commission.
(e) The Commission will remand to the Electric Reliability Organization for further consideration a proposed Reliability Standard or modification to a Reliability Standard that the Commission disapproves in whole or in part.
(f) The Commission may, upon its own motion or a complaint, order the Electric Reliability Organization to submit a proposed Reliability Standard or modification to a Reliability Standard that addresses a specific matter if the Commission considers such a new or modified Reliability Standard appropriate to carry out section 215 of the Federal Power Act.
(g) The Commission, when remanding a Reliability Standard to the Electric Reliability Organization or ordering the Electric Reliability Organization to submit to the Commission a proposed Reliability Standard or proposed modification to a Reliability Standard that addresses a specific matter may order a deadline by which the Electric Reliability Organization must submit a proposed or modified Reliability Standard.
§ 39.6 Conflict of a Reliability Standard with a Commission Order.
(a) If a user, owner or operator of the transmission facilities of a Transmission Organization determines that a Reliability Standard may conflict with a function, rule, order, tariff, rate schedule, or agreement accepted, approved, or ordered by the Commission with respect to such Transmission Organization, the Transmission Organization shall expeditiously notify the Commission, the Electric Reliability Organization and the relevant Regional Entity of the possible conflict.
(b) After notice and opportunity for hearing, within sixty (60) days of the date that a notice was filed under paragraph (a) of this section, unless the Commission orders otherwise, the Commission will issue an order determining whether a conflict exists and, if so, resolve the conflict by directing:
(1) The Transmission Organization to file a modification of the conflicting function, rule, order, tariff, rate schedule, or agreement pursuant to section 206 of the Federal Power Act, as appropriate, or
(2) The Electric Reliability Organization to propose a modification to the conflicting Reliability Standard pursuant to § 39.5 of the Commission’s regulations.
(c) The Transmission Organization shall continue to comply with the function, rule, order, tariff, rate schedule, or agreement accepted, approved, or ordered by the Commission until the Commission finds that a conflict exists, the Commission orders a change to such provision pursuant to section 206 of the Federal Power Act, and the ordered change becomes effective.
§ 39.7 Enforcement of Reliability Standards.
(a) The Electric Reliability Organization and each Regional Entity shall have an audit program that provides for rigorous audits of compliance with Reliability Standards by users, owners and operators of the Bulk-Power System.
(b) The Electric Reliability Organization and each Regional Entity shall have procedures to report promptly to the Commission any self-reported violation or investigation of a violation or an alleged violation of a Reliability Standard and its eventual disposition.
(1) Any person that submits an application to the Commission for certification as an Electric Reliability Organization shall include in such application a proposal for the prompt reporting to the Commission of any self-reported violation or investigation of a violation or an alleged violation of a Reliability Standard and its eventual disposition.
(2) Any agreement for the delegation of enforcement authority to a Regional Entity shall include a provision for the prompt reporting through the Electric Reliability Organization to the Commission of any self-reported violation or investigation of a violation or an alleged violation of a Reliability Standard and its eventual disposition.
(3) Each report of a violation or alleged violation by a user, owner or operator of the Bulk-Power System shall include the user’s, owner’s or operator’s name, which Reliability Standard or Reliability Standards were violated or allegedly violated, when the violation or alleged violation occurred, and the name of a person knowledgeable about the violation or alleged violation to serve as a point of contact with the Commission.
(4) Each violation or alleged violation shall be treated as nonpublic until the matter is filed with the Commission as a notice of penalty or resolved by an admission that the user, owner or operator of the Bulk-Power System violated a Reliability Standard or by a settlement or other negotiated disposition. The disposition of each violation or alleged violation that relates to a Cybersecurity Incident or that would jeopardize the security of the Bulk-Power System if publicly disclosed shall be nonpublic unless the Commission directs otherwise.
(5) The Electric Reliability Organization, and each Regional Entity through the ERO, shall file such periodic summary reports as the Commission shall from time to time direct on violations of Reliability Standards and summary analyses of such violations.
(c) The Electric Reliability Organization, or a Regional Entity, may impose, subject to section 215(e) of the Federal Power Act, a penalty on a user, owner or operator of the Bulk-Power System for a violation of a Reliability Standard approved by the Commission if, after notice and opportunity for hearing:
(1) The Electric Reliability Organization or the Regional Entity finds that the user, owner or operator has violated a Reliability Standard approved by the Commission; and
(2) The Electric Reliability Organization files a notice of penalty and the record of its or a Regional Entity’s proceeding with the Commission. Simultaneously with the filing of a notice of penalty with the Commission, the Electric Reliability Organization shall serve a copy of the notice of penalty on the entity that is the subject of the penalty.
(d) A notice of penalty by the Electric Reliability Organization shall consist of:
(1) The name of the entity on whom the penalty is imposed;
(2) Identification of each Reliability Standard violated;
(3) A statement setting forth findings of fact with respect to the act or practice resulting in the violation of each Reliability Standard;
(4) A statement describing any penalty imposed;
(5) The record of the proceeding;
(6) Other matters the Electric Reliability Organization or the Regional Entity, as appropriate, may find relevant.
(e) A penalty imposed under this section may take effect not earlier than the thirty-first (31st) day after the Electric Reliability Organization files with the Commission the notice of penalty and the record of the proceedings.
(1) Such penalty will be subject to review by the Commission, on its own motion or upon application by the user, owner or operator of the Bulk-Power System that is the subject of the penalty filed within thirty (30) days after the date such notice is filed with Commission. In the absence of the filing of an application for review or motion or other action by the Commission, the penalty shall be affirmed by operation of law upon the expiration of the thirty (30)-day period for filing of an application for review.
(2) An applicant filing an application for review shall comply with the requirements for filings in proceedings before the Commission. An application shall contain a complete and detailed explanation of why the applicant believes that the Electric Reliability Organization or Regional Entity erred in determining that the applicant violated a Reliability Standard, or in determining the appropriate form or amount of the penalty. The applicant may support its explanation by providing information that is not included in the record submitted by the Electric Reliability Organization.
(3) Application to the Commission for review, or the initiation of review by the Commission on its own motion, shall not operate as a stay of such penalty unless the Commission otherwise orders upon its own motion or upon application by the user, owner or operator that is the subject of such penalty.
(4) Any answer, intervention or comment to an application for review of a penalty imposed under this part must be filed within twenty (20) days after the application is filed, unless otherwise ordered by the Commission.
(5) In any proceeding to review a penalty imposed under this part, the Commission, after public notice and opportunity for hearing (which hearing may consist solely of the record before the Electric Reliability Organization or Regional Entity and the opportunity for the presentation of supporting reasons to affirm, modify, or set aside the penalty), will by order affirm, set aside, or modify the penalty or may remand the determination of a violation or the form or amount of the penalty to the Electric Reliability Organization for further consideration. The Commission may establish a hearing before an administrative law judge or initiate such further procedures as it determines to be appropriate, before issuing such an order. In the case of a remand to the Electric Reliability Organization, the Electric Reliability Organization may remand the matter to a Regional Entity for further consideration and resubmittal through the Electric Reliability Organization to the Commission.
(6) The Commission will take action on an application for review of a penalty within sixty (60) days of the date the application is filed unless the Commission determines on a case-by-case basis that an alternative expedited procedure is appropriate.
(7) A proceeding for Commission review of a penalty for violation of a Reliability Standard will be public unless the Commission determines that a nonpublic proceeding is necessary and lawful, including a proceeding involving a Cybersecurity Incident. For a nonpublic proceeding, the user, owner or operator of the Bulk-Power System that is the subject of the penalty will be given timely notice and an opportunity for hearing and the public will not be notified and the public will not be allowed to participate.
(f) On its own motion or upon complaint, the Commission may order compliance with a Reliability Standard and may impose a penalty against a user, owner or operator of the Bulk-Power System, if the Commission finds, after public notice and opportunity for hearing, that the user, owner or operator of the Bulk-Power System has engaged or is about to engage in any acts or practices that constitute or will constitute a violation of a Reliability Standard.
(g) Any penalty imposed for the violation of a Reliability Standard shall bear a reasonable relation to the seriousness of the violation and shall take into consideration efforts of such user, owner or operator of the Bulk-Power System to remedy the violation in a timely manner.
(1) The penalty imposed may be a monetary or a non-monetary penalty and may include, but is not limited to, a limitation on an activity, function, operation, or other appropriate sanction, including being added to a reliability watch list composed of major violators that is established by the Electric Reliability Organization, a Regional Entity or the Commission.
(2) The Electric Reliability Organization shall submit for Commission approval penalty guidelines that set forth a range of penalties for the violation of Reliability Standards. A penalty imposed by the Electric Reliability Organization or a Regional Entity must be within be within the range set forth in the penalty guidelines.
§ 39.8 Delegation to a Regional Entity.
(a) The Electric Reliability Organization may enter into an agreement to delegate authority to a Regional Entity for the purpose of proposing Reliability Standards to the Electric Reliability Organization and enforcing Reliability Standards under § 39.7.
(b) After notice and opportunity for comment, the Commission may approve a delegation agreement. A delegation agreement shall not be effective until it is approved by the Commission.
(c) The Electric Reliability Organization shall file a delegation agreement. Such filing shall include a statement demonstrating that:
(1) The Regional Entity is governed by an independent board, a balanced stakeholder board, or a combination independent and balanced stakeholder board;
(2) The Regional Entity otherwise satisfies the provisions of section 215(c) of the Federal Power Act; and
(3) The agreement promotes effective and efficient administration of Bulk-Power System reliability.
(d) The Commission may modify such delegation.
(e) The Electric Reliability Organization shall and the Commission will rebuttably presume that a proposal for delegation to a Regional Entity organized on an Interconnection-wide basis promotes effective and efficient administration of Bulk-Power System reliability and should be approved.
(f) An entity seeking to enter into a delegation agreement that is unable to reach an agreement with the Electric Reliability Organization within 180 days after proposing a delegation agreement to the Electric Reliability Organization may apply to the Commission to assign to it the Electric Reliability Organization’s authority to enforce Reliability Standards within its region. The entity must demonstrate in its application that it meets the requirements of paragraph (c) of this section and that continued negotiations with the Electric Reliability Organization would not likely result in an appropriate delegation agreement within a reasonable period of time. After notice and opportunity for hearing, the Commission may designate the entity as a Regional Entity and assign enforcement authority to it.
(g) An application pursuant to paragraph (f) of this section must state:
(1) Whether the Commission’s Dispute Resolution Service, or other alternative dispute resolution procedures were used, or why these procedures were not used; and
(2) Whether the Regional Entity believes that alternative dispute resolution under the Commission’s supervision could successfully resolve the disputes regarding the terms of the delegation agreement.
§ 39.9 Enforcement of Commission Rules and Orders.
(a) The Commission may take such action as is necessary and appropriate against the Electric Reliability Organization or a Regional Entity to ensure compliance with a Reliability Standard or any Commission order affecting the Electric Reliability Organization or a Regional Entity, including, but not limited to:
(1) After notice and opportunity for hearing, imposition of civil penalties under the Federal Power Act.
(2) After notice and opportunity for hearing, suspension or decertification of the Commission’s certification to be the Electric Reliability Organization.
(3) After notice and opportunity for hearing, suspension or rescission of the Commission’s approval of an agreement to delegate certain Electric Reliability Organization authorities to a Regional Entity.
(b) The Commission may periodically audit the Electric Reliability Organization’s performance under this part.
§ 39.10 Changes to an Electric Reliability Organization Rule or Regional Entity Rule.
(a) The Electric Reliability Organization shall file with the Commission for approval any proposed Electric Reliability Organization Rule or Rule change. A Regional Entity shall submit a Regional Entity Rule or Rule change to the Electric Reliability Organization and, if approved by the Electric Reliability Organization, the Electric Reliability Organization shall file the proposed Regional Entity Rule or Rule change with the Commission for approval. Any filing by the Electric Reliability Organization shall be accompanied by an explanation of the basis and purpose for the Rule or Rule change, together with a description of the proceedings conducted by the Electric Reliability Organization or Regional Entity to develop the proposal.
(b) The Commission, upon its own motion or upon complaint, may propose a change to an Electric Reliability Organization Rule or Regional Entity Rule.
(c) A proposed Electric Reliability Organization Rule or Rule change or Regional Entity Rule or Rule change shall take effect upon a finding by the Commission, after notice and opportunity for public comment, that the change is just, reasonable, not unduly discriminatory or preferential, is in the public interest, and satisfies the requirements of § 39.3.
§ 39.11 Reliability reports.
(a) The Electric Reliability Organization shall conduct assessments as determined by the Commission of the reliability of the Bulk-Power System in North America and provide a report to the Commission and provide subsequent reports of the same to the Commission.
(b) The Electric Reliability Organization shall conduct assessments of the adequacy of the Bulk-Power System in North America and report its findings to the Commission, the Secretary of Energy, each Regional Entity, and each Regional Advisory Body annually or more frequently if so ordered by the Commission.
(c) The Electric Reliability Organization shall make available to the Commission, on a non-public and ongoing basis, access to the Transmission Availability Data System, Generator Availability Data System, and protection system misoperations databases, or any successor databases thereto. Such access will be limited to:
(1) Data regarding U.S. facilities; and
(2) Data that is required to be provided to the ERO.
§ 39.12 Review of state action.
(a) Nothing in this section shall be construed to preempt any authority of any state to take action to ensure the safety, adequacy, and reliability of electric service within that state, as long as such action is not inconsistent with any Reliability Standard, except that the State of New York may establish rules that result in greater reliability within that state, as long as such action does not result in lesser reliability outside the state than that provided by the Reliability Standards.
(b) Where a state takes action to ensure the safety, adequacy, or reliability of electric service, the Electric Reliability Organization, a Regional Entity or other affected person may apply to the Commission for a determination of consistency of the state action with a Reliability Standard.
(1) The application shall:
(i) Identify the state action;
(ii) Identify the Reliability Standard with which the state action is alleged to be inconsistent;
(iii) State the basis for the allegation that the state action is inconsistent with the Reliability Standard; and
(iv) Be served on the relevant state agency and the Electric Reliability Organization, concurrent with its filing with the Commission.
(2) Within ninety (90) days of the application of the Electric Reliability Organization, the Regional Entity, or other affected person, and after notice and opportunity for public comment, the Commission will issue a final order determining whether the state action is inconsistent with a Reliability Standard, taking into consideration any recommendation of the Electric Reliability Organization and the state.
(c) The Commission, after consultation with the Electric Reliability Organization and the state taking action, may stay the effectiveness of the state action, pending the Commission’s issuance of a final order.
§ 39.13 Regional Advisory Bodies.
(a) The Commission will establish a Regional Advisory Body on the petition of at least two-thirds of the states within a region that have more than one-half of their electric load served within the region.
(b) A petition to establish a Regional Advisory Body shall include a statement that the Regional Advisory Body is composed of one member from each participating state in the region, appointed by the governor of each state, and may include representatives of agencies, states and provinces outside the United States.
(c) A Regional Advisory Body established by the Commission may provide advice to the Electric Reliability Organization or a Regional Entity or the Commission regarding:
(1) The governance of an existing or proposed Regional Entity within the same region;
(2) Whether a Reliability Standard proposed to apply within the region is just, reasonable, not unduly discriminatory or preferential, and in the public interest;
(3) Whether fees for all activities under this part proposed to be assessed within the region are just, reasonable, not unduly discriminatory or preferential, and in the public interest; and
(4) Any other responsibilities requested by the Commission.
(d) The Commission may give deference to the advice of a Regional Advisory Body established by the Commission that is organized on an Interconnection-wide basis.
PART 40—MANDATORY RELIABILITY STANDARDS FOR THE BULK-POWER SYSTEM
§ 40.1 Applicability.
(a) This part applies to all users, owners and operators of the Bulk-Power System within the United States (other than Alaska or Hawaii), including, but not limited to, entities described in section 201(f) of the Federal Power Act.
(b) Each Reliability Standard made effective by § 40.2 must identify the subset of users, owners and operators of the Bulk-Power System to which a particular Reliability Standard applies.
§ 40.2 Mandatory Reliability Standards.
(a) Each applicable user, owner or operator of the Bulk-Power System must comply with Commission-approved Reliability Standards developed by the Electric Reliability Organization.
(b) A proposed modification to a Reliability Standard proposed to become effective pursuant to § 39.5 of this Chapter will not be effective until approved by the Commission.
§ 40.3 Availability of Reliability Standards.
The Electric Reliability Organization must post on its Web site the currently effective Reliability Standards as approved and enforceable by the Commission. The effective date of the Reliability Standards must be included in the posting.
PART 41—ACCOUNTS, RECORDS, MEMORANDA AND DISPOSITION OF CONTESTED AUDIT FINDINGS AND PROPOSED REMEDIES
For rules of practice and procedure, see part 385 of this chapter.
Disposition of Contested Audit Findings and Proposed Remedies
§ 41.1 Notice to audited person.
(a) Applicability. This part applies to all audits conducted by the Commission or its staff under authority of the Federal Power Act except for Electric Reliability Organization audits conducted pursuant to the authority of part 39 of the Commission’s regulations.
(b) Notice. An audit conducted by the Commission’s staff under authority of the Federal Power Act may result in a notice of deficiency or audit report or similar document containing a finding or findings that the audited person has not complied with a requirement of the Commission with respect to, but not limited to, the following: A filed tariff or tariffs, contracts, data, records, accounts, books, communications or papers relevant to the audit of the audited person; matters under the Standards of Conduct or the Code of Conduct; and the activities or operations of the audited person. The notice of deficiency, audit report or similar document may also contain one or more proposed remedies that address findings of noncompliance. Where such findings, with or without proposed remedies, appear in a notice of deficiency, audit report or similar document, such document shall be provided to the audited person, and the finding or findings, and any proposed remedies, shall be noted and explained. The audited person shall timely indicate in a written response any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees. The audited person shall have 15 days from the date it is sent the notice of deficiency, audit report or similar document to provide a written response to the audit staff indicating any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees, and such further time as the audit staff may provide in writing to the audited person at the time the document is sent to the audited person. The audited person may move the Commission for additional time to provide a written response to the audit staff and such motion shall be granted for good cause shown. Any initial order that the Commission subsequently may issue with respect to the notice of deficiency, audit report or similar document shall note, but not address on the merits, the finding or findings, or the proposed remedy or remedies, or both, in any combination, with which the audited person disagreed. The Commission shall provide the audited person 30 days to respond to the initial Commission order concerning a notice of deficiency, audit report or similar document with respect to the finding or findings or any proposed remedy or remedies, or both, in any combination, with which it disagreed.
§ 41.2 Response to notification.
Upon issuance of a Commission order that notes a finding or findings, or proposed remedy or remedies, or both, in any combination, with which the audited person has disagreed, the audited person may: Acquiesce in the findings and/or proposed remedies by not timely responding to the Commission order, in which case the Commission may issue an order approving them or taking other action; or challenge the finding or findings and/or any proposed remedies, with which it disagreed by timely notifying the Commission in writing that it requests Commission review by means of a shortened procedure or, if there are material facts in dispute which require cross-examination, a trial-type hearing.
§ 41.3 Shortened procedure.
If the audited person subject to a Commission order described in § 41.1 notifies the Commission that it seeks to challenge one or more audit findings, or proposed remedies, or both, in any combination, by the shortened procedure, the Commission shall thereupon issue a notice setting a schedule for the filing of memoranda. The person electing the use of the shortened procedure, and any other interested entities, including the Commission staff, shall file, within 45 days of the notice, an initial memorandum that addresses the relevant facts and applicable law that support the position or positions taken regarding the matters at issue. Reply memoranda shall be filed within 20 days of the date by which the initial memoranda are due to be filed. Only participants who filed initial memoranda may file reply memoranda. Subpart T of part 385 of this chapter shall apply to all filings. Within 20 days after the last date that reply memoranda under the shortened procedure may be timely filed, the audited person who elected the shortened procedure may file a motion with the Commission requesting a trial-type hearing if new issues are raised by a party. To prevail in such a motion, the audited person must show that a party to the shortened procedure raised one or more new issues of material fact relevant to resolution of a matter in the shortened procedure such that fundamental fairness requires a trial-type hearing to resolve the new issue or issues so raised. Parties to the shortened procedure and the Commission staff may file responses to the motion. In ruling upon the motion, the Commission may determine that some or all of the issues be litigated in a trial-type hearing.
§ 41.4 Form and style.
Each copy of such memorandum must be complete in itself. All pertinent data should be set forth fully, and each memorandum should set out the facts and argument as prescribed for briefs in § 385.706 of this chapter.
§ 41.5 Verification.
The facts stated in the memorandum must be sworn to by persons having knowledge thereof, which latter fact must affirmatively appear in the affidavit. Except under unusual circumstances, such persons should be those who would appear as witnesses if hearing were had to testify as to the facts stated in the memorandum.
§ 41.6 Determination.
If no formal hearing is had the matter in issue will be determined by the Commission on the basis of the facts and arguments submitted.
§ 41.7 Assignment for oral hearing.
Except when there are no material facts in dispute, when a person does not consent to the shortened procedure, the Commission will assign the proceeding for hearing as provided by subpart E of part 385 of this chapter. Notwithstanding a person’s not giving consent to the shortened procedure, and instead seeking assignment for hearing as provided for by subpart E of part 385 of this chapter, the Commission will not assign the proceeding for a hearing when no material facts are in dispute. The Commission may also, in its discretion, at any stage in the proceeding, set the proceeding for hearing.
§ 41.8 Burden of proof.
The burden of proof to justify every accounting entry shall be on the person making, authorizing, or requiring such entry.
Certification of Compliance With Accounting Regulations
§ 41.10 Examination of accounts.
(a) All Major and Nonmajor public utilities and licensees not classified as Class C or Class D prior to January 1, 1984 shall secure, for the year 1968 and each year thereafter until December 31, 1975, the services of an independent certified public accountant, or independent licensed public accountant, certified or licensed by a regulatory authority of a State or other political subdivision of the United States, to test compliance in all material respects of those schedules as are indicated in the General Instructions set out in the Annual Report, Form No. 1, with the Commission’s applicable Uniform System of Accounts and published accounting releases. The Commission expects that identification of questionable matters by the independent accountant will facilitate their early resolution and that the independent accountant will seek advisory rulings by the Commission on such items. This examination shall be deemed supplementary to periodic Commission examinations of compliance.
(b) Beginning January 1, 1976, and each year thereafter, only independent certified public accountants, or independent licensed public accountants who were licensed on or before December 31, 1970, will be authorized to conduct annual audits and to certify to compliance in all material respects, of those schedules as are indicated in the General Instructions set out in the Annual Report, Form No. 1, with the Commission’s applicable Uniform System of Accounts, published accounting releases and all other regulatory matters.
§ 41.11 Report of certification.
Each Major and Nonmajor (including those companies classified as nonoperating under Part 101, General Instruction 1(A)(3) of this chapter) public utility or licensee operating on a calendar year and not classified as Class C or Class D prior to January 1, 1984 must file with the Commission a letter or report of the independent accountant certifying approval, together with or within 30 days after the filing of the Annual Report, Form No. 1, covering the subjects and in the form prescribed in the General Instructions of the Annual Report. For such utility or licensee operating on a non-calendar fiscal year, the letter or report of the independent accountant certifying approval must be filed within 150 days of the close of the company’s fiscal year; the letter or report must also identify which, if any, of the examined schedules do not conform to the Commission’s requirements and shall describe the discrepancies that exist. The Commission will not be bound by a certification of compliance made by an independent accountant pursuant to this paragraph.
§ 41.12 Qualifications of accountants.
The Commission will not recognize any certified public accountant or public accountant through December 31, 1975, who is not in fact independent. Beginning January 1, 1976, and each year thereafter, the Commission will recognize only independent certified public accountants, or independent licensed public accountants who were licensed on or before December 31, 1970, who are in fact independent. For example, an accountant will not be considered independent with respect to any person or any of its parents or subsidiaries in whom he has, or had during the period of report, any direct financial interest. The Commission will determine the fact of independence by considering all the relevant circumstances including evidence bearing on the relationships between the accountant and that person or any affiliate thereof.
PART 42—LONG-TERM FIRM TRANSMISSION RIGHTS IN ORGANIZED ELECTRICITY MARKETS
§ 42.1 Requirement that Transmission Organizations with Organized Electricity Markets Offer Long-Term Firm Transmission Rights.
(a) Purpose. This section requires a transmission organization with one or more organized electricity markets (administered either by it or by another entity) to make available long-term firm transmission rights, pursuant to section 217(b)(4) of the Federal Power Act, that satisfy each of the guidelines set forth in paragraph (d) of this section. This section does not require that a specific type of long-term firm transmission right be made available, and is intended to permit transmission organizations flexibility in satisfying the guidelines set forth in paragraph (d) of this section.
(b) Definitions. As used in this section:
(1) Transmission Organization means a Regional Transmission Organization, Independent System Operator, independent transmission provider, or other independent transmission organization finally approved by the Commission for the operation of transmission facilities.
(2) Load serving entity means a distribution utility or an electric utility that has a service obligation.
(3) Service obligation means a requirement applicable to, or the exercise of authority granted to, an electric utility under Federal, State, or local law or under long-term contracts to provide electric service to end-users or to a distribution utility.
(4) Organized Electricity Market means an auction-based day ahead and real time wholesale market where a single entity receives offers to sell and bids to buy electric energy and/or ancillary services from multiple sellers and buyers and determines which sales and purchases are completed and at what prices, based on formal rules contained in Commission-approved tariffs, and where the prices are used by a transmission organization for establishing transmission usage charges.
(c) General rule. (1) Every public utility that is a transmission organization and that owns, operates or controls facilities used for the transmission of electric energy in interstate commerce and has one or more organized electricity markets (administered either by it or by another entity) must file with the Commission, no later than January 29, 2007, one of the following:
(i) Tariff sheets and rate schedules that make available long-term firm transmission rights that satisfy each of the guidelines set forth in paragraph (d) of this section; or
(ii) An explanation of how its current tariff and rate schedules already provide for long-term firm transmission rights that satisfy each of the guidelines set forth in paragraph (d) of this section.
(2) Any transmission organization approved by the Commission for operation after January 29, 2007 that has one or more organized electricity markets (administered either by it or by another entity) will be required to satisfy this general rule.
(3) Filings made in compliance with this paragraph (c) must explain how the transmission organization’s transmission planning and expansion procedures will accommodate long-term firm transmission rights, including but not limited to how the transmission organization will ensure that allocated long-term firm transmission rights remain feasible over their entire term.
(4) Each transmission organization subject to this general rule must also make its transmission planning and expansion procedures and plans publicly available, including (but not limited to) both the actual plans and any underlying information used to develop the plans.
(d) Guidelines for Design and Administration of Long-term Firm Transmission Rights. Transmission organizations subject to paragraph (c) of this section must make available long-term firm transmission rights that satisfy the following guidelines:
(1) The long-term firm transmission right should specify a source (injection node or nodes) and sink (withdrawal node or nodes), and a quantity (MW).
(2) The long-term firm transmission right must provide a hedge against day-ahead locational marginal pricing congestion charges or other direct assignment of congestion costs for the period covered and quantity specified. Once allocated, the financial coverage provided by a financial long-term right should not be modified during its term (the “full funding” requirement) except in the case of extraordinary circumstances or through voluntary agreement of both the holder of the right and the transmission organization.
(3) Long-term firm transmission rights made feasible by transmission upgrades or expansions must be available upon request to any party that pays for such upgrades or expansions in accordance with the transmission organization’s prevailing cost allocation methods for upgrades or expansions.
(4) Long-term firm transmission rights must be made available with term lengths (and/or rights to renewal) that are sufficient to meet the needs of load serving entities to hedge long-term power supply arrangements made or planned to satisfy a service obligation. The length of term of renewals may be different from the original term. Transmission organizations may propose rules specifying the length of terms and use of renewal rights to provide long-term coverage, but must be able to offer firm coverage for at least a 10 year period.
(5) Load serving entities must have priority over non-load serving entities in the allocation of long-term firm transmission rights that are supported by existing capacity. The transmission organization may propose reasonable limits on the amount of existing capacity used to support long-term firm transmission rights.
(6) A long-term transmission right held by a load serving entity to support a service obligation should be re-assignable to another entity that acquires that service obligation.
(7) The initial allocation of the long-term firm transmission rights shall not require recipients to participate in an auction.
PART 45—APPLICATION FOR AUTHORITY TO HOLD INTERLOCKING POSITIONS
For rules of practice and procedure, see part 385 of this chapter. For forms under rules of practice and regulations under the Federal Power Act, see part 131 of this chapter.
§ 45.1 Applicability; who must file.
(a) This part applies to any person seeking to hold the following interlocking positions:
(1) Officer or director of more than one public utility;
(2) Officer or director of a public utility and of any bank, trust company, banking association, or firm that is authorized by law to underwrite or participate in the marketing of securities of a public utility; or
(3) Officer or director of a public utility and of any company supplying electrical equipment to such public utility.
(b) Any person seeking to hold any interlocking position described in § 45.2 of this chapter must do the following:
(1) Apply for Commission authorization under § 45.8 of this chapter; or
(2) If qualified, comply with the requirements for automatic authorization under § 45.9 of this chapter.
(c) Notwithstanding paragraphs (a) and (b) of this section, any person may temporarily hold an interlocking position described in § 45.2 for no more than 90 days within a twelve-month period without applying for Commission authorization under § 45.8 and without complying with the requirements for authorization under § 45.9.
(a) The positions subject to this part shall include those of any person elected or appointed to perform the duties or functions ordinarily performed by a president, vice president, secretary, treasurer, general manager, comptroller, chief purchasing agent, director or partner, or to perform any other similar executive duties or functions, in any corporation
(b) Corporations
(1) Any public utility under the Act, which means any person who owns or operates facilities for the transmission of electric energy in interstate commerce, or any person who owns or operates facilities for the sale at wholesale of electric energy in interstate commerce.
(2) Any bank, trust company, banking association, or firm that is authorized by law to underwrite or participate in the marketing of public utility securities; this includes any corporation when so authorized whether or not same may also be a public utility and/or a holding company. (See 12 U.S.C. 378)
(3) Any company that supplies electrical equipment to a public utility in which applicant seeks authorization to hold a position, whether the supplying company be a manufacturer, or dealer, or one supplying electrical equipment pursuant to a construction, service, agency, or other contract.
(c) Regardless of any action which may have been taken by the Commission upon a previous application under section 305(b) of the Act, an application for approval under such section is required with reference to any position or positions not previously authorized which are within the purview of said section.
(d) A person that holds or proposes to hold an interlocking position as officer or director of a public utility and of a corporation described by paragraph (b)(2) of this section shall not require authorization to hold such positions in the following circumstances—
(1) The person does not participate in any deliberations or decisions of the public utility regarding the selection of the bank, trust company, banking association, or firm to underwrite or participate in the marketing of securities of the public utility, if the person serves as an officer or director of a bank, trust company, banking association, or firm that is under consideration in the deliberation process;
(2) The bank, trust company, banking association, or firm of which the person is an officer or director does not engage in the underwriting of, or participate in the marketing of, securities of the public utility of which the person holds the position of officer or director;
(3) The public utility for which the person serves or proposes to serve as an officer or director selects underwriters by competitive procedures; or
(4) The issuance of securities of the public utility for which the person serves or proposes to serve as an officer or director has been approved by all Federal and State regulatory agencies having jurisdiction over the issuance.
§ 45.3 Timing of filing application.
(a) The holding of positions within the purview of section 305(b) of the Act shall be unlawful unless the holding shall have been authorized by order of the Commission. Nothing in this part shall be construed as authorizing the holding of positions within the purview of section 305(b) of the Act prior to order of the Commission on application therefor. Applications must be filed and authorization must be granted prior to holding any interlocking positions within the purview of section 305(b) of the Act; the Commission will consider late-filed applications on a case-by-case basis. The term “holding,” as used in this part, shall mean acting as, serving as, voting as, or otherwise performing or assuming the duties and responsibilities of officer or director within the purview of section 305(b) of the Act.
(b) Absent Commission action within 60 days of a completed application to hold interlocking positions, an application will be deemed granted. Such authorization is subject to revocation by the Commission after due notice to applicant and opportunity for hearing. In any such proceeding, the burden of proof shall be upon the applicant to show that neither public nor private interests will be adversely affected by the holding of such positions.
§ 45.4 Supplemental applications.
(a) New positions. In the event of a change or changes in the information set forth in an application, by the applicant’s election or appointment to another position or other positions in corporations within the purview of section 305(b) of the Act, the application shall be supplemented by the applicant’s setting forth all the data with respect to the new position or positions in accordance with the requirements of this part.
(b) Old positions. After applicant has been authorized to hold a particular position, further application in connection with each successive term so long as he continues in uninterrupted tenure of such position will not be required except as ordered by the Commission. If the term of office or the holding of any position for which authorization has been given shall be interrupted and the applicant shall subsequently be reelected or reappointed thereto, further authorization will be required.
(c) Changes in interlocking positions within the scope of § 45.9. Notwithstanding paragraphs (a) and (b) of this section, in the case of interlocking positions that qualify for automatic authorization pursuant to § 45.9(a), a filing under this section will not be required if the only changes to be reported are holding different or additional interlocking positions that would qualify for automatic authorization pursuant to § 45.9(a).
§ 45.5 Supplemental information.
(a) Required by Commission. Applicants under this part shall upon request of the Commission and within such time as may be allowed, supplement any application or any supplemental application with any information required by the Commission.
(b) Notice of changes. In the event of the applicant’s resignation, withdrawal, or failure of reelection or appointment in respect to any of the positions for which authorization has been granted by the Commission, or in the event of any other material or substantial change therein, the applicant shall, within 60 days after any such change occurs, give notice thereof to the Commission setting forth the position, corporation, and date of termination therewith, or other material or substantial change. In the case of interlocking positions that qualify for automatic authorization pursuant to § 45.9(a), a notice of change under this section will not be required if the only change to be reported is a resignation or withdrawal from fewer than all positions held between or among affiliated public utilities, a reelection or reappointment to a position that was previously authorized, or holding a different or additional interlocking position that would qualify for automatic authorization pursuant to § 45.9(a).
(c) Reports. All persons holding positions by authorization of the Commission under section 305(b) of the Act may be required to file such periodic or special reports as the Commission may deem necessary.
(a) By the Commission. Orders of authorization under section 305(b) of the Act are subject to revocation by the Commission after due notice to applicant and opportunity for hearing. In any such proceeding the burden of proof shall be upon the applicant to show that neither public nor private interests will be adversely affected by the holding of such positions.
(b) Without action of the Commission. Whenever a person shall cease to hold a position theretofore authorized to be held by the Commission or such position shall cease to be within the purview of section 305(b) of the Federal Power Act, the Commission’s authorization to hold such position shall terminate without further action by the Commission. If upon such termination of authorization as aforesaid, such person does not continue to hold at least two positions authorized and then requiring authorization pursuant to said section 305(b) of the Act, all authorization theretofore given by the Commission shall thereupon terminate.
§ 45.7 Form of application; filing procedure.
Applications, supplemental applications, statements of supplemental information, notices of change, and reports should be filed with the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov. Each filing must be dated, signed by the applicant, and verified under oath in accordance with § 385.2005(b) and (c).
§ 45.8 Contents of application.
Each application shall state the following:
(a) Identification of applicant. (1) Full name, business address and state of residence.
(2) Major business or professional activity.
(3) If former application or applications under section 305(b) of the Act have been made by the applicant, give date and docket number of the last application filed.
(b) List of positions within the purview of section 305(b) of the Act for which authorization is sought. (Indicate by asterisk positions which were the subjects of previous authorizations.)
| Position | Name of corporation | Classification: (1) Public utility, (2) authorized by law to underwrite, (3) supplying electrical equipment |
|---|---|---|
(c) Data as to positions with each public utility mentioned in paragraph (b) of this section. (The format should be adapted to the information submitted, in keeping with completeness and conciseness. In the case of public utilities of the same holding company system, brevity will generally be promoted by submitting the information for all of the utilities involved under each subsection progressively in the order of the subsections, utilizing tables when feasible.)
(1) Name of utility, unless said utility does not have officers or directors.
(2) Date elected or appointed, or anticipated date of election or appointment, to each position not previously authorized.
(3) Names of officers and directors; number of vacancies, if any, on Board of Directors.
(4) Description of applicant’s duties: Approximate amount of time devoted thereto; and, if applicant seeks authorization as a director, the percentage of directors meetings held during the past 12 months that were attended by the applicant.
(5) All other professional, contractual, or business relationships of applicant with the public utility, either directly or through other corporations or firms.
(6) Extent of applicant’s direct or indirect ownership, control of, or beneficial interest in the public utility or the securities thereof. If ownership or interest is held in a name other than that of applicant, state name and address of the holder.
(7) Extent of applicant’s indebtedness to the public utility, how and when incurred, and consideration therefor.
(8) All money or property received by applicant from the public utility or any affiliate (i) during the past 12 months, and expected during the ensuing 12 months, or (ii) during the public utility’s most recently ended fiscal year, and expected during the public utility’s current fiscal year, or (iii) during the past and current calendar years, whether for services, reimbursement for expenses, or otherwise. Specify in detail the amount thereof and the basis therefor. If applicant’s compensation for services to the public utility is not paid directly by the public utility, give name of the corporation that does pay same, the amount allocated or allocable to the public utility or any affiliate, and the basis or reason for such allocation.
(9) Whether during the past 5 years the public utility or any affiliate thereof or any security holders of either have commenced any suit against the officers or directors thereof for alleged waste, mismanagement or violation of duty, to which suit applicant was a party defendant. If so, give date of commencement of suit, court in which commenced, and present status.
(d) Data as to positions with each bank, trust company, banking association or firm, mentioned in paragraph (b) of this section, that is authorized by law to underwrite or participate in the marketing of securities of a public utility. (The applicant shall use a separate sheet for each corporation.)
(1) Name of corporation and address of principal place of business.
(2) Positions which applicant holds or seeks authorization to hold therein and when and by whom elected or appointed to each position.
(3) Description of applicant’s duties in each position and the approximate amount of time devoted thereto, and, if applicant seeks authorization as director, the percentage of directors meetings held during the past 12 months that were attended by the applicant.
(4) Extent of applicant’s direct or indirect ownership, or control of, or beneficial interest in, the company or in the securities thereof, including common stock, preferred stock, bonds, or other securities. If such ownership or interest is held in a name other than that of applicant, state name and address of such holder.
(5) All money or property received by applicant from the company (i) during the past 12 months, and expected during the ensuing 12 months, or (ii) during the company’s most recently ended fiscal year, and expected during the company’s current fiscal year, or (iii) during the past and current calendar years, whether for services, reimbursement for expenses, or otherwise. Specify in detail the amount thereof and the basis therefor.
(6) Names and titles of directors, officers, or partners.
(7) Whether the corporation is now engaged in underwriting or participating in the marketing of the securities of a public utility; if so, to what extent.
(8) Whether the corporation, during applicant’s connection therewith, has underwritten or participated in the marketing of the security issue of any public utility with which applicant was also connected; if so, the details with respect to every such transaction that occurred during the past 36 months.
(9) (If the answer to paragraph (d)(7) of this section is in the negative.) Give excerpts from the charter, declaration of trust, or articles of partnership that authorize the underwriting or participating in the marketing of securities of a public utility.
(10) (If the answer to paragraph (d)(7) of this section is in the negative.) Give general requirements of and appropriate reference to, the laws of the State of organization and of States in which corporation is doing business or has qualified to do business, with which it must comply in order to engage in the business of underwriting or participating in the marketing of the securities of a public utility.
(11) What steps, if any, have been taken to comply with laws mentioned in paragraph (d)(10) of this section.
(12) In lieu of paragraphs (d)(9), (10), and (11) of this section, an opinion by counsel to the same effect and including the information in respect thereto may be filed with the application.
(13) Whether the corporation has registered with the Securities and Exchange Commission; if so, when and under what section of what act.
(e) Data as to positions with each company, mentioned in paragraph (b) of this section, supplying electrical equipment to a public utility in which applicant holds a position. (Applicant shall use a separate sheet for each company.)
(1) Name of company and address of principal place of business.
(2) Positions which applicant holds or seeks authorization to hold therein and when and by whom elected or appointed to each position.
(3) Description of applicant’s duties in each position and approximate amounts of time devoted thereto, and, if applicant seeks authorization as director, the percentage of directors meetings held during the past 12 months that were attended by the applicant.
(4) Names and titles of directors or partners.
(5) Name of each public utility, with which applicant holds or seeks authorization to hold a position, to which the company supplies electrical equipment; the frequency of such transactions; the approximate annual dollar volume of such business; and the type of equipment supplied.
(6) Nature of relationship between the company supplying electrical equipment and the public utility:
(i) Whether company manufactures such electrical equipment or is a dealer therein.
(ii) Whether company supplies electrical equipment to the public utility pursuant to construction, service, agency, or other contract with the public utility or an affiliate thereof, and, if so, furnish brief summary of the terms of such contract.
(7) Extent of applicant’s direct or indirect ownership, or control of, or beneficial interest in, the company or in the securities thereof, including common stock, preferred stock, bonds, or other securities. If such ownership or interest is held in a name other than that of applicant, state name and address of such holder.
(8) All money or property received by applicant from the company (i) during the past 12 months, and expected during the ensuing 12 months, or (ii) during the company’s most recently ended fiscal year, and expected during the company’s current fiscal year, or (iii) during the past and current calendar years, whether for services, reimbursement for expenses, or otherwise. Specify in detail the amount thereof and the basis therefor.
(f) Data as to positions with public utility holding companies. (Do not include here data as to corporations listed in paragraph (b) of this section which are also holding companies. A holding company as herein used means any corporation which directly or indirectly owns, controls, or holds with power to vote, 10 per centum or more, of the outstanding voting securities of a public utility.)
(1) Name of holding company and address of principal place of business.
(2) Positions which applicant holds therein, when and by whom elected or appointed to each position.
(3) Extent of applicant’s direct or indirect ownership, or control of, or beneficial interest in, the holding company or in the securities thereof, including common stock, preferred stock, bonds, or other securities. If such ownership or interest is held in a name other than that of applicant, state name and address of such holder.
(4) All money or property received by applicant from the holding company (i) during the past 12 months, and expected during the ensuing 12 months, or (ii) during the holding company’s most recently ended fiscal year, and expected during the holding company’s current fiscal year, or (iii) during the past and current calendar years, whether for services, reimbursement for expenses, or otherwise. Specify in detail the amount thereof and the basis therefor.
(g) Positions with all other corporations. (Do not include here data that have been filed within the past 12 months in FERC–561, pursuant to part 46 of this chapter, or data as to any corporations listed in paragraph (b) or (f) of this section.)
(1) All other corporations and positions therein, including briefly the information required in parallel columns as below:
| Name of corporation | Address: Kind of business | Position held therein |
|---|---|---|
(2) Any corporate, contractual, financial, or business relationships between any of the corporations listed in paragraph (g)(1) of this section and any of the public utilities listed in paragraph (b) of this section.
(h) Data as to the public utility holding company system. The names of the public utility holding company systems of which each public utility listed in paragraph (b) of this section is a part, with a chart showing the corporate relationships existing between and among the corporations within the holding company systems.
For rules and regulations of the Securities and Exchange Commission, see 17 CFR, chap. II.
(a) Applicability. Subject to paragraphs (b) and (c) of this section, the Commission authorizes any officer or director of a public utility to hold the following interlocking positions:
(1) Officer or director of one or more other public utilities if the same holding company or person owns, directly or indirectly, that percentage of each utility’s stock (of whatever class or classes) which is required by each utility’s by-laws to elect directors;
(2) Officer or director of two public utilities, if one utility is owned, wholly or in part, by the other and, as its primary business, owns or operates transmission or generating facilities to provide transmission service or electric power for sale to its owners; and
(3) Officer or director of more than one public utility, if such officer or director is already authorized under this part to hold positions as officer or director of those or any other public utilities where the interlock involves affiliated public utilities.
(b) Conditions of authorization. (1) As a condition of authorization, any person eligible to seek authorization to hold interlocking positions under this section must submit, prior to performing or assuming the duties and responsibilities of the position, an informational report in accordance with paragraph (c) of this section, unless that person:
(i) Is already authorized to hold interlocking positions of the type governed by this section;
(ii) Is exempt from filing an informational report pursuant to § 45.4; or
(iii) Will hold a temporary interlocking position pursuant to § 45.1(c).
(2) The Commission will consider failures to timely file the informational report on a case-by-case basis.
(c) Informational report. An informational report required under paragraph (b) of this section must state:
(1) The full name and business address of the person required to submit this report;
(2) The names of all public utilities with which the person holds or will hold the positions of officer or director and a description of those positions;
(3) The names of any entity, other than those listed in paragraph (c)(2) of this section, of which the person is an officer or director and a description of those positions; and
(4) An explanation of the corporate relationship between or among the public utilities listed in paragraph (c)(2) of this section which qualifies the person for automatic authorization under this section.
(5) A statement or an affirmation that the applicant has not yet performed or assumed the duties or responsibilities of the position which necessitated the filing of this informational report.
PART 46—PUBLIC UTILITY FILING REQUIREMENTS AND FILING REQUIREMENTS FOR PERSONS HOLDING INTERLOCKING POSITIONS
§ 46.1 Purpose.
The purpose of this part is to implement section 305(c) of the Federal Power Act, as amended by section 211 of the Public Utility Regulatory Policies Act of 1978.
§ 46.2 Definitions.
For the purpose of this part:
(a) Public utility has the same meaning as in section 201(e) of the Federal Power Act. Such term does not include any rural electric cooperative which is regulated by the Rural Utilities Service of the Department of Agriculture or any other entities covered in section 201(f) of the Federal Power Act.
(b) [Reserved]
(c) Purchaser means any individual or corporation within the meaning of section 3 of the Federal Power Act who purchases electric energy from a public utility. Such term does not include the United States or any agency or instrumentality of the United States or any rural electric cooperative which is regulated by the Rural Utilities Service of the Department of Agriculture.
(d) Control and controlled mean the possession, directly or indirectly, of the power to direct the management or policies of an entity whether such power is exercised through one or more intermediary companies or pursuant to an agreement, written or oral, and whether such power is established through ownership or voting of securities, or common directors, officers, or stockholders, or voting trusts, holding trusts, or debt holdings, or contract, or any other direct or indirect means. A rebuttable presumption that control exists arises from the ownership or the power to vote, directly or indirectly, ten percent (10%) or more of the voting securities of such entity.
(e) Entity means any firm, company, or organization including any corporation, joint-stock company, partnership, association, business trust, organized group of persons, whether incorporated or not, or a receiver or receivers, trustee or trustees of any of the foregoing. Such term does not include municipality as defined in section 3 of the Federal Power Act and does not include any Federal, State, or local government agencies or any rural electric cooperative which is regulated by the Rural Utilities Service of the Department of Agriculture.
(f) Electrical equipment means any apparatus, device, integral component, or integral part used in an activity which is electrically, electronically, mechanically, or by legal prescription necessary to the process of generation, transmission, or distribution of electric energy.
(g) Produces or supplies means any transaction including a sale, lease, sale-leaseback, consignment, or any other transaction in which an entity provides electrical equipment, coal, natural gas, oil, nuclear fuel, or other fuel to any public utility either directly or through an entity controlled by such entity.
(h) Appointee means any person appointed on a temporary or permanent basis to perform any duties or functions described in § 46.4(a).
(i) Representative means any person empowered, through oral or written agreement, to transact business on behalf of an entity and any person who serves as an advisor regarding policy or management decisions of the entity. The term does not include attorneys, accountants, architects, or any other persons who render a professional service on a fee basis.
§ 46.3 Purchaser list.
(a)(1) Compilation and filing list. On or before January 31 of each year, except as provided below, each public utility shall compile a list of the purchasers described in paragraph (b) of this section, and subject to paragraph (a)(5) of this section, shall identify each purchaser by name and principal business address. The public utility must submit the list to the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov and make the list publicly available through its principal business office.
(2) Notwithstanding paragraph (a)(1) of this section, public utilities that are defined as Regional Transmission Organizations, as defined in § 35.34(b)(1) of this chapter, and public utilities that are defined as Independent System Operators, as defined in § 35.46(d) of this chapter, are exempt from the requirement to file.
(3) Notwithstanding paragraph (a)(1) of this section, public utilities that meet the criteria for exempt wholesale generators, as defined in § 366.1 of this chapter, and are certified as such pursuant to § 366.7 of this chapter, are exempt from the requirement to file.
(4) Notwithstanding paragraph (a)(1) of this section, public utilities that have either no reportable sales as defined in paragraph (b) or only sales for resale in any of the three preceding years are exempt from the requirement to file.
(5) Notwithstanding paragraph (a)(1) of this section, individual residential customers on the list should be identified as “Residential Customer,” and with a zip code in lieu of an address.
(b) Largest purchasers. The list required under paragraph (a) of this section shall include each purchaser who, during any of the three (3) preceding calendar years, purchased (for purposes other than resale) from a public utility one of the twenty (20) largest amounts of electric energy measured in kilowatt hours sold (for purposes other than resale) by such utility during such year.
(c) Special rules. If data for actual annual sales (for purposes other than resale) are not available in the records of the public utility, the utility may use estimates based on actual data available to it. If one purchaser maintains several billing accounts with the public utility, the kilowatt hours purchased in each account of that purchaser shall be aggregated to arrive at the total for that purchaser.
(d) Revision of the list. Each public utility relying upon any estimates for its January 31st filing, shall revise the list compiled under paragraph (b) of this section no later than March 1 of the year in which the list was originally filed to reflect actual data not available to the utility prior to that time. Any revised list shall be filed with the Commission and made publicly available through the utility’s principal business office no later than March 1. A utility filing a revised list shall indicate thereon the changes made to the list previously filed under paragraph (b) of this section. On or before the filing and publication of the revised list, the public utility shall notify the newly-listed purchasers and any purchasers whose names were removed from the list.
§ 46.4 General rule.
A person must file with the Secretary of the Commission a statement in accordance with § 46.6, and in the form specified in § 131.31 of this chapter (except that with respect to calendar year 1980, no filings in the form specified in § 131.31 is required if such person has previously filed the statement required for calendar year 1980 in a different form than specified in § 131.31), if such person:
(a) Serves for a public utility in any of the following positions: A director or a chief executive officer, president, vice president, secretary, treasurer, general manager, comptroller, chief purchasing agent, or any other position in which such person performs similar executive duties or functions for such public utility; and
(b) Serves for any entity described in § 46.5 in any of the positions described in paragraph (a) of this section or is a partner, appointee, or representative of such entity.
§ 46.5 Covered entities.
Entities to which the general rule in § 46.4(b) applies are the following:
(a) Any investment bank, bank holding company, foreign bank or subsidiary thereof doing business in the United States, insurance company, or any other organization primarily engaged in the business of providing financial services or credit, a mutual savings bank, or a savings and loan association;
(b) Any entity which is authorized by law to underwrite or participate in the marketing of securities of a public utility;
(c) Any entity which produces or supplies electrical equipment or coal, natural gas, oil, nuclear fuel, or other fuel, for the use of any public utility;
(d) Any entity specified in § 46.3;
(e) Any entity referred to in section 305(b) of the Federal Power Act; and
(f) Any entity which is controlled by any entity referred to in this section.
§ 46.6 Contents of the statement and procedures for filing.
Each person required to file a written statement under the general rule in § 46.4 shall comply with the following requirements:
(a) Each person shall provide the following information: full name and business address; identification of the public utilities and the covered entities in which such person holds executive positions described in § 46.4; and identification of the interlock described in § 46.4;
(b) If the interlock is between a public utility and an entity described in § 46.5(c), which produces or supplies electrical equipment for use of such public utility, such person shall provide the following information:
(1) The aggregate amount of revenues received by such entity from producing or supplying electrical equipment to such public utility in the calendar year specified in paragraph (d) of this section, rounded up to the nearest $100,000; and
(2) The nature of the business relationship between such public utility and such entity.
(c) If the person is authorized by the Commission to hold the positions of officer or director in accordance with part 45, such person shall identify the authorization by docket number and shall give the date of authorization.
(d)(1) Each person shall file an original and one copy of such written statement with the Office of Secretary of the Commission on or before April 30 of each year immediately following the calendar year during any portion of which such person held a position described in § 46.4. The original of such statement shall be dated and signed by such person. The copy shall bear the date that appeared on the original; the signature on the copy may be stamped or typed on the copy.
(2) Instead of submitting changes to the Commission on the pre-printed Form No. 561 sent annually by the Commission, a person may choose to make changes to the pre-filled electronic version provided by the Commission. This electronic version, along with the signed original and one copy (as required by Paragraph (d)(c)) shall also be filed with the Commission.
(3) Such statement shall be available to the public through the Commission’s eLibrary system on http://www.ferc.gov and shall be made publicly available through the principal business offices of the public utility and any entity to which it applies on or before April 30 of the year the statement was filed with the Commission.
PART 50—APPLICATIONS FOR PERMITS TO SITE INTERSTATE ELECTRIC TRANSMISSION FACILITIES
§ 50.1 Definitions.
As used in this part:
Affected landowners include owners of property interests, as noted in the most recent county/city tax records as receiving the tax notice, whose property:
(1) Is directly affected (i.e., crossed or used) by the proposed activity, including all facility sites, rights-of-way, access roads, staging areas, and temporary workspace; or
(2) Abuts either side of an existing right-of-way or facility site owned in fee by any utility company, or abuts the edge of a proposed facility site or right-of-way which runs along a property line in the area in which the facilities would be constructed, or contains a residence within 50 feet of a proposed construction work area.
Director means the Director of the Office of Energy Projects or his designees.
Federal authorization means permits, special use authorization, certifications, opinions, or other approvals that may be required under Federal law in order to site a transmission facility.
National interest electric transmission corridor means any geographic area experiencing electric energy transmission capacity constraints or congestion that adversely affects consumers, as designated by the Secretary of Energy.
Permitting entity means any Federal or State agency, Indian tribe, multistate, or local agency that is responsible for issuing separate authorizations pursuant to Federal law that are required to construct electric transmission facilities in a national interest electric transmission corridor.
Stakeholder means any Federal, State, interstate, Tribal, or local agency, any affected non-governmental organization, affected landowner, or interested person.
Transmitting utility means an entity that owns, operates, or controls facilities used for the transmission of electric energy in interstate commerce for the sale of electric energy at wholesale.
§ 50.2 Purpose and intent of rules.
(a) The purpose of the regulations in this part is to provide for efficient and timely review of requests for permits for the siting of electric transmission facilities under section 216 of the Federal Power Act. The regulations ensure that each stakeholder is afforded an opportunity to present views and recommendations with respect to the need for and impact of a facility covered by the permit. They also coordinate, to the maximum extent practicable, the Federal authorization and review processes of other Federal and State agencies, Indian tribes, multistate, and local entities that are responsible for conducting any separate permitting and environmental reviews of the proposed facilities.
(b) Every applicant shall file all pertinent data and information necessary for a full and complete understanding of the proposed project.
(c) Every requirement of this part will be considered as an obligation of the applicant which can only be avoided by a definite and positive showing that the information or data called for by the applicable rules is not necessary for the consideration and ultimate determination of the application.
(d) The burden of assuring that all applications and information submitted under this part is in an intelligible form and any omission of data is justified rests with the applicant.
§ 50.3 Applications/pre-filing; rules and format.
(a) Filings are subject to the formal paper and electronic filing requirements for proceedings before the Commission as provided in part 385 of this chapter.
(b) Applications, amendments, and all exhibits and other submissions required to be furnished by an applicant to the Commission under this part must be submitted in an original and 7 conformed copies.
(c) When an application considered alone is incomplete and depends vitally upon information in another application, it will not be accepted for filing until the supporting application has been filed. When applications are interdependent, they must be filed concurrently.
(d) All filings must be signed in compliance with § 385.2005 of this chapter.
(e) The Commission will conduct a paper hearing on applications for permits for electric transmission facilities.
(f) Permitting entities will be subject to the filing requirements of this section and the prompt and binding intermediate milestones and ultimate deadlines established in the notice issued under § 50.9.
(g) Any person submitting documents containing critical energy infrastructure information must follow the procedures specified in § 388.113 of this chapter.
§ 50.4 Stakeholder participation.
A Project Participation Plan is required to ensure stakeholders have access to accurate and timely information on the proposed project and permit application process.
(a) Project Participation Plan. An applicant must develop a Project Participation Plan and file it with the pre-filing materials under § 50.5(c)(7) that:
(1) Identifies specific tools and actions to facilitate stakeholder communications and public information, including an up-to-date project Web site and a readily accessible, single point of contact within the company;
(2) Lists all central locations in each county throughout the project area where the applicant will provide copies of all their filings related to the proposed project; and
(3) Includes a description and schedule explaining how the applicant intends to respond to requests for information from the public as well as Federal, State, and Tribal permitting agencies, and other legal entities with local authorization requirements.
(b) Document Availability. (1) Within three business days of the date the pre-filing materials are filed or application is issued a docket number, an applicant must ensure that:
(i) Complete copies of the pre-filing or application materials are available in accessible central locations in each county throughout the project area, either in paper or electronic format; and
(ii) Complete copies of all filed materials are available on the project Web site.
(2) An applicant is not required to serve voluminous or difficult to reproduce material, such as copies of certain environmental information, on all parties, as long as such material is publicly available in an accessible central location in each county throughout the project area and on the applicant’s project website.
(c) Project notification. (1) The applicant must make a good faith effort to notify: all affected landowners; landowners with a residence within a quarter mile from the edge of the construction right-of-way of the proposed project; towns and communities; permitting agencies; other local, State, Tribal, and Federal governments and agencies involved in the project; electric utilities and transmission owners and operators that are or may be connected to the application’s proposed transmission facilities; and any known individuals that have expressed an interest in the State permitting proceeding. Notification must be made:
(i) By certified or first class mail, sent:
(A) Within 14 days after the Director notifies the applicant of the commencement of the pre-filing process under § 50.5(d);
(B) Within 3 business days after the Commission notices the application under § 50.9; and
(ii) By twice publishing a notice of the pre-filing request and application filings, in a daily, weekly, and/or tribal newspaper of general circulation in each county in which the project is located, no later than 14 days after the date that a docket number is assigned for the pre-filing process or to the application.
(2) Contents of participation notice
(i) The pre-filing request notification must, at a minimum, include:
(A) The docket number assigned to the proceeding;
(B) The most recent edition of the Commission’s pamphlet Electric Transmission Facilities Permit Process. The newspaper notice need only refer to the pamphlet and indicate that it is available on the Commission’s website;
(C) A description of the applicant and a description of the proposed project, its location (including a general location map), its purpose, and the timing of the project;
(D) A general description of the property the applicant will need from an affected landowner if the project is approved, how to contact the applicant, including a local or toll-free phone number, the name of a specific person to contact who is knowledgeable about the project, and a reference to the project website. The newspaper notice need not include a description of the property, but should indicate that a separate notice is being mailed to affected landowners and governmental entities;
(E) A brief summary of what rights the affected landowner has at the Commission and in proceedings under the eminent domain rules of the relevant State. The newspaper notice does not need to include this summary;
(F) Information on how to get a copy of the pre-filing information from the company and the location(s) where copies of the pre-filing information may be found as specified in paragraph (b) of this section;
(G) A copy of the Director’s notification of commencement of the pre-filing process, the Commission’s Internet address, and the telephone number for the Commission’s Office of External Affairs; and
(H) Information explaining the pre-filing and application process and when and how to intervene in the application proceedings.
(ii) The application notification must include the Commission’s notice issued under § 50.9.
(3) If, for any reason, a stakeholder has not yet been identified when the notices under this paragraph are sent or published, the applicant must supply the information required under paragraphs (c)(2)(i) and (ii) of this section when the stakeholder is identified.
(4) If the notification is returned as undeliverable, the applicant must make a reasonable attempt to find the correct address and notify the stakeholder.
(5) Access to critical energy infrastructure information is subject to the requirements of § 388.113 of this chapter.
§ 50.5 Pre-filing procedures.
(a) Introduction. Any applicant seeking a permit to site new electric transmission facilities or modify existing facilities must comply with the following pre-filing procedures prior to filing an application for Commission review.
(b) Initial consultation. An applicant must meet and consult with the Director concerning the proposed project.
(1) At the initial consultation meeting, the applicant must be prepared to discuss the nature of the project, the contents of the pre-filing request, and the status of the applicant’s progress toward obtaining the information required for the pre-filing request described in paragraph (c) of this section.
(2) The initial consultation meeting will also include a discussion of whether a third-party contractor is likely to be needed to prepare the environmental documentation for the project and the specifications for the applicant’s solicitation for prospective third-party contractors.
(3) The applicant also must discuss how its proposed project will be subject to the Commission’s jurisdiction under section 216(b)(1) of the Federal Power Act. If the application is seeking Commission jurisdiction under section 216(b)(1)(C) of the Federal Power Act, the applicant must be prepared to discuss when it filed its application with the State and the status of that application.
(c) Contents of the initial filing. An applicant’s pre-filing request will be filed after the initial consultation and must include the following information:
(1) A description of the schedule desired for the project, including the expected application filing date, desired date for Commission approval, and proposed project operation date, as well as the status of any State siting proceedings.
(2) A detailed description of the project, including location maps and plot plans to scale showing all major components, including a description of zoning and site availability for any permanent facilities.
(3) A list of the permitting entities responsible for conducting separate Federal permitting and environmental reviews and authorizations for the project, including contact names and telephone numbers, and a list of local entities with local authorization requirements. The filing must include information concerning:
(i) How the applicant intends to account for each of the relevant entity’s permitting and environmental review schedules, including its progress in DOE’s pre-application process; and
(ii) When the applicant proposes to file with these permitting and local entities for the respective permits or other authorizations.
(4) A list of all affected landowners and other stakeholders (include contact names and telephone numbers) that have been contacted, or have contacted the applicant, about the project.
(5) A description of what other work already has been done, including, contacting stakeholders, agency and Indian tribe consultations, project engineering, route planning, environmental and engineering contractor engagement, environmental surveys/studies, open houses, and any work done or actions taken in conjunction with a State proceeding. This description also must include the identification of the environmental and engineering firms and sub-contractors under contract to develop the project.
(6) Proposals for at least three prospective third-party contractors from which Commission staff may make a selection to assist in the preparation of the requisite NEPA document, if the Director determined a third-party contractor would be necessary in the Initial Consultation meeting.
(7) A proposed Project Participation Plan, as set forth in § 50.4(a).
(d) Director’s notice. (1) When the Director finds that an applicant seeking authority to site and construct an electric transmission facility has adequately addressed the requirements of paragraphs (a), (b), and (c) of this section, and any other requirements determined at the Initial Consultation meeting, the Director will so notify the applicant.
(i) The notification will designate the third-party contractor, and
(ii) The pre-filing process will be deemed to have commenced on the date of the Director’s notification.
(2) If the Director determines that the contents of the initial pre-filing request are insufficient, the applicant will be notified and given a reasonable time to correct the deficiencies.
(e) Subsequent filing requirements. Upon the Director’s issuance of a notice commencing an applicant’s pre-filing process, the applicant must:
(1) Within 7 days, finalize and file the Project Participation Plan, as defined in § 50.4(a), and establish the dates and locations at which the applicant will conduct meetings with stakeholders and Commission staff.
(2) Within 14 days, finalize the contract with the selected third-party contractor, if applicable.
(3) Within 14 days:
(i) Provide all identified stakeholders with a copy of the Director’s notification commencing the pre-filing process;
(ii) Notify affected landowners in compliance with the requirements of § 50.4(c); and
(iii) Notify permitting entities and request information detailing any specific information not required by the Commission in the resource reports required under § 380.16 of this chapter that the permitting entities may require to reach a decision concerning the proposed project. The responses of the permitting entities must be filed with the Commission, as well as being provided to the applicant.
(4) Within 30 days, submit a mailing list of all stakeholders contacted under paragraph (e)(3) of this section, including the names of the Federal, State, Tribal, and local jurisdictions’ representatives. The list must include information concerning affected landowner notifications that were returned as undeliverable.
(5) Within 30 days, file a summary of the project alternatives considered or under consideration.
(6) Within 30 days, file an updated list of all Federal, State, Tribal, and local agencies permits and authorizations that are necessary to construct the proposed facilities. The list must include:
(i) A schedule detailing when the applications for the permits and authorizations will be submitted (or were submitted);
(ii) Copies of all filed applications; and
(iii) The status of all pending permit or authorization requests and of the Secretary of Energy’s pre-application process being conducted under section 216(h)(4)(C) of the Federal Power Act.
(7) Within 60 days, file the draft resource reports required in § 380.16 of this chapter.
(8) On a monthly basis, file status reports detailing the applicant’s project activities including surveys, stakeholder communications, and agency and tribe meetings, including updates on the status of other required permits or authorizations. If the applicant fails to respond to any request for additional information, fails to provide sufficient information, or is not making sufficient progress towards completing the pre-filing process, the Director may issue a notice terminating the process.
(f) Concluding the pre-filing process. The Director will determine when the information gathered during the pre-filing process is complete, after which the applicant may file an application. An application must contain all the information specified by the Commission staff during the pre-filing process, including the environmental material required in part 380 of this chapter and the exhibits required in § 50.7.
§ 50.6 Applications: general content.
Each application filed under this part must provide the following information:
(a) The exact legal name of applicant; its principal place of business; whether the applicant is an individual, partnership, corporation, or otherwise; the State laws under which the applicant is organized or authorized; and the name, title, and mailing address of the person or persons to whom communications concerning the application are to be addressed.
(b) A concise description of applicant’s existing operations.
(c) A concise general description of the proposed project sufficient to explain its scope and purpose. The description must, at a minimum: Describe the proposed geographic location of the principal project features and the planned routing of the transmission line; contain the general characteristics of the transmission line including voltage, types of towers, origin and termination points of the transmission line, and the geographic character of area traversed by the line; and be accompanied by an overview map of sufficient scale to show the entire transmission route on one or a few 8.5 by 11-inch sheets.
(d) Verification that the proposed route lies within a national interest electric transmission corridor designated by the Secretary of the Department of Energy under section 216 of the Federal Power Act.
(e) Evidence that:
(1) A State in which the transmission facilities are to be constructed or modified does not have the authority to approve the siting of the facilities or consider the interstate benefits expected to be achieved by the proposed construction or modification of transmission facilities in the State;
(2) The applicant is a transmitting utility but does not qualify to apply for a permit or siting approval of the proposed project in a State because the applicant does not serve end-use customers in the State; or
(3) A State commission or other entity that has the authority to approve the siting of the facilities has:
(i) Withheld approval for more than one year after the filing of an application seeking approval under applicable law or one year after the designation of the relevant national interest electric transmission corridor, whichever is later; or
(ii) Conditioned its approval in such a manner that the proposed construction or modification will not significantly reduce transmission congestion in interstate commerce or is not economically feasible.
(f) A demonstration that the facilities to be authorized by the permit will be used for the transmission of electric energy in interstate commerce, and that the proposed construction or modification:
(1) Is consistent with the public interest;
(2) Will significantly reduce transmission congestion in interstate commerce and protects or benefits consumers;
(3) Is consistent with sound national energy policy and will enhance energy interdependence; and
(4) Will maximize, to the extent reasonable and economical, the transmission capabilities of existing towers or structures.
(g) A description of the proposed construction and operation of the facilities, including the proposed dates for the beginning and completion of construction and the commencement of service.
(h) A general description of project financing.
(i) A full statement as to whether any other application to supplement or effectuate the applicant’s proposals must be or is to be filed by the applicant, any of the applicant’s customers, or any other person, with any other Federal, State, Tribal, or other regulatory body; and if so, the nature and status of each such application.
(j) A table of contents that must list all exhibits and documents filed in compliance with this part, as well as all other documents and exhibits otherwise filed, identifying them by their appropriate titles and alphabetical letter designations. The alphabetical letter designations specified in § 50.7 must be strictly adhered to and extra exhibits submitted at the volition of applicant must be designated in sequence under the letter Z (Z1, Z2, Z3, etc.).
(k) A form of notice suitable for publication in the
§ 50.7 Applications: exhibits.
Each exhibit must contain a title page showing the applicant’s name, title of the exhibit, the proper letter designation of the exhibit, and, if 10 or more pages, a table of contents, citing by page, section number or subdivision, the component elements or matters contained in the exhibit.
(a) Exhibit A—Articles of incorporation and bylaws. If the applicant is not an individual, a conformed copy of its articles of incorporation and bylaws, or other similar documents.
(b) Exhibit B—State authorization. For each State where the applicant is authorized to do business, a statement showing the date of authorization, the scope of the business the applicant is authorized to carry on and all limitations, if any, including expiration dates and renewal obligations. A conformed copy of applicant’s authorization to do business in each State affected must be supplied upon request.
(c) Exhibit C—Company officials. A list of the names and business addresses of the applicant’s officers and directors, or similar officials if the applicant is not a corporation.
(d) Exhibit D—Other pending applications and filings. A list of other applications and filings submitted by the applicant that are pending before the Commission at the time of the filing of an application and that directly and significantly affect the proposed project, including an explanation of any material effect the grant or denial of those other applications and filings will have on the application and of any material effect the grant or denial of the application will have on those other applications and filings.
(e) Exhibit E—Maps of general location of facilities. The general location map required under § 50.5(c) must be provided as Exhibit E. Detailed maps required by other exhibits must be filed in those exhibits, in a format determined during the pre-filing process in § 50.5.
(f) Exhibit F—Environmental report. An environmental report as specified in §§ 380.3 and 380.16 of this chapter. The applicant must submit all appropriate revisions to Exhibit F whenever route or site changes are filed. These revisions must identify the locations by mile post and describe all other specific differences resulting from the route or site changes, and should not simply provide revised totals for the resources affected. The format of the environmental report filing will be determined during the pre-filing process required under § 50.5.
(g) Exhibit G—Engineering data.
(1) A detailed project description including:
(i) Name and destination of the project;
(ii) Design voltage rating (kV);
(iii) Operating voltage rating (kV);
(iv) Normal peak operating current rating;
(v) Line design features for minimizing television and/or radio interference cause by operation of the proposed facilities; and
(vi) Line design features that minimize audible noise during fog/rain caused by operation of the proposed facilities, including comparing expected audible noise levels to the applicable Federal, State, and local requirements.
(2) A conductor, structures, and substations description including:
(i) Conductor size and type;
(ii) Type of structures;
(iii) Height of typical structures;
(iv) An explanation why these structures were selected;
(v) Dimensional drawings of the typical structures to be used in the project; and
(vi) A list of the names of all new (and existing if applicable) substations or switching stations that will be associated with the proposed new transmission line.
(3) The location of the site and right-of-way including:
(i) Miles of right-of-way;
(ii) Miles of circuit;
(iii) Width of the right-of-way;
(iv) A brief description of the area traversed by the proposed transmission line, including a description of the general land uses in the area and the type of terrain crossed by the proposed line;
(4) Assumptions, bases, formulae, and methods used in the development and preparation of the diagrams and accompanying data, and a technical description providing the following information:
(i) Number of circuits, with identification as to whether the circuit is overhead or underground;
(ii) The operating voltage and frequency; and
(iii) Conductor size, type and number of conductors per phase.
(5) If the proposed interconnection is an overhead line, the following additional information also must be provided:
(i) The wind and ice loading design parameters;
(ii) A full description and drawing of a typical supporting structure including strength specifications;
(iii) Structure spacing with typical ruling and maximum spans;
(iv) Conductor (phase) spacing; and
(v) The designed line-to-ground and conductor-side clearances.
(6) If an underground or underwater interconnection is proposed, the following additional information also must be provided:
(i) Burial depth;
(ii) Type of cable and a description of any required supporting equipment, such as insulation medium pressurizing or forced cooling;
(iii) Cathodic protection scheme; and
(iv) Type of dielectric fluid and safeguards used to limit potential spills in waterways.
(7) Technical diagrams that provide clarification of any of the above items should be included.
(8) Any other data or information not previously identified that has been identified as a minimum requirement for the siting of a transmission line in the State in which the facility will be located.
(h) Exhibit H—System analysis data. An analysis evaluating the impact the proposed facilities will have on the existing electric transmission system performance, including:
(1) An analysis of the existing and expected congestion on the electric transmission system.
(2) Power flow cases used to analyze the proposed and future transmission system under anticipated load growth, operating conditions, variations in power import and export levels, and additional transmission facilities required for system reliability. The cases must:
(i) Provide all files to model normal, single contingency, multiple contingency, and special protective systems, including the special protective systems’ automatic switching or load shedding system; and
(ii) State the assumptions, criteria, and guidelines upon which they are based and take into consideration transmission facility loading; first contingency incremental transfer capability (FCITC); normal incremental transfer capability (NITC); system protection; and system stability.
(3) A stability analysis including study assumptions, criteria, and guidelines used in the analysis, including load shedding allowables.
(4) A short circuit analysis for all power flow cases.
(5) A concise analysis to include:
(i) An explanation of how the proposed project will improve system reliability over the long and short term;
(ii) An analysis of how the proposed project will impact long term regional transmission expansion plans;
(iii) An analysis of how the proposed project will impact congestion on the applicant’s entire system; and
(iv) A description of proposed high technology design features.
(6) Detailed single-line diagrams, including existing system facilities identified by name and circuit number, that show system transmission elements, in relation to the project and other principal interconnected system elements, as well as power flow and loss data that represent system operating conditions.
(i) Exhibit I—Project Cost and Financing. (1) A statement of estimated costs of any new construction or modification.
(2) The estimated capital cost and estimated annual operations and maintenance expense of each proposed environmental measure.
(3) A statement and evaluation of the consequences of denial of the transmission line permit application.
(j) Exhibit J—Construction, operation, and management. A concise statement providing arrangements for supervision, management, engineering, accounting, legal, or other similar service to be rendered in connection with the construction or operation of the project, if not to be performed by employees of the applicant, including reference to any existing or contemplated agreements, together with a statement showing any affiliation between the applicant and any parties to the agreements or arrangements.
§ 50.8 Acceptance/rejection of applications.
(a) Applications will be docketed when received and the applicant so advised.
(b) If an application patently fails to comply with applicable statutory requirements or with applicable Commission rules, regulations, and orders for which a waiver has not been granted, the Director may reject the application as provided by § 385.2001(b) of this chapter. This rejection is without prejudice to an applicant’s refiling a complete application. However, an application will not be rejected solely on the basis that the environmental reports are incomplete because the company has not been granted access by affected landowners to perform required surveys.
(c) An application that relates to a proposed project or modification for which a prior application has been filed and rejected, will be docketed as a new application.
§ 50.9 Notice of application.
(a) Notice of each application filed, except when rejected in accordance with § 50.8, will be issued and subsequently published in the
(b) The notice will establish prompt and binding intermediate milestones and ultimate deadlines for the coordination, and review of, and action on Federal authorization decisions relating to, the proposed facilities.
§ 50.10 Interventions.
Notices of applications, as provided by § 50.9, will fix the time within which any person desiring to participate in the proceeding may file a petition to intervene, and within which any interested regulatory agency, as provided by § 385.214 of this chapter, desiring to intervene may file its notice of intervention.
§ 50.11 General conditions applicable to permits.
(a) The following terms and conditions, among others as the Commission will find are required by the public interest, will attach to the issuance of each permit and to the exercise of the rights granted under the permit.
(b) The permit will be void and without force or effect unless accepted in writing by the permittee within 30 days from the date of the order issuing the permit. Provided that, when an applicant files for rehearing of the order in accordance with FPA section 313(a), the acceptance must be filed within 30 days from the issue date of the order of the Commission upon the application for rehearing or within 30 days from the date on which the application may be deemed to have been denied when the Commission has not acted on such application within 30 days after it has been filed. Provided further, that when a petition for review is filed in accordance with the provisions of FPA section 313(b), the acceptance shall be filed within 30 days after final disposition of the judicial review proceedings thus initiated.
(c) Standards of construction and operation. In determining standard practice, the Commission will be guided by the provisions of the American National Standards Institute, Incorporated, the National Electrical Safety Code, and any other codes and standards that are generally accepted by the industry, except as modified by this Commission or by municipal regulators within their jurisdiction. Each electric utility will construct, install, operate, and maintain its plant, structures, equipment, and lines in accordance with these standards, and in a manner to best accommodate the public, and to prevent interference with service furnished by other public or non-public utilities insofar as practical.
(d) Written authorization must be obtained from the Director prior to commencing construction of the facilities or initiating operations. Requests for these authorizations must demonstrate compliance with all terms and conditions of the construction permit.
(e) Any authorized construction or modification must be completed and made available for service by the permitee within a period of time to be specified by the Commission in each order issuing the transmission line construction permit. If facilities are not completed within the specified timeframe, the permittee must file for an extension of time under § 385.2008 of this chapter.
(f) A permittee must file with the Commission, in writing and under oath, an original and four conformed copies, as provided in § 385.2011 of this chapter, of the following:
(1) Within ten days after the bona fide beginning of construction, notice of the date of the beginning; and
(2) Within ten days after authorized facilities have been constructed and placed in service, notice of the date of the completion of construction and commencement of service.
(g) The permit issued to the applicant may be transferred, subject to the approval of the Commission, to a person who agrees to comply with the terms, limitations or conditions contained in the filing and in every subsequent Order issued thereunder. A permit holder seeking to transfer a permit must file with the Secretary a petition for approval of the transfer. The petition must:
(1) State the reasons supporting the transfer;
(2) Show that the transferee is qualified to carry out the provisions of the permit and any Orders issued under the permit;
(3) Be verified by all parties to the proposed transfer;
(4) Be accompanied by a copy of the proposed transfer agreement;
(5) Be accompanied by an affidavit of service of a copy on the parties to the permit proceeding; and
(6) Be accompanied by an affidavit of publication of a notice concerning the petition and service of such notice on all affected landowners that have executed agreements to convey property rights to the transferee and all other persons, municipalities or agencies entitled by law to be given notice of, or be served with a copy of, any application to construct a major electric generation facility.
SUBCHAPTER C—ACCOUNTS, FEDERAL POWER ACT
PART 101—UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR PUBLIC UTILITIES AND LICENSEES SUBJECT TO THE PROVISIONS OF THE FEDERAL POWER ACT
Order 141, 12 FR 8503, Dec. 19, 1947, provides in part as follows: Prescribing a system of accounts for public utilities and licensees under the Federal Power Act. The Federal Power Commission acting pursuant to authority granted by the Federal Power Act, particularly sections 301(a), 304(a), and 309, and paragraph (13) of section 3, section 4(b) thereof, and finding such action necessary and appropriate for carrying out the provisions of said act, hereby adopts the accompanying system of accounts entitled “Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act,” and the rules and regulations contained therein; and It is hereby ordered: (a) That said system of accounts and said rules and regulations contained therein be and the same are hereby prescribed and promulgated as the system of accounts and rules and regulations of the Commission to be kept and observed by public utilities subject to the jurisdiction of the Commission and by licensees holding licenses issued by the Commission, to the extent and in the manner set forth therein; (b) That said system of accounts and rules and regulations therein contained shall, as to all public utilities now subject to the jurisdiction of the Commission and as to all present licensees, become effective on January 1, 1937, and as to public utilities and licensees which may hereafter become subject to the jurisdiction of the Commission, they shall become effective as of the date when such public utility becomes subject to the jurisdiction of the Commission or on the effective date of the license; (c) That a copy of said system of accounts and rules and regulation contained therein be forthwith served upon each public utility subject to the jurisdiction of the Commission, and each licensee or permittee holding a license or permit from the Commission. This system of accounts supersedes the system of accounts prescribed for licensees under the Federal Water Power Act; and Order No. 13, entered November 20, 1922, prescribing said system of accounts, was rescinded effective January 1, 1937. Applicability of system of accounts. This system of accounts is applicable in principle to all licensees subject to the Commission’s accounting requirements under the Federal Power Act, and to all public utilities subject to the provisions of the Federal Power Act. The Commission reserves the right, however, under the provisions of section 301(a) of the Federal Power Act to classify such licensees and public utilities and to prescribe a system of classification of accounts to be kept by and which will be convenient for and meet the requirements of each class. This system of accounts is applicable to public utilities, as defined in this part, and to licensees engaged in the generation and sale of electric energy for ultimate distribution to the public. This system of accounts shall also apply to agencies of the United States engaged in the generation and sale of electric energy for ultimate distribution to the public, so far as may be practicable, in accordance with applicable statutes. In accordance with the requirements of section 3 of the Act (49 Stat. 839; 16 U.S.C. 796(13)), the “classification of investment in road and equipment of steam roads, issue of 1914, Interstate Commerce Commission”, is published and promulgated as a part of the accounting rules and regulations of the Commission, and a copy thereof appears as part 103 of this chapter. Irrespective of any rules and regulations contained in this system of accounts, the cost of original projects licensed under the Act, and also the cost of additions thereto and betterments thereof, shall be determined under the rules and principles as defined and interpreted in said classification of the Interstate Commerce Commission so far as applicable. For application of uniform system of accounts to Class C and D public utilities and licensees, see part 104 of this chapter. For statements and reports, see part 141 of this chapter.
When used in this system of accounts:
1. Accounts means the accounts prescribed in this system of accounts.
2. Actually issued, as applied to securities issued or assumed by the utility, means those which have been sold to bona fide purchasers for a valuable consideration, those issued as dividends on stock, and those which have been issued in accordance with contractual requirements direct to trustees of sinking funds.
3. Actually outstanding, as applied to securities issued or assumed by the utility, means those which have been actually issued and are neither retired nor held by or for the utility; provided, however, that securities held by trustees shall be considered as actually outstanding.
4. Amortization means the gradual extinguishment of an amount in an account by distributing such amount over a fixed period, over the life of the asset or liability to which it applies, or over the period during which it is anticipated the benefit will be realized.
5. A. Associated (affiliated) companies means companies or persons that directly, or indirectly through one or more intermediaries, control, or are controlled by, or are under common control with, the accounting company.
B. Control (including the terms controlling, controlled by, and under common control with) means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a company, whether such power is exercised through one or more intermediary companies, or alone, or in conjunction with, or pursuant to an agreement, and whether such power is established through a majority or minority ownership or voting of securities, common directors, officers, or stockholders, voting trusts, holding trusts, associated companies, contract or any other direct or indirect means.
6. Book cost means the amount at which property is recorded in these accounts without deduction of related provisions for accrued depreciation, amortization, or for other purposes.
7. Commission, means the Federal Energy Regulatory Commission.
8. Continuing Plant Inventory Record means company plant records for retirement units and mass property that provide, as either a single record, or in separate records readily obtainable by references made in a single record, the following information:
A. For each retirement unit:
(1) The name or description of the unit, or both;
(2) The location of the unit;
(3) The date the unit was placed in service;
(4) The cost of the unit as set forth in Plant Instructions 2 and 3 of this part; and
(5) The plant control account to which the cost of the unit is charged; and
B. For each category of mass property:
(1) A general description of the property and quantity;
(2) The quantity placed in service by vintage year;
(3) The average cost as set forth in Plant Instructions 2 and 3 of this part; and
(4) The plant control account to which the costs are charged.
9. Cost means the amount of money actually paid for property or services. When the consideration given is other than cash in a purchase and sale transaction, as distinguished from a transaction involving the issuance of common stock in a merger or a pooling of interest, the value of such consideration shall be determined on a cash basis.
10. Cost of removal means the cost of demolishing, dismantling, tearing down or otherwise removing electric plant, including the cost of transportation and handling incidental thereto. It does not include the cost of removal activities associated with asset retirement obligations that are capitalized as part of the tangible long-lived assets that give rise to the obligation. (See General Instruction 25).
11. Debt expense means all expenses in connection with the issuance and initial sale of evidences of debt, such as fees for drafting mortgages and trust deeds; fees and taxes for issuing or recording evidences of debt; cost of engraving and printing bonds and certificates of indebtedness; fees paid trustees; specific costs of obtaining governmental authority; fees for legal services; fees and commissions paid underwriters, brokers, and salesmen for marketing such evidences of debt; fees and expenses of listing on exchanges; and other like costs.
12. Depreciation, as applied to depreciable electric plant, means the loss in service value not restored by current maintenance, incurred in connection with the consumption or prospective retirement of electric plant in the course of service from causes which are known to be in current operation and against which the utility is not protected by insurance. Among the causes to be given consideration are wear and tear, decay, action of the elements, inadequacy, obsolescence, changes in the art, changes in demand and requirements of public authorities.
13. Discount, as applied to the securities issued or assumed by the utility, means the excess of the par (stated value of no-par stocks) or face value of the securities plus interest or dividends accrued at the date of the sale over the cash value of the consideration received from their sale.
14. Investment advances means advances, represented by notes or by book accounts only, with respect to which it is mutually agreed or intended between the creditor and debtor that they shall be settled by the issuance of securities or shall not be subject to current settlement.
15. Lease, capital means a lease of property used in utility or nonutility operations, which meets one or more of the criteria stated in General Instruction 19.
16. Lease, operating means a lease of property used in utility or nonutility operations, which does not meet any of the criteria stated in General Instruction 19.
17. Licensee means any person, or State, licensed under the provisions of the Federal Power Act and subject to the Commission’s accounting requirements under the terms of the license.
18. Minor items of property means the associated parts or items of which retirement units are composed.
19. Net salvage value means the salvage value of property retired less the cost of removal.
20. Nominally issued, as applied to securities issued or assumed by the utility, means those which have been signed, certified, or otherwise executed, and placed with the proper officer for sale and delivery, or pledged, or otherwise placed in some special fund of the utility, but which have not been sold, or issued direct to trustees of sinking funds in accordance with contractual requirements.
21. Nominally outstanding, as applied to securities issued or assumed by the utility, means those which, after being actually issued, have been reacquired by or for the utility under circumstances which require them to be considered as held alive and not retired, provided, however, that securities held by trustees shall be considered as actually outstanding.
22. Nonproject property means the electric plant of a licensee which is not a part of the project property subject to a license issued by the Commission.
23. Original cost, as applied to electric plant, means the cost of such property to the person first devoting it to public service.
24. Person means an individual, a corporation, a partnership, an association, a joint stock company, a business trust, or any organized group of persons, whether incorporated or not, or any receiver or trustee.
25. Premium, as applied to securities issued or assumed by the utility, means the excess of the cash value of the consideration received from their sale over the sum of their par (stated value of no-par stocks) or face value and interest or dividends accrued at the date of sale.
26. Project means complete unit of improvement or development, consisting of a power house, all water conduits, all dams and appurtenant works and structures (including navigation structures) which are a part of said unit, and all storage, diverting, or forebay reservoirs directly connected therewith, the primary line or lines transmitting power therefrom to the point of junction with the distribution system or with the interconnected primary transmission system, all miscellaneous structures used and useful in connection with said unit or any part thereof, and all water rights, rights of way, ditches, dams, reservoirs, lands, or interest in lands the use and occupancy of which are necessary or appropriate in the maintenance and operation of such unit.
27. Project property means the property described in and subject to a license issued by the Commission.
28. Property retired, as applied to electric plant, means property which has been removed, sold, abandoned, destroyed, or which for any cause has been withdrawn from service.
29. Public utility means any person who owns or operates facilities subject to the jurisdiction of the Commission under the Federal Power Act. (See section 201(e) of said act.)
30. Regional market means an organized energy market operated by a public utility, whether directly or through a contractual relationship with another entity.
31. Regulatory Assets and Liabilities are assets and liabilities that result from rate actions of regulatory agencies. Regulatory assets and liabilities arise from specific revenues, expenses, gains, or losses that would have been included in net income determination in one period under the general requirements of the Uniform System of Accounts but for it being probable:
A. that such items will be included in a different period(s) for purposes of developing the rates the utility is authorized to charge for its utility services; or
B. in the case of regulatory liabilities, that refunds to customers, not provided for in other accounts, will be required.
32. A. Replacing or replacement, when not otherwise indicated in the context, means the construction or installation of electric plant in place of property retired, together with the removal of the property retired.
B. Research, Development, and Demonstration (RD&D) in the case of Major utilities means expenditures incurred by public utilities and licensees either directly or through another person or organization (such as research institute, industry association, foundation, university, engineering company or similar contractor) in pursuing research, development, and demonstration activities including experiment, design, installation, construction, or operation. This definition includes expenditures for the implementation or development of new and/or existing concepts until technically feasible and commercially feasible operations are verified. Such research, development, and demonstration costs should be reasonably related to the existing or future utility business, broadly defined, of the public utility or licensee or in the environment in which it operates or expects to operate. The term includes, but is not limited to: All such costs incidental to the design, development or implementation of an experimental facility, a plant process, a product, a formula, an invention, a system or similar items, and the improvement of already existing items of a like nature; amounts expended in connection with the proposed development and/or proposed delivery of alternate sources of electricity; and the costs of obtaining its own patent, such as attorney’s fees expended in making and perfecting a patent application. The term includes preliminary investigations and detailed planning of specific projects for securing for customers non-conventional electric power supplies that rely on technology that has not been verified previously to be feasible. The term does not include expenditures for efficiency surveys; studies of management, management techniques and organization; consumer surveys, advertising, promotions, or items of a like nature.
33. Retained Earnings (formerly earned surplus) means the accumulated net income of the utility less distribution to stockholders and transfers to other capital accounts.
34. Retirement units means those items of electric plant which, when retired, with or without replacement, are accounted for by crediting the book cost thereof to the electric plant account in which included.
35. Salvage value means the amount received for property retired, less any expenses incurred in connection with the sale or in preparing the property for sale; or, if retained, the amount at which the material recoverable is chargeable to materials and supplies, or other appropriate account.
36. Service life means the time between the date electric plant is includible in electric plant in service, or electric plant leased to others, and the date of its retirement. If depreciation is accounted for on a production basis rather than on a time basis, then service life should be measured in terms of the appropriate unit of production.
37. Service value means the difference between original cost and net salvage value of electric plant.
38. State means a State admitted to the Union, the District of Columbia, and any organized Territory of the United States.
39. Subsidiary Company in the case of Major utilities means a company which is controlled by the utility through ownership of voting stock. (See Definitions item 5B, Control). A corporate joint venture in which a corporation is owned by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group is a subsidiary company for the purposes of this system of accounts.
40. Utility, as used herein and when not otherwise indicated in the context, means any public utility or licensee to which this system of accounts is applicable.
1. Classification of utilities.
A. For purpose of applying the system of accounts prescribed by the Commission, electric utilities and licensees are divided into classes, as follows:
(1) Major. Utilities and licensees that had, in each of the last three consecutive years, sales or transmission service that exceeded any one or more of the following:
(a) One million megawatt-hours of total sales;
(b) 100 megawatt-hours of sales for resale;
(c) 500 megawatt-hours of power exchanges delivered; or
(d) 500 megawatt-hours of wheeling for others (deliveries plus losses).
(2) Nonmajor. Utilities and licensees that are not classified as Major (as defined above), and had total sales in each of the last three consecutive years of 10,000 megawatt-hours or more.
(3) Nonoperating. Utilities and licensees formerly designated as Major or Nonmajor that have ceased operation but continue to collect amounts pursuant to a Commission-accepted tariff or rate schedule, or a Commission order.
B. This system applies to Major, Nonmajor, and Nonoperating utilities and licensees. Provisions have been incorporated into this system for those entities which, prior to January 1, 1984, were applying the Commission’s Uniform System of Accounts Prescribed for Public Utilities and Licensees subject to the Provisions of the Federal Power Act (Class C and Class D) [part 104 of this chapter, now revoked]. The notations (Nonmajor) and (Major) have been used to indicate those instructions and accounts from previous systems and classifications, which by definition, are not interchangeable without causing a loss of detail for the Major (previously Class A and Class B) or an increase in detail burden on the Nonmajor (previously Class C and Class D).
C. The class to which any utility or licensee belongs will originally be determined by its annual megawatt hours in each of the last three consecutive years, or in the case of a newly established entity, the projected data shall be the basis. Subsequent changes in classification shall be made as necessary when the megawatt-hours for each of the three immediately preceding years shall exceed the upper limit, or be less than the lower limit of the classification previously applicable to the utility.
D. Any utility may, at its option, adopt the system of accounts prescribed by the Commission for any larger class of utilities.
2. Records.
A. Each utility shall keep its books of account, and all other books, records, and memoranda which support the entries in such books of account so as to be able to furnish readily full information as to any item included in any account. Each entry shall be supported by such detailed information as will permit ready identification, analysis, and verification of all facts relevant thereto.
B. The books and records referred to herein include not only accounting records in a limited technical sense, but all other records, such as minute books, stock books, reports, correspondence, memoranda, etc., which may be useful in developing the history of or facts regarding any transaction.
C. No utility shall destroy any such books or records unless the destruction thereof is permitted by rules and regulations of the Commission.
D. In addition to prescribed accounts, clearing accounts, temporary or experimental accounts, and subdivisions of any accounts, may be kept, provided the integrity of the prescribed accounts is not impaired.
E. All amounts included in the accounts prescribed herein for electric plant and operating expenses shall be just and reasonable and any payments or accruals by the utility in excess of just and reasonable charges shall be included in account 426.5, Other Deductions.
F. The arrangement or sequence of the accounts prescribed herein shall not be controlling as to the arrangement or sequence in report forms which may be prescribed by the Commission.
3. Numbering System.
A. The account numbering plan used herein consists of a system of three-digit whole numbers as follows:
B. In certain instances, numbers have been skipped in order to allow for possible later expansion or to permit better coordination with the numbering system for other utility departments.
C. The numbers prefixed to account titles are to be considered as parts of the titles. Each utility, however, may adopt for its own purposes a different system of account numbers (see also general instruction 2D) provided that the numbers herein prescribed shall appear in the descriptive headings of the ledger accounts and in the various sources of original entry; however, if a utility uses a different group of account numbers and it is not practicable to show the prescribed account numbers in the various sources of original entry, such reference to the prescribed account numbers may be omitted from the various sources of original entry. Moreover, each utility using different account numbers for its own purposes shall keep readily available a list of such account numbers which it uses and a reconciliation of such account numbers with the account numbers provided herein. It is intended that the utility’s records shall be so kept as to permit ready analysis by prescribed accounts (by direct reference to sources of original entry to the extent practicable) and to permit preparation of financial and operating statements directly from such records at the end of each accounting period according to the prescribed accounts.
4. Accounting Period.
Each utility shall keep its books on a monthly basis so that for each month all transactions applicable thereto, as nearly as may be ascertained, shall be entered in the books of the utility. Amounts applicable or assignable to specific utility departments shall be so segregated monthly. Each utility shall close its books at the end of each calendar year unless otherwise authorized by the Commission.
5. Submittal of Questions.
To maintain uniformity of accounting, utilities shall submit questions of doubtful interpretation to the Commission for consideration and decision.
6. Item Lists.
Lists of items appearing in the texts of the accounts or elsewhere herein are for the purpose of more clearly indicating the application of the prescribed accounting. The lists are intended to be representative, but not exhaustive. The appearance of an item in a list warrants the inclusion of the item in the account mentioned only when the text of the account also indicates inclusion inasmuch as the same item frequently appears in more than one list. The proper entry in each instance must be determined by the texts of the accounts.
7. Extraordinary Items.
It is the intent that net income shall reflect all items of profit and loss during the period with the exception of prior period adjustments as described in paragraph 7.1 and long-term debt as described in paragraph 17 below. Those items related to the effects of events and transactions which have occurred during the current period and which are of unusual nature and infrequent occurrence shall be considered extraordinary items. Accordingly, they will be events and transactions of significant effect which are abnormal and significantly different from the ordinary and typical activities of the company, and which would not reasonably be expected to recur in the forseeable future. (In determining significance, items should be considered individually and not in the aggregate. However, the effects of a series of related transactions arising from a single specific and identifiable event or plan of action should be considered in the aggregate. To be considered as extraordinary under the above guidelines, an item should be more than approximately 5 percent of income, computed before extraordinary items. Commission approval must be obtained to treat an item of less than 5 percent, as extraordinary. (See accounts 434 and 435.)
7.1 Prior period items.
A. Items of profit and loss related to the following shall be accounted for as prior period adjustments and excluded from the determination of net income for the current year:
(1) Correction of an error in the financial statements of a prior year.
(2) Adjustments that result from realization of income tax benefits of pre-acquisition operating loss carryforwards of purchased subsidiaries.
B. All other items of profit and loss recognized during the year shall be included in the determination of net income for that year.
8. Unaudited Items (Major Utility).
Whenever a financial statement is required by the Commission, if it is known that a transaction has occurred which affects the accounts but the amount involved in the transaction and its effect upon the accounts cannot be determined with absolute accuracy, the amount shall be estimated and such estimated amount included in the proper accounts. The utility is not required to anticipate minor items which would not appreciably affect the accounts.
9. Distribution of Pay and Expenses of Employees.
The charges to electric plant, operating expense and other accounts for services and expenses of employees engaged in activities chargeable to various accounts, such as construction, maintenance, and operations, shall be based upon the actual time engaged in the respective classes of work, or in case that method is impracticable, upon the basis of a study of the time actually engaged during a representative period.
10. Payroll Distribution.
Underlying accounting data shall be maintained so that the distribution of the cost of labor charged direct to the various accounts will be readily available. Such underlying data shall permit a reasonably accurate distribution to be made of the cost of labor charged initially to clearing accounts so that the total labor cost may be classified among construction, cost of removal, electric operating functions (steam generation, nuclear generation, hydraulic generation, transmission, distribution, etc.) and nonutility operations.
11. Accounting to be on Accrual Basis.
A. The utility is required to keep its accounts on the accrual basis. This requires the inclusion in its accounts of all known transactions of appreciable amount which affect the accounts. If bills covering such transactions have not been received or rendered, the amounts shall be estimated and appropriate adjustments made when the bills are received.
B. When payments are made in advance for items such as insurance, rents, taxes or interest the amount applicable to future periods shall be charged to account 165, Prepayments, and spread over the periods to which applicable by credits to account 165, and charges to the accounts appropriate for the expenditure.
12. Records for Each Plant (Major Utility).
Separate records shall be maintained by electric plant accounts of the book cost of each plant owned, including additions by the utility to plant leased from others, and of the cost of operating and maintaining each plant owned or operated. The term plant as here used means each generating station and each transmission line or appropriate group of transmission lines.
13. Accounting for Other Departments.
If the utility also operates other utility departments, such as gas, water, etc., it shall keep such accounts for the other departments as may be prescribed by proper authority and in the absence of prescribed accounts, it shall keep such accounts as are proper or necessary to reflect the results of operating each such department. It is not intended that proprietary and similar accounts which apply to the utility as a whole shall be departmentalized.
14. Transactions With Associated Companies (Major Utility).
Each utility shall keep its accounts and records so as to be able to furnish accurately and expeditiously statements of all transactions with associated companies. The statements may be required to show the general nature of the transactions, the amounts involved therein and the amounts included in each account prescribed herein with respect to such transactions. Transactions with associated companies shall be recorded in the appropriate accounts for transactions of the same nature. Nothing herein contained, however, shall be construed as restraining the utility from subdividing accounts for the purpose of recording separately transactions with associated companies.
15. Contingent Assets and Liabilities (Major Utility).
Contingent assets represent a possible source of value to the utility contingent upon the fulfillment of conditions regarded as uncertain. Contingent liabilities include items which may under certain conditions become obligations of the utility but which are neither direct nor assumed liabilities at the date of the balance sheet. The utility shall be prepared to give a complete statement of significant contingent assets and liabilities (including cumulative dividends on preference stock) in its annual report and at such other times as may be requested by the Commission.
16. Separate Accounts or Records for Each Licensed Project.
The accounts or records of each licensee shall be so kept as to show for each project (including pumped storage) under license;
(a) The actual legitimate original cost of the project, including the original cost (or fair value, as determined under section 23 of the Federal Power Act) of the original project, the original cost of additions thereto and betterments thereof and credits for property retired from service, as determined under the Commission’s regulations;
(b) The charges for operation and maintenance of the project property directly assignable to the project;
(c) The credits and debits to the depreciation and amortization accounts, and the balances in such accounts;
(d) The credits and debits to operating revenue, income, and retained earnings accounts that can be identified with and directly assigned to the project.
The purpose of this instruction is to insure that accounts or records are currently maintained by each licensee from which reports may be made to the Commission for use in determining the net investment in each licensed project. The instruction covers only the debit and credit items appearing in the licensee’s accounts which may be identified with and assigned directly to any licensed project. In the determination of the net investment as defined in section 3 of the Federal Power Act, allocations of items affecting the net investment may be required where direct assignment is not practicable.
17. Long-Term Debt: Premium, Discount and Expense, and Gain or Loss on Reacquisition.
A. Premium, discount and expense. A separate premium, discount and expense account shall be maintained for each class and series of long-term debt (including receivers’ certificates) is- sued or assumed by the utility. The premium will be recorded in account 225, Unamortized Premium on Long-Term Debt, the discount will be recorded in account 226, Unamortized Discount on Long-Term Debt—Debit, and the expense of issuance shall be recorded in account 181, Unamortized Debt Expense.
The premium, discount and expense shall be amortized over the life of the respective issues under a plan which will distribute the amounts equitably over the life of the securities. The amortization shall be on a monthly basis, and amounts thereof relating to discount and expense shall be charged to account 428, Amortization of Debt Discount and Expense. The amounts relating to premium shall be credited to account 429, Amortization of Premium on Debt—Credit.
B. Reacquisition, without refunding. When long-term debt is reacquired or redeemed without being converted into another form of long-term debt and when the transaction is not in connection with a refunding operation (primarily redemptions for sinking fund purposes), the difference between the amount paid upon reacquisition and the face value; plus any un- amortized premium less any related unamortized debt expense and reacquisition costs; or less any unamortized discount, related debt expense and reacquisition costs applicable to the debt redeemed, retired and canceled, shall be included in account 189, Unamortized Loss on Reacquired Debt, or account 257, Unamortized Gain on Reacquired Debt, as appropriate. The utility shall amortize the recorded amounts equally on a monthly basis over the remaining life of the respective security issues (old original debt). The amounts so amortized shall be charged to account 428.1, Amortization of Loss on Reacquired Debt, or credited to account 429.1, Amortization of Gain on Reacquired Debt—Credit, as appropriate.
C. Reacquisition, with refunding. When the redemption of one issue or series of bonds or other long-term obligations is financed by another issue or series before the maturity date of the first issue, the difference between the amount paid upon refunding and the face value; plus any unamortized premium less related debt expense or less any unamortized discount and related debt expense, applicable to the debt refunded, shall be included in account 189, Unamortized Loss on Reacquired Debt, or account 257, Unamortized Gain on Reacquired Debt, as appropriate. The utility may elect to account for such amounts as follows:
(1) Write them off immediately when the amounts are insignificant.
(2) Amortize them by equal monthly amounts over the remainder of the original life of the issue retired, or
(3) Amortize them by equal monthly amounts over the life of the new issue.
Once an election is made, it shall be applied on a consistent basis. The amounts in (1), (2) or (3) above shall be charged to account 428.1. Amortization of Loss on Reacquired Debt, or credited to account 429.1, Amortization of Gain on Reacquired Debt—Credit, as appropriate.
D. Under methods (2) and (3) above, the increase or reduction in current income taxes resulting from the reacquisition should be apportioned over the remainder of the original life of the issue retired or over the life of the new issue, as appropriate, as directed more specifically in paragraphs E and F below.
E. When the utility recognizes the loss in the year of reacquisition as a tax deduction, account 410.1, Provision for Deferred Income Taxes, Utility Operating Income, shall be debited and account 283, Accumulated Deferred Income Taxes—Other, shall be credited with the amount of the related tax effect, such amount to be allocated to the periods affected in accordance with the provisions of account 283.
F. When the utility chooses to recognize the gain in the year of reacquisition as a taxable gain, account 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, shall be credited and account 190, Accumulated Deferred Income Taxes, shall be debited with the amount of the related tax effect, such amount to be allocated to the periods affected in accordance with the provisions of account 190.
G. When the utility chooses to use the optional privilege of deferring the tax on the gain attributable to the reacquisition of debt by reducing the depreciable basis of utility property for tax purposes, pursuant to section 108 of the Internal Revenue Code, the related tax effects shall be deferred as the income is recognized for accounting purposes, and the deferred amounts shall be amortized over the life of the associated property on a vintage year basis. Account 410.1, Provision for Deferred Income Taxes, Utility Operating Income, shall be debited, and account 282, Accumulated Deferred Income Taxes—Other Property shall be credited with an amount equal to the estimated income tax effect applicable to the portion of the income, attributable to reacquired debt, recognized for accounting purposes during the period. Account 282 shall be debited and account 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, shall be credited with an amount equal to the estimated income tax effects, during the life of the property, attributable to the reduction in the depreciable basis for tax purposes.
H. The tax effects relating to gain or loss shall be allocated as above to utility operations except in cases where a portion of the debt reacquired is directly applicable to nonutility operations. In that event, the related portion of the tax effects shall be allocated to nonutility operations. Where it can be established that reacquired debt is generally applicable to both utility and nonutility operations, the tax effects shall be allocated between utility and nonutility operations based on the ratio of net investment in utility plant to net investment in nonutility plant.
I. Premium, discount, or expense on debt shall not be included as an element in the cost of construction or acquisition of property (tangible or intangible), except under the provisions of account 432, Allowance for Borrowed Funds Used During Construction—Credit.
J. Alternate method. Where a regulatory authority or a group of regulatory authorities having prime rate jurisdiction over the utility specifically disallows the rate principle of amortizing gains or losses on reacquisition of long-term debt without refunding, and does not apply the gain or loss to reduce interest charges in computing the allowed rate of return for rate purposes, then the following alternate method may be used to account for gains or losses relating to reacquisition of long-term debt, with or without refunding.
(1) The difference between the amount paid upon reacquisition of any long-term debt and the face value, adjusted for unamortized discount, expenses or premium, as the case may be, applicable to the debt redeemed shall be recognized currently in income and recorded in account 421, Miscellaneous Nonoperating Income, or account 426.5, Other Deductions.
(2) When this alternate method of accounting is used, the utility shall include a footnote to each financial statement, prepared for public use, explaining why this method is being used along with the treatment given for ratemaking purposes.
18. Comprehensive Interperiod In- come Tax Allocation.
A. Where there are timing differences between the periods in which transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income, the income tax effects of such transactions are to be recognized in the periods in which the differences between book accounting income and taxable income arise and in the periods in which the differences reverse using the deferred tax method. In general, comprehensive interperiod tax allocation should be followed whenever transactions enter into the determination of pretax accounting income for the period even though some transactions may affect the determination of taxes payable in a different period, as further qualified below.
B. Utilities are not required to utilize comprehensive interperiod income tax allocation until the deferred income taxes are included as an expense in the rate level by the regulatory authority having rate jurisdiction over the utility. Where comprehensive interperiod tax allocation accounting is not practiced the utility shall include as a note to each financial statement, prepared for public use, a footnote explanation setting forth the utility’s accounting policies with respect to interperiod tax allocation and describing the treatment for ratemaking purposes of the tax timing differences by regulatory authorities having rate jurisdiction.
C. Should the utility be subject to more than one agency having rate jurisdiction, its accounts shall appropriately reflect the ratemaking treatment (deferral or flow through) of each jurisdiction.
D. Once comprehensive interperiod tax allocation has been initiated either in whole or in part it shall be practiced on a consistent basis and shall not be changed or discontinued without prior Commission approval.
E. Tax effects deferred currently will be recorded as deferred debits or deferred credits in accounts 190, Accumulated Deferred Income Taxes, 281, Accumulated Deferred Income Tax- es—Accelerated Amortization Property, 282, Accumulated Deferred Income Taxes—Other Property, and 283, Accumulated Deferred Income Taxes—Other, as appropriate. The resulting amounts recorded in these accounts shall be disposed of as prescribed in this system of accounts or as otherwise authorized by the Commission.
19. Criteria for classifying leases.
A. If at its inception a lease meets one or more of the following criteria, the lease shall be classified as a capital lease. Otherwise, it shall be classified as an operating lease.
(1) The lease transfers ownership of the property to the lessee by the end of the lease term
(2) The lease contains a bargain purchase option.
(3) The lease term is equal to 75 percent or more of the estimated economic life of the leased property. However, if the beginning of the lease term falls within the last 25 percent of the total estimated economic life of the leased property, including earlier years of use, this criterion shall not be used for purposes of classifying the lease.
(4) The present value at the beginning of the lease term of the minimum lease payments, excluding that portion of the payments representing executory costs such as insurance, maintenance, and taxes to be paid by the lessor, including any profit thereon, equals or exceeds 90 percent of the excess of the fair value of the leased property to the lessor at the inception of the lease over any related investment tax credit retained by the lessor and expected to be realized by the lessor. However, if the beginning of the lease term falls within the last 25 percent of the total estimated economic life of the leased property, including earlier years of use, this criterion shall not be used for purposes of classifying the lease. The lessee utility shall compute the present value of the minimum lease payments using its incremental borrowing rate, unless (A) it is practicable for the utility to learn the implicit rate computed by the lessor, and (B) the implicit rate computed by the lessor is less than the lessee’s incremental borrowing rate. If both of those conditions are met, the lessee shall use the implicit rate.
B. If at any time the lessee and lessor agree to change the provisions of the lease, other than by renewing the lease or extending its term, in a manner that would have resulted in a different classification of the lease under the criteria in paragraph A had the changed terms been in effect at the inception of the lease, the revised agreement shall be considered as a new agreement over its term, and the criteria in paragraph A shall be applied for purposes of classifying the new lease. Likewise, any action that extends the lease beyond the expiration of the existing lease term, such as the exercise of a lease renewal option other than those already included in the lease term, shall be considered as a new agreement and shall be classified according to the above provisions. Changes in estimates (for example, changes in estimates of the economic life or of the residual value of the leased property) or changes in circumstances (for example, default by the lessee) shall not give rise to a new classification of a lease for accounting purposes.
20. Accounting for leases.
A. All leases shall be classified as either capital or operating leases. The accounting for capitalized leases is effective January 1, 1984, except for the retroactive classification of certain leases which, in accordance with FASB No. 71, will not be required to be capitalized until after a three year transition period. For the purpose of reporting to the FERC, the transition period shall be deemed to end December 31, 1986.
B. The utility shall record a capital lease as an asset in account 101.1, Property under Capital Leases, Account 120.6, Nuclear Fuel under Capital Leases, or account 121, Nonutility Property, as appropriate, and an obligation in account 227, Obligations under Capital Leases—Noncurrent, or account 243, Obligations under Capital Leases—Current, at an amount equal to the present value at the beginning of the lease term of minimum lease payments during the lease term, excluding that portion of the payments representing executory costs such as insurance, maintenance, and taxes to be paid by the lessor, together with any profit thereon. However, if the amount so determined exceeds the fair value of the leased property at the inception of the lease, the amount recorded as the asset and obligation shall be the fair value.
C. The utility, as a lessee, shall recognize an asset retirement obligation (See General Instruction 25) arising from the plant under a capital lease unless the obligation is recorded as an asset and liability under a capital lease. The utility shall record the asset retirement cost by debiting account 101.1, Property under capital leases, or account 120.6, Nuclear fuel under capital leases, or account 121, Nonutility property, as appropriate, and crediting the liability for the asset retirement obligation in account 230, Asset retirement obligations. Asset retirement costs recorded in account 101.1, account 120.6, or account 121 shall be amortized by charging rent expense (See Operating Expense Instruction 3), or account 518, Nuclear fuel expense (Major only), or account 421, Miscellaneous nonoperating income, as appropriate, and crediting a separate subaccount of the account in which the asset retirement costs are recorded. Charges for the periodic accretion of the liability in account 230, Asset retirement obligations, shall be recorded by a charge to account 411.10, Accretion expense, for electric utility plant, and account 421, Miscellaneous nonoperating income, for nonutility plant and a credit to account 230, Asset retirement obligations.
D. Rental payments on all leases shall be charged to rent expense, fuel expense, construction work in progress, or other appropriate accounts as they become payable.
E. For a capital lease, for each period during the lease term, the amounts recorded for the asset and obligation shall be reduced by an amount equal to the portion of each lease payment that would have been allocated to the reduction of the obligation, if the payment had been treated as a payment on an installment obligation (liability) and allocated between interest expense and a reduction of the obligation so as to produce a constant periodic rate of interest on the remaining balance.
21. Allowances.
A. Title IV of the Clean Air Act Amendments of 1990, Public Law No. 101–549, 104 Stat. 2399, 2584, provides for the issuance of allowances as a means to limit the emissions of certain airborne pollutants by various entities, including public utilities. Public utilities owning allowances, other than those acquired for speculative purposes, shall account for such allowances at cost in Account 158.1, Allowance Inventory, or Account 158.2, Allowances Withheld, as appropriate. Allowances acquired for speculative purposes and identified as such in contemporaneous records at the time of purchase shall be accounted for in Account 124, Other Investments.
B. When purchased allowances become eligible for use in different years, and the allocation of the purchase cost cannot be determined by fair value, the purchase cost allocated to allowances of each vintage shall be determined through use of a present-value based measurement. The interest rate used in the present-value measurement shall be the utility’s incremental borrowing rate, in the month in which the allowances are acquired, for a loan with a term similar to the period that it will hold the allowances and in an amount equal to the purchase price.
C. The underlying records supporting Account 158.1 and Account 158.2 shall be maintained in sufficient detail so as to provide the number of allowances and the related cost by vintage year.
D. Issuances from inventory from inventory included in Account 158.1 and Account 158.2 shall be accounted for on a vintage basis using a monthly weighted-average method of cost determination. The cost of eligible allowances not used in the current year shall be transferred to the vintage for the immediately following year.
E. Account 158.1 shall be credited and Account 509, Allowances, debited so that the cost of the allowances to be remitted for the year is charged to expense monthly based on each month’s emissions. This may, in certain circumstances, require allocation of the cost of an allowance between months on a fractional basis.
F. In any period in which actual emissions exceed the amount allowable based on eligible allowances owned, the utility shall estimate the cost to acquire the additional allowances needed and charge Account 158.1 with the estimated cost. This estimated cost of future allowance acquisitions shall be credited to Account 158.1 and charged to Account 509 in the same accounting period as the related charge to Account 158.1. Should the actual cost of these allowances differ from the estimated cost, the differences shall be recognized in the then-current period’s inventory issuance cost.
G. Any penalties assessed by the Environmental Protection Agency for the emission of excess pollutants shall be charged to Account 426.3, Penalties.
H. Gains on dispositions of allowances, other than allowances held for speculative purposes, shall be accounted for as follows. First, if there is uncertainty as to the regulatory treatment, the gain shall be deferred in Account 254, Other Regulatory Liabilities, pending resolution of the uncertainty. Second, if there is certainty as to the existence of a regulatory liability, the gain will be credited to Account 254, with subsequent recognition in income when reductions in charges to customers occur or the liability is otherwise satisfied. Third, all other gains will be credited to Account 411.8, Gains from Disposition of Allowances. Losses on disposition of allowances, other than allowances held for speculative purposes, shall be accounted for as follows. Losses that qualify as regulatory assets shall be charged directly to Account 182.3, Other Regulatory Assets. All other losses shall be charged to Account 411.9, Losses from Disposition of Allowances. (See Definition No. 30.) Gains or losses on disposition of allowances held for speculative purposes shall be recognized in Account 421, Miscellaneous Nonoperating Income, or Account 426.5, Other Deductions, as appropriate.
22. Depreciation Accounting.
A. Method. Utilities must use a method of depreciation that allocates in a systematic and rational manner the service value of depreciable property over the service life of the property.
B. Service lives. Estimated useful service lives of depreciable property must be supported by engineering, economic, or other depreciation studies.
C. Rate. Utilities must use percentage rates of depreciation that are based on a method of depreciation that allocates in a systematic and rational manner the service value of depreciable property to the service life of the property. Where composite depreciation rates are used, they should be based on the weighted average estimated useful service lives of the depreciable property comprising the composite group.
23. Accounting for other comprehensive income.
A. Utilities shall record items of other comprehensive income in account 219, Accumulated other comprehensive income. Amounts included in this account shall be maintained by each category of other comprehensive income. Examples of categories of other comprehensive income include, foreign currency items, minimum pension liability adjustments, unrealized gains and losses on available-for-sale type securities and cash flow hedge amounts. Supporting records shall be maintained for account 219 so that the company can readily identify the cumulative amount of other comprehensive income for each item included in this account.
B. When an item of other comprehensive income enters into the determination of net income in the current or subsequent periods, a reclassification adjustment shall be recorded in account 219 to avoid double counting of that amount.
C. When it is probable that an item of other comprehensive income will be included in the development of cost-of-service rates in subsequent periods, that amount of unrealized losses or gains will be recorded in Accounts 182.3 or 254 as appropriate.
24. Accounting for derivative instruments and hedging activities.
A. Utilities shall recognize derivative instruments as either assets or liabilities in the financial statements and measure those instruments at fair value, except those falling within recognized exceptions. Normal purchases or sales are contracts that provide for the purchase or sale of goods that will be delivered in quantities expected to be used or sold by the utility over a reasonable period in the normal course of business. A derivative instrument is a financial instrument or other contract with all of the following characteristics:
(1) It has one or more underlyings and a notional amount or payment provision. Those terms determine the amount of the settlement or settlements, and, in some cases, whether or not a settlement is required.
(2) It requires no initial net investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have a similar response to changes in market factors.
(3) Its terms require or permit net settlement, can readily be settled net by a means outside the contract, or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement.
B. The accounting for the changes in the fair value of derivative instruments depends upon its intended use and designation. Changes in the fair value of derivative instruments not designated as fair value or cash flow hedges shall be recorded in account 175, derivative instrument assets, or account 244, derivative instrument liabilities, as appropriate, with the gains recorded in account 421, miscellaneous nonoperating income, and losses recorded in account 426.5, other deductions.
C. A derivative instrument may be specifically designated as a fair value or cash flow hedge. A hedge is used to manage risk to price, interest rates, or foreign currency transactions. A company shall maintain documentation of the hedge relationship at the inception of the hedge that details the risk management objective and strategy for undertaking the hedge, the nature of the risk being hedged, and how hedge effectiveness will be determined.
D. If the utility designates the derivative instrument as a fair value hedge against exposure to changes in the fair value of a recognized asset, liability, or a firm commitment, it shall record the change in fair value of the derivative instrument to account 176, derivative instrument assets-hedges, or account 245, derivative instrument liabilities-hedges, as appropriate, with a corresponding adjustment to the subaccount of the item being hedged. The ineffective portion of the hedge transaction shall be reflected in the same income or expense account that will be used when the hedged item enters into the determination of net income. In the case of a fair value hedge of a firm commitment a new asset or liability is created. As a result of the hedge relationship, the new asset or liability will become part of the carrying amount of the item being hedged.
E. If the utility designates the derivative instrument as a cash flow hedge against exposure to variable cash flows of a probable forecasted transaction, it shall record changes in the fair value of the derivative instrument in account 176, derivative instrument assets-hedges, or account 245, derivative instrument liabilities-hedges, as appropriate, with a corresponding amount in account 219, accumulated other comprehensive income, for the effective portion of the hedge. The ineffective portion of the hedge transaction shall be reflected in the same income or expense account that will be used when the hedged item enters into the determination of net income. Amounts recorded in other comprehensive income shall be reclassified into earnings in the same period or periods that the hedged forecasted item enters into the determination of net income.
25. Accounting for asset retirement obligations.
A. An asset retirement obligation represents a liability for the legal obligation associated with the retirement of a tangible long-lived asset that a company is required to settle as a result of an existing or enacted law, statute, ordinance, or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel. An asset retirement cost represents the amount capitalized when the liability is recognized for the long-lived asset that gives rise to the legal obligation. The amount recognized for the liability and an associated asset retirement cost shall be stated at the fair value of the asset retirement obligation in the period in which the obligation is incurred.
B. The utility shall initially record a liability for an asset retirement obligation in account 230, Asset retirement obligations, and charge the associated asset retirement costs to electric utility plant (including accounts 101.1 and 120.6), and nonutility plant, as appropriate, related to the plant that gives rise to the legal obligation. The asset retirement cost shall be depreciated over the useful life of the related asset that gives rise to the obligations. For periods subsequent to the initial recording of the asset retirement obligation, a utility shall recognize the period to period changes of the asset retirement obligation that result from the passage of time due to the accretion of the liability and any subsequent measurement changes to the initial liability for the legal obligation recorded in account 230, Asset retirement obligations, as follows:
(1) The utility shall record the accretion of the liability by debiting account 411.10, Accretion expense, for electric utility plant, account 413, Expenses of electric plant leased to others, for electric plant leased to others, and account 421, Miscellaneous nonoperating income, for nonutility plant and crediting account 230, Asset retirement obligations; and
(2) The utility shall recognize any subsequent measurement changes of the liability initially recorded in account 230, Asset retirement obligations, for each specific asset retirement obligation as an adjustment of that liability in account 230 with the corresponding adjustment to electric utility plant, electric plant leased to others, and nonutility plant, as appropriate. The utility shall on a timely basis monitor any measurement changes of the asset retirement obligations.
C. Gains or losses resulting from the settlement of asset retirement obligations associated with utility plant resulting from the difference between the amount of the liability for the asset retirement obligation included in account 230, Asset retirement obligations, and the actual amount paid to settle the obligation shall be accounted for as follows:
(1) Gains shall be credited to account 411.6, Gains from disposition of utility plant, and;
(2) Losses shall be charged to account 411.7, Losses from disposition of utility plant.
D. Gains or losses on the settlement of asset retirement obligations associated with nonutility plant resulting from the difference between the amount of the liability for the asset retirement obligation in account 230, Asset retirement obligations, and the amount paid to settle the obligation, shall be accounted for as follows:
(1) Gains shall be credited to account 421, Miscellaneous nonoperating income, and;
(2) Losses shall be charged to account 426.5, Other deductions.
E. Separate subsidiary records shall be maintained for each asset retirement obligation showing the initial liability and associated asset retirement cost, any incremental amounts of the liability incurred in subsequent reporting periods for additional layers of the original liability and related asset retirement cost, the accretion of the liability, the subsequent measurement changes to the asset retirement obligation, the depreciation and amortization of the asset retirement costs and related accumulated depreciation, and the settlement date and actual amount paid to settle the obligation. For purposes of analyses a utility shall maintain supporting documentation so as to be able to furnish accurately and expeditiously with respect to each asset retirement obligation the full details of the identity and nature of the legal obligation, the year incurred, the identity of the plant giving rise to the obligation, the full particulars relating to each component and supporting computations related to the measurement of the asset retirement obligation.
1. Classification of electric plant at effective date of system of accounts (Major utilities).
A. The electric plant accounts provided herein are the same as those contained in the prior system of accounts except for inclusion of accounts for nuclear production plant and some changes in classification in the general equipment accounts. Except for these changes, the balances in the various plant accounts, as determined under the prior system of accounts, should be carried forward. Any remaining balance of plant which has not yet been classified, pursuant to the requirements of the prior system, shall be classified in accordance with the following instructions.
B. The cost to the utility of its unclassified plant shall be ascertained by analysis of the utility’s records. Adjustments shall not be made to record in utility plant accounts amounts previously charged to operating expenses or to income deductions in accordance with the uniform system of accounts in effect at the time or in accordance with the discretion of management as exercised under a uniform system of accounts, or under accounting practices previously followed.
C. The detailed electric plant accounts (301 to 399, inclusive) shall be stated on the basis of cost to the utility of plant constructed by it and the original cost, estimated if not known, of plant acquired as an operating unit or system. The difference between the original cost, as above, and the cost to the utility of electric plant after giving effect to any accumulated provision for depreciation or amortization shall be recorded in account 114, Electric Plant Acquisition Adjustments. The original cost of electric plant shall be determined by analysis of the utility’s records or those of the predecessor or vendor companies with respect to electric plant previously acquired as operating units or systems and the difference between the original cost so determined, less accumulated provisions for depreciation and amortization and the cost to the utility with necessary adjustments for retirements from the date of acquisition, shall be entered in account 114, Electric Plant Acquisition Adjustments. Any difference between the cost of electric plant and its book cost, when not properly includible in other accounts, shall be recorded in account 116, Other Electric Plant Adjustments.
D. Plant acquired by lease which qualifies as capital lease property under General Instruction 19. Criteria for Classifying Leases, shall be recorded in Account 101.1, Property under Capital Leases, or Account 120.6, Nuclear Fuel under Capital Leases, as appropriate.
2. Electric Plant To Be Recorded at Cost.
A. All amounts included in the accounts for electric plant acquired as an operating unit or system, except as otherwise provided in the texts of the intangible plant accounts, shall be stated at the cost incurred by the person who first devoted the property to utility service. All other electric plant shall be included in the accounts at the cost incurred by the utility, except for property acquired by lease which qualifies as capital lease property under General Instruction 19. Criteria for Classifying Leases, and is recorded in Account 101.1, Property under Capital Leases, or Account 120.6, Nuclear Fuel under Capital Leases. Where the term cost is used in the detailed plant accounts, it shall have the meaning stated in this paragraph.
B. When the consideration given for property is other than cash, the value of such consideration shall be determined on a cash basis (see, however, definition 9). In the entry recording such transition, the actual consideration shall be described with sufficient particularity to identify it. The utility shall be prepared to furnish the Commission the particulars of its determination of the cash value of the consideration if other than cash.
C. When property is purchased under a plan involving deferred payments, no charge shall be made to the electric plant accounts for interest, insurance, or other expenditures occasioned solely by such form of payment.
D. The electric plant accounts shall not include the cost or other value of electric plant contributed to the company. Contributions in the form of money or its equivalent toward the construction of electric plant shall be credited to accounts charged with the cost of such construction. Plant constructed from contributions of cash or its equivalent shall be shown as a reduction to gross plant constructed when assembling cost data in work orders for posting to plant ledgers of accounts. The accumulated gross costs of plant accumulated in the work order shall be recorded as a debit in the plant ledger of accounts along with the related amount of contributions concurrently be recorded as a credit.
3. Components of construction cost.
A. For Major utilities, the cost of construction properly includible in the electric plant accounts shall include, where applicable, the direct and overhead cost as listed and defined hereunder:
(1) Contract work includes amounts paid for work performed under contract by other companies, firms, or individuals, costs incident to the award of such contracts, and the inspection of such work.
(2) Labor includes the pay and expenses of employees of the utility engaged on construction work, and related workmen’s compensation insurance, payroll taxes and similar items of expense. It does not include the pay and expenses of employees which are distributed to construction through clearing accounts nor the pay and expenses included in other items hereunder.
(3) Materials and supplies includes the purchase price at the point of free delivery plus customs duties, excise taxes, the cost of inspection, loading and transportation, the related stores expenses, and the cost of fabricated materials from the utility’s shop. In determining the cost of materials and supplies used for construction, proper allowance shall be made for unused materials and supplies, for materials recovered from temporary structures used in performing the work involved, and for discounts allowed and realized in the purchase of materials and supplies.
The cost of individual items of equipment of small value (for example, $500 or less) or of short life, including small portable tools and implements, shall not be charged to utility plant accounts unless the correctness of the accounting therefor is verified by current inventories. The cost shall be charged to the appropriate operating expense or clearing accounts, according to the use of such items, or, if such items are consumed directly in construction work, the cost shall be included as part of the cost of the construction
(4) Transportation includes the cost of transporting employees, materials and supplies, tools, purchased equipment, and other work equipment (when not under own power) to and from points of construction. It includes amounts paid to others as well as the cost of operating the utility’s own transportation equipment. (See item 5 following.)
(5) Special machine service includes the cost of labor (optional), materials and supplies, depreciation, and other expenses incurred in the maintenance, operation and use of special machines, such as steam shovels, pile drivers, derricks, ditchers, scrapers, material unloaders, and other labor saving machines; also expenditures for rental, maintenance and operation of machines of others. It does not include the cost of small tools and other individual items of small value or short life which are included in the cost of materials and supplies. (See item 3, above.) When a particular construction job requires the use for an extended period of time of special machines, transportation or other equipment, the net book cost thereof, less the appraised or salvage value at time of release from the job, shall be included in the cost of construction.
(6) Shop service includes the proportion of the expense of the utility’s shop department assignable to construction work except that the cost of fabricated materials from the utility’s shop shall be included in materials and supplies.
(7) Protection includes the cost of protecting the utility’s property from fire or other casualties and the cost of preventing damages to others, or to the property of others, including payments for discovery or extinguishment of fires, cost of apprehending and prosecuting incendiaries, witness fees in relation thereto, amounts paid to municipalities and others for fire protection, and other analogous items of expenditures in connection with construction work.
(8) Injuries and damages includes expenditures or losses in connection with construction work on account of injuries to persons and damages to the property of others; also the cost of investigation of and defense against actions for such injuries and damages. Insurance recovered or recoverable on account of compensation paid for injuries to persons incident to construction shall be credited to the account or accounts to which such compensation is charged Insurance recovered or recoverable on account of property damages incident to construction shall be credited to the account or accounts charged with the cost of the damages.
(9) Privileges and permits includes payments for and expenses incurred in securing temporary privileges, permits or rights in connection with construction work, such as for the use of private or public property, streets, or highways, but it does not include rents, or amounts chargeable as franchises and consents for which see account 302, Franchises and Consents.
(10) Rents includes amounts paid for the use of construction quarters and office space occupied by construction forces and amounts properly includible in construction costs for such facilities jointly used.
(11) Engineering and supervision includes the portion of the pay and expenses of engineers, surveyors, draftsmen, inspectors, superintendents and their assistants applicable to construction work.
(12) General administration capitalized includes the portion of the pay and expenses of the general officers and administrative and general expenses applicable to construction work.
(13) Engineering services includes amounts paid to other companies, firms, or individuals engaged by the utility to plan, design, prepare estimates, supervise, inspect, or give general advice and assistance in connection with construction work.
(14) Insurance includes premiums paid or amounts provided or reserved as self-insurance for the protection against loss and damages in connection with construction, by fire or other casualty injuries to or death of persons other than employees, damages to property of others, defalcation of employees and agents, and the nonperformance of contractual obligations of others. It does not include workmen’s compensation or similar insurance on employees included as labor in item 2, above.
(15) Law expenditures includes the general law expenditures incurred in connection with construction and the court and legal costs directly related thereto, other than law expenses included in protection, item 7, and in injuries and damages, item 8.
(16) Taxes includes taxes on physical property (including land) during the period of construction and other taxes properly includible in construction costs before the facilities become available for service.
(17) Allowance for funds used during construction (Major and Nonmajor Utilities) includes the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used, not to exceed, without prior approval of the Commission, allowances computed in accordance with the formula prescribed in paragraph (a) of this subparagraph. No allowance for funds used during construction charges shall be included in these accounts upon expenditures for construction projects which have been abandoned.
(a) The formula and elements for the computation of the allowance for funds used during construction shall be:
(b) The rates shall be determined annually. The balances for long-term debt, preferred stock and common equity shall be the actual book balances as of the end of the prior year. The cost rates for long-term debt and preferred stock shall be the weighted average cost determined in the manner indicated in § 35.13 of the Commission’s Regulations Under the Federal Power Act. The cost rate for common equity shall be the rate granted common equity in the last rate proceeding before the ratemaking body having primary rate jurisdictions. If such cost rate is not available, the average rate actually earned during the preceding three years shall be used. The short-term debt balances and related cost and the average balance for construction work in progress plus nuclear fuel in process of refinement, conversion, enrichment, and fabrication shall be estimated for the current year with appropriate adjustments as actual data becomes available.
When a part only of a plant or project is placed in operation or is completed and ready for service but the construction work as a whole is incomplete, that part of the cost of the property placed in operation or ready for service, shall be treated as Electric Plant in Service and allowance for funds used during construction thereon as a charge to construction shall cease. Allowance for funds used during construction on that part of the cost of the plant which is incomplete may be continued as a charge to construction until such time as it is placed in operation or is ready for service, except as limited in item 17, above.
(18) Earnings and expenses during construction. The earnings and expenses during construction shall constitute a component of construction costs.
(a) The earnings shall include revenues received or earned for power produced by generating plants during the construction period and sold or used by the utility. Where such power is sold to an independent purchaser before intermingling with power generated by other plants, the credit shall consist of the selling price of the energy. Where the power generated by a plant under construction is delivered to the utility’s electric system for distribution and sale, or is delivered to an associated company, or is delivered to and used by the utility for purposes other than distribution and sale (for manufacturing or industrial use, for example), the credit shall be the fair value of the energy so delivered. The revenues shall also include rentals for lands, buildings etc., and miscellaneous receipts not properly includible in other accounts.
(b) The expenses shall consist of the cost of operating the power plant, and other costs incident to the production and delivery of the power for which construction is credited under paragraph (a), above, including the cost of repairs and other expenses of operating and maintaining lands, buildings, and other property, and other miscellaneous and like expenses not properly includible in other accounts.
(19) Training costs (Major and Nonmajor Utilities). When it is necessary that employees be trained to operate or maintain plant facilities that are being constructed and such facilities are not conventional in nature, or are new to the company’s operations, these costs may be capitalized as a component of construction cost. Once plant is placed in service, the capitalization of training costs shall cease and subsequent training costs shall be expensed. (See Operating Expense Instruction 4.)
(20) Studies includes the costs of studies such as nuclear operational, safety, or seismic studies or environmental studies mandated by regulatory bodies relative to plant under construction. Studies relative to facilities in service shall be charged to account 183, Preliminary Survey and Investigation Charges.
(21) Asset retirement costs. The costs recognized as a result of asset retirement obligations incurred during the construction and testing of utility plant shall constitute a component of construction costs.
B. For Nonmajor utilities, the cost of construction of property chargeable to the electric plant accounts shall include, where applicable, the cost of labor; materials and supplies; transportation; work done by others for the utility; injuries and damages incurred in construction work; privileges and permits; special machine service; allowance for funds used during construction, not to exceed without prior approval of the Commission, amounts computed in accordance with the formula prescribed in paragraph (a) of paragraph (17) of this Instruction; training costs; and such portion of general engineering, administrative salaries and expenses, insurance, taxes, and other analogous items as may be properly includable in construction costs. (See Operating Expense Instruction 4.) The rates and balances of short and long-term debt, preferred stock, common equity and construction work in progress shall be determined as prescribed in paragraph (b) of paragraph (17) of this Instruction.
4. Overhead Construction Costs.
A. All overhead construction costs, such as engineering, supervision, general office salaries and expenses, construction engineering and supervision by others than the accounting utility, law expenses, insurance, injuries and damages, relief and pensions, taxes and interest, shall be charged to particular jobs or units on the basis of the amounts of such overheads reasonably applicable thereto, to the end that each job or unit shall bear its equitable proportion of such costs and that the entire cost of the unit, both direct and overhead, shall be deducted from the plant accounts at the time the property is retired.
B. As far as practicable, the determination of pay roll charges includible in construction overheads shall be based on time card distributions thereof. Where this procedure is impractical, special studies shall be made periodically of the time of supervisory employees devoted to construction activities to the end that only such overhead costs as have a definite relation to construction shall be capitalized. The addition to direct construction costs of arbitrary percentages or amounts to cover assumed overhead costs is not permitted.
C. For Major utilities, the records supporting the entries for overhead construction costs shall be so kept as to show the total amount of each overhead for each year, the nature and amount of each overhead expenditure charged to each construction work order and to each electric plant account, and the bases of distribution of such costs.
5. Electric Plant Purchased or Sold.
A. When electric plant constituting an operating unit or system is acquired by purchase, merger, consolidation, liquidation, or otherwise, after the effective date of this system of accounts, the costs of acquisition, including expenses incidental thereto properly includible in electric plant, shall be charged to account 102, Electric Plant Purchased or Sold.
B. The accounting for the acquisition shall then be completed as follows:
(1) The original cost of plant, estimated if not known, shall be credited to account 102, Electric Plant Purchased or Sold, and concurrently charged to the appropriate electric plant in service accounts and to account 104, Electric Plant Leased to Others, account 105, Electric Plant Held for Future Use, and account 107, Construction Work in Progress—Electric, as appropriate.
(2) The depreciation and amortization applicable to the original cost of the properties purchased shall be charged to account 102, Electric Plant Purchased or Sold, and concurrently credited to the appropriate account for accumulated provision for depreciation or amortization.
(3) The cost to the utility of any property includible in account 121, Nonutility Property, shall be transferred thereto.
(4) The amount remaining in account 102, Electric Plant Purchased or Sold, shall then be closed to account 114, Electric Plant Acquisition Adjustments.
C. If property acquired in the purchase of an operating unit or system is in such physical condition when acquired that it is necessary substantially to rehabilitate it in order to bring the property up to the standards of the utility, the cost of such work, except replacements, shall be accounted for as a part of the purchase price of the property.
D. When any property acquired as an operating unit or system includes duplicate or other plant which will be retired by the accounting utility in the reconstruction of the acquired property or its consolidation with previously owned property, the proposed accounting for such property shall be presented to the Commission.
E. In connection with the acquisition of electric plant constituting an operating unit or system, the utility shall procure, if possible, all existing records relating to the property acquired, or certified copies thereof, and shall preserve such records in conformity with regulations or practices governing the preservation of records of its own construction.
F. When electric plant constituting an operating unit or system is sold, conveyed, or transferred to another by sale, merger, consolidation, or otherwise, the book cost of the property sold or transferred to another shall be credited to the appropriate utility plant accounts, including amounts carried in account 114, Electric Plant Acquisition Adjustments. The amounts (estimated if not known) carried with respect thereto in the accounts for accumulated provision for depreciation and amortization and in account 252, Customer Advances for Construction, shall be charged to such accounts and contra entries made to account 102, Electric Plant Purchased or Sold. Unless otherwise ordered by the Commission, the difference, if any, between (1) the net amount of debits and credits and (2) the consideration received for the property (less commissions and other expenses of making the sale) shall be included in account 421.1. Gain on Disposition of Property, or account 421.2, Loss on Disposition of Property. (See account 102, Electric Plant Purchased or Sold.)
In cases where existing utilities merge or consolidate because of financial or operating reasons or statutory requirements rather than as a means of transferring title of purchased properties to a new owner, the accounts of the constituent utilities, with the approval of the Commission, may be combined. In the event original cost has not been determined, the resulting utility shall proceed to determine such cost as outlined herein.
6. Expenditures on Leased Property.
A. The cost of substantial initial improvements (including repairs, rear-rangements, additions, and betterments) made in the course of preparing for utility service property leased for a period of more than one year, and the cost of subsequent substantial additions, replacements, or betterments to such property, shall be charged to the electric plant account appropriate for the class of property leased. If the service life of the improvements is terminable by action of the lease, the cost, less net salvage, of the improvements shall be spread over the life of the lease by charges to account 404, Amortization of Limited-Term Electric Plant. However, if the service life is not terminated by action of the lease but by depreciation proper, the cost of the improvements, less net salvage, shall be accounted for as depreciable plant. The provisions of this paragraph are applicable to property leased under either capital leases or operating leases.
B. If improvements made to property leased for a period of more than one year are of relatively minor cost, or if the lease is for a period of not more than one year, the cost of the improvements shall be charged to the account in which the rent is included, either directly or by amortization thereof.
7. Land and Land Rights.
A. The accounts for land and land rights shall include the cost of land owned in fee by the utility and rights. Interests, and privileges held by the utility in land owned by others, such as leaseholds, easements, water and water power rights, diversion rights, submersion rights, rights-of-way, and other like interests in land. Do not include in the accounts for land and land rights and rights-of-way costs incurred in connection with first clearing and grading of land and rights-of-way and the damage costs associated with the construction and installation of plant. Such costs shall be included in the appropriate plant accounts directly benefited.
B. Where special assessments for public improvements provide for deferred payments, the full amount of the assessments shall be charged to the appropriate land account and the unpaid balance shall be carried in an appropriate liability account. Interest on unpaid balances shall be charged to the appropriate interest account. If any part of the cost of public improvements is included in the general tax levy, the amount thereof shall be charged to the appropriate tax account.
C. The net profit from the sale of timber, cord wood, sand, gravel, other resources or other property acquired with the rights-of-way or other lands shall be credited to the appropriate plant account to which related. Where land is held for a considerable period of time and timber and other natural resources on the land at the time of purchase increases in value, the net profit (after giving effect to the cost of the natural resources) from the sales of timber or its products or other natural resources shall be credited to the appropriate utility operating income account when such land has been recorded in account 105, Electric Plant Held for Future Use or classified as plant in service, otherwise to account 421, Miscellaneous Nonoperating Income.
D. Separate entries shall be made for the acquisition, transfer, or retirement of each parcel of land, and each land right (except rights of way for distribution lines), or water right, having a life of more than one year. A record shall be maintained showing the nature of ownership, full legal description, area, map reference, purpose for which used, city, county, and tax district on which situated, from whom purchased or to whom sold, payment given or received, other costs, contract date and number, date of recording of deed, and book and page of record. Entries transferring or retiring land or land rights shall refer to the original entry recording its acquisition.
E. Any difference between the amount received from the sale of land or land rights, less agents’ commissions and other costs incident to the sale, and the book cost of such land or rights, shall be included in account 411.6, Gains from Disposition of Utility Plant, or 411.7, Losses from Disposition of Utility Plant when such property has been recorded in account 105, Electric Plant Held for Future Use, otherwise to account 421.1, Gain on Disposition of Property or 421.2, Loss on Disposition of Property, as appropriate, unless a reserve therefor has been authorized and provided. Appropriate adjustments of the accounts shall be made with respect to any structures or improvements located on land sold.
F. The cost of buildings and other improvements (other than public improvements) shall not be included in the land accounts. If at the time of acquisition of an interest in land such interest extends to buildings or other improvements (other than public improvements) which are then devoted to utility operations, the land and improvements shall be separately appraised and the cost allocated to land and buildings or improvements on the basis of the appraisals. If the improvements are removed or wrecked without being used in operations, the cost of removing or wrecking shall be charged and the salvage credited to the account in which the cost of the land is recorded.
G. When the purchase of land for electric operations requires the purchase of more land than needed for such purposes, the charge to the specific land account shall be based upon the cost of the land purchased, less the fair market value of that portion of the land which is not to be used in utility operations. The portion of the cost measured by the fair market value of the land not to be used shall be included in account 105, Electric Plant Held for Future Use, or account 121, Nonutility Property, as appropriate.
H. Provisions shall be made for amortizing amounts carried in the accounts for limited-term interests in land so as to apportion equitably the cost of each interest over the life thereof. (For Major utilities, see account 111, Accumulated Provision for Amortization of Electric Plant Utility, and account 404, Amortization of Limited-Term Electric Plant. For Nonmajor utilities, see account 404.)
I. The items of cost to be included in the accounts for land and land rights are as follows:
1. Bulkheads, buried, not requiring maintenance or replacement.
2. Cost, first, of acquisition including mortgages and other liens assumed (but not subsequent interest thereon).
3. [Reserved]
4. Condemnation proceedings, including court and counsel costs.
5. Consents and abutting damages, payment for.
6. Conveyancers’ and notaries’ fees.
7. Fees, commissions, and salaries to brokers, agents and others in connection with the acquisition of the land or land rights.
8. [Reserved]
9. Leases, cost of voiding upon purchase to secure possession of land.
10. Removing, relocating, or reconstructing, property of others, such as buildings, highways, railroads, bridges, cemeteries, churches, telephone and power lines, etc., in order to acquire quiet possession.
11. Retaining walls unless identified with structures.
12. Special assessments levied by public authorities for public improvements on the basis of benefits for new roads, new bridges, new sewers, new curbing, new pavements, and other public improvements, but not taxes levied to provide for the maintenance of such improvements.
13. Surveys in connection with the acquisition, but not amounts paid for topographical surveys and maps where such costs are attributable to structures or plant equipment erected or to be erected or installed on such land.
14. Taxes assumed, accrued to date of transfer of title.
15. Title, examining, clearing, insuring and registering in connection with the acquisition and defending against claims relating to the period prior to the acquisition.
16. Appraisals prior to closing title.
17. Cost of dealing with distributees or legatees residing outside of the state or county, such as recording power of attorney, recording will or exemplification of will, recording satisfaction of state tax.
18. Filing satisfaction of mortgage.
19. Documentary stamps.
20. Photographs of property at acquisition.
21. Fees and expenses incurred in the acquisition of water rights and grants.
22. Cost of fill to extend bulkhead line over land under water, where riparian rights are held, which is not occasioned by the erection of a structure.
23. Sidewalks and curbs constructed by the utility on public property.
24. Labor and expenses in connection with securing rights of way, where performed by company employees and company agents.
8. Structures and Improvements.
A. The accounts for structures and improvements shall include the cost of all buildings and facilities to house, support, or safeguard property or persons, including all fixtures permanently attached to and made a part of buildings and which cannot be removed therefrom without cutting into the walls, ceilings, or floors, or without in some way impairing the buildings, and improvements of a permanent character on or to land. Also include those costs incurred in connection with the first clearing and grading of land and rights-of-way and the damage costs associated with construction and installation of plant.
B. The cost of specially provided foundations not intended to outlast the machinery or apparatus for which provided, and the cost of angle irons, castings, etc., installed at the base of an item of equipment, shall be charged to the same account as the cost of the machinery, apparatus, or equipment.
C. Minor buildings and structures, such as valve towers, patrolmen’s towers, telephone stations, fish and wildlife, and recreation facilities, etc., which are used directly in connection with or form a part of a reservoir, dam, waterway, etc., shall be considered a part of the facility in connection with which constructed or operated and the cost thereof accounted for accordingly.
D. Where furnaces and boilers are used primarily for furnishing steam for some particular department and only incidentally for furnishing steam for heating a building and operating the equipment therein, the entire cost of such furnaces and boilers shall be charged to the appropriate plant account, and no part to the building account.
E. Where the structure of a dam forms also the foundation of the power plant building, such foundation shall be considered a part of the dam.
F. The cost of disposing of materials excavated in connection with construction of structures shall be considered as a part of the cost of such work, except as follows: (a) When such material is used for filling, the cost of loading, hauling, and dumping shall be equitably apportioned between the work in connection with which the removal occurs and the work in connection with which the material is used; (b) when such material is sold, the net amount realized from such sales shall be credited to the work in connection with which the removal occurs. If the amount realized from the sale of excavated materials exceeds the removal costs and the costs in connection with the sale, the excess shall be credited to the land account in which the site is carried.
G. Lighting or other fixtures temporarily attached to buildings for purposes of display or demonstration shall not be included in the cost of the building but in the appropriate equipment account.
H. The items of cost to be included in the accounts for structures and improvements are as follows:
1. Architects’ plans and specifications including supervision.
2. Ash pits (when located within the building). (Major Utilities)
3. Athletic field structures and improvements.
4. Boilers, furnaces, piping, wiring, fixtures, and machinery for heating, lighting, signaling, ventilating, and air-conditioning systems, plumbing, vacuum cleaning systems, incinerator and smoke pipe, flues, etc.
5. Bulkheads, including dredging, riprap fill, piling, decking, concrete, fenders, etc., when exposed and subject to maintenance and replacement.
6. Chimneys (Major Utilities).
7. Coal bins and bunkers.
8. Commissions and fees to brokers, agents, architects, and others.
9. Conduit (not to be removed) with its contents.
10. Damages to abutting property during construction.
11. Docks (Major Utilities).
12. Door checks and door stops (Major Utilities).
13. Drainage and sewerage systems.
14. Elevators, cranes, hoists, etc., and the machinery for operating them.
15. Excavation, including shoring, bracing, bridging, refill and disposal of excess excavated material, cofferdams around foundation, pumping water from cofferdams during construction, and test borings.
16. Fences and fence curbs (not including protective fences isolating items of equipment, which shall be charged to the appropriate equipment account).
17. Fire protection systems when forming a part of a structure.
18. Flagpole (Major Utilities).
19. Floor covering (permanently attached) (Major Utilities).
20. Foundations and piers for machinery, constructed as a permanent part of a building or other item listed herein.
21. Grading and clearing when directly occasioned by the building of a structure.
22. Intrasite communication system, poles, pole fixtures, wires, and cables.
23. Landscaping, lawns, shrubbery, etc.
24. Leases, voiding upon purchase to secure possession of structures.
25. Leased property, expenditures on.
26. Lighting fixtures and outside lighting system.
27. Mailchutes when part of a building (Major Utilities).
28. Marquee, permanently attached to building (Major Utilities).
29. Painting, first cost.
30. Permanent paving, concrete, brick, flagstone, asphalt, etc., within the property lines.
31. Partitions, including movable (Major Utilities).
32. Permits and privileges.
33. Platforms, railings, and gratings when constructed as a part of a structure.
34. Power boards for services to a building (Major Utilities).
35. Refrigerating systems for general use (Major Utilities).
36. Retaining walls except when identified with land.
37. Roadways, railroads, bridges, and trestles intrasite except railroads provided for in equipment accounts.
38. Roofs (Major Utilities).
39. Scales, connected to and forming a part of a structure (Major Utilities).
40. Screens (Major Utilities).
41. Sewer systems, for general use (Major Utilities).
42. Sidewalks, culverts, curbs and streets constructed by the utility on its property (Major Utilities).
43. Sprinkling systems (Major Utilities).
44. Sump pumps and pits (Major Utilities).
45. Stacks—brick, steel, or concrete, when set on foundation forming part of general foundation and steelwork of a building.
46. Steel inspection during construction (Major Utilities).
47. Storage facilities constituting a part of a building.
48. Storm doors and windows (Major Utilities).
49. Subways, areaways, and tunnels, directly connected to and forming part of a structure.
50. Tanks, constructed as part of a building or as a distinct structural unit.
51. Temporary heating during construction (net cost) (Major Utilities).
52. Temporary water connection during construction (net cost) (Major Utilities).
53. Temporary shanties and other facilities used during construction (net cost)
54. Topographical maps (Major Utilities).
55. Tunnels, intake and discharge, when constructed as part of a structure, including sluice gates, and those constructed to house mains.
56. Vaults constructed as part of a building.
57. Watchmen’s sheds and clock systems (net cost when used during construction only) (Major Utilities).
58. Water basins or reservoirs.
59. Water front improvements (Major Utilities).
60. Water meters and supply system for a building or for general company purposes (Major Utilities).
61. Water supply piping, hydrants and wells (Major Utilities).
62. Wharves.
63. Window shades and ventilators (Major Utilities).
64. Yard drainage system (Major Utilities).
65. Yard lighting system (Major Utilities).
66. Yard surfacing, gravel, concrete, or oil. (First cost only.) (Major Utilities)
Structures and Improvements accounts shall be credited with the cost of coal bunkers, stacks, foundations, subways, tunnels, etc., the use of which has terminated with the removal of the equipment with which they are associated even though they have not been physically removed.
9. Equipment.
A. The cost of equipment chargeable to the electric plant accounts, unless otherwise indicated in the text of an equipment account, includes the net purchase price thereof, sales taxes, investigation and inspection expenses necessary to such purchase, expenses of transportation when borne by the utility, labor employed, materials and supplies consumed, and expenses incurred by the utility in unloading and placing the equipment in readiness to operate. Also include those costs incurred in connection with the first clearing and grading of land and rights-of-way and the damage costs associated with construction and installation of plant.
B. Exclude from equipment accounts hand and other portable tools, which are likely to be lost or stolen or which have relatively small value (for example, $500 or less) or short life, unless the correctness of the accounting therefor as electric plant is verified by current inventories. Special tools acquired and included in the purchase price of equipment shall be included in the appropriate plant account. Portable drills and similar tool equipment when used in connection with the operation and maintenance of a particular plant or department, such as production, transmission, distribution, etc., or in stores, shall be charged to the plant account appropriate for their use.
C. The equipment accounts shall include angle irons and similar items which are installed at the base of an item of equipment, but piers and foundations which are designed to be as permanent as the buildings which house the equipment, or which are constructed as a part of the building and which cannot be removed without cutting into the walls, ceilings or floors or without in some way impairing the building, shall be included in the building accounts.
D. The equipment accounts shall include the necessary costs of testing or running a plant or parts thereof during an experimental or test period prior to such plant becoming ready for or placed in service. In the case of Nonmajor utilities, the utility shall pay the fee prescribed in part 381 of this chapter and shall furnish the Commission with full particulars of and justification for any test or experimental run extending beyond a period of 30 days. In the case of Major utilities, the utility shall furnish the Commission with full particulars of and justification for any test or experimental run extending beyond a period of 120 days for nuclear plant, and a period of 90 days for all other plant. Such particulars shall include a detailed operational and downtime log showing days of production, gross kilowatts generated by hourly increments, types, and periods of outages by hours with explanation thereof, beginning with the first date the equipment was either tested or synchronized on the line to the end of the test period.
E. The cost of efficiency or other tests made subsequent to the date equipment becomes available for service shall be charged to the appropriate expense accounts, except that tests to determine whether equipment meets the specifications and requirements as to efficiency, performance, etc., guaranteed by manufacturers, made after operations have commenced and within the period specified in the agreement or contract of purchase may be charged to the appropriate electric plant account.
10. Additions and Retirements of Electric Plant.
A. For the purpose of avoiding undue refinement in accounting for additions to and retirements and replacements of electric plant, all property will be considered as consisting of (1) retirement units and (2) minor items of property. Each utility shall maintain a written property units listing for use in accounting for additions and retirements of electric plant and apply the listing consistently.
B. The addition and retirement of retirement units shall be accounted for as follows:
(1) When a retirement unit is added to electric plant, the cost thereof shall be added to the appropriate electric plant account, except that when units are acquired in the acquisition of any electric plant constituting an operating system, they shall be accounted for as provided in electric plant instruction 5.
(2) When a retirement unit is retired from electric plant, with or without replacement, the book cost thereof shall be credited to the electric plant account in which it is included, determined in the manner set forth in paragraph D, below. If the retirement unit is of a depreciable class, the book cost of the unit retired and credited to electric plant shall be charged to the accumulated provision for depreciation applicable to such property. The cost of removal and the salvage shall be charged or credited, as appropriate, to such depreciation account.
C. The addition and retirement of minor items of property shall be accounted for as follows:
(1) When a minor item of property which did not previously exist is added to plant, the cost thereof shall be accounted for in the same manner as for the addition of a retirement unit, as set forth in paragraph B(1), above, if a substantial addition results, otherwise the charge shall be to the appropriate maintenance expense account.
(2) When a minor item of property is retired and not replaced, the book cost thereof shall be credited to the electric plant account in which it is included; and, in the event the minor item is a part of depreciable plant, the account for accumulated provision for depreciation shall be charged with the book cost and cost of removal and credited with the salvage. If, however, the book cost of the minor item retired and not replaced has been or will be accounted for by its inclusion in the retirement unit of which it is a part when such unit is retired, no separate credit to the property account is required when such minor item is retired.
(3) When a minor item of depreciable property is replaced independently of the retirement unit of which it is a part, the cost of replacement shall be charged to the maintenance account appropriate for the item, except that if the replacement effects a substantial betterment (the primary aim of which is to make the property affected more useful, more efficient, of greater durability, or of greater capacity), the excess cost of the replacement over the estimated cost at current prices of replacing without betterment shall be charged to the appropriate electric plant account.
D. The book cost of electric plant retired shall be the amount at which such property is included in the electric plant accounts, including all components of construction costs. The book cost shall be determined from the utility’s records and if this cannot be done it shall be estimated. Utilities must furnish the particulars of such estimates to the Commission, if requested. When it is impracticable to determine the book cost of each unit, due to the relatively large number or small cost thereof, an appropriate average book cost of the units, with due allowance for any differences in size and character, shall be used as the book cost of the units retired.
E. The book cost of land retired shall be credited to the appropriate land account. If the land is sold, the difference between the book cost (less any accumulated provision for depreciation or amortization therefore which has been authorized and provided) and the sale price of the land (less commissions and other expenses of making the sale) shall be recorded in account 411.6, Gains from Disposition of Utility Plant, or 411.7, Losses from Disposition of Utility Plant when the property has been recorded in account 105, Electric Plant Held for Future Use, otherwise to accounts 421.1, Gain on Disposition of Property or 421.2, Loss on Disposition of Property, as appropriate. If the land is not used in utility service but is retained by the utility, the book cost shall be charged to account 105, Electric Plant Held for Future Use, or account 121, Nonutility Property, as appropriate.
F. The book cost less net salvage of depreciable electric plant retired shall be charged in its entirety to account 108. Accumulated Provision for Depreciation of Electric Plant in Service (Account 110, Accumulated Provision for Depreciation and Amortization of Electric Utility Plant, in the case of Nonmajor utilities). Any amounts which, by approval or order of the Commission, are charged to account 182.1, Extraordinary Property Losses, shall be credited to account 108 (Account 110 for Nonmajor utilities).
G. In the case of Major utilities, the accounting for the retirement of amounts included in account 302, Franchises and Consents, and account 303, Miscellaneous Intangible Plant, and the items of limited-term interest in land included in the accounts for land and land rights, shall be as provided for in the text of account 111. Accumulated Provision for Amortization of Electric Plant in Service, account 404, Amortization of Limited-Term Electric Plant, and account 405, Amortization of Other Electric Plant.
11. Work Order and Property Record System Required.
A. Each utility shall record all construction and retirements of electric plant by means of work orders or job orders. Separate work orders may be opened for additions to and retirements of electric plant or the retirements may be included with the construction work order, provided, however, that all items relating to the retirements shall be kept separate from those relating to construction and provided, further, that any maintenance costs involved in the work shall likewise be segregated.
B. Each utility shall keep its work order system so as to show the nature of each addition to or retirement of electric plant, the total cost thereof, the source or sources of costs, and the electric plant account or accounts to which charged or credited. Work orders covering jobs of short duration may be cleared monthly.
C. In the case of Major utilities, each utility shall maintain records in which, for each plant account, the amounts of the annual additions and retirements are classified so as to show the number and cost of the various record units or retirement units.
12. Transfers of Property.
When property is transferred from one electric plant account to another, from one utility department to another, such as from electric to gas, from one operating division or area to another, to or from accounts 101, Electric Plant in Service, 104. Electric Plant Leased to Others, 105. Electric Plant Held for Future Use, and 121, Nonutility Property, the transfer shall be recorded by transferring the original cost thereof from the one account, department, or location to the other. Any related amounts carried in the accounts for accumulated provision for depreciation or amortization shall be transferred in accordance with the segregation of such accounts.
13. Common Utility Plant.
A. If the utility is engaged in more than one utility service, such as electric, gas, and water, and any of its utility plant is used in common for several utility services or for other purposes to such an extent and in such manner that it is impracticable to segregate it by utility services currently in the accounts, such property, with the approval of the Commission, may be designated and classified as common utility plant.
B. The book amount of utility plant designated as common plant shall be included in account 118, Other Utility Plant, and if applicable in part to the electric department, shall be segregated and accounted for in subaccounts as electric plant is accounted for in accounts 101 to 107, inclusive, and electric plant adjustments in account 116; any amounts classifiable as common plant acquisition adjustments or common plant adjustments shall be subject to disposition as provided in paragraphs C and B of accounts 114 and 116, respectively, for amounts classified in those accounts. The original cost of common utility plant in service shall be classified according to detailed utility plant accounts appropriate for the property.
C. The utility shall be prepared to show at any time and to report to the Commission annually, or more frequently, if required, and by utility plant accounts (301 to 399) the following: (1) The book cost of common utility plant, (2) The allocation of such cost to the respective departments using the common utility plant, and (3) The basis of the allocation.
D. The accumulated provision for depreciation and amortization of the utility shall be segregated so as to show the amount applicable to the property classified as common utility plant.
E. The expenses of operation, maintenance, rents, depreciation and amortization of common utility plant shall be recorded in the accounts prescribed herein, but designated as common expenses, and the allocation of such expenses to the departments using the common utility plant shall be supported in such manner as to reflect readily the basis of allocation used.
14. Transmission and Distribution Plant.
For the purpose of this system of accounts:
A. Transmission system means:
(1) All land, conversion structures, and equipment employed at a primary source of supply (i.e., generating station, or point of receipt in the case of purchased power) to change the voltage or frequency of electricity for the purpose of its more efficient or convenient transmission;
(2) All land, structures, lines, switching and conversion stations, high tension apparatus, and their control and protective equipment between a generating or receiving point and the entrance to a distribution center or wholesale point; and
(3) All lines and equipment whose primary purpose is to augment, integrate or tie together the sources of power supply
B. Distribution system means all land, structures, conversion equipment, lines, line transformers, and other facilities employed between the primary source of supply (i.e., generating station, or point of receipt in the case of purchased power) and of delivery to customers, which are not includible in transmission system, as defined in paragraph A, whether or not such land, structures, and facilities are operated as part of a transmission system or as part of a distribution system.
Stations which change electricity from transmission to distribution voltage shall be classified as distribution stations.
C. Where poles or towers support both transmission and distribution conductors, the poles, towers, anchors, guys, and rights of way shall be classified as transmission system. The conductors, crossarms, braces, grounds, tiewire, insulators, etc., shall be classified as transmission or distribution facilities, according to the purpose for which used.
D. Where underground conduit contains both transmission and distribution conductors, the underground conduit and right of way shall be classified as distribution system. The conductors shall be classified as transmission or distribution facilities according to the purpose for which used.
E. Land (other than rights of way) and structures used jointly for transmission and distribution purposes shall be classified as transmission or distribution according to the major use thereof.
15. Hydraulic production plant (Major Utilities).
For the purpose of this system of accounts hydraulic production plant means all land and land rights, structures and improvements used in connection with hydraulic power generation, reservoirs dams and waterways, water wheels, turbines, generators, accessory electric equipment, miscellaneous powerplant equipment, roads, railroads, and bridges, and structures and improvements used in connection with fish and wildlife, and recreation.
16. Nuclear Fuel Records Required (Major Utilities).
Each utility shall keep all the necessary records to support the entries to the various nuclear fuel plant accounts classified under “Assets and Other Debits,” Utility Plant 120.1 through 120.6, inclusive, account 518, Nuclear Fuel Expense and account 157, Nuclear Materials Held for Sale. These records shall be so kept as to readily furnish the basis of the computation of the net nuclear fuel costs.
1. Supervision and Engineering (Major Utilities).
The supervision and engineering includible in the operating expense accounts shall consist of the pay and expenses of superintendents, engineers, clerks, other employees and consultants engaged in supervising and directing the operation and maintenance of each utility function. Wherever allocations are necessary in order to arrive at the amount to be included in any account, the method and basis of allocation shall be reflected by underlying records.
1. Special tests to determine efficiency of equipment operation.
2. Preparing or reviewing budgets, estimates, and drawings relating to operation or maintenance for departmental approval.
3. Preparing instructions for operations and maintenance activities.
4. Reviewing and analyzing operating results.
5. Establishing organizational setup of departments and executing changes therein.
6. Formulating and reviewing routines of departments and executing changes therein.
7. General training and instruction of employees by supervisors whose pay is chargeable hereto. Specific instruction and training in a particular type of work is chargeable to the appropriate functional account (See Electric Plant Instruction 3(19)).
8. Secretarial work for supervisory personnel, but not general clerical and stenographic work chargeable to other accounts.
9. Consultants’ fees and expenses.
10. Meals, traveling and incidental expenses.
2. Maintenance.
A. The cost of maintenance chargeable to the various operating expense and clearing accounts includes labor, materials, overheads and other expenses incurred in maintenance work. A list of work operations applicable generally to utility plant is included hereunder. Other work operations applicable to specific classes of plant are listed in functional maintenance expense accounts.
B. Materials recovered in connection with the maintenance of property shall be credited to the same account to which the maintenance cost was charged.
C. If the book cost of any property is carried in account 102, Electric Plant Purchased or Sold, the cost of maintaining such property shall be charged to the accounts for maintenance of property of the same class and use, the book cost of which is carried in other electric plant in service accounts. Maintenance of property leased from others shall be treated as provided in operating expense instruction 3.
1. Direct field supervision of maintenance.
2. Inspecting, testing, and reporting on condition of plant specifically to determine the need for repairs, replacements, rearrangements and changes and inspecting and testing the adequacy of repairs which have been made.
3. Work performed specifically for the purpose of preventing failure, restoring serviceability or maintaining life of plant.
4. Rearranging and changing the location of plant not retired.
5. Repairing for reuse materials recovered from plant.
6. Testing for locating and clearing trouble.
7. Net cost of installing, maintaining, and removing temporary facilities to prevent interruptions in service.
8. Replacing or adding minor items of plant which do not constitute a retirement unit. (See electric plant instruction 10.)
3. Rents.
A. The rent expense accounts provided under the several functional groups of expense accounts shall include all rents, including taxes paid by the lessee on leased property, for property used in utility operations, except (1) minor amounts paid for occasional or infrequent use of any property or equipment and all amounts paid for use of equipment that, if owned, would be includible in plant accounts 391 to 398, inclusive, which shall be treated as an expense item and included in the appropriate functional account and (2) rents which are chargeable to clearing accounts, and distributed therefrom to the appropriate account. If rents cover property used for more than one function, such as production and transmission, or by more than one department, the rents shall be apportioned to the appropriate rent expense or clearing accounts of each department on an actual, or, if necessary, an estimated basis.
B. When a portion of property or equipment rented from others for use in connection with utility operations is subleased, the revenue derived from such subleasing shall be credited to the rent revenue account in operating revenues; provided, however, that in case the rent was charged to a clearing account, amounts received from subleasing the property shall be credited to such clearing account.
C. The cost, when incurred by the lessee, of operating and maintaining leased property, shall be charged to the accounts appropriate for the expense if the property were owned.
D. The cost incurred by the lessee of additions and replacements to electric plant leased from others shall be accounted for as provided in electric plant instruction 6.
4. Training Costs.
When it is necessary that employees be trained to specifically operate or maintain plant facilities that are being constructed, the related costs shall be accounted for as a current operating and maintenance expense. These expenses shall be charged to the appropriate functional accounts currently as they are incurred. However, when the training costs involved relate to facilities which are not conventional in nature, or are new to the company’s operations, then see Electric Plant Instruction 3(19), for accounting.
A. This account shall include the original cost of electric plant, included in accounts 301 to 399, prescribed herein, owned and used by the utility in its electric utility operations, and having an expectation of life in service of more than one year from date of installation, including such property owned by the utility but held by nominees. (See also account 106 for unclassified construction costs of completed plant actually in service.)
B. The cost of additions to and betterments of property leased from others, which are includible in this account, shall be recorded in subdivisions separate and distinct from those relating to owned property. (See electric plant instruction 6.)
A. This account shall include the amount recorded under capital leases for plant leased from others and used by the utility in its utility operations.
B. The electric property included in this account shall be classified separately according to the detailed accounts (301 to 399) prescribed for electric plant in service.
C. Records shall be maintained with respect to each capital lease reflecting: (1) name of lessor, (2) basic details of lease, (3) terminal date, (4) original cost or fair market value of property leased, (5) future minimum lease payments, (6) executory costs, (7) present value of minimum lease payments, (8) the amount representing interest and the interest rate used, and (9) expenses paid. Records shall also be maintained for plant under a lease, to identify the asset retirement obligation and cost originally recognized for each lease and the periodic charges and credits made to the asset retirement obligations and asset retirement costs.
A. This account shall be charged with the cost of electric plant acquired as an operating unit or system by purchase, merger, consolidation liquidation, or otherwise, and shall be credited with the selling price of like property transferred to others pending the distribution to appropriate accounts in accordance with electric plant instruction 5.
B. Within six months from the date of acquisition or sale of property recorded herein, the utility shall file with the Commission the proposed journal entries to clear from this account the amounts recorded herein.
A. This account shall include the cost of electric plant which was constructed as a research, development, and demonstration plant under the provisions of paragraph C, Account 107, Construction Work in Progress—Electric, and due to the nature of the plant it is desirous to operate it for a period of time in an experimental status.
B. Amounts in this account shall be transferred to Account 101, Electric Plant in Service, or Account 121, Nonutility Property as appropriate when the project is no longer considered as experimental.
C. The depreciation on plant in this account shall be charged to account 403, Depreciation expense, and account 403.1, Depreciation expense for asset retirement costs, as appropriate, and credited to account 108, Accumulated provision for depreciation of electric utility plant (Major only). The amounts herein shall be depreciated over a period which corresponds to the estimated useful life of the relevant project considering the characteristics involved. However, when projects are transferred to account 101, Electric plant in service, a new depreciation rate based on the remaining service life and undepreciated amounts, will be established.
D. Records shall be maintained with respect to each unit of experiment so that full details may be obtained as to the cost, depreciation and the experimental status.
E. Should it be determined that experimental plant recorded in this account will fail to satisfactorily perform its function, the costs thereof shall be accounted for as directed or authorized by the Commission.
A. This account shall include temporarily the balance of electric plant as of the effective date of the prior system of accounts, which has not yet been reclassified as of the effective date of this system of accounts. The detail or primary accounts in support of this account employed prior to such date shall be continued pending reclassification into the electric plant accounts herein prescribed (301–399), but shall not be used for additions, betterments, or new construction.
B. No charges other than as provided in paragraph A, above, shall be made to this account, but retirements of such unclassified electric plant shall be credited hereto and to the supporting (old) fixed capital accounts until the reclassification shall have been accomplished.
A. This account shall include the original cost of electric plant owned by the utility, but leased to others as operating units or systems, where the lessee has exclusive possession.
B. The property included in this account shall be classified according to the detailed accounts (301 to 399) prescribed for electric plant in service and this account shall be maintained in such detail as though the property were used by the owner in its utility operations.
A. This account shall include the original cost of electric plant (except land and land rights) owned and held for future use in electric service under a definite plan for such use, to include: (1) Property acquired (except land and land rights) but never used by the utility in electric service, but held for such service in the future under a definite plan, and (2) property (except land and land rights) previously used by the utility in service, but retired from such service and held pending its reuse in the future, under a definite plan, in electric service.
B. This account shall also include the original cost of land and land rights owned and held for future use in electric service under a plan for such use, to include land and land rights: (1) Acquired but never used by the utility in electric service, but held for such service in the future under a plan, and (2) previously held by the utility in service, but retired from such service and held pending its reuse in the future under a plan, in electric service. (See Electric Plant Instruction 7.)
C. In the event that property recorded in this account shall no longer be needed or appropriate for future utility operations, the company shall request Commission approval of journal entries to remove such property from this account when the gain realized from the sale or other disposition of the property is $100,000 or more, prior to their being recorded. Such filings shall include the description and original cost of individual properties removed from this account, the accounts charged upon removal, and any associated gains realized upon disposition of such property.
D. Gains or losses from the sale of land and land rights or other disposition of such property previously recorded in this account and not placed in utility service shall be recorded directly in accounts 411.6 or 411.7, as appropriate, except when determined to be significant by the Commission. Upon such a determination, the amounts shall be transferred to account 256, Deferred Gains from Disposition of Utility Plant, or account 187, Deferred Losses from Disposition of Utility Plant, and amortized to accounts 411.6, Gains from Disposition of Utility Plant, or 411.7, Losses from Disposition of Utility Plant, as appropriate.
E. The property included in this account shall be classified according to the detail accounts (301 to 399) prescribed for electric plant in service and the account shall be maintained in such detail as though the property were in service.
Materials and supplies, meters and transformers held in reserve, and normal spare capacity of plant in service shall not be included in this account.
At the end of the year or such other date as a balance sheet may be required by the Commission, this account shall include the total of the balances of work orders for electric plant which has been completed and placed in service but which work orders have not been classified for transfer to the detailed electric plant accounts.
For the purpose of reporting to the Commission the classification of electric plant in service by accounts is required, the utility shall also report the balance in this account tentatively classified as accurately as practicable according to prescribed account classifications. The purpose of this provision is to avoid any significant omissions in reported amounts of electric plant in service.
A. This account shall include the total of the balances of work orders for electric plant in process of construction.
B. Work orders shall be cleared from this account as soon as practicable after completion of the job. Further, if a project, such as a hydroelectric project, a steam station or a transmission line, is designed to consist of two or more units or circuits which may be placed in service at different dates, any expenditures which are common to and which will be used in the operation of the project as a whole shall be included in electric plant in service upon the completion and the readiness for service of the first unit. Any expenditures which are identified exclusively with units of property not yet in service shall be included in this account.
C. Expenditures on research, development, and demonstration projects for construction of utility facilities are to be included in a separate subdivision in this account. Records must be maintained to show separately each project along with complete detail of the nature and purpose of the research, development, and demonstration project together with the related costs.
A. This account shall be credited with the following:
(1) Amounts charged to account 403, Depreciation Expense, or to clearing accounts for current depreciation expense for electric plant in service.
(2) Amounts charged to account 403.1, Depreciation expense for asset retirement costs, for current depreciation expense related to asset retirement costs in electric plant in service in a separate subaccount.
(3) Amounts charged to account 421, Miscellaneous Nonoperating Income, for depreciation expense on property included in account 105, Electric Plant Held for Future Use. Include, also, the balance of accumulated provision for depreciation on property when transferred to account 105, Electric Plant Held for Future Use, from other property accounts. Normally account 108 will not be used for current depreciation provisions because, as provided herein, the service life during which depreciation is computed commences with the date property is includible in electric plant in service; however, if special circumstances indicate the propriety of current accruals for depreciation, such charges shall be made to account 421, Miscellaneous Nonoperating Income.
(4) Amounts charged to account 413, Expenses of Electric Plant Leased to Others, for electric plant included in account 104, Electric Plant Leased to Others.
(5) Amounts charged to account 416, Costs and Expenses of Merchandising, Jobbing, and Contract Work, or to clearing accounts for current depreciation expense.
(6) Amounts of depreciation applicable to electric properties acquired as operating units or systems. (See electric plant instruction 5.)
(7) Amounts charged to account 182, Extraordinary Property Losses, when authorized by the Commission.
(8) Amounts of depreciation applicable to electric plant donated to the utility.
(The utility shall maintain separate subaccounts for depreciation applicable to electric plant in service, electric plant leased to others and electric plant held for future use.)
B. At the time of retirement of depreciable electric utility plant, this account shall be charged with the book cost of the property retired and the cost of removal and shall be credited with the salvage value and any other amounts recovered, such as insurance. When retirement, costs of removal and salvage are entered originally in retirement work orders, the net total of such work orders may be included in a separate subaccount hereunder. Upon completion of the work order, the proper distribution to subdivisions of this account shall be made as provided in the following paragraph.
C. For general ledger and balance sheet purposes, this account shall be regarded and treated as a single composite provision for depreciation. For purposes of analysis, however, each utility shall maintain subsidiary records in which this account is segregated according to the following functional classification for electric plant:
(1) Steam production,
(2) Nuclear production,
(3) Hydraulic production,
(4) Other production,
(5) Transmission,
(6) Distribution,
(7) Regional Transmission and Market Operation, and
(8) General.
These subsidiary records shall reflect the current credits and debits to this account in sufficient detail to show separately for each such functional classification:
(a) The amount of accrual for depreciation,
(b) The book cost of property retired,
(c) Cost of removal,
(d) Salvage, and
(e) Other items, including recoveries from insurance.
Separate subsidiary records shall be maintained for the amount of accrued cost of removal other than legal obligations for the retirement of plant recorded in Account 108, Accumulated provision for depreciation of electric utility plant (Major only).
D. When transfers of plant are made from one electric plant account to another, or from or to another utility department, or from or to nonutility property accounts, the accounting for the related accumulated provision for depreciation shall be as provided in electric plant instruction 12.
E. The utility is restricted in its use of the accumulated provision for depreciation to the purposes set forth above. It shall not transfer any portion of this account to retained earnings or make any other use thereof without authorization by the Commission.
A. This account shall be credited with the following:
(1) Amounts charged to account 403 Depreciation Expense, to account 404 Amortization of Limited-Term Electric Plant, to account 405, Amortization of Other Electric Plant, to account 413, Expenses of Electric Plant Leased to Others, to account 416. Costs and Expenses of Merchandising, Jobbing and Contract Work, or to clearing accounts for currently accruing depreciation and amortization.
(2) Amounts charged to account 403.1, Depreciation expense for asset retirement costs, in electric utility plant in service in a separate subaccount.
(3) Amounts of depreciation applicable to electric properties acquired as operating units or systems. (See electric plant instruction 4.)
(4) Amounts chargeable to account 182, Extraordinary Property Losses, when authorized by the Commission.
(5) Amounts of depreciation applicable to electric plant donated to the utility.
B. At the time of retirement of electric plant, this account shall be charged with the book cost of the property retired and the cost of removal, and shall be credited with the salvage value and any other amounts recovered, such as insurance. When retirements, cost of removal and salvage are entered originally in retirement work orders, the net total of such work orders may be included in a separate subaccount hereunder. Upon completion of the work order, the proper distribution to subdivisions of this account shall be made as provided in the following paragraph.
C. For general ledger and balance sheet purposes, this account shall be regarded and treated as a single composite provision for depreciation. This account shall be subdivided to show the amount applicable to Electric Plant in Service, Electric Plant Leased to Others, and Electric Plant Held for Future Use. These subsidiary records shall show the current credits and debits to this account in sufficient detail to show separately for each subdivision, (1) the amount of accrual for depreciation or amortization, (2) the book cost of property retired, (3) cost of removal, (4) salvage and (5) other items, including recoveries from insurance. Separate subsidiary records shall be maintained for the amount of accrued cost of removal other than legal obligations for the retirement of plant recorded in account 110, Accumulated provision for depreciation of electric utility plant (Nonmajor only).
D. When transfers of plant are made from one electric plant account to another, or form or to nonutility property, the accounting shall be as provided in electric plant instruction 10.
E. The utility is restricted in its use of the accumulated provision for depreciation to the purposes set forth above. It shall not transfer any portion of this account to retained earnings or make any other use thereof without authorization by the Commission.
A. This account shall be credited with the following:
(1) Amounts charged to account 404, Amortization of Limited-Term Electric Plant, for the current amortization of limited-term electric plant investments.
(2) Amounts charged to account 421, Miscellaneous Nonoperating Income, for amortization expense on property included in account 105, Electric Plant Held for Future Use. Include also the balance of accumulated provision for amortization on property when transferred to account 105, Electric Plant Held for Future Use, from other property accounts. See also paragraph A(2), account 108, Accumulated Provision for Depreciation of Electric Utility Plant.
(3) Amounts charged to account 405, Amortization of Other Electric Plant.
(4) Amounts charged to account 413, Expenses of Electric Plant Leased to Others, for the current amortization of limited-term or other investments subject to amortization included in account 104, Electric Plant Leased to Others.
(5) Amounts charged to account 425, Miscellaneous Amortization, for the amortization of intangible or other electric plant which does not have a definite or terminable life and is not subject to charges for depreciation expense, with Commission approval.
(The utility shall maintain subaccounts of this account for the amortization applicable to electric plant in service, electric plant leased to others and electric plant held for future use.)
B. When any property to which this account applies is sold, relinquished, or otherwise retired from service, this account shall be charged with the amount previously credited in respect to such property. The book cost of the property so retired less the amount chargeable to this account and less the net proceeds realized at retirement shall be included in account 421.1, Gain on Disposition of Property, or account 421.2, Loss on Disposition of Property, as appropriate.
C. For general ledger and balance sheet purposes, this account shall be regarded and treated as a single composite provision for amortization. For purposes of analysis, however, each utility shall maintain subsidiary records in which this account is segregated according to the following functional classification for electric plant: (1) Steam production, (2) nuclear production, (3) hydraulic production, (4) other production, (5) transmission, (6) distribution, and (7) general. These subsidiary records shall reflect the current credits and debits to this account in sufficient detail to show separately for each such functional classification (a) the amount of accrual for amortization, (b) the book cost of property retired, (c) cost of removal, (d) salvage, and (e) other items, including recoveries from insurance.
D. The utility is restricted in its use of the accumulated provision for amortization to the purposes set forth above. It shall not transfer any portion of this account to retained earnings or make any other use thereof without authorization by the Commission.
A. This account shall include the difference between (1) the cost to the accounting utility of electric plant acquired as an operating unit or system by purchase, merger, consolidation, liquidation, or otherwise, and (2) the original cost, estimated, if not known, of such property, less the amount or amounts credited by the accounting utility at the time of acquisition to accumulated provisions for depreciation and amortization and contributions in aid of construction with respect to such property.
B. With respect to acquisitions after the effective date of this system of accounts, this account shall be subdivided so as to show the amounts included herein for each property acquisition and to electric plant in service, electric plant held for future use, and electric plant leased to others. (See electric plant instruction 5.)
C. Debit amounts recorded in this account related to plant and land acquisition may be amortized to account 425, Miscellaneous Amortization, over a period not longer than the estimated remaining life of the properties to which such amounts relate. Amounts related to the acquisition of land only may be amortized to account 425 over a period of not more than 15 years. Should a utility wish to account for debit amounts in this account in any other manner, it shall petition the Commission for authority to do so. Credit amounts recorded in this account shall be accounted for as directed by the Commission.
This account shall be credited or debited with amounts which are includible in account 406. Amortization of Electric Plant Acquisition Adjustments or account 425, Miscellaneous Amortization, for the purpose of providing for the extinguishment of amounts in account 114, Electric Plant Acquisition Adjustments, in instances where the amortization of account 114 is not being made by direct write-off of the account.
A. This account shall include the difference between the original cost, estimated if not known, and the book cost of electric plant to the extent that such difference is not properly includible in account 114, Electric Plant Acquisition Adjustments. (See electric plant instruction 1C).
B. Amounts included in this account shall be classified in such manner as to show the origin of each amount and shall be disposed of as the Commission may approve or direct.
The provisions of this account shall not be construed as approving or authorizing the recording of appreciation of electric plant.
This account shall include the balances in accounts for utility plant, other than electric plant, such as gas, railway, etc.
This account shall include the accumulated provision for depreciation and amortization applicable to utility property other than electric plant.
A. This account shall include the original cost to the utility of nuclear fuel materials while in process of refinement, conversion, enrichment, and fabrication into nuclear fuel assemblies and components, including processing, fabrication, and necessary shipping costs. This account shall also include the salvage value of nuclear materials which are actually being reprocessed for use and were transferred from account 120.5, Accumulated Provision for Amortization of Nuclear Fuel Assemblies. (See definition 20.)
B. This account shall be credited and account 120.2, Nuclear Fuel Materials and Assemblies—Stock Account, shall be debited for the cost of completed fuel assemblies delivered for use in refueling or to be held as spares. In the case of the initial core loading, the transfer shall be made directly to account 120.3, Nuclear Fuel Assemblies in Reactor, upon the conclusion of the experimental or test period of the plant prior to its becoming available for service.
1. Cost of natural uranium, uranium ores concentrates or other nuclear fuel sources, such as thorium, plutonium, and U–233.
2. Value of recovered nuclear materials being reprocessed for use.
3. Milling process costs.
4. Sampling and weighing, and assaying costs.
5. Purification and conversion process costs.
6. Costs of enrichment by gaseous diffusion or other methods.
7. Costs of fabrication into fuel forms suitable for insertion in the reactor.
8. All shipping costs of materials and components, including shipping of fabricated fuel assemblies to the reactor site.
9. Use charges on leased nuclear materials while in process of refinement, conversion, enrichment, and fabrication.
A. This account shall be debited and account 120.1, Nuclear Fuel in Process of Refinement, Conversion, Enrichment, and Fabrication, shall be credited with the cost of fabricated fuel assemblies delivered for use in refueling or to be carried in stock as spares. It shall also include the original cost of fabricated fuel assemblies purchased in completed form. This account shall also include the original cost of partially irradiated fuel assemblies being held in stock for reinsertion in a reactor which had been transferred from account 120.3, Nuclear Fuel Assemblies in Reactor.
B. When fuel assemblies included in this account are inserted in a reactor, this account shall be credited and account 120.3, Nuclear Fuel Assemblies in Reactor, debited for the cost of such assemblies.
C. This account shall also include the cost of nuclear materials and byproduct materials being held for future use and not actually in process in account 120.1, Nuclear Fuel in Process of Refinement, Conversion, Enrichment, and Fabrication.
A. This account shall include the cost of nuclear fuel assemblies when inserted in a reactor for the production of electricity. The amounts included herein shall be transferred from account 120.2, Nuclear Fuel Materials and Assemblies—Stock Account, except for the initial core loading which will be transferred directly from account 120.1.
B. Upon removal of fuel assemblies from a reactor, the original cost of the assemblies removed shall be transferred to account 120.4, Spent Nuclear Fuel or account 120.2, Nuclear Fuel Materials and Assemblies—Stock Account, as appropriate.
A. This account shall include the original cost of nuclear fuel assemblies, in the process of cooling, transferred from account 120.3, Nuclear Fuel Assemblies in Reactor, upon removal from a reactor pending reprocessing.
B. This account shall be credited and account 120.5, Accumulated Provision for Amortization of Nuclear Fuel Assemblies, debited for fuel assemblies, after the cooling period is over, at the cost recorded in this account.
A. This account shall be credited and account 518, Nuclear fuel expense shall be debited for the amortization of the net cost of nuclear fuel assemblies used in the production of energy. The net cost of nuclear fuel assemblies subject to amortization shall be the original cost of nuclear fuel assemblies, plus or less the expected net salvage value of uranium, plutonium, and other by-products.
B. This account shall be credited with the net salvage value of uranium, plutonium, and other nuclear by-products when such items are sold, transferred or otherwise disposed of. Account 120.1, Nuclear Fuel in Process of Refinement, Conversion, Enrichment, and Fabrication, shall be debited with the net salvage value of nuclear materials to be reprocessed. Account 157, Nuclear Materials Held for Sale shall be debited for the net salvage value of nuclear materials not to be reprocessed but to be sold or otherwise disposed of and account 120.2, will be debited with the net salvage value of nuclear materials that will be held for future use and not actually in process, in account 120.1, Nuclear Fuel in Process of Refinement, Conversion, Enrichment, and Fabrication.
C. This account shall be debited and account 120.4, Spent Nuclear Fuel, shall be credited with the cost of fuel assemblies at the end of the cooling period.
A. This account shall include the amount recorded under capital leases for nuclear fuel leased from others for use by the utility in its utility operations.
B. Records shall be maintained with respect to each capital lease reflecting: (1) Name of lessor, (2) basic details of lease, (3) terminal date, (4) original cost or fair market value of nuclear fuel leased, (5) future minimum lease payments, (6) executory costs, (7) present value of minimum lease payments, (8) the amount representing interest and the interest rate used, and (9) expenses paid.
A. This account shall include the book cost of land, structures, equipment, or other tangible or intangible property owned by the utility, but not used in utility service and not properly includible in account 105, Electric Plant Held for Future Use. This account shall also include, where applicable, amounts recorded for asset retirement costs associated with nonutility plant.
B. This account shall also include the amount recorded under capital leases for property leased from others and used by the utility in its nonutility operations. Records shall be maintained with respect to each lease reflecting: (1) name of lessor, (2) basic details of lease, (3) terminal date, (4) original cost or fair market value of property leased, (5) future minimum lease payments, (6) executory costs, (7) present value of minimum lessee payments, (8) the amount representing interest and the interest rate used, and (9) expenses paid.
C. This account shall be subdivided so as to show the amount of property used in operations which are nonutility in character but nevertheless constitute a distinct operating activity of the company (such as operation of an ice department where such activity is not classed as a utility) and the amount of miscellaneous property not used in operations. The records in support of each subaccount shall be maintained so as to show an appropriate classification of the property.
The gain from the sale or other disposition of property included in this account which had been previously recorded in account 105, Electric Plant Held for Future Use, shall be accounted for in accordance with paragraph C of account 105.
This account shall include the accumulated provision for depreciation and amortization applicable to nonutility property.
A. This account shall include the book cost of investments in securities issued or assumed by associated companies and investment advances to such companies, including interest accrued thereon when such interest is not subject to current settlement, provided that the investment does not relate to a subsidiary company. (If the investment relates to a subsidiary company it shall be included in account 123.1, Investment in Subsidiary Companies.) Include herein the offsetting entry to the recording of amortization of discount or premium on interest bearing investments. (See account 419, Interest and Dividend Income.)
B. This account shall be maintained in such manner as to show the investment in securities of, and advances to, each associated company together with full particulars regarding any of such investments that are pledged.
Securities and advances of associated companies owned and pledged shall be included in this account, but such securities, if held in special deposits or in special funds, shall be included in the appropriate deposit or fund account. A complete record of securities pledged shall be maintained.
Securities of associated companies held as temporary cash investments are includible in account 136, Temporary Cash Investments.
Balances in open accounts with associated companies, which are subject to current settlement, are includible in account 146, Accounts Receivable from Associated Companies.
The utility may write down the cost of any security in recognition of a decline in the value thereof. Securities shall be written off or written down to a nominal value if there is no reasonable prospect of substantial value. Fluctuations in market value shall not be recorded but a permanent impairment in the value of securities shall be recognized in the accounts. When securities are written off or written down, the amount of the adjustment shall be charged to account 426.5, Other Deductions, or to an appropriate account for accumulated provisions for loss in value established as a separate subdivision of this account.
A. This account shall include the cost of investments in securities issued or assumed by subsidiary companies and investment advances to such companies, including interest accrued thereon when such interest is not subject to current settlement plus the equity in undistributed earnings or losses of such subsidiary companies since acquisition. This account shall be credited with any dividends declared by such subsidiaries.
B. This account shall be maintained in such a manner as to show separately for each subsidiary: the cost of such investments in the securities of the subsidiary at the time of acquisition; the amount of equity in the subsidiary’s undistributed net earnings or net losses since acquisition; advances or loans to such subsidiary; and full particulars regarding any such investments that are pledged.
A. This account shall include the book cost of investments in securities issued or assumed by nonassociated companies, investment advances to such companies, and any investments not accounted for elsewhere. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments. Include also the offsetting entry to the recording of amortization of discount or premium on interest bearing investments. (See account 419, interest and dividend income.)
B. The cost of capital stock of the utility reacquired by it under a definite plan for resale pursuant to authorization by the Board of Directors may, if permitted by statutes, be included in a separate subdivision of this account. (See also account 210, Gain on Resale or Cancellation of Reacquired Capital Stock, and account 217, Reacquired Capital Stock.)
C. The records shall be maintained in such manner as to show the amount of each investment and the investment advances to each person.
Securities owned and pledged shall be included in this account, but securities held in special deposits or in special funds shall be included in appropriate deposit or fund accounts. A complete record of securities pledged shall be maintained.
Securities held as temporary cash investments shall not be included in this account.
Special funds. See Note D of account 123.
This account shall include the amount of cash and book cost of investments held in sinking funds. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments. A separate account, with appropriate title, shall be kept for each sinking fund. Transfers from this account to special deposit accounts may be made as necessary for the purpose of paying matured sinking-fund obligations, or obligations called for redemption but not presented, or the interest thereon.
This account shall include the amount of cash and book cost of investments which have been segregated in a special fund for the purpose of identifying such assets with the accumulated provisions for depreciation. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments.
This account shall include the amount of cash and book cost of investments of any investments of any fund maintained pursuant to the requirements of a federal regulatory body, as the cash and investments segregated for the purpose of identifying the specific assets associated with account 215.1, appropriated retained earnings—amortization reserve, federal. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments.
This account shall include the amount of cash and book cost of investments which have been segregated in special funds for insurance, employee pensions, savings, relief, hospital, and other purposes not provided for elsewhere. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments. A separate account with appropriate title, shall be kept for each fund.
Amounts deposited with a trustee under the terms of an irrevocable trust agreement for pensions or other employee benefits shall not be included in this account.
Special Instructions for Current and Accrued Assets. Current and accrued assets are cash, those assets which are readily convertible into cash or are held for current use in operations or construction, current claims against others, payment of which is reasonably assured, and amounts accruing to the utility which are subject to current settlement, except such items for which accounts other than those designated as current and accrued assets are provided. There shall not be included in the group of accounts designated as current and accrued assets any item, the amount or collectibility of which is not reasonably assured, unless an adequate provision for possible loss has been made therefor. Items of current character but of doubtful value may be written down and for record purposes carried in these accounts at nominal value.
This account shall include the amount of cash and book cost of investments which have been segregated in special funds for bond retirements, property additions and replacements, insurance, employees’ pensions, savings, relief, hospital, and other purposes not provided for elsewhere. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments. A separate account, with appropriate title, shall be kept for each fund.
Amounts deposited with a trustee under the terms of an irrevocable trust agreement for pensions or other employees benefits shall not be included in this account.
Licensees under the Federal Power Act which are required to establish an amortization fund under terms of the license shall provide a special subdivision of this account for the purpose of accounting for and identifying the cash, investments or other specific assets associated with account 215.1, Appropriated Retained Earnings—Amortization Reserve, Federal.
Special Instructions for Current and Accrued Assets. Current and accrued assets are cash, those assets which are readily convertible into cash or are held for current use in operations or construction, current claims against others, payment of which is reasonably assured, and amounts accruing to the utility which are subject to current settlement, except such items for which accounts other than those designated as current and accrued assets are provided. There shall not be included in the group of accounts designated as current and accrued assets any item, the amount or collectibility of which is not reasonably assured, unless an adequate provision for possible loss has been made therefor. Items of current character but of doubtful value may be written down and for record purposes carried in these accounts at nominal value.
This account shall include the amount of cash on hand and in banks and cash advanced to officers, agents, employees, and others as petty cash or working funds. Special cash deposits for payment of interest, dividends or other special purposes shall be included in this account in separate subdivisions which shall specify the purpose for which each such special deposit is made.
Special Deposits for more than one year which are not offset by current liabilities, shall not be charged to this account but to account 125, Special Funds.
This account shall include the amount of current cash funds except working funds.
This account shall include special deposits with fiscal agents or others for the payment of interest.
This account shall include special deposits with fiscal agents or others for the payment of dividends.
This account shall include deposits with fiscal agents or others for special purposes other than the payment of interest and dividends. Such special deposits may include cash deposited with federal, state, or municipal authorities as a guaranty for the fulfillment of obligations; cash deposited with trustees to be held until mortgaged property sold, destroyed, or otherwise disposed of is replaced; cash realized from the sale of the accounting utility’s securities and deposited with trustees to be held until invested in property of the utility, etc. Entries to this account shall specify the purpose for which the deposit is made.
Assets available for general corporate purposes shall not be included in this account. Further, deposits for more than one year, which are not offset by current liabilities, shall not be charged to this account but to account 128, Other Special Funds.
This account shall include cash advanced to officers, agents, employees, and others as petty cash or working funds.
A. This account shall include the book cost of investments, such as demand and time loans, bankers’ acceptances, United States Treasury certificates, marketable securities, and other similar investments, acquired for the purpose of temporarily investing cash.
B. This account shall be so maintained as to show separately temporary cash investments in securities of associated companies and of others. Records shall be kept of any pledged investments.
This account shall include the book cost, not includible elsewhere, of all collectible obligations in the form of notes receivable and similar evidences (except interest coupons) of money due on demand or within one year from the date of issue, except, however, notes receivable from associated companies. (See account 136, Temporary Cash Investments, and account 145, Notes Receivable from Associated Companies.)
The face amount of notes receivable discounted, sold, or transferred without releasing the utility from liability as endorser thereon, shall be credited to a separate subdivision of this account and appropriate disclosure shall be made in financial statements of any contingent liability arising from such transactions.
A. This account shall include amounts due from customers for utility service, and for merchandising, jobbing and contract work. This account shall not include amounts due from associated companies.
B. This account shall be maintained so as to permit ready segregation of the amounts due for merchandising, jobbing and contract work.
A. This account shall include amounts due the utility upon open accounts, other than amounts due from associated companies and from customers for utility services and merchandising, jobbing and contract work.
B. This account shall be maintained so as to show separately amounts due on subscriptions to capital stock and from officers and employees, but the account shall not include amounts advanced to officers or others as working funds. (See account 135, Working Funds.)
A. This account shall be credited with amounts provided for losses on accounts receivable which may become uncollectible, and also with collections on accounts previously charged hereto. Concurrent charges shall be made to account 904, Uncollectible Accounts, for amounts applicable to utility operations, and to corresponding accounts for other operations. Records shall be maintained so as to show the write-offs of account receivable for each utility department.
B. This account shall be subdivided to show the provision applicable to the following classes of accounts receivable:
Accretions to this account shall not be made in excess of a reasonable provision against losses of the character provided for.
If provisions for uncollectible notes receivable or for uncollectible receivables from associated companies are necessary, separate subaccounts therefor shall be established under the account in which the receivable is carried.
A. These accounts shall include notes and drafts upon which associated companies are liable, and which mature and are expected to be paid in full not later than one year from the date of issue, together with any interest thereon, and debit balances subject to current settlement in open accounts with associated companies. Items which do not bear a specified due date but which have been carried for more than twelve months and items which are not paid within twelve months from due date shall be transferred to account 123, Investment in Associated Companies.
B. A public utility or licensee participating in a cash management program must maintain supporting documentation for all deposits into, borrowings from, interest income from, and interest expense to such program. Cash management programs include all agreements in which funds in excess of the daily needs of the public utility or licensee along with the excess funds of the public utility’s or licensee’s parent, affiliated and subsidiary companies are concentrated, consolidated, or otherwise made available for use by other entities within the corporate group. The written documentation must include the following information:
(1) For deposits with and withdrawals from the cash management program: the date of the deposit or withdrawal, the amount of the deposit or withdrawal, and the maturity date, if any, of the deposit;
(2) For borrowings from a cash management program: the date of the borrowing, the amount of the borrowing, and the maturity date, if any, of the borrowing;
(3) The security, if any, provided by the cash management program for repayment of deposits into the cash management program and the security required, if any, by the cash management program in support of borrowings from the program; and
(4) The monthly balance of the cash management program.
C. The public utility or licensee must maintain current and up-to-date copies of the documents authorizing the establishment of the cash management program including the following:
(1) The duties and responsibilities of the administrator and the public utilities or licensees in the cash management program;
(2) The restrictions on deposits or borrowings by public utilities or licensees in the cash management program;
(3) The interest rate, including the method used to determine the interest earning rates and interest borrowing rates for deposits into and borrowings from the program; and
(4) The method used to allocate interest income and expenses among public utilities or licensees in the program.
On the balance sheet, accounts receivable from an associated company may be set off against accounts payable to the same company.
The face amount of notes receivable discounted, sold or transferred without releasing the utility from liability as endorser thereon, shall be credited to a separate subdivision of this account and appropriate disclosure shall be made in financial statements of any contingent liability arising from such transactions.
This account shall include the book cost of fuel on hand.
1. Invoice price of fuel less any cash or other discounts.
2. Freight, switching, demurrage and other transportation charges, not including, however, any charges for unloading from the shipping medium.
3. Excise taxes, purchasing agents’ commissions, insurance and other expenses directly assignable to cost of fuel.
4. Operating, maintenance and depreciation expenses and ad valorem taxes on utility-owned transportation equipment used to transport fuel from the point of acquisition to the unloading point.
5. Lease or rental costs of transportation equipment used to transport fuel from the point of acquisition to the unloading point.
A. This account may include the cost of labor and of supplies used and expenses incurred in unloading fuel from the shipping medium and in the handling thereof prior to its use, if such expenses are sufficiently significant in amount to warrant being treated as a part of the cost of fuel inventory rather than being charged direct to expense as incurred.
B. Amounts included herein shall be charged to expense as the fuel is used to the end that the balance herein shall not exceed the expenses attributable to the inventory of fuel on hand.
1. Procuring and handling of fuel.
2. All routine fuel analyses.
3. Unloading from shipping facility and putting in storage.
4. Moving of fuel in storage and transferring from one station to another.
5. Handling from storage or shipping facility to first bunker, hopper, bucket, tank or holder of boiler house structure.
6. Operation of mechanical equipment, such as locomotives, trucks, cars, boats, barges, cranes, etc.
7. Tools, lubricants and other supplies.
8. Operating supplies for mechanical equipment.
9. Transportation and other expenses in moving fuel.
10. Stores expenses applicable to fuel.
This account shall include the book cost of any residuals produced in production or manufacturing processes.
A. This account shall include the cost of materials purchased primarily for use in the utility business for construction, operation and maintenance purposes. For Nonmajor utilities, this account shall include the cost of fuel on hand and unapplied materials and supplies (except meters and house regulators). For both Major and Nonmajor utilities, it shall include also the book cost of materials recovered in connection with construction, maintenance or the retirement of property, such materials being credited to construction, maintenance or accumulated depreciation provision, respectively, and included herein as follows:
(1) Reusable materials consisting of large individual items shall be included in this account at original cost, estimated if not known. The cost of repairing such items shall be charged to the maintenance account appropriate for the previous use.
(2) Reusable materials consisting of relatively small items, the identity of which (from the date of original installation to the final abandonment or sale thereof) cannot be ascertained without undue refinement in accounting, shall be included in this account at current prices new for such items. The cost of repairing such items shall be charged to the appropriate expense account as indicated by previous use.
(3) Scrap and nonusable materials included in this account shall be carried at the estimated net amount realizable therefrom. The difference between the amounts realized for scrap and nonusable materials sold and the net amount at which the materials were carried in this account, as far as practicable, shall be adjusted to the accounts credited when the materials were charged to this account.
B. Materials and supplies issued shall be credited hereto and charged to the appropriate construction, operating expense, or other account on the basis of a unit price determined by the use of cumulative average, first-in-first-out, or such other method of inventory accounting as conforms with accepted accounting standards consistently applied.
C. For Nonmajor utilities, inventories of materials, supplies, fuel, etc., shall be taken at least annually and the necessary adjustments shall be made to bring this account into agreement with the actual inventories. In effecting the adjustments, large differences which can be assigned to important classes of materials shall be equitably adjusted among the accounts to which such classes of materials have been charged since the previous inventory. Other differences shall be equitably apportioned among the accounts to which materials have been charged.
1. Invoice price of materials less cash or other discounts.
2. Freight, switching or other transportation charges when practicable to include as part of the cost of particular materials to which they relate.
3. Customs duties and excise taxes.
4. Costs of inspection and special tests prior to acceptance.
5. Insurance and other directly assignable charges.
Where expenses applicable to materials purchased cannot be directly assigned to particular purchases, they may be charged to a stores expense clearing account (account 163, Stores Expense Undistributed, in the case of Major utilities), and distributed therefrom to the appropriate account.
When materials and supplies are purchased for immediate use, they need not be carried through this account but may be charged directly to the appropriate utility plant or expense account.
This account shall include the book cost of materials and supplies and appliances and equipment held primarily for merchandising, jobbing and contract work. The principles prescribed in accounting for utility materials and supplies shall be observed in respect to items carried in this account.
This account shall include the book cost of materials and supplies held primarily for nonutility purposes. The principles prescribed in accounting for utility materials and supplies shall be observed in respect to items carried in this account.
This account shall include the net salvage value of uranium, plutonium and other nuclear materials held by the company for sale or other disposition and that are not to be reused by the company in its electric utility operations. This account shall be debited and account 120.5, Accumulated Provision for Amortization of Nuclear Fuel Assemblies, credited for such net salvage value. Any difference between the amount recorded in this account and the actual amount realized from the sale of materials shall be debited or credited, as appropriate, to account 518, Nuclear Fuel Expense at the time of such sale.
A. This account shall include the cost of allowances owned by the utility and not withheld by the Environmental Protection Agency. See General Instruction No. 21 and Account 158.2, Allowances Withheld.
B. This account shall be credited and Account 509, Allowances, shall be debited concurrent with the monthly emission of sulfur dioxide.
C. Separate subdivisions of this account shall be maintained so as to separately account for those allowances usable in the current year and in each subsequent year. The underlying records of these subdivisions shall be maintained in sufficient detail so as to identify each allowance included; the origin of each allowance; and the acquisition cost, if any, of the allowance.
A. This account shall include the cost of allowances owned by the utility but withheld by the Environmental Protection Agency. (See General Instruction No. 21.)
B. The inventory cost of the allowances released by the Environmental Protection Agency for use by the utility shall be transferred to Account 158.1, Allowance Inventory.
C. The underlying records of this account shall be maintained in sufficient detail so as to identify each allowance included; the origin of each allowance; and the acquisition cost, if any, of the allowances.
A. This account shall include the cost of supervision, labor and expenses incurred in the operation of general storerooms, including purchasing, storage, handling and distribution of materials and supplies.
B. This account shall be cleared by adding to the cost of materials and supplies issued a suitable loading charge which will distribute the expense equitably over stores issues. The balance in the account at the close of the year shall not exceed the amount of stores expenses reasonably attributable to the inventory of materials and supplies exclusive of fuel, as any amount applicable to fuel costs should be included in account 152, Fuel Stock Expenses Undistributed.
1. Inspecting and testing materials and supplies when not assignable to specific items.
2. Unloading from shipping facility and putting in storage.
3. Supervision of purchasing and stores department to extent assignable to materials handled through stores.
4. Getting materials from stock and in readiness to go out.
5. Inventorying stock received or stock on hand by stores employees but not including inventories by general department employees as part of internal or general audits.
6. Purchasing department activities in checking material needs, investigating sources of supply, analyzing prices, preparing and placing orders, and related activities to extent applicable to materials handled through stores. (Optional. Purchasing department expenses may be included in administrative and general expenses.)
7. Maintaining stores equipment.
8. Cleaning and tidying storerooms and stores offices.
9. Keeping stock records, including recording and posting of material receipts and issues and maintaining inventory record of stock.
10. Collecting and handling scrap materials in stores.
11. Adjustments of inventories of materials and supplies but not including large differences which can readily be assigned to important classes of materials and equitably distributed among the accounts to which such classes of materials have been charged since the previous inventory.
12. Cash and other discounts not practically assignable to specific materials.
13. Freight, express, etc., when not assignable to specific items.
14. Heat, light and power for storerooms and store offices.
15. Brooms, brushes, sweeping compounds and other supplies used in cleaning and tidying storerooms and stores offices.
16. Injuries and damages.
17. Insurance on materials and supplies and on stores equipment.
18. Losses due to breakage, leakage, evaporation, fire or other causes, less credits for amounts received from insurance, transportation companies or others in compensation of such losses.
19. Postage, printing, stationery and office supplies.
20. Rent of storage space and facilities.
21. Communication service.
22. Excise and other similar taxes not assignable to specific materials.
23. Transportation expense on inward movement of stores and on transfer between storerooms but not including charges on materials recovered from retirements which shall be accounted for as part of cost of removal.
A physical inventory of each class of materials and supplies shall be made at least every two years.
This account shall include amounts representing prepayments of insurance, rents, taxes, interest and miscellaneous items, and shall be kept or supported in such manner as to disclose the amount of each class of prepayment.
This account shall include the amount of interest on bonds, mortgages, notes, commercial paper, loans, open accounts, deposits, etc., the payment of which is reasonably assured, and the amount of dividends declared or guaranteed on stocks owned.
Interest which is not subject to current settlement shall not be included herein but in the account in which is carried the principal on which the interest is accrued.
Interest and dividends receivable from associated companies shall be included in account 146, Accounts receivable from associated companies.
This account shall include rents receivable or accrued on property rented or leased by the utility to others.
Rents receivable from associated companies shall be included in account 146, Accounts Receivable from Associated Companies.
At the option of the utility, the estimated amount accrued for service rendered, but not billed at the end of any accounting period, may be included herein. In case accruals are made for unbilled revenues, they shall be made likewise for unbilled expenses, such as for the purchase of energy.
This account shall include the book cost of all other current and accrued assets, appropriately designated and supported so as to show the nature of each asset included herein.
This account shall include the amounts paid for derivative instruments, and the change in the fair value of all derivative instrument assets not designated as cash flow or fair value hedges. Account 421, miscellaneous nonoperating income, shall be credited or debited, as appropriate, with the corresponding amount of the change in the fair value of the derivative instrument.
A. This account shall include the amounts paid for derivative instruments, and the change in the fair value of derivative instrument assets designated by the utility as cash flow or fair value hedges.
B. When a utility designates a derivative instrument asset as a cash flow hedge it will record the change in the fair value of the derivative instrument in this account with a concurrent charge to account 219, accumulated other comprehensive income, with the effective portion of the gain or loss. The ineffective portion of the cash flow hedge shall be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
C. When a utility designates a derivative instrument as a fair value hedge it shall record the change in the fair value of the derivative instrument in this account with a concurrent charge to a subaccount of the asset or liability that carries the item being hedged. The ineffective portion of the fair value hedge shall be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
This account shall include expenses related to the issuance or assumption of debt securities. Amounts recorded in this account shall be amortized over the life of each respective issue under a plan which will distribute the amount equitably over the life of the security. The amortization shall be on a monthly basis, and the amounts thereof shall be charged to account 428, Amortization of Debt Discount and Expense. Any unamortized amounts outstanding at the time that the related debt is prematurely reacquired shall be accounted for as indicated in General Instruction 17.
A. When authorized or directed by the Commission, this account shall include extraordinary losses, which could not reasonably have been anticipated and which are not covered by insurance or other provisions, such as unforeseen damages to property.
B. Application to the Commission for permission to use this account shall be accompanied by a statement giving a complete explanation with respect to the items which it is proposed to include herein, the period over which, and the accounts to which it is proposed to write off the charges, and other pertinent information.
A. This account shall include: (1) Nonrecurring costs of studies and analyses mandated by regulatory bodies related to plants in service, transferred from account 183, Preliminary Survey and Investigation Charges, and not resulting in construction; and (2) when authorized by the Commission, significant unrecovered costs of plant facilities where construction has been cancelled or which have been prematurely retired.
B. This account shall be credited and account 407, Amortization of Property Losses, Unrecovered Plant and Regulatory Study Costs, shall be debited over the period specified by the Commission.
C. Any additional costs incurred, relative to the cancellation or premature retirement, may be included in this account and amortized over the remaining period of the original amortization period. Should any gains or recoveries be realized relative to the cancelled or prematurely retired plant, such amounts shall be used to reduce the unamortized amount of the costs recorded herein.
D. In the event that the recovery of costs included herein is disallowed in the rate proceedings, the disallowed costs shall be charged to account 426.5, Other Deductions, or account 435, Extraordinary Deductions, in the year of such disallowance.
A. This account shall include the amounts of regulatory-created assets, not includible in other accounts, resulting from the ratemaking actions of regulatory agencies. (See Definition No. 30.)
B. The amounts included in this account are to be established by those charges which would have been included in net income, or accumulated other comprehensive income, determinations in the current period under the general requirements of the Uniform System of Accounts but for it being probable that such items will be included in a different period(s) for purposes of developing rates that the utility is authorized to charge for its utility services. When specific identification of the particular source of a regulatory asset cannot be made, such as in plant phase-ins, rate moderation plans, or rate levelization plans, account 407.4, regulatory credits, shall be credited. The amounts recorded in this account are generally to be charged, concurrently with the recovery of the amounts in rates, to the same account that would have been charged if included in income when incurred, except all regulatory assets established through the use of account 407.4 shall be charged to account 407.3, regulatory debits, concurrent with the recovery in rates.
C. If rate recovery of all or part of an amount included in this account is disallowed, the disallowed amount shall be charged to Account 426.5, Other Deductions, or Account 435, Extraordinary Deductions, in the year of the disallowance.
D. The records supporting the entries to this account shall be kept so that the utility can furnish full information as to the nature and amount of each regulatory asset included in this account, including justification for inclusion of such amounts in this account.
A. This account shall be charged with all expenditures for preliminary surveys, plans, investigations, etc., made for the purpose of determining the feasibility of utility projects under contemplation. If construction results, this account shall be credited and the appropriate utility plant account charged. If the work is abandoned, the charge shall be made to account 426.5, Other Deductions, or to the appropriate operating expense account.
B. This account shall also include costs of studies and analyses mandated by regulatory bodies related to plant in service. If construction results from such studies, this account shall be credited and the appropriate utility plant account charged with an equitable portion of such study costs directly attributable to new construction. The portion of such study costs not attributable to new construction or the entire cost if construction does not result shall be charged to account 182.2, Unrecovered Plant and Regulatory Costs, or the appropriate operating expense account. The costs of such studies relative to plant under construction shall be included directly in account 107, Construction Work in Progress-Electric.
C. The records supporting the entries to this account shall be so kept that the utility can furnish complete information as to the nature and the purpose of the survey, plans, or investigations and the nature and amounts of the several charges.
The amount of preliminary survey and investigation charges transferred to utility plant shall not exceed the expenditures which may reasonably be determined to contribute directly and immediately and without duplication to utility plant.
This caption shall include undistributed balances in clearing accounts at the date of the balance sheet. Balances in clearing accounts shall be substantially cleared not later than the end of the calendar year unless items held therein relate to a future period.
This account shall include amounts shown by work orders for plant installed for temporary use in utility service for periods of less than one year. Such work orders shall be charged with the cost of temporary facilities and credited with payments received from customers and net salvage realized on removal of the temporary facilities. Any net credit or debit resulting shall be cleared to account 451, Miscellaneous Service Revenues.
A. For Major utilities, this account shall include all debits not elsewhere provided for, such as miscellaneous work in progress, and unusual or extraordinary expenses, not included in other accounts, which are in process of amortization and items the proper final disposition of which is uncertain.
B. For Nonmajor utilities, this account shall include the following classes of items:
(1) Expenditures for preliminary surveys, plans, investigations, etc., made for the purpose of determining the feasibility of utility projects under contemplation. If construction results, this account shall be credited with the amount applicable thereto and the appropriate plant accounts shall be charged with an amount which does not exceed the expenditures which may reasonably be determined to contribute directly and immediately and without duplication to plant. If the work is abandoned, the charge shall be to account 426.5, Other Deductions, or to the appropriate operating expense accounts.
(2) Undistributed balances in clearing accounts at the date of the balance sheet. Balances in clearing accounts shall be substantially cleared not later than the end of the calendar year unless items held therein related to a future period.
(3) Balances representing expenditures for work in progress other than on utility plant. This includes jobbing and contract work in progress.
(4) Other debit balances, the proper final disposition of which is uncertain and unusual or extraordinary expenses not included in other accounts, which are in process of being written off.
C. For both Major and Nonmajor utilities, the records supporting the entries to this account shall be so kept that the utility can furnish full information as to each deferred debit included herein.
This account shall include losses from the sale or other disposition of property previously recorded in account 105, Electric Plant held for Future Use, under the provisions of paragraphs B, C, and D thereof, where such losses are significant and are to be amortized over a period of 5 years, unless otherwise authorized by the Commission. The amortization of the amounts in this account shall be made by debits to account 411.7, Losses from Disposition of Utility Plant. (See account 105, Electric Plant Held for Future Use.)
A. This account shall be charged with the cost of all expenditures coming within the meaning of Research, Development and Demonstration (RD & D) of this uniform system of accounts (see definition 27.B.), except those expenditures properly chargeable to account 107, Construction Work in Progress—Electric.
B. Costs that are minor or of a general or recurring nature shall be transferred from this account to the appropriate operating expense function or if such costs are common to the overall operations or cannot be feasibly allocated to the various operating accounts, then such costs shall be recorded in account 930.2, Miscellaneous General Expenses.
C. In certain instances a company may incur large and significant research, development, and demonstration expenditures which are nonrecurring and which would distort the annual research, development, and demonstration charges for the period. In such a case the portion of such amounts that cause the distortion may be amortized to the appropriate operating expense account over a period not to exceed 5 years unless otherwise authorized by the Commission.
D. The entries in this account must be so maintained as to show separately each project along with complete detail of the nature and purpose of the research, development, and demonstration project together with the related costs.
This account shall include the losses on long-term debt reacquired or redeemed. The amounts in this account shall be amortized in accordance with General Instruction 17.
A. This account shall be debited and account 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, or account 411.2, Provision for Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited with an amount equal to that by which income taxes payable for the year are higher because of the inclusion of certain items in income for tax purposes, which items for general accounting purposes will not be fully reflected in the utility’s determination of annual net income until subsequent years.
B. This account shall be credited and account 410.1, Provision for Deferred Income Taxes, Utility Operating Income, or account 410.2, Provision for Deferred Income Taxes, Other Income and Deductions, as appropriate, shall be debited with an amount equal to that by which income taxes payable for the year are lower because of prior payment of taxes as provided by paragraph A above, because of difference in timing for tax purposes of particular items of income or income deductions from that recognized by the utility for general accounting purposes. Such credit to this account and debit to account 410.1 or 410.2 shall, in general, represent the effect on taxes payable in the current year of the smaller amount of book income recognized for tax purposes as compared to the amount recognized in the utility’s current accounts with respect to the item or class of items for which deferred tax accounting by the utility was authorized by the Commission.
C. Vintage year records with respect to entries to this account, as described above, and the account balance, shall be so maintained as to show the factor of calculation with respect to each annual amount of the item or class of items for which deferred tax accounting by the utility is utilized.
D. The utility is restricted in its use of this account to the purpose set forth above. It shall not make use of the balance in this account or any portion thereof except as provided in the text of this account, without prior approval of the Commission. Any remaining deferred tax account balance with respect to an amount for any prior year’s tax deferral, the amortization of which or other recognition in the utility’s income accounts has been completed, or other disposition made, shall be debited to account 410.1, Provision for Deferred Income Taxes, Utility Operating Income, or account 410.2, Provision for Deferred Income Taxes, Other Income and Deductions, as appropriate, or otherwise disposed of as the Commission may authorize or direct. (See General Instruction 18.)
A. These accounts shall include the par value or the stated value of stock without par value if such stock has a stated value, and, if not, the cash value of the consideration received for such nonpar stock, of each class of capital stock actually issued, including the par or stated value of such capital stock in account 124, Other Investments, and account 217, Reacquired Capital Stock.
B. When the actual cash value of the consideration received is more or less than the par or stated value of any stock having a par or stated value, the difference shall be credited or debited, as the case may be, to the premium or discount account for the particular class and series.
C. When capital stock is retired, these accounts shall be charged with the amount at which such stock is carried herein.
D. A separate ledger account, with a descriptive title, shall be maintained for each class and series of stock. The supporting records shall show the shares nominally issued, actually issued, and nominally outstanding.
When a levy or assessment, except a call for payment on subscriptions, is made against holders of capital stock, the amount collected upon such levy or assessment shall be credited to account 207, Premium on Capital Stock (for Nonmajor utilities, account 211, Miscellaneous Paid-In Capital), provided, however, that the credit shall be made to account 213, Discount on Capital Stock, to the extent of any remaining balance of discount on the issue of stock.
A. These accounts shall include the amount of legally enforceable subscriptions to capital stock of the utility. They shall be credited with the par or stated value of the stock subscribed, exclusive of accrued dividends, if any. Concurrently, a debit shall be made to subscriptions to capital stock, included as a separate subdivision of account 143, Other Accounts Receivable, for the agreed price, and any discount or premium shall be debited or credited to the appropriate discount or premium account. When properly executed stock certificates have been issued representing the shares subscribed, this account shall be debited, and the appropriate capital stock account credited, with the par or stated value of such stock.
B. The records shall be kept in such manner as to show the amount of subscriptions to each class and series of stock.
A. These accounts shall include the par value or stated value, as appropriate, of capital stock which the utility has agreed to exchange for outstanding securities of other companies in connection with the acquisition of properties of such companies under terms which allow the holders of the securities of the other companies to surrender such securities and receive in return therefor capital stock of the accounting utility.
B. When the securities of the other companies have been surrendered and capital stock issued in accordance with the terms of the exchange, these accounts shall be charged and accounts 201, Common Stock Issued, or 204, Preferred Stock Issued, as the case may be, shall be credited.
C. The records shall be kept so as to show separately the stocks of each class and series for which a conversion liability exists.
A. This account shall include, in a separate subdivision for each class and series of stock, the excess of the actual cash value of the consideration received on original issues of capital stock over the par or stated value and accrued dividends of such stock, together with assessments against stockholders representing payments required in excess of par or stated values.
B. Premium on capital stock shall not be set off against expenses. Further, a premium received on an issue of a certain class or series of stock shall not be set off against expenses of another issue of the same class or series.
C. When capital stock which has been actually issued is retired, the amount in this account applicable to the shares retired shall be transferred to account 210, Gain on Resale or Cancellation of Reacquired Capital Stock.
This account shall include the balance of credits for donations received from stockholders consisting of capital stock of the utility, cancellation or reduction of debt of the utility, and the cash value of other assets received as a donation.
This account shall include the balance of credits arising from a reduction in the par or stated value of capital stock.
This account shall include the balance of credits arising from the resale or cancellation of reacquired capital stock. (See account 217. Reacquired Capital Stock.)
This account shall include the balance of all other credits for paid-in capital which are not properly includible in the foregoing accounts. This account may include all commissions and expenses incurred in connection with the issuance of capital stock. (In the case of Nonmajor companies, this account shall be kept so as to show the source of the credits includible herein.)
1. Premium received on original issues of capital stock.
2. Donations received from stockholders or reduction of debt of the utility, and the cash value of other assets received as a donation.
3. Reduction in part or stated value of capital stock.
4. Gain on resale or cancellation of reacquired capital stock.
(Major utilities) Amounts included in capital surplus at the effective date of this system of accounts which cannot be classified as to the source thereof shall be included in this account.
(Nonmajor utilities) Premium on capital stock shall not be set off against expenses. Further, a premium received on an issue of a certain class or series of stock shall not be set off against expense of another issue of the same class or series.
A. This account shall include in a separate subdivision for each class and series of capital stock the amount of installments received on capital stock on a partial or installment payment plan from subscribers who are not bound by legally enforceable subscription contracts.
B. As subscriptions are paid in full and certificates issued, this account shall be charged and the appropriate capital stock account credited with the par or stated value of such stock. Any discount or premium on an original issue shall be included in the appropriate discount or premium account.
A. This account shall include in a separate subdivision for each class and series of capital stock all discount on the original issuance and sale of capital stock, including additional capital stock of a particular class or series as well as first issues.
B. When capital stock which has been actually issued is retired, the amount in this account applicable to the shares retired shall be written off to account 210, Gain on Resale or Cancellation of Reacquired Capital Stock, provided, however, that the amount shall be charged to account 439, Adjustments to Retained Earnings, to the extent that it exceeds the balance in account 210.
A. This account shall include in a separate subdivision for each class and series of stock all commissions and expenses incurred in connection with the original issuance and sale of capital stock, including additional capital stock of a particular class or series as well as first issues. Expenses applicable to capital stock shall not be deducted from premium on capital stock.
B. When capital stock which has been actually issued by the utility is retired the amount in this account, applicable to the shares retired shall be written off to account 210, Gain on Resale or Cancellation of Reacquired Capital Stock, provided, however, that the amount shall be charged to account 439, Adjustments to Retained Earnings, to the extent that it exceeds the balance in account 210.
Expenses in connection with the reacquisition or resale of the utility’s capital stock shall not be included herein.
The utility may write off capital stock expense in whole or in part by charges to account 211, Miscellaneous Paid-in Capital.
This account shall include the amount of retained earnings which has been appropriated or set aside for specific purposes. Separate subaccounts shall be maintained under such titles as will designate the purpose for which each appropriation was made.
A. This account shall be credited with such amounts as are appropriated by a licensee from account 216, Unappropriated Retained Earnings, for amortization reserve purposes in accordance with the requirements of a hydroelectric project license.
B. This account shall be debited with only such items or amounts as the Commission may require or approve. (See account 127, Amortization Fund—Federal.)
This account shall include the balances, either debit or credit, of unappropriated retained earnings arising from earnings of the utility. This account shall not include any amounts representing the undistributed earnings of subsidiary companies.
This account shall include the balances, either debit or credit, of undistributed retained earnings of subsidiary companies since their acquisition. When dividends are received from subsidiary companies relating to amounts included in this account, this account shall be debited and account 216, “Unappropriated Retained Earnings,” credited.
A. This account shall include in a separate subdivision for each class and series of capital stock, the cost of capital stock actually issued by the utility and reacquired by it and not retired or canceled, except, however, stock which is held by trustees in sinking or other funds.
B. When reacquired capital stock is retired or canceled, the difference between its cost, including commissions and expenses paid in connection with the reacquisition, and its par or stated value plus any premium and less any discount and expenses applicable to the shares retired, shall be debited or credited, as appropriate, to account 210, Gain on Resale or Cancellation of Reacquired Capital Stock, provided, however, that debits shall be charged to account 439, Adjustments to Retained Earnings, to the extent that they exceed the balance in account 210.
C. When reacquired capital stock is resold by the utility, the difference between the amount received on the resale of the stock, less expenses incurred in the resale, and the cost of the stock included in this account shall be accounted for as outlined in paragraph B.
See account 124. Other Investments, for permissive accounting treatment of stock reacquired under a definite plan for resale.
The accounting for reacquired stock shall be as prescribed herein unless otherwise specifically required by statute.
This account shall include the investment in an unincorporated utility by the proprietor thereof, and shall be charged with all withdrawals from the business by its proprietor. At the end of each calendar year the net income for the year, as developed in the income account, shall be transferred to this account. (See optional accounting procedure provided in Note C, hereunder.)
Amounts payable to the proprietor as just and reasonable compensation for services performed shall not be charged to this account but to appropriate operating expense or other accounts.
When the utility is owned by a partnership, a separate account shall be kept to show the net equity of each member therein and the transactions affecting the interest of each such partner.
This account may be restricted to the amount considered by the proprietor to be the permanent investment in the business, subject to change only by additional investment by the proprietor or the withdrawal of portions thereof not representing net income. When this option is taken, the retained earnings accounts shall be maintained and entries thereto shall be made in accordance with the texts thereof.
A. This account shall include revenues, expenses, gains, and losses that are properly includable in other comprehensive income during the period. Examples of other comprehensive income include foreign currency items, minimum pension liability adjustments, unrealized gains and losses on certain investments in debt and equity securities, and cash flow hedges. Records supporting the entries to this account shall be maintained so that the utility can furnish the amount of other comprehensive income for each item included in this account.
B. This account shall also be debited or credited, as appropriate, with amounts of accumulated other comprehensive income that have been included in the determination of net income during the period and in accumulated other comprehensive income in prior periods. Separate records for each category of items shall be maintained to identify the amount of the reclassification adjustments from accumulated other comprehensive income to earnings made during the period.
This account shall include in a separate subdivision for each class and series of bonds the face value of the actually issued and unmatured bonds which have not been retired or canceled; also the face value of such bonds issued by others the payment of which has been assumed by the utility.
A. This account shall include the face value of bonds actually issued or assumed by the utility and reacquired by it and not retired or canceled. The account for reacquired debt shall not include securities which are held by trustees in sinking or other funds.
B. When bonds are reacquired, the difference between face value, adjusted for unamortized discount, expenses or premium, and the amount paid upon reacquisition, shall be included in account 189, Unamortized Loss on Reacquired Debt, or account 257, Unamortized Gain on Reacquired Debt, as appropriate. (See General Instruction 17.)
A. This account shall include the face value of notes payable to associated companies and the amount of open book accounts representing advances from associated companies. It does not include notes and open accounts representing indebtedness subject to current settlement which are includible in account 233. Notes Payable to Associated Companies, or account 234, Accounts Payable to Associated Companies.
B. The records supporting the entries to this account shall be so kept that the utility can furnish complete information concerning each note and open account.
A. This account shall include, until maturity all long-term debt not otherwise provided for. This covers such items as receivers’ certificates, real estate mortgages executed or assumed, assessments for public improvements, notes and unsecured certificates of indebtedness not owned by associated companies, receipts outstanding for long-term debt, and other obligations maturing more than one year from date of issue or assumption.
B. Separate accounts shall be maintained for each class of obligation, and records shall be maintained to show for each class all details as to date of obligation, date of maturity, interest dates and rates, security for the obligation, etc.
Miscellaneous long-term debt reacquired shall be accounted for in accordance with the procedure set forth in account 222. Reacquired Bonds.
A. This account shall include the excess of the cash value of consideration received over the face value upon the issuance or assumption of long-term debt securities.
B. Amounts recorded in this account shall be amortized over the life of each respective issue under a plan which will distribute the amount equitably over the life of the security. The amortization shall be on a monthly basis, with the amounts thereof to be credited to account 429, Amortization of Premium on Debt—Credit. (See General Instruction 17.)
A. This account shall include the excess of the face value of long-term debt securities over the cash value of consideration received therefor, related to the issue or assumption of all types and classes of debt.
B. Amounts recorded in this account shall be amortized over the life of the respective issues under a plan which will distribute the amount equitably over the life of the securities. The amortization shall be on a monthly basis, with the amounts thereof charged to account 428, Amortization of Debt Discount and Expense. (See General Instruction 17.)
Special Instructions for Current and Accrued Liabilities. Current and accrued liabilities are those obligations which have either matured or which become due within one year from the date thereof: except, however, bonds, receivers’ certificates and similar obligations which shall be classified as long-term debt until date of maturity; accrued taxes, such as income taxes, which shall be classified as accrued liabilities even though payable more than one year from date; compensation awards, which shall be classified as current liabilities regardless of date due; and minor amounts payable in installments which may be classified as current liabilities. If a liability is due more than one year from date of issuance or assumption by the utility, it shall be credited to a long-term debt account appropriate for the transaction, except, however, the current liabilities previously mentioned.
This account shall include the portion not due within one year, of the obligations recorded for the amounts applicable to leased property recorded as assets in account 101.1, Property under Capital Leases, account 120.6, Nuclear Fuel under Capital Leases, or account 121, Nonutility Property.
No amounts shall be credited to these accounts unless authorized by a regulatory authority or authorities to be collected in a utility’s rate levels.
A. This account shall include amounts reserved by the utility for losses through accident, fire, flood, or other hazards to its own property or property leased from others, not covered by insurance. The amounts charged to account 924, Property Insurance, or other appropriate accounts to cover such risks shall be credited to this account. A schedule of risks covered shall be maintained, giving a description of the property involved, the character of the risks covered and the rates used.
B. Charges shall be made to this account for losses covered, not to exceed the account balance. Details of these charges shall be maintained according to the year the casualty occurred which gave rise to the loss.
A. This account shall be credited with amounts charged to account 925, Injuries and Damages, or other appropriate accounts, to meet the probable liability, not covered by insurance, for deaths or injuries to employees and others and for damages to property neither owned nor held under lease by the utility.
B. When liability for any injury or damage is admitted by the utility either voluntarily or because of the decision of a court or other lawful authority, such as a workmen’s compensation board, the admitted liability shall be charged to this account and credited to the appropriate current liability account. Details of these charges shall be maintained according to the year the casualty occurred which gave rise to the loss.
Recoveries or reimbursements for losses charged to this account shall be credited hereto; the cost of repairs to property of others if provided for herein shall be charged to this account.
A. This account shall include provisions made by the utility and amounts contributed by employees for pensions, accident and death benefits, savings, relief, hospital and other provident purposes, where the funds are included in the assets of the utility either in general or in segregated fund accounts.
B. Amounts paid by the utility for the purposes for which this liability is established shall be charged hereto.
C. A separate account shall be kept for each kind of provision included herein.
If employee pension or benefit plan funds are not included among the assets of the utility but are held by outside trustees, payments into such funds, or accruals therefor, shall not be included in this account.
A. This account shall include all operating provisions which are not provided for elsewhere.
B. This account shall be maintained in such manner as to show the amount of each separate provision and the nature and amounts of the debits and credits thereto.
This account includes only provisions as may be created for operating purposes and does not include any reservations of income the credits for which should be carried in account 215, Appropriated Retained Earnings.
A. This account shall be credited with amounts charged to Account 449.1, Provisions for Rate Refunds, to provide for estimated refunds where the utility is collecting amounts in rates subject to refund.
B. When refund of any amount recorded in this account is ordered by a regulatory authority, such amount shall be changed hereto and credited to account 242, Miscellaneous Current and Accrued Liabilities.
C. Records supporting the entries to this account shall be kept so as to identify each amount recorded by the respective rate filing docket number.
A. This account shall include the amount of liabilities for the recognition of asset retirement obligations related to electric utility plant and nonutility plant that gives rise to the obligations. This account shall be credited for the amount of the liabilities for asset retirement obligations with amounts charged to the appropriate electric utility plant accounts or nonutility plant account to record the related asset retirement costs.
B. The utility shall charge the accretion expense to account 411.10, Accretion expense, for electric utility plant, account 413, Expenses of electric plant leased to others, for electric plant leased to others, or account 421, Miscellaneous nonoperating income, for nonutility plant, as appropriate, and credit account 230, Asset retirement obligations.
C. This account shall be debited with amounts paid to settle the asset retirement obligations recorded herein.
D. The utility shall clear from this account any gains or losses resulting from the settlement of asset retirement obligations in accordance with the instructions prescribed in General Instruction 25.
This account shall include the face value of all notes, drafts, acceptances, or other similar evidences of indebtedness, payable on demand or within a time not exceeding one year from date of issue, to other than associated companies.
This account shall include all amounts payable by the utility within one year, which are not provided for in other accounts.
These accounts shall include amounts owing to associated companies on notes, drafts, acceptances, or other similar evidences of indebtedness, and open accounts payable on demand or not more than one year from date of issue or creation.
Exclude from these accounts notes and accounts which are includible in account 223, Advances from Associated Companies.
This account shall include all amounts deposited with the utility by customers as security for the payment of bills.
A. This account shall be credited with the amount of taxes accrued during the accounting period, corresponding debits being made to the appropriate accounts for tax charges. Such credits may be based upon estimates, but from time to time during the year as the facts become known, the amount of the periodic credits shall be adjusted so as to include as nearly as can be determined in each year the taxes applicable thereto. Any amount representing a prepayment of taxes applicable to the period subsequent to the date of the balance sheet, shall be shown under account 165, Prepayments.
B. If accruals for taxes are found to be insufficient or excessive, correction therefor shall be made through current tax accruals.
C. Accruals for taxes shall be based upon the net amounts payable after credit for any discounts, and shall not include any amounts for interest on tax deficiencies or refunds. Interest received on refunds shall be credited to account 419, Interest and Dividend Income, and interest paid on deficiencies shall be charged to account 431, Other Interest Expense.
D. The records supporting the entries to this account shall be kept so as to show for each class of taxes, the amount accrued, the basis for the accrual, the accounts to which charged, and the amount of tax paid.
This account shall include the amount of interest accrued but not matured on all liabilities of the utility not including, however, interest which is added to the principal of the debt on which incurred. Supporting records shall be maintained so as to show the amount of interest accrued on each obligation.
This account shall include the amount of dividends which have been declared but not paid. Dividends shall be credited to this account when they become a liability.
This account shall include the amount of long-term debt (including any obligation for premiums) matured and unpaid, without specific agreement for extension of the time of payment and bonds called for redemption but not presented.
This account shall include the amount of matured interest on long-term debt or other obligations of the utility at the date of the balance sheet unless such interest is added to the principal of the debt on which incurred.
This account shall include the amount of taxes collected by the utility through payroll deductions or otherwise pending transmittal of such taxes to the proper taxing authority.
Do not include liability for taxes assessed directly against the utility which are accounted for as part of the utility’s own tax expense.
This account shall include the amount of all other current and accrued liabilities not provided for elsewhere appropriately designated and supported so as to show the nature of each liability.
1. Dividends declared but not paid.
2. Matured long-term debt.
3. Matured interest.
4. Taxes collected through payroll deductions or otherwise pending transmittal to the proper taxing authority.
This account shall include the portion, due within one year, of the obligations recorded for the amounts applicable to leased property recorded as assets in account 101.1, Property under Capital Leases, account 120.6, Nuclear Fuel under Capital Leases (Major only), or account 121, Nonutility Property.
This account shall include the change in the fair value of all derivative instrument liabilities not designated as cash flow or fair value hedges. Account 426, other deductions, shall be debited or credited as appropriate with the corresponding amount of the change in the fair value of the derivative instrument.
A. This account shall include the change in the fair value of derivative instrument liabilities designated by the utility as cash flow or fair value hedges.
B. A utility shall record the change in the fair value of a derivative instrument liability related to a cash flow hedge in this account, with a concurrent charge to account 219, accumulated other comprehensive income, with the effective portion of the derivative’s gain or loss. The ineffective portion of the cash flow hedge shall be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
C. A utility shall record the change in the fair value of a derivative instrument liability related to a fair value hedge in this account, with a concurrent charge to a subaccount of the asset or liability that carries the item being hedged. The ineffective portion of the fair value hedge shall be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
This account shall include advances by customers for construction which are to be refunded either wholly or in part. When a customer is refunded the entire amount to which he is entitled, according to the agreement or rule under which the advance was made, the balance, if any, remaining in this account shall be credited to the respective plant account.
This account shall include advance billings and receipts and other deferred credit items, not provided for elsewhere, including amounts which cannot be entirely cleared or disposed of until additional information has been received.
A. This account shall include the amounts of regulatory liabilities, not includible in other accounts, imposed on the utility by the ratemaking actions of regulatory agencies. (See Definition No. 30.)
B. The amounts included in this account are to be established by those credits which would have been included in net income, or accumulated other comprehensive income, determinations in the current period under the general requirements of the Uniform System of Accounts but for it being probable that: Such items will be included in a different period(s) for purposes of developing the rates that the utility is authorized to charge for its utility services; or refunds to customers, not provided for in other accounts, will be required. When specific identification of the particular source of the regulatory liability cannot be made or when the liability arises from revenues collected pursuant to tariffs on file at a regulatory agency, account 407.3, regulatory debits, shall be debited. The amounts recorded in this account generally are to be credited to the same account that would have been credited if included in income when earned except: All regulatory liabilities established through the use of account 407.3 shall be credited to account 407.4, regulatory credits; and in the case of refunds, a cash account or other appropriate account should be credited when the obligation is satisfied.
C. If it is later determined that the amounts recorded in this account will not be returned to customers through rates or refunds, such amounts shall be credited to Account 421, Miscellaneous Nonoperating Income, or Account 434, Extraordinary Income, as appropriate, in the year such determination is made.
D. The records supporting the entries to this account shall be so kept that the utility can furnish full information as to the nature and amount of each regulatory liability included in this account, including justification for inclusion of such amounts in this account.
A. This account shall be credited with all investment tax credits deferred by companies which have elected to follow deferral accounting, partial or full, rather than recognizing in the income statement the total benefits of the tax credit as realized. After such election, a company may not transfer amounts from this account, except as authorized herein and in accounts 411.4, Investment Tax Credit Adjustments, Utility Operations, 411.5, Investment Tax Credit Adjustments, Nonutility Operations, and 420, Investment Tax Credits, or with approval of the Commission.
B. Where the company’s accounting provides that investment tax credits are to be passed on to customers, this account shall be debited and account 411.4 credited with a proportionate amount determined in relation to the average useful life of electric utility property to which the tax credits relate or such lesser period of time as allowed by a regulatory agency having rate jurisdiction. If, however, the deferral procedure provides that investment tax credits are not to be passed on to customers, the proportionate restorations to income shall be credited to account 420.
C. Subdivisions of this account by department shall be maintained for deferred investment tax credits that are related to nonelectric utility or other operations. Contra entries affecting such account subdivisions shall be appropriately recorded in account 413, Expenses of Electric Plant Leased to Others; or account 414, Other Utility Operating Income. Use of deferral or nondeferral accounting procedures adopted for nonelectric utility or other operations are to be followed on a consistent basis.
D. Separate records for electric and nonelectric utility or other operations shall be maintained identifying the properties giving rise to the investment tax credits for each year with the weighted-average service life of such properties and any unused balances of such credits. Such records are not necessary unless the tax credits are deferred.
This account shall include gains from the sale or other disposition of property previously recorded in account 105, Electric Plant Held for Future Use, under the provisions of paragraphs B, C, and D thereof, where such gains are significant and are to be amortized over a period of 5 years, unless otherwise authorized by the Commission. The amortization of the amounts in this account shall be made by credits to account 411.6, Gains from Disposition of Utility Plant. (See account 105, Electric Plant Held for Future Use.)
This account shall include the amounts of discount realized upon reacquisition or redemption of long-term debt. The amounts in this account shall be amortized in accordance with General Instruction 17.
Before using the deferred tax accounts provided below refer to General Instruction 18. Comprehensive Interperiod Income Tax Allocation.
The text of these accounts are designed primarily to cover deferrals of Federal income taxes. However, they are also to be used when making deferrals of state and local income taxes. Public utilities and licensees which, in addition to an electric utility department, have another utility department, gas, water, etc., and nonutility property and which have deferred taxes on income with respect thereto shall separately classify such deferrals in the accounts provided below so as to allow ready identification of items relating to each utility Deductions.
A. This account shall include tax deferrals resulting from adoption of the principles of comprehensive interperiod tax allocation described in General Instruction 18 of this system of accounts that relate to property for which the utility has availed itself of the use of accelerated (5-year) amortization of (1) certified defense facilities as permitted by Section 168 of the Internal Revenue Code and (2) certified pollution control facilities as permitted by Section 169 of the Internal Revenue Code.
B. This account shall be credited and accounts 410.1, Provision for Deferred Income Taxes, Utility Operating Income, or 410.2, Provision for Deferred Income Taxes, Other Income and Deductions, as appropriate, shall be debited with tax effects related to property described in paragraph A above where taxable income is lower than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
C. This account shall be debited and accounts 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, or 411.2, Provision for Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited with tax effects related to property described in paragraph A above where taxable income is higher than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
D. The utility is restricted in its use of this account to the purposes set forth above. It shall not transfer the balance in this account or any portion thereof to retained earnings or make any use thereof except as provided in the text of this account without prior approval of the Commission. Upon the disposition by sale exchange, transfer, abandonment or premature retirement of plant on which there is a related balance herein, this account shall be charged with an amount equal to the related income tax expense, if any, arising from such disposition and account 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, or 411.2, Provision for Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited. When the remaining balance, after consideration of any related income tax expense, is less than $25,000, this account shall be charged and account 411.1 or 411.2, as appropriate, credited with such balance. If after consideration of any related income tax expense, there is a remaining amount of $25,000 or more, the Commission shall authorize or direct how such amount shall be accounted for at the time approval for the disposition of accounting is granted. When plant is disposed of by transfer to a wholly owned subsidiary the related balance in this account shall also be transferred. When the disposition relates to retirement of an item or items under a group method of depreciation where there is no tax effect in the year of retirement, no entries are required in this account if it can be determined that the related balances would be necessary to be retained to offset future group item tax deficiencies.
A. This account shall include the tax deferrals resulting from adoption of the principle of comprehensive interperiod income tax allocation described in General Instruction 18 of this system of accounts which are related to all property other than accelerated amortization property.
B. This account shall be credited and accounts 410.1, Provision for Deferred Income Taxes, Utility Operating Income, or 410.2, Provision for Deferred Income Taxes, Other Income and Deductions, as appropriate, shall be debited with tax effects related to property described in paragraph A above where taxable income is lower than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
C. This account shall be debited and accounts 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, or 411.2, Provision for Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited with tax effects related to property described in paragraph A above where taxable income is higher than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
D. The utility is restricted in its use of this account to the purposes set forth above. It shall not transfer the balance in this account or any portion thereof to retained earnings or make any use thereof except as provided in the text of this account without prior approval of the Commission. Upon the disposition by sale, exchange, transfer, abandonment or premature retirement of plant on which there is a related balance herein, this account shall be charged with an amount equal to the related income tax expense, if any, arising from such disposition and account 411.1, Income Taxes Deferred in Prior Years—Credit, Utility Operating Income, or 411.2, Income Taxes Deferred in Prior Years—Credit, Other Income and Deductions, shall be credited. When the remaining balance after consideration of any related tax expenses, is less than $25,000, this account shall be charged and account 411.1 or 411.2, as appropriate, credited with such balance. If after consideration of any related income tax expense, there is a remaining amount of $25,000 or more, the Commission shall authorize or direct how such amount shall be accounted for at the time approval for the disposition of accounting is granted. When plant disposed of by transfer to a wholly owned subsidiary, the related balance in this account shall also be transferred. When the disposition relates to retirement of an item or items under a group method of depreciation where there is no tax effect in the year of retirement, no entries are required in this account if it can be determined that the related balance would be necessary to be retained to offset future group item tax deficiencies.
A. This account shall include all credit tax deferrals resulting from the adoption of the principles of comprehensive interperiod income tax allocation described in General Instruction 18 of this system of accounts other than those deferrals which are includible in Accounts 281, Accumulated Deferred Income Taxes—Accelerated Amortization Property and 282, Accumulated Deferred Income Taxes—Other Property.
B. This account shall be credited and accounts 410.1 Provision for Deferred Income Taxes, Utility Operating Income, or 410.2, Provision for Deferred Income Taxes, Other Income and Deductions, as appropriate, shall be debited with tax effects related to items described in paragraph A above where taxable income is lower than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
C. This account shall be debited and accounts 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income or 411.2, Provision for Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited with tax effects related to items described in paragraph A above where taxable income is higher than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
D. Records with respect to entries to this account, as described above, and the account balance, shall be so maintained as to show the factors of calculation with respect to each annual amount of the item or class of items.
E. The utility is restricted in its use of this account to the purposes set forth above. It shall not transfer the balance in the account or any portion thereof to retained earnings or to any other account or make any use thereof except as provided in the text of this account, without prior approval of the Commission. Upon the disposition by sale, exchange, transfer, abandonment or premature retirement of items on which there is a related balance herein, this account shall be charged with an amount equal to the related income tax effect, if any, arising from such disposition and account 411.1, Provision For Deferred Income Taxes—Credit, Utility Operating Income, or 411.2, Provision For Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited. When the remaining balance, after consideration of any related tax expenses, is less than $25,000, this account shall be charged and account 411.1 or 411.2, as appropriate, credited with such balance. If after consideration of any related income tax expense, there is a remaining amount of $25,000 or more, the Commission shall authorize or direct how such amount shall be accounted for at the time approval for the disposition of accounting is granted.
When plant is disposed of by transfer to a wholly owned subsidiary, the related balance in this account shall also be transferred. When the disposition relates to retirement of an item or items under a group method of depreciation where there is no tax effect in the year of retirement, no entries are required in this account if it can be determined that the related balance would be necessary to be retained to offset future group item tax deficiencies.
This account shall include all fees paid to federal or state governments for the privilege of incorporation and expenditures incident to organizing the corporation, partnership, or other enterprise and putting it into readiness to do business.
1. Cost of obtaining certificates authorizing an enterprise to engage in the public-utility business.
2. Fees and expenses for incorporation
3. Fees and expenses for mergers or consolidations.
4. Office expenses incident to organizing the utility.
5. Stock and minute books and corporate seal.
This account shall not include any discounts upon securities issued or assumed; nor shall it include any costs incident to negotiating loans, selling bonds or other evidences of debt or expenses in connection with the authorization, issuance or sale of capital stock.
Exclude from this account and include in the appropriate expense account the cost of preparing and filing papers in connection with the extension of the term of incorporation unless the first organization costs have been written off. When charges are made to this account for expenses incurred in mergers, consolidations, or reorganizations, amounts previously included herein or in similar accounts in the books of the companies concerned shall be excluded from this account.
A. This account shall include amounts paid to the federal government, to a state or to a political subdivision thereof in consideration for franchises, consents, water power licenses, or certificates, running in perpetuity or for a specified term of more than one year, together with necessary and reasonable expenses incident to procuring such franchises, consents, water power licenses, or certificates of permission and approval, including expenses of organizing and merging separate corporations, where statutes require, solely for the purpose of acquiring franchises.
B. If a franchise, consent, water power license or certificate is acquired by assignment, the charge to this account in respect thereof shall not exceed the amount paid therefor by the utility to the assignor, nor shall it exceed the amount paid by the original grantee, plus the expense of acquisition to such grantee. Any excess of the amount actually paid by the utility over the amount above specified shall be charged to account 426.5, Other Deductions.
C. When any franchise has expired, the book cost thereof shall be credited hereto and charged to account 426.5, Other Deductions, or to account 111, Accumulated Provision for Amortization of Electric Utility Plant (for Nonmajor utilities, account 110, Accumulated Provision for Depreciation and Amortization of Electric Plant), as appropriate.
D. Records supporting this account shall be kept so as to show separately the book cost of each franchise or consent.
Annual or other periodic payments under franchises shall not be included herein but in the appropriate operating expense account.
A. This account shall include the cost of patent rights, licenses, privileges, and other intangible property necessary or valuable in the conduct of utility operations and not specifically chargeable to any other account.
B. When any item included in this account is retired or expires, the book cost thereof shall be credited hereto and charged to account 426.5, Other Deductions, or account 111, Accumulated Provision for Amortization of Electric Utility Plant (for Nonmajor utilities, account 110, Accumulated Provision for Depreciation and Amortization of Electric Plant), as appropriate.
C. This account shall be maintained in such a manner that the utility can furnish full information with respect to the amounts included herein.
This account shall include the cost of land and land rights used in connection with steam-power generation. (See electric plant instruction 7.)
This account shall include the cost in place of structures and improvements used in connection with steam-power generation. (See electric plant instruction 8.)
Include steam production roads and railroads in this account.
This account shall include the cost installed of furnaces, boilers, coal and ash handling and coal preparing equipment, steam and feed water piping, boiler apparatus and accessories used in the production of steam, mercury, or other vapor, to be used primarily for generating electricity.
1. Ash handling equipment, including hoppers, gates, cars, conveyors, hoists, sluicing equipment, including pumps and motors, sluicing water pipe and fittings, sluicing trenches and accessories, etc., except sluices which are a part of a building.
2. Boiler feed system, including feed water heaters, evaporator condensers, heater drain pumps, heater drainers, deaerators, and vent condensers, boiler feed pumps, surge tanks, feed water regulators, feed water measuring equipment, and all associated drives.
3. Boiler plant cranes and hoists and associated drives.
4. Boilers and equipment, including boilers and baffles, economizers, superheaters, soot blowers, foundations and settings, water walls, arches, grates, insulation, blow-down system, drying out of new boilers, also associated motors or other power equipment.
5. Breeching and accessories, including breeching, dampers, soot spouts, hoppers and gates, cinder eliminators, breeching insulation, soot blowers and associated motors.
6. Coal handling and storage equipment, including coal towers, coal lorries, coal cars, locomotives and tracks when devoted principally to the transportation of coal, hoppers, downtakes, unloading and hoisting equipment, skip hoists and conveyors, weighing equipment, magnetic separators, cable ways, housings and supports for coal handling equipment.
7. Draft equipment, including air preheaters and accessories, induced and forced draft fans, air ducts, combustion control mechanisms, and associated motors or other power equipment.
8. Gas-burning equipment, including holders, burner equipment and piping, control equipment, etc.
9. Instruments and devices, including all measuring, indicating, and recording equipment for boiler plant service together with mountings and supports.
10. Lighting systems.
11. Oil-burning equipment, including tanks, heaters, pumps with drive, burner equipment and piping, control equipment, etc.
12. Pulverized fuel equipment, including pulverizers, accessory motors, primary air fans, cyclones and ducts, dryers, pulverized fuel bins, pulverized fuel conveyors and equipment, burners, burner piping, priming equipment, air compressors, motors, etc.
13. Stacks, including foundations and supports, stack steel and ladders, stack brick work, stack concrete, stack lining, stack painting (first), when set on separate foundations, independent of substructure or superstructure of building.
14. Station piping, including pipe, valves, fittings, separators, traps, desuperheaters, hangers, excavation, covering, etc., for station piping system, including all steam, condensate, boiler feed and water supply piping, etc., but not condensing water, plumbing, building heating, oil, gas, air piping or piping specifically provided for in account 313.
15. Stoker or equivalent feeding equipment, including stokers and accessory motors, clinker grinders, fans and motors, etc.
16. Ventilating equipment.
17. Water purification equipment, including softeners and accessories, evaporators and accessories, heat exchangers, filters, tanks for filtered or softened water, pumps, motors, etc.
18. Water-supply systems, including pumps, motors, strainers, raw-water storage tanks, boiler wash pumps, intake and discharge pipes and tunnels not a part of a building.
19. Wood fuel equipment, including hoppers, fuel hogs and accessories, elevators and conveyors, bins and gates, spouts, measuring equipment and associated drives.
When the system for supplying boiler or condenser water is elaborate, as when it includes a dam, reservoir, canal, pipe line, cooling ponds, or where gas or oil is used as a fuel for producing steam and is supplied through a pipe line system owned by the utility, the cost of such special facilities shall be charged to a subdivision of account 311, Structures and Improvements.
This account shall include the cost installed of steam engines, reciprocating or rotary, and their associated auxiliaries; and engine-driven main generators, except turbogenerator units.
1. Air cleaning and cooling apparatus, including blowers, drive equipment, air ducts not a part of building, louvers, pumps, hoods, etc.
2. Belting, shafting, pulleys, reduction gearing, etc.
3. Circulating pumps, including connections between condensers and intake and discharge tunnels.
4. Cooling system, including towers, pumps, tank, and piping.
5. Condensers, including condensate pumps, air and vacuum pumps, ejectors, unloading valves and vacuum breakers, expansion devices, screens, etc.
6. Cranes, hoists, etc., including items wholly identified with items listed herein.
7. Engines, reciprocating or rotary.
8. Fire-extinguishing systems.
9. Foundations and settings, especially constructed for and not expected to outlast the apparatus for which provided.
10. Generators—Main, a.c. or d.c., including field rheostats and connections for self-excited units, and excitation systems when identified with the generating unit.
11. Governors.
12. Lighting systems.
13. Lubricating systems including gauges, filters, tanks, pumps, piping, motors, etc.
14. Mechanical meters, including gauges, recording instruments, sampling and testing equipment.
15. Piping—main exhaust, including connections between generator and condenser and between condenser and hotwell.
16. Piping—main steam, including connections from main throttle valve to turbine inlet.
17. Platforms, railings, steps, gratings, etc., appurtenant to apparatus listed herein.
18. Pressure oil system, including accumulators, pumps, piping, motors, etc.
19. Throttle and inlet valve.
20. Tunnels, intake and discharge, for condenser system, when not a part of a structure.
21. Water screens, motors, etc.
This account shall include the cost installed of main turbine-driven units and accessory equipment used in generating electricity by steam.
1. Air cleaning and cooling apparatus, including blowers, drive equipment, air ducts not a part of building, louvers, pumps, hoods, etc.
2. Circulating pumps, including connections between condensers and intake and discharge tunnels.
3. Condensers, including condensate pumps, air and vacuum pumps, ejectors, unloading valves and vacuum breakers, expansion devices, screens, etc.
4. Generator hydrogen, gas piping and detrainment equipment.
5. Cooling system, including towers, pumps, tanks, and piping.
6. Cranes, hoists, etc., including items wholly identified with items listed herein.
7. Excitation system, when identified with main generating units.
8. Fire-extinguishing systems.
9. Foundations and settings, especially constructed for and not expected to outlast the apparatus for which provided.
10. Governors.
11. Lighting systems.
12. Lubricating systems, including gauges, filters, water separators, tanks, pumps, piping, motors, etc.
13. Mechanical meters, including gauges, recording instruments, sampling and testing equipment.
14. Piping—main exhaust, including connections between turbogenerator and condenser and between condenser and hotwell.
15. Piping—main steam, including connections from main throttle valve to turbine inlet.
16. Platforms, railings, steps, gratings, etc., appurtenant to apparatus listed herein.
17. Pressure oil systems, including accumulators, pumps, piping, motors, etc.
18. Steelwork, specially constructed for apparatus listed herein.
19. Throttle and inlet valve.
20. Tunnels, intake and discharge, for condenser system, when not a part of structure, water screens, etc.
21. Turbogenerators—main, including turbine and generator, field rheostats and electric connections for self-excited units.
22. Water screens, motors, etc.
23. Moisture separator for turbine steam.
24. Turbine lubricating oil (initial charge).
This account shall include the cost installed of auxiliary generating apparatus, conversion equipment, and equipment used primarily in connection with the control and switching of electric energy produced by steam power, and the protection of electric circuits and equipment, except electric motors used to drive equipment included in other accounts. Such motors shall be included in the account in which the equipment with which they are associated is included.
1. Auxiliary generators, including boards, compartments, switching equipment, control equipment, and connections to auxiliary power bus.
2. Excitation system, including motor, turbine and dual-drive exciter sets and rheostats, storage batteries and charging equipment, circuit breakers, panels and accessories, knife switches and accessories, surge arresters, instrument shunts, conductors and conduit, special supports for conduit, generator field and exciter switch panels, exciter bus tie panels, generator and exciter rheostats, etc., special housing, protective screens, etc.
3. Generator main connections, including oil circuit breakers and accessories, disconnecting switches and accessories, operating mechanisms and interlocks, current transformers, potential transformers, protective relays, isolated panels and equipment, conductors and conduit, special supports for generator main leads grounding switch, etc., special housings, protective screens, etc.
4. Station buses including main, auxiliary, transfer, synchronizing and fault ground buses, including oil circuit breakers and accessories, disconnecting switches and accessories, operating mechanisms and interlocks, reactors and accessories, voltage regulators and accessories, compensators, resistors, starting transformers, current transformers, potential transformers, protective relays, storage batteries and charging equipment, isolated panels and equipment, conductors and conduit, special supports, special housings, concrete pads, general station grounding system, special fire-extinguishing system, and test equipment.
5. Station control system, including station switchboards with panel wiring, panels with instruments and control equipment only, panels with switching equipment mounted or mechanically connected, truck-type boards complete, cubicles, station supervisory control boards, generator and exciter signal stands, temperature recording devices, frequency-control equipment, master clocks, watt-hour meters and synchronoscope in the turbine room, station totalizing wattmeter, boiler-room load indicator equipment, storage batteries, panels and charging sets, instrument transformers for supervisory metering, conductors and conduit, special supports for conduit, switchboards, batteries, special housing for batteries, protective screens, doors, etc.
Do not include in this account transformers and other equipment used for changing the voltage or frequency of electricity for the purposes of transmission or distribution.
When any item of equipment listed herein is used wholly to furnish power to equipment included in another account, its cost shall be included in such other account.
This account shall include the cost installed of miscellaneous equipment in and about the steam generating plant devoted to general station use, and which is not properly includible in any of the foregoing steam-power production accounts.
1. Compressed air and vacuum cleaning systems, including tanks, compressors, exhausters, air filters, piping, etc.
2. Cranes and hoisting equipment, including cranes, cars, crane rails, monorails, hoists, etc., with electric and mechanical connections.
3. Fire-extinguishing equipment for general station use.
4. Foundations and settings specially constructed for and not expected to outlast the apparatus for which provided.
5. Locomotive cranes not includible elsewhere.
6. Locomotives not includible elsewhere.
7. Marine equipment, including boats, barges, etc.
8. Miscellaneous belts, pulleys, countershafts, etc.
9. Miscellaneous equipment, including atmospheric and weather indicating devices, intrasite communication equipment, laboratory equipment, signal systems, callophones emergency whistles and sirens, fire alarms, insect-control equipment, and other similar equipment.
10. Railway cars not includible elsewhere.
11. Refrigerating systems, including compressors, pumps, cooling coils, etc.
12. Station maintenance equipment, including lathes, shapers, planers, drill presses, hydraulic presses, grinders, etc., with motors, shafting, hangers, pulleys, etc.
13. Ventilating equipment, including items wholly identified with apparatus listed herein.
When any item of equipment listed herein is wholly used in connection with equipment included in another account, its cost shall be included in such other account.
This account shall include asset retirement costs on plant included in the steam production function.
This account shall include the cost of land and land rights used in connection with nuclear power generation. (See electric plant instruction 7.)
This account shall include the cost in place of structures and improvements used and useful in connection with nuclear power generation. (See electric plant instruction 8.)
Include vapor containers and nuclear production roads and railroads in this account.
This account shall include the installed cost of reactors, reactor fuel handling and storage equipment, pressurizing equipment, coolant charging equipment, purification and discharging equipment, radioactive waste treatment and disposal equipment, boilers, steam and feed water piping, reactor and boiler apparatus and accessories and other reactor plant equipment used in the production of steam to be used primarily for generating electricity, including auxiliary superheat boilers and associated equipment in systems which change temperatures or pressure of steam from the reactor system.
1. Auxiliary superheat boilers and associated fuel storage handling preparation and burning equipment, etc. (See account 312 Boiler Plant Equipment, for items, but exclude water supply, water flow lines, and steam lines, as well as other equipment not strictly within the superheat function.)
2. Boiler feed system, including feed water heaters, evaporator condensers, heater drain pumps, heater drainers, deaerators, and vent condensers, boiler feed pumps, surge tanks, feed water regulators, feed water measuring equipment, and all associated drivers.
3. Boilers and heat exchangers.
4. Instruments and devices, including all measuring, indicating, and recording equipment for reactor and boiler plant service together with mountings and supports.
5. Lighting systems.
6. Moderators, such as heavy water, graphite, etc., initial charge.
7. Reactor coolant; primary and secondary systems (initial charge).
8. Radioactive waste treatment and disposal equipment, including tanks, ion exchangers, incinerators, condensers, chimneys, and diluting fans and pumps.
9. Foundations and settings, especially constructed for and not expected to outlast the apparatus for which provided.
10. Reactor including shielding, control rods and mechanisms.
11. Reactor fuel handling equipment, including manipulating and extraction tools, underwater viewing equipment, seal cutting and welding equipment, fuel transfer equipment and fuel disassembly machinery.
12. Reactor fuel element failure detection system.
13. Reactor emergency poison container and injection system.
14. Reactor pressurizing and pressure relief equipment, including pressurizing tanks and immersion heaters.
15. Reactor coolant or moderator circulation charging, purification, and discharging equipment, including tanks, pumps, heat exchangers, demineralizers, and storage.
16. Station piping, including pipes, valves, fittings, separators, traps, desuperheaters, hangers, excavation, covering, etc., for station piping system, including all-reactor coolant, steam, condensate, boiler feed and water supply piping, etc., but not condensing water, plumbing, building heating, oil, gas, or air piping.
17. Ventilating equipment.
18. Water purification equipment, including softeners, demineralizers, and accessories, evaporators and accessories, heat exchangers, filters, tanks for filtered or softened water, pumps, motors, etc.
19. Water supply systems, including pumps, motors, strainers, raw-water storage tanks, boiler wash pumps, intake and discharge pipes and tunnels not a part of a building.
20. Reactor plant cranes and hoists, and associated drives.
When the system for supplying boiler or condenser water is elaborate, as when it includes a dam, reservoir, canal, pipe lines, or cooling ponds, the cost of such special facilities shall be charged to a subdivision of account 321, Structures and Improvements.
This account shall include the cost installed of main turbine-driven units and accessory equipment used in generating electricity by steam.
1. Air cleaning and cooling apparatus, including blowers, drive equipment, air ducts not a part of building, louvers, pumps, hoods, etc.
2. Circulating pumps, including connections between condensers, and intake and discharge tunnels.
3. Condensers, including condensate pumps, air and vacuum pumps ejectors, unloading valves and vacuum breakers, expansion devices, screens, etc.
4. Generator hydrogen gas piping system and hydrogen detrainment equipment, and bulk hydrogen gas storage equipment.
5. Cooling system, including towers, pumps, tanks and piping.
6. Cranes, hoists, etc., including items wholly identified with items listed herein.
7. Excitation system, when identified with main generating units.
8. Fire extinguishing systems.
9. Foundations and settings, especially constructed for and not expected to outlast the apparatus for which provided.
10. Governors.
11. Lighting systems.
12. Lubricating systems, including gauges filters, water separators, tanks, pumps, piping motors, etc.
13. Mechanical meters, including gauges recording instruments, sampling and testing equipment.
14. Piping—main exhaust, including connections between turbogenerator and condenser and between condenser and hotwell.
15. Piping—main steam, including connections from main throttle valve to turbine inlet.
16. Platforms, railings, steps, gratings, etc. appurtenant to apparatus listed herein.
17. Pressure oil systems, including accumulators, pumps, piping, motors, etc.
18. Steelwork, specially constructed for apparatus listed herein.
19. Throttle and inlet valve.
20. Tunnels, intake and discharge, for condenser system, when not a part of structure water screens, etc.
21. Turbogenerators—main, including turbine and generator, field rheostats and electric connections for self-excited units.
22. Water screens, motors, etc.
23 Moisture separators for turbine steam.
24. Turbine lubricating oil (initial charge).
This account shall include the cost installed of auxiliary generating apparatus, conversion equipment, and equipment used primarily in connection with the control and switching of electric energy produced by nuclear power, and the protection of electric circuits and equipment, except electric motors used to drive equipment included in other accounts. Such motors shall be included in the account in which the equipment with which they are associated is included.
Do not include in this account transformers and other equipment used for changing the voltage or frequency of electric energy for the purpose of transmission or distribution.
1. Auxiliary generators, including boards, compartments, switching equipment, control equipment, and connections to auxiliary power bus.
2. Excitation system, including motor, turbine and dual-drive exciter sets and rheostats, storage batteries and charging equipment, circuit breakers, panels and accessories, knife switches and accessories, surge arresters, instrument shunts, conductors and conduit, special supports for conduit, generator field and exciter switch panels, exciter bus tie panels, generator and exciter rheostats, etc., special housing, protective screens, etc.
3. Generator main connections, including oil circuit breakers and accessories, disconnecting switches and accessories, operating mechanisms and interlocks, current transformers, potential transformers, protective relays, isolated panels and equipment, conductors and conduit, special supports for generator main leads, grounding switch, etc., special housings, protective screens, etc.
4. Station buses, including main, auxiliary, transfer, synchronizing and fault ground buses, including oil circuit breakers and accessories, disconnecting switches and accessories, operating mechanisms and interlocks, reactors and accessories, voltage regulators and accessories, compensators, resistors, starting transformers, current transformers, potential transformers, protective relays, storage batteries and charging equipment, isolated panels and equipment, conductors and conduit, special supports, special housings, concrete pads, general station grounding system, fire-extinguishing system, and test equipment.
5. Station control system, including station switchboards with panel wiring, panels with instruments and control equipment only, panels with switching equipment mounted or mechanically connected, truck-type boards complete, cubicles, station supervisory control boards, generator and exciter signal stands, temperature recording devices, frequency-control equipment, master clocks, watt-hour meters and synchronoscope in the turbine room, station totalizing wattmeter, boiler-room load indicator equipment, storage batteries, panels and charging sets, instrument transformers for supervisory metering, conductors and conduit, special supports for conduit, switchboards, batteries, special housing for batteries, protective screens, doors, etc.
When any item of equipment listed herein is used wholly to furnish power to equipment included in another account, its cost shall be included in such other account
This account shall include the cost installed of miscellaneous equipment in and about the nuclear generating plant devoted to general station use, and which is not properly includible in any of the foregoing nuclear-power production accounts.
1. Compressed air and vacuum cleaning systems, including tanks, compressors, exhausters, air filters, piping, etc.
2. Cranes and hoisting equipment, including cranes, cars, crane rails, monorails, hoists, etc., with electric and mechanical connections.
3. Fire-extinguishing equipment for general station and site use.
4. Foundations and settings specially constructed for and not expected to outlast the apparatus for which provided.
5. Locomotive cranes not includible elsewhere.
6. Locomotives not included elsewhere.
7. Marine equipment, including boats, barges, etc.
8. Miscellaneous belts, pulleys, countershafts, etc.
9. Miscellaneous equipment, including atmospheric and weather recording devices, intrasite communication equipment, laboratory equipment, signal systems, callophones emergency whistles and sirens, fire alarms, insect-control equipment, and other similar equipment.
10. Railway cars or special shipping containers not includible elsewhere.
11. Refrigerating systems, including compressors, pumps, cooling coils, etc.
12. Station maintenance equipment, including lathes, shapers, planers, drill presses, hydraulic presses, grinders, etc., with motors, shafting, hangers, pulleys, etc.
13. Ventilating equipment, including items wholly identified with apparatus listed herein.
14. Station and area radiation monitoring equipment.
When any item of equipment listed herein is wholly used in connection with equipment included in another account, its cost shall be included in such other account.
This account shall include asset retirement costs on plant included in the nuclear production function.
This account shall include the cost of land and land rights used in connection with hydraulic power generation. (See electric plant instruction 7.) For Major utilities, it shall also include the cost of land and land rights used in connection with (1) the conservation of fish and wildlife, and (2) recreation. Separate subaccounts shall be maintained for each of the above.
This account shall include the cost in place of structures and improvements used in connection with hydraulic power generation. (See electric plant instruction 8.) For Major utilities, it shall also include the cost in place of structures and improvements used in connection with (1) the conservation of fish and wildlife, and (2) recreation. Separate subaccounts shall be maintained for each of the above.
This account shall include the cost in place of facilities used for impounding, collecting, storage, diversion, regulation, and delivery of water used primarily for generating electricity. For Major utilities, it shall also include the cost in place of facilities used in connection with (a) the conservation of fish and wildlife, and (b) recreation. Separate subaccounts shall be maintained for each of the above. (See electric plant instruction 8C.)
1. Bridges and culverts (when not a part of roads or railroads).
2. Clearing and preparing land.
3. Dams, including wasteways, spillways, flash boards, spillway gates with operating and control mechanisms, tunnels, gate houses, and fish ladders.
4. Dikes and embankments.
5. Electric system, including conductors control system, transformers, lighting fixtures, etc.
6. Excavation, including shoring, bracing, bridging, refill, and disposal of excess excavated material.
7. Foundations and settings specially constructed for and not expected to outlast the apparatus for which provided.
8. Intakes, including trash racks, rack cleaners, control gates and valves with operating mechanisms, and intake house when not a part of station structure.
9. Platforms, railings, steps, gratings, etc., appurtenant to structures listed herein.
10. Power line wholly identified with items included herein.
11. Retaining walls.
12. Water conductors and accessories, including canals, tunnels, flumes, penstocks pipe conductors, forebays, tailraces, navigation locks and operating mechanisms, waterhammer and surge tanks, and supporting trestles and structures.
13. Water storage reservoirs, including dams, flashboards, spillway gates and operating mechanisms, inlet and outlet tunnels, regulating valves and valve towers, silt and mud sluicing tunnels with valve or gate towers, and all other structures wholly identified with any of the foregoing items.
This account shall include the cost installed of water wheels and hydraulic turbines (from connection with penstock or flume to tailrace) and generators driven thereby devoted to the production of electricity by water power or for the production of power for industrial or other purposes, if the equipment used for such purposes is a part of the hydraulic power plant works.
1. Exciter water wheels and turbines, including runners, gates, governors, pressure regulators, oil pumps, operating mechanisms, scroll cases, draft tubes, and draft-tube supports.
2. Fire-extinguishing equipment.
3. Foundations and settings, specially constructed for and not expected to outlast the apparatus for which provided.
4. Generator cooling system, including air cooling and washing apparatus, air fans and accessories, air ducts, etc.
5. Generators—main, a.c. or d.c., including field rheostats and connections for self-excited units and excitation system when identified with the generating unit.
6. Lighting systems.
7. Lubricating systems, including gauges, filters, tanks, pumps, piping, etc.
8. Main penstock valves and appurtenances, including main valves, control equipment, bypass valves and fittings, and other accessories.
9. Main turbines and water wheels, including runners, gates, governors, pressure regulators, oil pumps, operating mechanisms, scroll cases, draft tubes, and draft-tube supports.
10. Mechanical meters and recording instruments.
11. Miscellaneous water-wheel equipment, including gauges, thermometers, meters, and other instruments.
12. Platforms, railings, steps, gratings, etc., appurtenant to apparatus listed herein.
13. Scroll case filling and drain system, including gates, pipe, valves, fittings, etc.
14. Water-actuated pressure-regulator system, including tanks and housings, pipes, valves, fittings and insulations, piers and anchorage, and excavation and backfill.
This account shall include the cost installed of auxiliary generating apparatus, conversion equipment, and equipment used primarily in connection with the control and switching of electric energy produced by hydraulic power and the protection of electric circuits and equipment, except electric motors used to drive equipment included in other accounts, such motors being included in the account in which the equipment with which they are associated is included.
1. Auxiliary generators, including boards, compartments, switching equipment, control equipment, and connections to auxiliary power bus.
2. Excitation system, including motor, turbine, and dual-drive exciter sets and rheostats, storage batteries and charging equipment, circuit breakers, panels and accessories, knife switches and accessories, surge arresters, instrument shunts, conductors and conduit, special supports for conduit, generator field and exciter switch panels, exciter bus tie panels, generator and exciter rheostats, etc., special housings, protective screens, etc.
3. Generator main connections, including oil circuit breakers and accessories, disconnecting switches and accessories, operating mechanisms and interlocks, current transformers, potential transformers, protective relays, isolated panels and equipment, conductors and conduit, special supports for generator main leads, grounding switch, etc., special housings, protective screens, etc.
4. Station buses, including main, auxiliary, transfer, synchronizing, and fault ground buses, including oil circuit breakers and accessories, disconnecting switches and accessories, operating mechanisms and interlocks, reactors and accessories, voltage regulators and accessories, compensators, resistors starting transformers, current transformers, potential transformers, protective relays, storage batteries, and charging equipment, isolated panels and equipment, conductors and conduit, special supports, special fire-extinguishing system, and test equipment.
5. Station control system, including station switchboards with panel wiring panels with instruments and control equipment only, panels with switching equipment mounted or mechanically connected, trucktype boards complete, cubicles, station supervisory control devices, frequency control equipment, master clocks, watt-hour meter, station totalizing watt-meter, storage batteries, panels and charging sets, instrument transformers for supervisory metering, conductors and conduit, special supports for conduit, switchboards, batteries, special housings for batteries, protective screens, doors, etc.
Do not include in this account transformers and other equipment used for changing the voltage or frequency of electricity for the purpose of transmission or distribution.
When any item of equipment listed herein is used wholly to furnish power to equipment, it shall be included in such equipment account.
This account shall include the cost installed of miscellaneous equipment in and about the hydroelectric generating plant which is devoted to general station use and is not properly includible in other hydraulic production accounts. For Major utilities, it shall also include the cost of equipment used in connection with (a) the conservation of fish and wildlife, and (b) recreation. Separate subaccounts shall be maintained for each of the above.
1. Compressed air and vacuum cleaning systems, including tanks, compressors, exhausters, air filters, piping, etc.
2. Cranes and hoisting equipment, including cranes, cars, crane rails, monorails, hoists, etc., with electric and mechanical connections.
3. Fire-extinguishing equipment for general station use.
4. Foundations and settings, specially constructed for and not expected to outlast the apparatus for which provided.
5. Locomotive cranes not includible elsewhere.
6. Locomotives not includible elsewhere.
7. Marine equipment, including boats, barges, etc.
8. Miscellaneous belts, pulleys, countershafts, etc.
9. Miscellaneous equipment, including atmospheric and weather indicating devices, intrasite communication equipment, laboratory equipment, insect control equipment, signal systems, callophones, emergency whistles and sirens, fire alarms, and other similar equipment.
10. Railway cars, not includible elsewhere.
11. Refrigerating system, including compressors, pumps, cooling coils, etc.
12. Station maintenance equipment, including lathes, shapers, planers, drill presses, hydraulic presses, grinders, etc., with motors, shafting, hangers, pulleys, etc.
13. Ventilating equipment, including items wholly identified with apparatus listed herein.
When any item of equipment, listed herein is used wholly in connection with equipment included in another account, its cost shall be included in such other account.
This account shall include the cost of roads, railroads, trails, bridges, and trestles used primarily as production facilities. It includes also those roads, etc., necessary to connect the plant with highway transportation systems, except when such roads are dedicated to public use and maintained by public authorities.
1. Bridges, including foundations, piers, girders, trusses, flooring, etc.
2. Clearing land.
3. Railroads, including grading, ballast, ties, rails, culverts, hoists, etc.
4. Roads, including grading, surfacing, culverts, etc.
5. Structures, constructed and maintained in connection with items listed herein.
6. Trails, including grading, surfacing, culverts, etc.
7. Trestles, including foundations, piers, girders, trusses, flooring, etc.
Roads intended primarily for connecting employees’ houses with the powerplant, and roads used primarily in connection with fish and wildlife, and recreation activities, shall not be included herein but in account 331, Structures and Improvements.
The cost of temporary roads, bridges, etc. necessary during the period of construction but abandoned or dedicated to public use upon completion of the plant, shall not be included herein but shall be charged to the accounts appropriate for the construction.
This account shall include asset retirement costs on plant included in the hydraulic production function.
This account shall include the cost of land and land rights used in connection with other power generation. (See electric plant instruction 7.)
This account shall include the cost in place of structures and improvements used in connection with other power generation. (See electric plant instruction 8.)
This account shall include the cost installed of fuel handling and storage equipment used between the point of fuel delivery to the station and the intake pipe through which fuel is directly drawn to the engine, also the cost of gas producers and accessories devoted to the production of gas for use in prime movers driving main electric generators.
1. Blower and fans.
2. Boilers and pumps.
3. Economizers.
4. Exhauster outfits.
5. Flues and piping.
6. Pipe system.
7. Producers.
8. Regenerators.
9. Scrubbers.
10. Steam injectors.
11. Tanks for storage of oil, gasoline, etc.
12. Vaporizers.
This account shall include the cost installed of Diesel or other prime movers devoted to the generation of electric energy, together with their auxiliaries.
1. Air-filtering system.
2. Belting, shafting, pulleys, reduction gearing, etc.
3. Cooling system, including towers, pumps, tanks, and piping.
4. Cranes, hoists, etc., including items wholly identified with apparatus listed herein.
5. Engines, Diesel, gasoline, gas, or other internal combustion.
6. Foundations and settings specially constructed for and not expected to outlast the apparatus for which provided.
7. Governors.
8. Ignition system.
9. Inlet valve.
10. Lighting systems.
11. Lubricating systems, including filters, tanks, pumps, and piping.
12. Mechanical meters, including gauges, recording instruments, sampling, and testing equipment.
13. Mufflers.
14. Piping.
15. Starting systems, compressed air, or other, including compressors and drives, tanks, piping, motors, boards and connections, storage tanks, etc.
16. Steelwork, specially constructed for apparatus listed herein.
17. Waste heat boilers, antifluctuators, etc.
This account shall include the cost installed of Diesel or other power driven main generators.
1. Cranes, hoists, etc., including items wholly identified with such apparatus.
2. Fire-extinguishing equipment.
3. Foundations and settings, specially constructed for and not expected to outlast the apparatus for which provided.
4. Generator cooling system, including air cooling and washing apparatus, air fans and accessories, air ducts, etc.
5. Generators—main, a.c. or d.c., including field rheostats and connections for self-excited units and excitation system when identified with the generating unit.
6. Lighting systems.
7. Lubricating system, including tanks, filters, strainers, pumps, piping, coolers, etc.
8. Mechanical meters, and recording instruments.
9. Platforms, railings, steps, gratings, etc., appurtenant to apparatus listed herein.
If prime movers and generators are so integrated that it is not practical to classify them separately, the entire unit may be included in account 344, Generators.
This account shall include the cost installed of auxiliary generating apparatus, conversion equipment, and equipment used primarily in connection with the control and switching of electric energy produced in other power generating stations, and the protection of electric circuits and equipment, except electric motors used to drive equipment included in other accounts. Such motors shall be included in the account in which the equipment with which it is associated is included.
1. Auxiliary generators, including boards, compartments, switching equipment, control equipment, and connections to auxiliary power bus.
2. Excitation system, including motor, turbine and dual-drive exciter sets and rheostats, storage batteries and charging equipment, circuit breakers, panels and accessories, knife switches and accessories, surge arresters, instrument shunts, conductors and conduit, special supports for conduit, generator field and exciter switch panels, exciter bus tie panels, generator and exciter rheostats, etc., special housings, protective screens, etc.
3. Generator main connections, including oil circuit breakers and accessories, disconnecting switches and accessories, operating mechanisms and interlocks, current transformers, potential transformers, protective relays, isolated panels and equipment, conductors and conduit, special supports for generator main leads, grounding switch, etc., special housing, protective screens, etc.
4. Station control system, including station switchboards with panel wiring, panels with instruments and control equipment only, panels with switching equipment mounted or mechanically connected, trunktype boards complete, cubicles, station supervisory control boards, generator and exciter signal stands, temperature-recording devices, frequency control equipment, master clocks, watt-hour meter, station totalizing wattmeter, storage batteries, panels and charging sets, instrument transformers for supervisory metering, conductors and conduit, special supports for conduit, switchboards, batteries, special housing for batteries, protective screens, doors, etc.
5. Station buses, including main, auxiliary transfer, synchronizing and fault ground buses, including oil curcuit breakers and accessories, disconnecting switches and accessories, operating mechanisms and interlocks, reactors and accessories, voltage regulators and accessories, compensators, resistors, starting transformers, current transformers, potential transformers, protective relays, storage batteries and charging equipment, isolated panels and equipment, conductors and conduit, special supports, special housings, concrete pads, general station ground system, special fire-extinguishing system, and test equipment.
Do not include in this account transformers and other equipment used for changing the voltage or frequency of electric energy for the purpose of transmission or distribution.
When any item of equipment listed herein is used wholly to furnish power to equipment included in another account, its cost shall be included in such other account.
This account shall include the cost installed of miscellaneous equipment in and about the other power generating plant, devoted to general station use, and not properly includible in any of the foregoing other power production accounts.
1. Compressed air and vacuum cleaning systems, including tanks, compressors, exhausters, air filters, piping, etc.
2. Cranes and hoisting equipment, including cranes, cars, crane rails, monorails, hoists, etc., with electric and mechanical connections.
3. Fire-extinguishing equipment for general station use.
4. Foundations and settings, specially constructed for and not expected to outlast the apparatus for which provided.
5. Miscellaneous equipment, including atmospheric and weather indicating devices, intrasite communication equipment, laboratory equipment, signal systems, callophones, emergency whistles and sirens, fire alarms, and other similar equipment.
6. Miscellaneous belts, pulleys, countershafts, etc.
7. Refrigerating system including compressors, pumps, cooling coils, etc.
8. Station maintenance equipment, including lathes, shapers, planers, drill presses, hydraulic presses, grinders, etc., with motors, shafting, hangers, pulleys, etc.
9. Ventilating equipment, including items wholly identified with apparatus listed herein.
When any item of equipment, listed herein is used wholly in connection with equipment included in another account, its cost shall be included in such other account.
This account shall include asset retirement costs on plant included in the other production function.
A. This account shall include the cost installed of energy storage equipment used to store energy for load managing purposes. Where energy storage equipment can perform more than one function or purpose, the cost of the equipment shall be allocated among production, transmission, and distribution plant based on the services provided by the asset and the allocation of the asset’s cost through rates approved by a relevant regulatory agency. Reallocation of the cost of equipment recorded in this account shall be in accordance with Electric Plant Instruction No. 12, Transfers of Property.
B. Labor costs and power purchased to energize the equipment are includible on the first installation only. The cost of removing, relocating and resetting energy storage equipment shall not be charged to this account but to accounts Account 548.1, Operation of Energy Storage Equipment, and Account 553.1, Maintenance of Energy Storage Equipment., as appropriate.
C. The records supporting this account shall show, by months, the function(s) each energy storage asset supports or performs.
Note: The cost of pumped storage hydroelectric plant shall be charged to hydraulic production plant. These are examples of items includible in this account. This list is not exhaustive.
This account shall include the cost of land and land rights used in connection with transmission operations. (See electric plant instruction 7.)
A. This account shall include the cost installed of energy storage equipment used to store energy for load managing purposes. Where energy storage equipment can perform more than one function or purposes, the cost of the equipment shall be allocated among production, transmission, and distribution plant based on the services provided by the asset and the allocation of the asset’s cost through rates approved by a relevant regulatory agency. Reallocation of the cost of equipment recorded in this account shall be in accordance with Electric Plant Instruction No. 12, Transfers of Property.
B. Labor costs and power purchased to energize the equipment are includible on the first installation only. The cost of removing, relocating and resetting energy storage equipment shall not be charged to this account but to Account 562.1, Operation of Energy Storage Equipment, and Account, 570.1, Maintenance of Energy Storage Equipment, as appropriate.
C. The records supporting this account shall show, by months, the function(s) each energy storage asset supports or performs.
This account shall include the cost in place of structures and improvements used in connection with transmission operations. (See electric plant instruction 8.)
This account shall include the cost installed of transforming, conversion, and switching equipment used for the purpose of changing the characteristics of electricity in connection with its transmission or for controlling transmission circuits.
1. Bus compartments, concrete, brick, and sectional steel, including items permanently attached thereto.
2. Conduit, including concrete and iron duct runs not a part of a building.
3. Control equipment, including batteries battery charging equipment, transformers, remote relay boards, and connections.
4. Conversion equipment, including transformers, indoor and outdoor, frequency changers, motor generator sets, rectifiers, synchronous converters, motors, cooling equipment, and associated connections.
5. Fences.
6. Fixed and synchronous condensers, including transformers, switching equipment blowers, motors and connections.
7. Foundations and settings, specially constructed for and not expected to outlast the apparatus for which provided.
8. General station equipment, including air compressors, motors, hoists, cranes, test equipment, ventilating equipment, etc.
9. Platforms, railings, steps, gratings, etc. appurtenant to apparatus listed herein.
10. Primary and secondary voltage connections, including bus runs and supports, insulators, potheads, lightning arresters, cable and wire runs from and to outdoor connections or to manholes and the associated regulators, reactors, resistors, surge arresters, and accessory equipment.
11. Switchboards, including meters, relays, control wiring, etc.
12. Switching equipment, indoor and outdoor, including oil circuit breakers and operating mechanisms, truck switches, and disconnect switches.
13. Tools and appliances.
This account shall include the cost installed of towers and appurtenant fixtures used for supporting overhead transmission conductors.
1. Anchors, guys, braces.
2. Brackets.
3. Crossarms, including braces.
4. Excavation, backfill, and disposal of excess excavated material.
5. Foundations.
6. Guards.
7. Insulator pins and suspension bolts.
8. Ladders and steps.
9. Railings, etc.
10. Towers.
This account shall include the cost installed of transmission line poles, wood, steel, concrete, or other material, together with appurtenant fixtures used for supporting overhead transmission conductors.
1. Anchors, head arm and other guys, including guy guards, guy clamps, strain insulators, pole plates, etc.
2. Brackets.
3. Crossarms and braces.
4. Excavation and backfill, including disposal of excess excavated material.
5. Extension arms.
6. Gaining, roofing stenciling, and tagging.
7. Insulator pins and suspension bolts.
8. Paving.
9. Pole steps.
10. Poles, wood, steel, concrete, or other material.
11. Racks complete with insulators.
12. Reinforcing and stubbing.
13. Settings.
14. Shaving and painting.
This account shall include the cost installed of overhead conductors and devices used for transmission purposes.
1. Circuit breakers.
2. Conductors, including insulated and bare wires and cables.
3. Ground wires and ground clamps.
4. Insulators, including pin, suspension, and other types.
5. Lightning arresters.
6. Switches.
7. Other line devices.
This account shall include the cost installed of underground conduit and tunnels used for housing transmission cables or wires. (See electric plant instruction 14.)
1. Conduit, concrete, brick or tile, including iron pipe, fiber pipe, Murray duct, and standpipe on pole or tower.
2. Excavation, including shoring, bracing, bridging, backfill, and disposal of excess excavated material.
3. Foundations and settings specially constructed for and not expected to outlast the apparatus for which provided.
4. Lighting systems.
5. Manholes, concrete or brick, including iron or steel, frames and covers, hatchways, gratings, ladders, cable racks and hangers, etc., permanently attached to manholes.
6. Municipal inspection.
7. Pavement disturbed, including cutting and replacing pavement, pavement base and sidewalks.
8. Permits.
9. Protection of street openings.
10. Removal and relocation of subsurface obstructions.
11. Sewer connections, including drains, traps, tide valves, check valves, etc.
12. Sumps, including pumps.
13. Ventilating equipment.
This account shall include the cost installed of underground conductors and devices used for transmission purposes.
1. Armored conductors, buried, including insulators, insulating materials, splices, potheads, trenching, etc.
2. Armored conductors, submarine, including insulators, insulating materials, splices in terminal chambers, potheads, etc.
3. Cables in standpipe, including pothead and connection from terminal chamber of manhole to insulators on pole.
4. Circuit breakers.
5. Fireproofing, in connection with any items listed herein.
6. Hollow-core oil-filled cable, including straight or stop joints pressure tanks, auxiliary air tanks, feeding tanks, terminals, potheads and connections, ventilating equipment, etc.
7. Lead and fabric covered conductors, including insulators, compound filled, oil filled, or vacuum splices, potheads, etc.
8. Lightning arresters.
9. Municipal inspection.
10. Permits.
11. Protection of street openings.
12. Racking of cables.
13. Switches.
14. Other line devices.
This account shall include the cost of roads, trails, and bridges used primarily as transmission facilities.
1. Bridges, including foundation piers, girders, trusses, flooring, etc.
2. Clearing land.
3. Roads, including grading, surfacing, culverts, etc.
4. Structures, constructed and maintained in connection with items included herein.
5. Trails, including grading, surfacing, culverts, etc.
The cost of temporary roads, bridges, etc., necessary during the period of construction but abandoned or dedicated to public use upon completion of the plant, shall be charged to the accounts appropriate for the construction.
This account shall include asset retirement costs on plant included in the transmission plant function.
This account shall include the cost of land and land rights used in connection with distribution operations. (See electric plant instruction 7.)
Do not include in this account the cost of permits to erect poles, towers, etc., or to trim trees. (See account 364, Poles, Towers and Fixtures, and account 365, Overhead Conductors and Devices.)
This account shall include the cost in place of structures and improvements used in connection with distribution operations. (See electric plant instruction 8.)
This account shall include the cost installed of station equipment, including transformer banks, etc., which are used for the purpose of changing the characteristics of electricity in connection with its distribution.
1. Bus compartments, concrete, brick and sectional steel, including items permanently attached thereto.
2. Conduit, including concrete and iron duct runs not part of building.
3. Control equipment, including batteries, battery charging equipment, transformers, remote relay boards, and connections.
4. Conversion equipment, indoor and outdoor, frequency changers, motor generator sets, rectifiers, synchronous converters, motors, cooling equipment, and associated connections.
5. Fences.
6. Fixed and synchronous condensers, including transformers, switching equipment, blowers, motors, and connections.
7. Foundations and settings, specially constructed for and not expected to outlast the apparatus for which provided.
8. General station equipment, including air compressors, motors, hoists, cranes, test equipment, ventilating equipment, etc.
9. Platforms, railings, steps, gratings, etc., appurtenant to apparatus listed herein.
10. Primary and secondary voltage connections, including bus runs and supports, insulators, potheads, lightning arresters, cable and wire runs from and to outdoor connections or to manholes and the associated regulators, reactors, resistors, surge arresters, and accessory equipment.
11. Switchboards, including meters, relays, control wiring, etc.
12. Switching equipment, indoor and outdoor, including oil circuit breakers and operating mechanisms, truck switches, disconnect switches.
The cost of rectifiers, series transformers, and other special station equipment devoted exclusively to street lighting service shall not be included in this account, but in account 373, Street Lighting and Signal Systems.
A. This account shall include the cost installed of energy storage equipment used to store energy for load managing purposes. Where energy storage equipment can perform more than one function or purpose, the cost of the equipment shall be allocated among production, transmission, and distribution plant based on the services provided by the asset and the allocation of the asset’s cost through rates approved by a relevant regulatory agency. Reallocation of the cost of equipment recorded in this account shall be in accordance with Electric Plant Instruction No. 12, Transfers of Property.
B. Labor costs and power purchased to energize the equipment are includible on the first installation only. The cost of removing, relocating and resetting energy storage equipment shall not be charged to this account but to Account 582.1, Operation of Energy Storage Equipment, and Account, 592.1, Maintenance of Energy Storage Equipment, as appropriate.
C. The records supporting this account shall show, by months, the function(s) each energy storage asset supports or performs.
This account shall include the cost installed of poles, towers, and appurtenant fixtures used for supporting overhead distribution conductors and service wires.
1. Anchors, head arm, and other guys, including guy guards, guy clamps, strain insulators, pole plates, etc.
2. Brackets.
3. Crossarms and braces.
4. Excavation and backfill, including disposal of excess excavated material.
5. Extension arms.
6. Foundations.
7. Guards.
8. Insulator pins and suspension bolts.
9. Paving.
10. Permits for construction.
11. Pole steps and ladders.
12. Poles, wood, steel, concrete, or other material.
13. Racks complete with insulators.
14. Railings.
15. Reinforcing and stubbing.
16. Settings.
17. Shaving, painting, gaining, roofing, stenciling, and tagging.
18. Towers.
19. Transformer racks and platforms.
This account shall include the cost installed of overhead conductors and devices used for distribution purposes.
1. Circuit breakers.
2. Conductors, including insulated and bare wires and cables.
3. Ground wires, clamps, etc.
4. Insulators, including pin, suspension, and other types, and tie wire or clamps.
5. Lightning arresters.
6. Railroad and highway crossing guards.
7. Splices.
8. Switches.
9. Tree trimming, initial cost including the cost of permits therefor.
10. Other line devices.
The cost of conductors used solely for street lighting or signal systems shall not be included in this account but in account 373, Street Lighting and Signal Systems.
This account shall include the cost installed of underground conduit and tunnels used for housing distribution cables or wires.
1. Conduit, concrete, brick and tile, including iron pipe, fiber pipe, Murray duct, and standpipe on pole or tower.
2. Excavation, including shoring, bracing, bridging, backfill, and disposal of excess excavated material.
3. Foundations and settings specially constructed for and not expected to outlast the apparatus for which constructed.
4. Lighting systems.
5. Manholes, concrete or brick, including iron or steel frames and covers, hatchways, gratings, ladders, cable racks and hangers, etc., permanently attached to manholes.
6. Municipal inspection.
7. Pavement disturbed, including cutting and replacing pavement, pavement base, and sidewalks.
8. Permits.
9. Protection of street openings.
10. Removal and relocation of subsurface obstructions.
11. Sewer connections, including drains, traps, tide valves, check valves, etc.
12. Sumps, including pumps.
13. Ventilating equipment.
The cost of underground conduit used solely for street lighting or signal systems shall be included in account 373, Street Lighting and Signal Systems.
This account shall include the cost installed of underground conductors and devices used for distribution purposes.
1. Armored conductors, buried, including insulators, insulating materials, splices, potheads, trenching, etc.
2. Armored conductors, submarine, including insulators, insulating materials, splices in terminal chamber, potheads, etc.
3. Cables in standpipe, including pothead and connection from terminal chamber or manhole to insulators on pole.
4. Circuit breakers.
5. Fireproofing, in connection with any items listed herein.
6. Hollow-core oil-filled cable, including straight or stop joints, pressure tanks, auxiliary air tanks, feeding tanks, terminals, potheads and connections, etc.
7. Lead and fabric covered conductors, including insulators, compound-filled, oil-filled or vacuum splices, potheads, etc.
8. Lightning arresters.
9. Municipal inspection.
10. Permits.
11. Protection of street openings.
12. Racking of cables.
13. Switches.
14. Other line devices.
The cost of underground conductors and devices used solely for street lighting or signal systems shall be included in account 373, Street Lighting and Signal Systems.
A. This account shall include the cost installed of overhead and underground distribution line transformers and poletype and underground voltage regulators owned by the utility, for use in transforming electricity to the voltage at which it is to be used by the customer, whether actually in service or held in reserve.
B. When a transformer is permanently retired from service, the original installed cost thereof shall be credited to this account.
C. The records covering line transformers shall be so kept that the utility can furnish the number of transformers of various capacities in service and those in reserve, and the location and the use of each transformer.
1. Installation, labor of (first installation only).
2. Transformer cut-out boxes.
3. Transformer lightning arresters.
4. Transformers, line and network.
5. Capacitors.
6. Network protectors.
The cost of removing and resetting line transformers shall not be charged to this account but to account 583, Overhead Line Expenses, or account 584, Underground Line Expenses (for Nonmajor utilities, account 561, Line and Station Labor, or account 562, Line and Station Supplies and Expenses), as appropriate. The cost of line transformers used solely for street lighting or signal systems shall be included in account 373, Street Lighting and Signal Systems.
This account shall include the cost installed of overhead and underground conductors leading from a point where wires leave the last pole of the overhead system or the distribution box or manhole, or the top of the pole of the distribution line, to the point of connection with the customer’s outlet or wiring. Conduit used for underground service conductors shall be included herein.
1. Brackets.
2. Cables and wires.
3. Conduit.
4. Insulators.
5. Municipal inspection.
6. Overhead to underground, including conduit or standpipe and conductor from last splice on pole to connection with customer’s wiring.
7. Pavement disturbed, including cutting and replacing pavement, pavement base, and sidewalks.
8. Permits.
9. Protection of street openings.
10. Service switch.
11. Suspension wire.
A. This account shall include the cost installed of meters or devices and appurtenances thereto, for use in measuring the electricity delivered to its users, whether actually in service or held in reserve.
B. When a meter is permanently retired from service, the installed cost included herein shall be credited to this account.
C. The records covering meters shall be so kept that the utility can furnish information as to the number of meters of various capacities in service and in reserve as well as the location of each meter owned.
1. Alternating current, watt-hour meters.
2. Current limiting devices.
3. Demand indicators.
4. Demand meters.
5. Direct current watt-hour meters.
6. Graphic demand meters.
7. Installation, labor of (first installation only).
8. Instrument transformers.
9. Maximum demand meters.
10. Meter badges and their attachments.
11. Meter boards and boxes.
12. Meter fittings, connections, and shelves (first set).
13. Meter switches and cut-outs.
14. Prepayment meters.
15. Protective devices.
16. Testing new meters.
This account shall not include meters for recording output of a generating station, substation meters, etc. It includes only those meters used to record energy delivered to customers.
The cost of removing and resetting meters shall be charged to account 586, Meter Expenses (for Nonmajor utilities, account 556, Meter Expenses).
This account shall include the cost installed of equipment on the customer’s side of a meter when the utility incurs such cost and when the utility retains title to and assumes full responsibility for maintenance and replacement of such property. This account shall not include leased equipment, for which see account 372, Leased Property on Customers’ Premises.
1. Cable vaults.
2. Commercial lamp equipment.
3. Foundations and settings specially provided for equipment included herein.
4. Frequency changer sets.
5. Motor generator sets.
6. Motors.
7. Switchboard panels, high or low tension.
8. Wire and cable connections to incoming cables.
Do not include in this account any costs incurred in connection with merchandising, jobbing, or contract work activities.
This account shall include the cost of electric motors, transformers, and other equipment on customers’ premises (including municipal corporations), leased or loaned to customers, but not including property held for sale.
The cost of setting and connecting such appliances or equipment on the premises of customers and the cost of resetting or removal shall not be charged to this account but to operating expenses, account 587, Customer Installations Expenses (for Nonmajor utilities, account 567, Customer Installations Expenses).
Do not include in this account any costs incurred in connection with merchandising, jobbing, or contract work activities.
This account shall include the cost installed of equipment used wholly for public street and highway lighting or traffic, fire alarm, police, and other signal systems.
1. Armored conductors, buried or submarine, including insulators, insulating materials, splices, trenching, etc.
2. Automatic control equipment.
3. Conductors, overhead or underground, including lead or fabric covered, parkway cables, etc., including splices, insulators, etc.
4. Lamps, are, incandescent, or other types, including glassware, suspension fixtures, brackets, etc.
5. Municipal inspection.
6. Ornamental lamp posts.
7. Pavement disturbed, including cutting and replacing pavement, pavement base, and sidewalks.
8. Permits.
9. Posts and standards.
10. Protection of street openings.
11. Relays or time clocks.
12. Series contactors.
13. Switches.
14. Transformers, pole or underground.
This account shall include asset retirement costs on plant included in the distribution plant function.
This account shall include the cost of land and land rights used in connection with regional transmission and market operations.
This account shall include the cost in place of structures and improvements used for regional transmission and market operations.
This account shall include the cost of computer hardware and miscellaneous information technology equipment to provide scheduling, system control and dispatching, system planning, standards development, market monitoring, and market administration activities. Records shall be maintained identifying to the maximum extent practicable computer hardware owned and used for: (1) Scheduling, system control and dispatching, (2) system planning and standards development, and (3) market monitoring and market administration activities.
1. Personal computers
2. Servers
3. Workstations
4. Energy Management System (EMS) hardware
5. Supervisory Control and Data Acquisition (SCADA) system hardware
6. Peripheral equipment
7. Networking components
This account shall include the cost of off-the-shelf and in-house developed software purchased and used to provide scheduling, system control and dispatching, system planning, standards development, market monitoring, and market administration activities. Records shall be maintained identifying to the maximum extent practicable the cost of software used for:
(1) Scheduling, system control and dispatching,
(2) System planning and standards development, and
(3) Market monitoring and market administration activities.
1. Software licenses
2. User interface software
3. Modeling software
4. Database software
5. Tracking and monitoring software
6. Energy Management System (EMS) software
7. Supervisory Control and Data Acquisition (SCADA) system software
8. Evaluation and assessment system software
9. Operating, planning and transaction scheduling software
10. Reliability applications
11. Market application software
This account shall include the cost of communication equipment owned and used to acquire or share data and information used to control and dispatch the system.
1. Fiber optic cable
2. Remote terminal units
3. Microwave towers
4. Global Positioning System (GPS) equipment
5. Servers
6. Workstations
7. Telephones
This account shall include the cost of regional transmission and market operation plant and equipment not provided for elsewhere,
This account shall include asset retirement costs on regional control and market operation plant and equipment.
This account shall include the cost of land and land rights used for utility purposes, the cost of which is not properly includible in other land and land rights accounts. (See electric plant instruction 7.)
This account shall include the cost in place of structures and improvements used for utility purposes, the cost of which is not properly includible in other structures and improvements accounts (See electric plant instruction 8.)
This account shall include the cost of office furniture and equipment owned by the utility and devoted to utility service, and not permanently attached to buildings, except the cost of such furniture and equipment which the utility elects to assign to other plant accounts on a functional basis.
1. Bookcases and shelves.
2. Desks, chairs, and desk equipment.
3. Drafting-room equipment.
4. Filing, storage, and other cabinets.
5. Floor covering.
6. Library and library equipment.
7. Mechanical office equipment, such as accounting machines, typewriters, etc.
8. Safes.
9. Tables.
This account shall include the cost of transportation vehicles used for utility purposes.
1. Airplanes.
2. Automobiles.
3. Bicycles.
4. Electrical vehicles.
5. Motor trucks.
6. Motorcycles.
7. Repair cars or trucks.
8. Tractors and trailers.
9. Other transportation vehicles.
This account shall include the cost of equipment used for the receiving, shipping, handling, and storage of materials and supplies.
1. Chain falls.
2. Counters.
3. Cranes (portable).
4. Elevating and stacking equipment (portable).
5. Hoists.
6. Lockers.
7. Scales.
8. Shelving.
9. Storage bins.
10. Trucks, hand and power driven.
11. Wheelbarrows.
This account shall include the cost of tools, implements, and equipment used in construction, repair work, general shops and garages and not specifically provided for or includible in other accounts.
1. Air compressors.
2. Anvils.
3. Automobile repair shop equipment.
4. Battery charging equipment.
5. Belts, shafts and countershafts.
6. Boilers.
7. Cable pulling equipment.
8. Concrete mixers.
9. Drill presses.
10. Derricks.
11. Electric equipment.
12. Engines.
13. Forges.
14. Furnaces.
15. Foundations and settings specially constructed for and not expected to outlast the equipment for which provided.
16. Gas producers.
17. Gasoline pumps, oil pumps and storage tanks.
18. Greasing tools and equipment.
19. Hoists.
20. Ladders.
21. Lathes.
22. Machine tools.
23. Motor-driven tools.
24. Motors.
25. Pipe threading and cutting tools
26. Pneumatic tools.
27. Pumps.
28. Riveters.
29. Smithing equipment.
30. Tool racks.
31. Vises.
32. Welding apparatus.
33. Work benches.
This account shall include the cost installed of laboratory equipment used for general laboratory purposes and not specifically provided for or includible in other departmental or functional plant accounts.
1. Ammeters.
2. Current batteries.
3. Frequency changers.
4. Galvanometers.
5. Inductometers.
6. Laboratory standard millivolt meters.
7. Laboratory standard volt meters.
8. Meter-testing equipment.
9. Millivolt meters.
10. Motor generator sets.
11. Panels.
12. Phantom loads.
13. Portable graphic ammeters, voltmeters, and wattmeters.
14. Portable loading devices.
15. Potential batteries.
16. Potentiometers.
17. Rotating standards.
18. Standard cell, reactance, resistor, and shunt.
19. Switchboards.
20. Synchronous timers.
21. Testing panels.
22. Testing resistors.
23. Transformers.
24. Voltmeters.
25. Other testing, laboratory, or research equipment not provided for elsewhere.
This account shall include the cost of power operated equipment used in construction or repair work exclusive of equipment includible in other accounts. Include, also, the tools and accessories acquired for use with such equipment and the vehicle on which such equipment is mounted.
1. Air compressors, including driving unit and vehicle.
2. Back filling machines.
3. Boring machines.
4. Bulldozers.
5. Cranes and hoists.
6. Diggers.
7. Engines.
8. Pile drivers.
9. Pipe cleaning machines.
10. Pipe coating or wrapping machines.
11. Tractors—Crawler type.
12. Trenchers.
13. Other power operated equipment.
It is intended that this account include only such large units as are generally self-propelled or mounted on movable equipment.
This account shall include the cost installed of telephone, telegraph, and wireless equipment for general use in connection with utility operations.
1. Antennae.
2. Booths.
3. Cables.
4. Distributing boards.
5. Extension cords.
6. Gongs
7. Hand sets, manual and dial.
8. Insulators.
9. Intercommunicating sets.
10. Loading coils.
11. Operators’ desks.
12. Poles and fixtures used wholly for telephone or telegraph wire.
13. Radio transmitting and receiving sets.
14. Remote control equipment and lines.
15. Sending keys.
16. Storage batteries
17. Switchboards.
18. Telautograph circuit connections.
19. Telegraph receiving sets.
20. Telephone and telegraph circuits.
21. Testing instruments.
22. Towers.
23. Underground conduit used wholly for telephone or telegraph wires and cable wires.
This account shall include the cost of equipment, apparatus, etc., used in the utility operations, which is not includible in any other account of this system of accounts.
1. Hospital and infirmary equipment.
2. Kitchen equipment.
3. Employees’ recreation equipment.
4. Radios.
5. Restaurant equipment.
6. Soda fountains.
7. Operators’ cottage furnishings.
8. Other miscellaneous equipment.
Miscellaneous equipment of the nature indicated above wherever practicable shall be included in the utility plant accounts on a functional basis.
This account shall include the cost of tangible utility plant not provided for elsewhere.
This account shall include asset retirement costs on plant included in the general plant function.
There shall be shown under this caption the total amount included in the electric operating revenue accounts provided herein.
There shall be shown under this caption the total amount included in the electric operation expense accounts provided herein. (See note to operating expense instruction 3.)
There shall be shown under this caption the total amount included in the electric maintenance expense accounts provided herein.
A. This account shall include the amount of depreciation expense for all classes of depreciable electric plant in service except such depreciation expense as is chargeable to clearing accounts or to account 416, Costs and Expenses of Merchandising, Jobbing and Contract Work.
B. The utility shall keep such records of property and property retirements as will reflect the service life of property which has been retired and aid in estimating probable service life by mortality, turnover, or other appropriate methods; and also such records as will reflect the percentage of salvage and costs of removal for property retired from each account, or subdivision thereof, for depreciable electric plant.
Depreciation expense applicable to property included in account 104, Electric Plant Leased to Others, shall be charged to account 413, Expenses of Electric Plant Leased to Others.
Depreciation expenses applicable to transportation equipment, shop equipment, tools, work equipment, power operated equipment and other general equipment may be charged to clearing accounts as necessary in order to obtain a proper distribution of expenses between construction and operation.
Depreciation expense applicable to transportation equipment used for transportation of fuel from the point of acquisition to the unloading point shall be charged to Account 151, Fuel Stock.
This account shall include the depreciation expense for asset retirement costs included in electric utility plant in service.
This account shall include amortization charges applicable to amounts included in the electric plant accounts for limited-term franchises, licenses, patent rights, limited-term interests in land, and expenditures on leased property where the service life of the improvements is terminable by action of the lease. The charges to this account shall be such as to distribute the book cost of each investment as evenly as may be over the period of its benefit to the utility.
(See account 111, Accumulated Provision for Amortization of Electric Utility Plant.)
A. When authorized by the Commission, this account shall include charges for amortization of intangible or other electric utility plant which does not have a definite or terminable life and which is not subject to charges for depreciation expense.
B. This account shall be supported in such detail as to show the amortization applicable to each investment being amortized, together with the book cost of the investment and the period over which it is being written off.
This account shall be debited or credited, as the case may be, with amounts includible in operating expenses, pursuant to approval or order of the Commission, for the purpose of providing for the extinguishment of the amount in account 114, Electric Plant Acquisition Adjustments.
This account shall be charged with amounts credited to account 182.1, Extraordinary Property Losses, and account 182.2, Unrecovered Plant and Regulatory Study Costs, when the Commission has authorized the amount in the latter account to be amortized by charges to electric operations.
This account shall be debited, when appropriate, with the amounts credited to Account 254, Other Regulatory Liabilities, to record regulatory liabilities imposed on the utility by the ratemaking actions of regulatory agencies. This account shall also be debited, when appropriate, with the amounts credited to Account 182.3, Other Regulatory Assets, concurrent with the recovery of such amounts in rates.
This account shall be credited, when appropriate, with the amounts debited to Account 182.3, Other Regulatory Assets, to establish regulatory assets. This account shall also be credited, when appropriate, with the amounts debited to Account 254, Other Regulatory Liabilities, concurrent with the return of such amounts to customers through rates.
A. These accounts shall include the amounts of ad valorem, gross revenue or gross receipts taxes, state unemployment insurance, franchise taxes, Federal excise taxes, social security taxes, and all other taxes assessed by Federal, state, county, municipal, or other local governmental authorities, except income taxes.
B. These accounts shall be charged in each accounting period with the amounts of taxes which are applicable thereto, with concurrent credits to account 236, Taxes Accrued, or account 165, Prepayments, as appropriate. When it is not possible to determine the exact amounts of taxes, the amounts shall be estimated and adjustments made in current accruals as the actual tax levies become known.
C. The charges to these accounts shall be made or supported so as to show the amount of each tax and the basis upon which each charge is made. In the case of a utility rendering more than one utility service, taxes of the kind includible in these accounts shall be assigned directly to the utility department the operation of which gave rise to the tax in so far as practicable. Where the tax is not attributable to a specific utility department, it shall be distributed among the utility departments or nonutility operations on an equitable basis after appropriate study to determine such basis.
Special assessments for street and similar improvements shall be included in the appropriate utility plant or nonutility property account.
Taxes specifically applicable to construction shall be included in the cost of construction.
Gasoline and other sales taxes shall be charged as far as practicable to the same account as the materials on which the tax is levied.
Social security and other forms of so-called payroll taxes shall be distributed to utility departments and to nonutility functions on a basis related to payroll. Amounts applicable to construction shall be charged to the appropriate plant account.
Interest on tax refunds or deficiencies shall not be included in these accounts but in account 419, Interest and Dividend Income, or 431, Other Interest Expense, as appropriate.
This account shall include those taxes other than income taxes which relate to utility operating income. This account shall be maintained so as to allow ready identification of the various classes of taxes relating to Utility Operating Income (by department), Utility Plant Leased to Others and Other Utility Operating Income.
This account shall include those taxes other than income taxes which relate to Other Income and Deductions.
A. These accounts shall include the amounts of local, state and Federal income taxes on income properly accruable during the period covered by the income statement to meet the actual liability for such taxes. Concurrent credits for the tax accruals shall be made to account 236, Taxes Accrued, and as the exact amounts of taxes become known, the current tax accruals shall be adjusted by charges or credits to these accounts, so that these accounts as nearly as can be ascertained shall include the actual taxes payable by the utility.
B. The accruals for income taxes shall be apportioned among utility departments and to Other Income and Deductions so that, as nearly as practicable, each tax shall be included in the expenses of the utility department or Other Income and Deductions, the income from which gave rise to the tax. The tax effects relating to Interest Charges shall be allocated between utility and nonutility operations. The basis for this allocation shall be the ratio of net investment in utility plant to net investment in nonutility plant.
Taxes assumed by the utility on interest shall be charged to account 431, Other Interest Expense.
Interest on tax refunds or deficiencies shall not be included in these accounts but in account 419, Interest and Dividend Income, or account 431, Other Interest Expense, as appropriate.
This account shall include the amount of those local, state and Federal income taxes which relate to utility operating income. This account shall be maintained so as to allow ready identification of tax effects (both positive and negative) relating to Utility Operating Income (by department), Utility Plant Leased to Others and Other Utility Operating Income.
This account shall include the amount of those local, state and Federal income taxes (both positive and negative), which relate to Other Income and Deductions.
This account shall include the amount of those local, state and Federal income taxes (both positive and negative), which relate to Extraordinary Items.
A. Accounts 410.1 and 410.2 shall be debited, and Accumulated Deferred Income Taxes shall be credited, with amounts equal to any current deferrals of taxes on income or any allocations of deferred taxes originating in prior periods, as provided by the texts of accounts 190, 281, 282, and 283. There shall not be netted against entries required to be made to these accounts any credit amounts appropriately includible in account 411.1 or 411.2.
B. Accounts 411.1 and 411.2 shall be credited, and Accumulated Deferred Income Taxes shall be debited, with amounts equal to any allocations of deferred taxes originating in prior periods or any current deferrals of taxes on income, as provided by the texts of accounts 190, 281, 282, and 283. There shall not be netted against entries required to be made to these accounts any debit amounts appropriately includible in account 410.1 or 410.2.
This account shall include the amounts of those deferrals of taxes and allocations of deferred taxes which relate to Utility Operating Income (by department).
This account shall include the amounts of those deferrals of taxes and allocations of deferred taxes which relate to Other Income and Deductions.
This account shall include the amounts of those allocations of deferred taxes and deferrals of taxes, credit, which relate to Utility Operating Income (by department).
This account shall include the amounts of those allocations of deferred taxes and deferrals of taxes, credit, which relate to Other Income and Deductions.
A. Account 411.4 shall be debited with the amounts of investment tax credits related to electric utility property that are credited to account 255, Accumulated Deferred Investment Tax Credits, by companies which do not apply the entire amount of the benefits of the investment credit as a reduction of the overall income tax expense in the year in which such credit is realized (see account 255).
B. Account 411.4 shall be credited with the amounts debited to account 255 for proportionate amounts of tax credit deferrals allocated over the average useful life of electric utility property to which the tax credits relate or such lesser period of time as may be adopted and consistently followed by the company.
C. Account 411.5 shall also be debited and credited as directed in paragraphs A and B, for investment tax credits related to nonutility property.
This account shall include the amount of those investment tax credit adjustments related to property used in Utility Operations (by department).
This account shall include the amount of those investment tax credit adjustments related to property used in Nonutility Operations.
A. This account shall include, as approved by the Commission, amounts relating to gains from the disposition of future use utility plant including amounts which were previously recorded in and transferred from account 105, Electric Plant Held for Future Use, under the provisions of paragraphs B, C, and D thereof. Income taxes relating to gains recorded in this account shall be recorded in account 409.1, Income Taxes, Utility Operating Income.
B. The utility shall record in this account gains resulting from the settlement of asset retirement obligations related to utility plant in accordance with the accounting prescribed in General Instruction 25.
A. This account shall include, as approved by the Commission, amounts relating to losses from the disposition of future use utility plant including amounts which were previously recorded in and transferred from account 105, Electric Plant Held for Future Use, under the provisions of paragraphs B, C, and D thereof. Income taxes relating to losses, recorded in this account shall be recorded in account 409.1, Income Taxes, Utility Operating Income.
B. The utility shall record in this account losses resulting from the settlement of asset retirement obligations related to utility plant in accordance with the accounting prescribed in General Instruction 25.
This account shall be credited with the gain on the sale, exchange, or other disposition of allowances in accordance with paragraph (H) of General Instruction No. 21. Income taxes relating to gains recorded in this account shall be recorded in Account 409.1, Income Taxes, Utility Operating Income.
This account shall be debited with the loss on the sale, exchange, or other disposition of allowances in accordance with paragraph (H) of General Instruction No. 21. Income taxes relating to losses recorded in this account shall be recorded in Account 409.1, Income Taxes, Utility Operating Income.
This account shall be charged for accretion expense on the liabilities associated with asset retirement obligations included in account 230, Asset retirement obligations, related to electric utility plant.
A. These accounts shall include respectively, revenues from electric property constituting a distinct operating unit or system leased by the utility to others, and which property is properly includible in account 104, Electric Plant Leased to Others, and the expenses attributable to such property.
B. The detail of expenses shall be kept or supported so as to show separately the following:
Operation.
Maintenance.
Depreciation.
Amortization.
Related taxes shall be recorded in account 408.1, Taxes Other Than Income Taxes, Utility Operating Income, or account 409.1, Income Taxes, Utility Operating Income, as appropriate.
A. This account shall include the revenues received and expenses incurred in connection with the operations of utility plant, the book cost of which is included in account 118, Other Utility Plant.
B. The expenses shall include every element of cost incurred in such operations, including depreciation, rents, and insurance.
Related taxes shall be recorded in account 408.1, Taxes Other Than Income Taxes, Utility Operating Income, or account 409.1, Income Taxes, Utility Operating Income, as appropriate.
A. These accounts shall include respectively, all revenues derived from the sale of merchandise and jobbing or contract work, including any profit or commission accruing to the utility on jobbing work performed by it as agent under contracts whereby it does jobbing work for another for a stipulated profit or commission, and all expenses incurred in such activities. Interest related income from installment sales shall be recorded in Account 419, Interest and Dividend income.
B. Records in support of these accounts shall be so kept as to permit ready summarization of revenues, costs and expenses by such major items as are feasible.
The classification of revenues, costs, and expenses of merchandising, jobbing, and contract work as nonoperating, and thus inclusion in this account, is for accounting purposes. It does not preclude consideration of justification to the contrary for ratemaking or other purposes.
Related taxes shall be recorded in account 408.2, Taxes Other Than Income Taxes, Other Income and Deductions, or account 409.2, Income Taxes, Other Income and Deductions, as appropriate.
1. Revenues from sale of merchandise and from jobbing and contract work.
2. Discounts and allowances made in settlement of bills for merchandise and jobbing work.
1. Canvassing and demonstrating appliances in homes and other places for the purpose of selling appliances.
2. Demonstrating and selling activities in sales rooms.
3. Installing appliances on customer premises where such work is done only for purchasers of appliances from the utility.
4. Installing wiring, piping, or other property work, on a jobbing or contract basis.
5. Preparing advertising materials for appliance sales purposes.
6. Receiving and handling customer orders for merchandise or for jobbing services.
7. Cleaning and tidying sales rooms.
8. Maintaining display counters and other equipment used in merchandising.
9. Arranging merchandise in sales rooms and decorating display windows.
10. Reconditioning repossessed appliances.
11. Bookkeeping and other clerical work in connection with merchandise and jobbing activities.
12. Supervising merchandise and jobbing operations.
13. Advertising in newspapers, periodicals, radio, television, etc.
14. Cost of merchandise sold and of materials used in jobbing work.
15. Stores expenses on merchandise and jobbing stocks.
16. Fees and expenses of advertising and commercial artists’ agencies.
17. Printing booklets, dodgers, and other advertising data.
18. Premiums given as inducement to buy appliances.
19. Light, heat and power.
20. Depreciation on equipment used primarily for merchandise and jobbing operations.
21. Rent of sales rooms or of equipment.
22. Transportation expense in delivery and pick-up of appliances by utility’s facilities or by others.
23. Stationery and office supplies and expenses.
24. Losses from uncollectible merchandise and jobbing accounts.
A. These accounts shall include revenues and expenses applicable to operations which are nonutility in character but nevertheless constitute a distinct operating activity of the enterprise as a whole, such as the operation of an ice department where applicable statutes do not define such operation as a utility, or the operation of a servicing organization for furnishing supervision, management, engineering, and similar services to others.
B. The expenses shall include all elements of costs incurred in such operations, and the accounts shall be maintained so as to permit ready summarization as follows:
Operation.
Maintenance.
Rents.
Depreciation.
Amortization.
Related taxes shall be recorded in account 408.2, Taxes Other Than Income Taxes, Other Income and Deductions, or account 409.2, Income Taxes, Other Income and Deductions, as appropriate.
A. This account shall include all rent revenues and related expenses of land, buildings, or other property included in account 121, Nonutility Property, which is not used in operations covered by account 417 or 417.1.
B. The expenses shall include all elements of costs incurred in the ownership and rental of property and the accounts shall be maintained so as to permit ready summarization as follows:
Operation.
Maintenance.
Rents.
Depreciation.
Amortization.
Related taxes shall be recorded in account 408.2. Taxes Other Than Income Taxes, Other Income and Deductions, or account 409.2, Income Taxes, Other Income and Deductions, as appropriate.
This account shall include the utility’s equity in the earnings or losses of subsidiary companies for the year.
A. This account shall include interest revenues on securities, loans, notes, advances, special deposits, tax refunds and all other interest-bearing assets, and dividends on stocks of other companies, whether the securities on which the interest and dividends are received are carried as investments or included in sinking or other special fund accounts.
B. This account may include the pro rata amount necessary to extinguish (during the interval between the date of acquisition and the date of maturity) the difference between the cost to the utility and the face value of interest-bearing securities. Amounts thus credited or charged shall be concurrently included in the accounts in which the securities are carried.
C. Where significant in amount, expenses, excluding operating taxes and income taxes, applicable to security investments and to interest and dividend revenues thereon shall be charged hereto.
Related taxes shall be recorded in account 408.2, Taxes Other Than Income Taxes, Other Income and Deductions, or account 409.2, Income Taxes, Other Income and Deductions, as appropriate.
Interest accrued, the payment of which is not reasonably assured, dividends receivable which have not been declared or guaranteed, and interest or dividends upon reacquired securities issued or assumed by the utility shall not be credited to this account.
This account shall include concurrent credits for allowance for other funds used during construction, not to exceed amounts computed in accordance with the formula prescribed in Electric Plant Instruction 3(17).
This account shall be credited as follows with investment tax credit amounts not passed on to customers:
A. By amounts equal to debits to accounts 411.4, Investment Tax Credit Adjustments, Utility Operations, and 411.5, Investment Tax Credit Adjustments, Nonutility Operations, for investment tax credits used in calculating income taxes for the year when the company’s accounting provides for nondeferral of all or a portion of such credits; and,
B. By amounts equal to debits to account 255, Accumulated deferred investment tax credits, for proportionate amounts of tax credit deferrals allocated over the average useful life of the property to which the tax credits relate, or such lesser period of time as may be adopted and consistently used by the company.
This account shall include all revenue and expense items except taxes properly includible in the income account and not provided for elsewhere. Related taxes shall be recorded in account 408.2, Taxes Other Than Income Taxes, Other Income and Deductions, or account 409.2, Income Taxes, Other Income and Deductions, as appropriate.
1. Profit on sale of timber. (See electric plant instruction 7C.)
2. Profits from operations of others realized by the utility under contracts.
3. Gains on disposition of investments. Also, gains on reacquisition and resale or retirement of utilities debt securities when the gain is not amortized and used by a jurisdictional regulatory agency to reduce embedded debt cost in establishing rates. See General Instruction 17.
4. This account shall include the accretion expense on the liability for an asset retirement obligation included in account 230, Asset retirement obligations, related to nonutility plant.
5. This account shall include the depreciation expense for asset retirement costs related to nonutility plant.
6. The utility shall record in this account gains resulting from the settlement of asset retirement obligations related to nonutility plant in accordance with the accounting prescribed in General Instruction 25.
This account shall be credited with the gain on the sale, conveyance, exchange, or transfer of utility or other property to another. Amounts relating to gains on land and land rights held for future use recorded in account 105, Electric Plant Held for Future Use will be accounted for as prescribed in paragraphs B, C, and D thereof. (See electric plant instructions 5F, 7E, and 10E.) Income taxes on gains recorded in this account shall be recorded in account 409.2, Income Taxes, Other Income and Deductions.
This account shall be charged with the loss on the sale, conveyance, exchange or transfer of utility or other property to another. Amounts relating to losses on land and land rights held for future use recorded in account 105, Electric Plant Held for Future Use will be accounted for as prescribed in paragraphs B, C, and D thereof. (See electric plant instructions 5F, 7E, and 10E.) The reduction in income taxes relating to losses recorded in this account shall be recorded in account 409.2, Income Taxes, Other Income and Deductions.
This account shall include amortization charges not includible in other accounts which are properly deductible in determining the income of the utility before interest charges. Charges includible herein, if significant in amount, must be in accordance with an orderly and systematic amortization program.
1. Amortization of utility plant acquisition adjustments, or of intangibles included in utility plant in service when not authorized to be included in utility operating expenses by the Commission.
2. Other miscellaneous amortization charges allowed to be included in this account by the Commission.
These accounts shall include miscellaneous expense items which are nonoperating in nature but which are properly deductible before determining total income before interest charges.
The classification of expenses as nonoperating and their inclusion in these accounts is for accounting purposes. It does not preclude Commission consideration of proof to the contrary for ratemaking or other purposes.
This account shall include all payments or donations for charitable, social or community welfare purposes.
This account shall include all payments for life insurance of officers and employees where company is beneficiary (net premiums less increase in cash surrender value of policies).
This account shall include payments by the company for penalties or fines for violation of any regulatory statutes by the company or its officials.
This account shall include expenditures for the purpose of influencing public opinion with respect to the election or appointment of public officials, referenda, legislation, or ordinances (either with respect to the possible adoption of new referenda, legislation or ordinances or repeal or modification of existing referenda, legislation or ordinances) or approval, modification, or revocation of franchises; or for the purpose of influencing the decisions of public officials, but shall not include such expenditures which are directly related to appearances before regulatory or other governmental bodies in connection with the reporting utility’s existing or proposed operations.
This account shall include other miscellaneous expenses which are nonoperating in nature, but which are properly deductible before determining total income before interest charges.
1. Loss relating to investments in securities written-off or written-down.
2. Loss on sale of investments.
3. Loss on reacquisition, resale or retirement of utility’s debt securities, when the loss is not amortized and used by a jurisdictional regulatory agency to increase embedded debt cost in establishing rates. See General Instruction 17.
4. Preliminary survey and investigation expenses related to abandoned projects, when not written-off to the appropriate operating expense account.
5. Costs of preliminary abandonment costs recorded in accounts 182.1, Extraordinary Property Losses, and 182.2, Unrecovered Plant and Regulatory Study Costs, not allowed to be amortized to account 407, Amortization of Property Losses, Unrecovered Plant and Regulatory Study Costs.
6. The utility shall record in this account losses resulting from the settlement of asset retirement obligations related to nonutility plant in accordance with the accounting prescribed in General Instruction 25.
A. This account shall include the amount of interest on outstanding long-term debt issued or assumed by the utility, the liability for which is included in account 221, Bonds, or account 224, Other Long-Term Debt.
B. This account shall be so kept or supported as to show the interest accruals on each class and series of long-term debt.
This account shall not include interest on nominally issued or nominally outstanding long-term debt, including securities assumed.
A. This account shall include the amortization of unamortized debt discount and expense on outstanding long-term debt. Amounts charged to this account shall be credited concurrently to accounts 181, Unamortized Debt Expense, and 226, Unamortized Discount on Long-Term Debt—Debit.
B. This account shall be so kept or supported as to show the debt discount and expense on each class and series of long-term debt.
A. This account shall include the amortization of the losses on reacquisition of debt. Amounts charged to this account shall be credited concurrently to account 189, Unamortized Loss on Reacquired Debt.
B. This account shall be maintained so as to allow ready identification of the loss amortized applicable to each class and series of long-term debt reacquired. See General Instruction 17.
A. This account shall include the amortization of unamortized net premium on outstanding long-term debt. Amounts credited to this account shall be charged concurrently to account 225, Unamortized Premium on Long-Term Debt.
B. This account shall be so kept or supported as to show the premium on each class and series of long-term debt.
A. This account shall include the amortization of the gains realized from reacquisition of debt. Amounts credited to this account shall be charged concurrently to account 257, Unamortized Gain on Reacquired Debt.
B. This account shall be maintained so as to allow ready identification of the gains amortized applicable to each class and series of long-term debt reacquired. See General Instruction 17.
A. This account shall include the interest accrued on amounts included in account 223, Advances from Associated Companies, and on all other obligations to associated companies.
B. The records supporting the entries to this account shall be so kept as to show to whom the interest is to be paid, the period covered by the accrual, the rate of interest and the principal amount of the advances or other obligations on which the interest is accrued.
This account shall include all interest charges not provided for elsewhere.
1. Interest on notes payable on demand or maturing one year or less from date and on open accounts, except notes and accounts with associated companies.
2. Interest on customers’ deposits.
3. Interest on claims and judgments, tax assessments, and assessments for public improvements past due.
4. Income and other taxes levied upon bondholders of utility and assumed by it.
This account shall include concurrent credits for allowance for borrowed funds used during construction, not to exceed amounts computed in accordance with the formula prescribed in Electric Plant Instruction 3(17).
This account shall be credited with gains of unusual nature and infrequent occurrence, which would significantly distort the current year’s income computed before Extraordinary Items, if reported other than as extraordinary items. Income tax relating to the amounts recorded in this account shall be recorded in account 409.3, Income Taxes, Extraordinary Items. (See General Instruction 7.)
This account shall be debited with losses of unusual nature and infrequent occurrence, which would significantly distort the current year’s income computed before Extraordinary Items, if reported other than as extraordinary items. Income tax relating to the amounts recorded in this account shall be recorded in account 409.3, Income Taxes, Extraordinary Items. (See General Instruction 7.)
This account shall include the net credit or debit transferred from income for the year.
This account shall include appropriations of retained earnings.
1. Appropriations required under terms of mortgages, orders of courts, contracts, or other agreements.
2. Appropriations required by action of regulatory authorities.
3. Other appropriations made at option of utility for specific purposes.
A. This account shall include amounts declared payable out of retained earnings as dividends on actually outstanding preferred or prior lien capital stock issued by the utility.
B. Dividends shall be segregated for each class and series of preferred stock as to those payable in cash, stock, and other forms. If not payable in cash, the medium of payment shall be described with sufficient detail to identify it.
A. This account shall include amounts declared payable out of retained earnings as dividends on actually outstanding common capital stock issued by the utility.
B. Dividends shall be segregated for each class of common stock as to those payable in cash, stock and other forms. If not payable in cash, the medium of payment shall be described with sufficient detail to identify it.
A. This account shall, with prior Commission approval, include significant nonrecurring transactions accounted for as prior period adjustments, as follows:
(1) Correction of an error in the financial statements of a prior year.
(2) Adjustments that result from realization of income tax benefits of pre-acquisition operating loss carryforwards of purchased subsidiaries.
All other items of profit and loss recognized during a year shall be included in the determination of net income for that year;
B. Adjustments, charges, or credits due to losses on reacquisition, resale or retirement of the company’s own capital stock shall be included in this account. (See account 210, Gain on Resale or Cancellation of Reacquired Capital Stock, for the treatment of gains.)
A. This account shall include the net billing for electricity supplied for residential or domestic purposes.
B. Records shall be maintained so that the quantity of electricity sold and the revenue received under each rate schedule shall be readily available.
When electricity supplied through a single meter is used for both residential and commercial purposes, the total revenue shall be included in this account, or account 442, Commercial and Industrial Sales, according to the rate schedule which is applied. If the same rate schedules apply to residential as to commercial and industrial service, classification shall be made according to principal use.
A. This account shall include the net billing for electricity supplied to customers for commercial and industrial purposes.
B. Records shall be maintained so that the quantity of electricity sold and the revenue received under each rate schedule shall be readily available. Records shall be maintained also so as to show separately the revenues from commercial and industrial customers (1) which have demands generally of 1000 kw or more, and (2) those which have demands generally less than 1000 kw. Reasonable deviations above or below the 1000 kw demand are permissible in order that transfers of customers between the two classes during the year may be minimized.
If the utility classifies large commercial and industrial customers and related revenues on a lesser basis than 1000 kilowatts of demand, or segregates industrial customers and related revenues according to a recognized definition of an industrial customer, such classifications are acceptable in lieu of those otherwise required by the text of this account on the basis of 1000 kilowatts of demand.
When electricity supplied through a single meter is used for both commercial and residential purposes, the total revenue shall be included in this account, or in account 440, Residential Sales, according to the rate schedule which is applied. If the same rate schedules apply to residential as to commercial and industrial service, classification shall be made according to the principal use.
A. This account shall include the net billing for electricity supplied and services rendered for the purposes of lighting streets, highways, parks and other public places, or for traffic or other signal system service, for municipalities or other divisions or agencies of state or federal governments.
B. Records shall be maintained so that the quantity of electricity sold and the revenue received from each customer shall be readily available. In addition, the records shall be maintained so as to show the revenues from (1) contracts which include both electricity and services, and (2) contracts which include sales of electricity only.
A. This account shall include the net billing for electricity supplied to municipalities or divisions or agencies of federal or state governments, under special contracts or agreements or service classifications applicable only to public authorities, except such revenues as are includible in accounts 444 and 447.
B. Records shall be maintained so as to show the quantity of electricity sold and the revenues received from each customer.
A. This account shall include the net billing for electricity supplied to railroads and interurban and street railways, for general railroad use, including the propulsion of cars or locomotives, where such electricity is supplied under separate and distinct rate schedules.
B. Records shall be maintained so that the quantity of electricity sold and the revenue received from each customer shall be readily available.
Revenues from incidental use of electricity furnished under a contract for propulsion of cars or locomotives shall be included herein.
A. This account shall include the net billing for electricity supplied to other electric utilities or to public authorities for resale purposes.
B. Records shall be maintained so as to show the quantity of electricity sold and the revenue received from each customer.
Revenues from electricity supplied to other public utilities for use by them and not for distribution, shall be included in account 442, Commercial and Industrial Sales, unless supplied under the same contract as and not readily separable from revenues includible in this account.
A. This account shall include amounts charged by the electric department at tariff or other specified rates for electricity supplied by it to other utility departments.
B. Records shall be maintained so that the quantity of electricity supplied each other department and the charges therefor shall be readily available.
A. This account shall include revenues for electricity supplied which are not provided for elsewhere.
B. Records shall be maintained so as to show the quantity of electricity sold and the revenues received from each customer.
A. This account shall be charged with provisions for the estimated pretax effects on net income of the portions of amounts being collected subject to refund which are estimated to be required to be refunded. Such provisions shall be credited to Account 229, Accumulated Provision for Rate Refunds.
B. This account shall also be charged with amounts refunded when such amounts had not been previously accrued.
C. Income tax effects relating to the amounts recorded in this account shall be recorded in account 410.1, Provision for Deferred Income Taxes, Utility Operating Income, or account 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, as appropriate.
This account shall include the amount of discounts forfeited or additional charges imposed because of the failure of customers to pay their electric bills on or before a specified date.
This account shall include revenues for all miscellaneous services and charges billed to customers which are not specifically provided for in other accounts.
1. Fees for changing, connecting or disconnecting service.
2. Profit on maintenance of appliances, wiring, piping or other installations on customers’ premises.
3. Net credit or debit (cost less net salvage and less payment from customers) on closing of work orders for plant installed for temporary service of less than one year. (See account 185, Temporary Facilities.)
4. Recovery of expenses in connection with current diversion cases (billing for the electricity consumed shall be included in the appropriate electric revenue account).
A. This account shall include revenues derived from the sale of water for irrigation, domestic, industrial or other uses, or for the development by others of water power, or for headwater benefits; also, revenues derived from furnishing water power for mechanical purposes when the investment in the property used in supplying such water or water power is carried as electric plant in service.
B. The records for this account shall be kept in such manner as to permit an analysis of the rates charged and the purposes for which the water was used.
A. This account shall include rents received for the use by others of land, buildings, and other property devoted to electric operations by the utility.
B. When property owned by the utility is operated jointly with others under a definite arrangement for apportioning the actual expenses among the parties to the arrangement, any amount received by the utility for interest or return or in reimbursement of taxes or depreciation on the property shall be credited to this account.
Do not include in this account rents from property constituting an operating unit or system. (See account 412, Revenues from Electric Plant Leased to Others.)
This account shall include rents credited to the electric department on account of rental charges made against other departments (gas, water, etc.) of the utility. In the case of property operated under a definite arrangement to allocate the costs among the departments using the property, any reimbursement to the electric department for interest or return and depreciation and taxes shall be credited to this account.
This account shall include revenues derived from electric operations not includible in any of the foregoing accounts. It shall also include in a separate subaccount revenues received from operation of fish and wildlife, and recreation facilities whether operated by the company or by contract concessionaires, such as revenues from leases, or rentals of land for cottage, homes, or campsites.
1. Commission on sale or distribution of electricity of others when sold under rates filed by such others.
2. Compensation for minor or incidental services provided for others such as customer billing, engineering, etc.
3. Profit or loss on sale of material and supplies not ordinarily purchased for resale and not handled through merchandising and jobbing accounts.
4. Sale of steam, but not including sales made by a steamheating department or transfers of steam under joint facility operations.
5. Include in a separate subaccount revenues in payment for rights and/or benefits received from others which are realized through research, development, and demonstration ventures. In the event the amounts received are so large as to distort revenues for the year in which received (5 percent of net income before application of the benefit) the amounts shall be credited to Account 253, Other Deferred Credits, and amortized by credits to this account over a period not to exceed 5 years.
This account shall include revenues from transmission of electricity of others over transmission facilities of the utility.
This account shall include revenues derived from providing scheduling, system control and dispatching services. Include also in this account reimbursements for system planning, standards development, and market monitoring and market compliance activities. Records shall be maintained so as to show: (1) The services supplied and revenues received from each customer and (2) the amounts billed by tariff or specified rates.
This account shall include revenues and reimbursements for costs incurred by regional transmission service providers not provided for elsewhere. Records shall be maintained so as to show: (1) The services supplied and revenues received from each customer, and (2) the amounts billed by tariff or specified rates.
A. For Major Utilities, this account shall include the cost of labor and expenses incurred in the general supervision and direction of the operation of steam power generating stations. Direct supervision of specific activities, such as fuel handling, boiler room operations, generator operations, etc., shall be charged to the appropriate account. (See operating expense instruction 1.)
B. For Nonmajor Utilities, this account shall include the cost of supervision and labor in the operation of steam power generating stations.
1. Supervising steam production.
2. Operating fuel conveying, storage, weighing and processing equipment within boiler plant.
3. Operating boiler and boiler auxiliary equipment.
4. Operating boiler feed water purification and treatment equipment.
5. Operating ash collection and disposal equipment located inside the plant.
6. Operating boiler plant electrical equipment.
7. Keeping boiler plant log and records and preparing reports on boiler plant operations.
8. Testing boiler water.
9. Testing, checking, and adjusting meters, gauges and other instruments in boiler plant.
10. Cleaning boiler plant equipment when not incidental to maintenance work.
11. Repacking glands and replacing gauge classes where the work involved is of a minor nature and is performed by regular operating crews. Where the work is of a major character such as that performed on high pressure boilers the item should be considered as maintenance.
12. Supervising electric production.
13. Operating turbines, engines, generators and exciters.
14. Operating condensers, circulating water systems and other auxiliary apparatus.
15. Operating generator cooling system.
16. Operating lubrication and oil control system, including oil purification.
17. Operating switchboards, switch gear and electric control and protective equipment.
18. Keeping electric plant log and records and preparing reports on electric plant operations.
19. Testing, checking and adjusting meters, gauges, and other instruments, relays, controls and other equipment in electric plant.
20. Cleaning electric plant equipment when not incidental to maintenance work.
21. Repacking glands and replacing gauge glasses.
22. General clerical and stenographic work at plant.
23. Guarding and patrolling plant and yard.
24. Building service.
25. Care of grounds including snow removal, cutting grass, etc.
26. Miscellaneous labor.
A. This account shall include the cost of fuel used in the production of steam for the generation of electricity, including expenses in unloading fuel from the shipping media and handling thereof up to the point where the fuel enters the first boiler plant bunker, hopper, bucket, tank or holder of the boiler-house structure. Records shall be maintained to show the quantity, B.t.u. content and cost of each type of fuel used.
B. The cost of fuel shall be charged initially to account 151, Fuel Stock (for Nonmajor utilities, appropriate fuel accounts carried under account 154, Plant Materials and Operating Supplies) and cleared to this account on the basis of the fuel used. Fuel handling expenses may be charged to this account as incurred or charged initially to account 152, Fuel Stock Expenses Undistributed (for Nonmajor utilities, an appropriate subaccount of account 154, Plant Materials and Operating Supplies). In the latter event, they shall be cleared to this account on the basis of the fuel used. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
1. Supervising purchasing and handling of fuel.
2. All routine fuel analyses.
3. Unloading from shipping facility and putting in storage.
4. Moving of fuel in storage and transferring fuel from one station to another.
5. Handling from storage or shipping facility to first bunker, hopper, bucket, tank or holder of boiler-house structure.
6. Operation of mechanical equipment, such as locomotives, trucks, cars, boats, barges, cranes, etc.
7. Operating, maintenance and depreciation expenses and ad valorem taxes on utility-owned transportation equipment used to transport fuel from the point of acquisition to the unloading point (Major only).
8. Lease or rental costs of transportation equipment used to transport fuel from the point of acquisition to the unloading point (Major only).
9. Cost of fuel including freight, switching, demurrage and other transportation charges.
10. Excise taxes, insurance, purchasing commissions and similar items.
11. Stores expenses to extent applicable to fuel.
12. Transportation and other expenses in moving fuel in storage.
13. Tools, lubricants and other supplies.
14. Operating supplies for mechanical equipment.
15. Residual disposal expenses less any proceeds from sale of residuals.
Abnormal fuel handling expenses occasioned by emergency conditions shall be charged to expense as incurred.
This account shall include the cost of labor, materials used and expenses incurred in production of steam for electric generation. This includes all expenses of handling and preparing fuel beginning at the point where the fuel enters the first boiler plant bunker, hopper, tank or holder of the boiler-house structure.
1. Supervising steam production.
2. Operating fuel conveying, storage weighing and processing equipment within boiler plant.
3. Operating boiler and boiler auxiliary equipment.
4. Operating boiler feed water purification and treatment equipment.
5. Operating ash-collecting and disposal equipment located inside the plant.
6. Operating boiler plant electrical equipment.
7. Keeping boiler plant log and records and preparing reports on boiler plant operation.
8. Testing boiler water.
9. Testing, checking, and adjusting meters, gauges, and other instruments and equipment in boiler plant.
10. Cleaning boiler plant equipment when not incidental to maintenance work.
11. Repacking glands and replacing gauge glasses where the work involved is of a minor nature and is performed by regular operating crews. Where the work is of a major character, such as that performed on high-pressure boilers, the item should be considered as maintenance.
12. Chemicals and boiler inspection fees.
13. Lubricants.
14. Boiler feed water purchased and pumping supplies.
This account shall include the cost of steam purchased, or transferred from another department of the utility or from others under a joint facility operating arrangement, for use in prime movers devoted to the production of electricity.
The records shall be so kept as to show separately for each company from which steam is purchased, the point of delivery, the quantity, the price, and the total charge. When steam is transferred from another department or from others under a joint operating arrangement, the utility shall be prepared to show full details of the cost of producing such steam, the basis of the charge to electric generation and the extent and manner of use by each department or party involved.
A. This account shall include credits for expenses of producing steam which are charged to others or to other utility departments under a joint operating arrangement. Include also credits for steam expenses chargeable to other electric accounts outside of the steam generation group. Full details of the basis of determination of the cost of steam transferred shall be maintained.
B. If the charges to others or to other departments of the utility include an amount for depreciation, taxes and return on the joint steam facilities, such portion of the charge shall be credited, in the case of others, to account 454, Rent from Electric Property, and in the case of other departments of the utility, to account 455, Interdepartmental Rents.
This account shall include the cost of labor, materials used and expenses incurred in operating prime movers, generators, and their auxiliary apparatus, switch gear and other electric equipment to the points where electricity leaves for conversion for transmission or distribution.
1. Supervising electric production.
2. Operating turbines, engines, generators and exciters.
3. Operating condensers, circulating water systems and other auxiliary apparatus.
4. Operating generator cooling system.
5. Operating lubrication and oil control system, including oil purification.
6. Operating switchboards, switch gear and electric control and protective equipment.
7. Keeping electric plant log and records and preparing reports on electric plant operations.
8. Testing, checking and adjusting meters, gauges, and other instruments, relays, controls and other equipment in the electric plant.
9. Cleaning electric plant equipment when not incidental to maintenance work.
10. Repacking glands and replacing gauge glasses.
11. Lubricants and control system oils.
12. Generator cooling gases.
13. Circulating water purification supplies.
14. Cooling water purchased.
15. Motor and generator brushes.
This account shall include the cost of labor, materials used and expenses incurred which are not specifically provided for or are not readily assignable to other steam generation operation expense accounts.
1. General clerical and stenographic work.
2. Guarding and patrolling plant and yard.
3. Building service.
4. Care of grounds including snow removal, cutting grass, etc.
5. Miscellaneous labor.
6. General operating supplies, such as tools, gaskets, packing waste, gauge glasses, hose, indicating lamps, record and report forms, etc.
7. First-aid supplies and safety equipment.
8. Employees’ service facilities expenses.
9. Building service supplies.
10. Communication service.
11. Miscellaneous office supplies and expenses, printing and stationery.
12. Transportation expenses.
13. Meals, traveling and incidental expenses.
14. Research, development, and demonstration expenses.
This account shall include all rents of property of others used, occupied or operated in connection with steam power generation. (See operating expense instruction 3.)
This account shall include the cost of materials used and expenses incurred in the operation of steam power generating stations.
1. Chemicals and boiler inspection fees.
2. Lubricants and control system oils.
3. Boiler feed water purchased and pumping supplies.
4. Generator cooling gases.
5. Circulating water purification supplies.
6. Cooling water purchased.
7. Motor and generator brushes.
8. General operating supplies, such as tools, gaskets, packing waste, gauge glasses, hose, indicating lamps, record and report forms, etc.
9. First-aid supplies and safety equipment.
10. Employees’ service facilities expenses.
11. Building service supplies.
12. Communication service.
13. Miscellaneous office supplies and expenses, printing and stationery.
14. Transportation expenses.
15. Meals, traveling and incidental expenses.
This account shall include the cost of allowances expensed concurrent with the monthly emission of sulfur dioxide. (See General Instruction No. 21.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of steam generation facilities. Direct field supervision of specific jobs shall be charged to the appropriate maintenance account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of steam structures, the book cost of which is includible in account 311, Structures and Improvements. (See operating expense instruction 2.)
A. This account shall include the cost of labor, materials used and expenses incurred in the maintenance of steam plant, the book cost of which is includible in account 312, Boiler Plant Equipment. (See operating expense instruction 2.)
B. For the purpose of making charges hereto and to account 513, Maintenance of Electric Plant, the point at which steam plant is distinguished from electric plant is defined as follows:
1. Inlet flange of throttle valve on prime mover.
2. Flange of all steam extraction lines on prime mover.
3. Hotwell pump outlet on condensate lines.
4. Inlet flange of all turbine-room auxiliaries.
5. Connection to line side of motor starter for all boiler-plant equipment.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of electric plant, the book cost of which is includible in account 313, Engines and Engine-Driven Generators, account 314, Turbogenerator Units, and account 315, Accessory Electric Equipment. (See operating expense instruction 2 and paragraph B of account 512.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of miscellaneous steam generation plant, the book cost of which is includible in account 316, Miscellaneous Power Plant Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of steam production plant the book cost of which is includible in plant accounts 311 to 316, inclusive. (See operating expense instruction 2.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of the operation of nuclear power generating stations. Direct supervision of specific activities, such as fuel handling, reactor operations, generator operations, etc., shall be charged to the appropriate account. (See operating expense instruction 1.)
A. This account shall be debited and account 120.5, Accumulated Provision for Amortization of Nuclear Fuel Assemblies, credited for the amortization of the net cost of nuclear fuel assemblies used in the production of energy. The net cost of nuclear fuel assemblies subject to amortization shall be the cost of nuclear fuel assemblies plus or less the expected net salvage of uranium, plutonium, and other byproducts and unburned fuel. The utility shall adopt the necessary procedures to assure that charges to this account are distributed according to the thermal energy produced in such periods.
B. This account shall also include the costs involved when fuel is leased.
C. This account shall also include the cost of other fuels, used for ancillary steam facilities, including superheat.
D. This account shall be debited or credited as appropriate for significant changes in the amounts estimated as the net salvage value of uranium, plutonium, and other byproducts contained in account 157, Nuclear Materials Held for Sale and the amount realized upon the final disposition of the materials. Significant declines in the estimated realizable value of items carried in account 157 may be recognized at the time of market price declines by charging this account and crediting account 157. When the declining change occurs while the fuel is recorded in account 120.3, Nuclear Fuel Assemblies in Reactor, the effect shall be amortized over the remaining life of the fuel.
This account shall include the cost of labor, materials used and expenses incurred for heat transfer materials and water used for steam and cooling purposes.
1. Operation of water supply facilities.
2. Handling of coolants and heat transfer materials.
3. Chemicals.
4. Additions to or refining of, fluids used in reactor systems.
5. Lubricants.
6. Pumping supplies and expenses.
7. Miscellaneous supplies and expenses.
8. Purchased water.
Do not include in this account water for general station use or the initial charge for coolants, heat transfer or moderator fluids, chemicals or other supplies capitalized.
This account shall include the cost of labor, materials used and expenses incurred in production of steam through nuclear processes, and similar expenses for operation of any auxiliary superheat facilities.
1. Supervising steam production.
2. Fuel handling including removal, insertion, disassembly and preparation for cooling operations and shipment.
3. Testing instruments and gauges.
4. Health, safety, monitoring and decontamination activities.
5. Waste disposal.
6. Operating steam boilers and auxiliary steam, superheat facilities.
7. Chemical supplies.
8. Charts, logs, etc.
9. Health, safety, monitoring and decontamination supplies.
10. Boiler inspection fees.
11. Lubricants.
This account shall include the cost of steam purchased or transferred from another department of the utility or from others under a joint facility operating arrangement for use in prime movers devoted to the production of electricity.
The records shall be so kept as to show separately for each company from which steam is purchased, the point of delivery, the quantity, the price, and the total charge. When steam is transferred from another operating department, the utility shall be prepared to show full details of the cost of producing such steam, the basis of the charges to electric generation, and the extent and manner of use by each department involved.
A. This account shall include credits for expenses of producing steam which are charged to others or to other utility departments under a joint operating arrangement. Include also credits for steam expenses chargeable to other electric accounts outside of the steam generation group. Full details of the basis of determination of the cost of steam transferred shall be maintained.
B. If the charges to others or to other departments of the utility include an amount for depreciation, taxes and return on the joint steam facilities, such portion of the charge shall be credited, in the case of others, to account 454, Rent from Electric Property, and in the case of other departments of the utility, to account 455, Interdepartmental Rents.
This account shall include the cost of labor, materials used and expenses incurred in operating turbogenerators, steam turbines and their auxiliary apparatus, switch gear and other electric equipment to the points where electricity leaves for conversion for transmission or distribution.
1. Supervising electric production.
2. Operating turbines, engines, generators and exciters.
3. Operating condensers, circulating water systems and other auxiliary apparatus.
4. Operating generator cooling system.
5. Operating lubrication and oil control system, including oil purification.
6. Operating switchboards, switch gear and electric control and protective equipment.
7. Keeping plant log and records and preparing reports on electric plant operations.
8. Testing, checking and adjusting meters, gauges, and other instruments, relays, controls and other equipment in the electric plant.
9. Cleaning electric plant equipment when not incidental to maintenance.
10. Repacking glands and replacing gauge glasses.
11. Lubricants and control system oils.
12. Generator cooling gases.
13. Log sheets and charts.
14. Motor and generator brushes.
This account shall include the cost of labor, materials used and expenses incurred which are not specifically provided for or are not readily assignable to other nuclear generation operation accounts.
1. General clerical and stenographic work.
2. Plant security.
3. Building service.
4. Care of grounds, including snow removal, cutting grass, etc.
5. Miscellaneous labor.
6. General operating supplies, such as tools, gaskets, hose, indicating lamps, record and report forms, etc.
7. First-aid supplies and safety equipment.
8. Employees’ service facilities expenses.
9. Building service supplies.
10. Communication service.
11. Miscellaneous office supplies and expenses, printing and stationery.
12. Transportation expenses.
13. Meals, traveling and incidental expenses.
14. Research, development, and demonstration expenses.
This account shall include all rents of property of others used, occupied or operated in connection with nuclear generation. (See operating expense instruction 3.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of nuclear generation facilities. Direct field supervision of specific jobs shall be charged to the appropriate maintenance account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures, the book cost of which is includible in account 321, Structures and Improvements. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of reactor plant, the book cost of which is includible in account 322, Reactor Plant Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of electric plant, the book cost of which is includible in account 323, Turbogenerator Units, and account 324, Accessory Electric Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of miscellaneous nuclear generating plant, the book cost of which is includible in account 325, Miscellaneous Power Plant Equipment. (See operating expense instruction 2.)
A. For Major utilities, this account shall include the cost of labor and expenses incurred in the general supervision and direction of the operation of hydraulic power generating stations. Direct supervision of specific activities, such as hydraulic operation, generator operation, etc., shall be charged to the appropriate account (See operating expense instruction 1).
B. For Nonmajor utilities, this account shall include the cost of supervision and labor in the operation of hydraulic power generating stations.
1. Supervising hydraulic operation.
2. Removing debris and ice from trash racks, reservoirs and waterways.
3. Patrolling reservoirs and waterways.
4. Operating intakes, spillways, sluiceways and outlet works.
5. Operating bubbler, heater or other deicing systems.
6. Ice and log jam work.
7. Operating navigation facilities.
8. Operations relating to conservation of game, fish, forests, etc.
9. Insect control activities.
10. Supervising electric production.
11. Operating prime movers, generators and auxiliary equipment.
12. Operating generator cooling system.
13. Operating lubrication and oil control systems, including oil purification.
14. Operating switchboards, switchgear and electric control and protection equipment.
15. Keeping plant log and records and preparing reports on plant operations.
16. Testing, checking and adjusting meters, gauges, and other instruments, relays, controls and other equipment in the plant.
17. Cleaning plant equipment when not incidental to maintenance work.
18. Repacking glands.
19. General clerical and stenographic work.
20. Guarding and patrolling plant and yard.
21. Building service.
22. Care of grounds, including snow removal, cutting grass, etc.
23. Snow removal from roads and bridges.
24. Miscellaneous labor.
This account shall include the cost of water used for hydraulic power generation.
1. Cost of water purchased from others, including water tolls paid reservoir companies.
2. Periodic payments for licenses or permits from any governmental agency for water rights, or payments based on the use of the water.
3. Periodic payments for riparian rights.
4. Periodic payments for headwater benefits or for detriments to others.
5. Cloud seeding.
This account shall include the cost of labor, materials used and expenses incurred in operating hydraulic works including reservoirs, dams, and waterways, and in activities directly relating to the hydroelectric development outside the generating station. It shall also include the cost of labor, materials used and other expenses incurred in connection with the operation of (a) fish and wildlife, and (b) recreation facilities. Separate subaccounts shall be maintained for each of the above.
1. Supervising hydraulic operation.
2. Removing debris and ice from trash racks, reservoirs and waterways.
3. Patrolling reservoirs and waterways.
4. Operating intakes, spillways, sluiceways, and outlet works.
5. Operating bubbler, heater or other deicing systems.
6. Ice and log jam work.
7. Operating navigation facilities.
8. Operations relating to conservation of game, fish, forests, etc.
9. Insect control activities.
10. Insect control materials.
11. Lubricants, packing, and other supplies used in operation of hydraulic equipment.
12. Transportation expense.
This account shall include the cost of labor, materials used and expenses incurred in operating prime movers, generators, and their auxiliary apparatus, switchgear, and other electric equipment, to the point where electricity leaves for conversion for transmission or distribution.
1. Supervising electric production.
2. Operating prime movers, generators and auxiliary equipment.
3. Operating generator cooling system.
4. Operating lubrication and oil control systems, including oil purification.
5. Operating switchboards, switchgear, and electric control and protection equipment.
6. Keeping plant log and records and preparing reports on plant operations.
7. Testing, checking and adjusting meters, gauges, and other instruments, relays, controls, and other equipment in the plant.
8. Cleaning plant equipment when not incidental to maintenance work.
9. Repacking glands.
10. Lubricants and control system oils.
11. Motor and generator brushes.
This account shall include the cost of labor, materials used and expenses incurred which are not specifically provided for or are not readily assignable to other hydraulic generation operation expense accounts.
1. General clerical and stenographic work.
2. Guarding and patrolling plant and yard.
3. Building service.
4. Care of grounds including snow removal, cutting grass, etc.
5. Snow removal from roads and bridges.
6. Miscellaneous labor.
7. General operating supplies, such as tools, gaskets, packing, waste, hose, indicating lamps, record and report forms, etc.
8. First-aid supplies and safety equipment.
9. Employees’ service facilities expenses.
10. Building service supplies.
11. Communication service.
12. Office supplies, printing and station- ery.
13. Transportation expenses.
14. Fuel.
15. Meals, traveling and incidental expenses.
16. Research, development, and demonstration expenses.
This account shall include all rents of property of others used, occupied or operated in connection with hydraulic power generation, including amounts payable to the United States for the occupancy of public lands and reservations for reservoirs, dams, flumes, forebays, penstocks, power houses, etc., but not including transmission right of way. (See operating expense instruction 3.)
This account shall include the cost of materials used and expenses incurred in the operation of hydraulic power generating stations.
1. Insect control materials.
2. Lubricants, packing, and other supplies used in operation of hydraulic equipment.
3. Supplies and expenses in conservation of game, fish, forests, etc.
4. Transportation expense.
5. Control system oils.
6. Motor and generator brushes.
7. General operating supplies, such as tools, gaskets, packing, waste hose, indicating lamps, record and report forms, etc.
8. First-aid supplies and safety equipment.
9. Employees’ service facilities expenses.
10. Building service supplies.
11. Communication service.
12. Office supplies, printing and stationery.
13. Transportation expenses.
14. Fuel.
15. Meals, traveling and incidental expenses.
This account shall include the cost of labor and expenses incurred in the general supervision and direction of the maintenance of hydraulic power generating stations. Direct field supervision of specific jobs shall be charged to the appropriate maintenance account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used, and expenses incurred in maintenance of hydraulic structures, the book cost of which is includible in Account 331, Structures and Improvements. (See operating expense instruction 2) However, the cost of labor, materials used and expenses incurred in the maintenance of fish and wildlife, and recreation facilities, the book cost of which is includible in Account 331, Structures and Improvements, shall be charged to Account 545, Maintenance of Miscellaneous Hydraulic Plant.
This account shall include the cost of labor, materials used, and expenses incurred in maintenance of plant includible in Account 332, Reservoirs, Dams, and Waterways. (See operating expense instruction 2) However, the cost of labor materials used and expenses incurred in the maintenance of fish and wildlife, and recreation facilities, the book cost of which is includible in Account 332, Reservoirs, Dams and Waterways, shall be charged to Account 545, Maintenance of Miscellaneous Hydraulic Plant.
This account shall include the cost of labor, materials used and expenses incurred in maintenance of plant includible in Account 333, Water Wheels, Turbines and Generators, and account 334, Accessory Electric Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used, and expenses incurred in maintenance of plant, the book cost of which is includible in Account 335, Miscellaneous Power Plant Equipment, and Account 336, Roads, Railroads and Bridges. (See operating expense instruction 2.) It shall also include the cost of labor, materials used and other expenses incurred in the maintenance of (a) fish and wildlife, and (b) recreation facilities. Separate subaccounts shall be maintained for each of the above.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of hydraulic production plant the book cost of which is includible in plant accounts 331 to 336, inclusive. (See operating expense instruction 2.)
A. For Major utilities, this account shall include the cost of labor and expenses incurred in the general supervision and direction of the operation of other power generating stations. Direct supervision of specific activities, such as fuel handling, engine and generator operation, etc., shall be charged to the appropriate account. (See operating expense instruction 1.)
B. For Nonmajor utilities, this account shall include the cost of supervision and labor in the operation of other power generating stations.
1. Supervising other power generation operation.
2. Operating prime movers, generators and auxiliary apparatus and switching and other electric equipment.
3. Keeping plant log and records and preparing reports on plant operations.
4. Testing, checking, cleaning, oiling and adjusting equipment.
5. General clerical and stenographic work.
6. Guarding and patrolling plant and yard.
7. Building service.
8. Care of grounds, including snow removal, cutting grass, etc.
9. Miscellaneous labor.
This account shall include the cost delivered at the station (see account 151, Fuel Stock, for Major utilities, and account 154, Plant Materials and Operating Supplies, for Nonmajor utilities) of all fuel, such as gas, oil, kerosene, and gasoline used in other power generation.
This account shall include the cost of labor, materials used and expenses incurred in operating prime movers, generators and electric equipment in other power generating stations, to the point where electricity leaves for conversion for transmission or distribution.
1. Supervising other power generation operation.
2. Operating prime movers, generators and auxiliary apparatus and switching and other electric equipment.
3. Keeping plant log and records and preparing reports on plant operations.
4. Testing, checking, cleaning, oiling and adjusting equipment.
5. Dynamo, motor, and generator brushes.
6. Lubricants and control system oils.
7. Water for cooling engines and generators.
This account shall include the cost of labor, materials used and expenses incurred in the operation of energy storage equipment includible in Account 348, Energy Storage Equipment—Production, which are not specifically provided for or are readily assignable to other production operation expense accounts.
This account shall include the cost of labor, materials used and expenses incurred in the operation of other power generating stations which are not specifically provided for or are not readily assignable to other generation expense accounts.
1. General clerical and stenographic work.
2. Guarding and patrolling plant and yard.
3. Building service.
4. Care of grounds, including snow removal, cutting grass, etc.
5. Miscellaneous labor.
6. Building service supplies.
7. First-aid supplies and safety equipment.
8. Communication service.
9. Employees’ service facilities expenses.
10. Office supplies, printing and station- ery.
11. Transportation expense.
12. Meals, traveling and incidental expenses.
13. Fuel for heating.
14. Water for fire protection or general use.
15. Miscellaneous supplies, such as hand tools, drills, saw blades, files, etc.
16. Research, development, and demonstration expenses.
This account shall include all rents of property of others used, occupied, or operated in connection with other power generation. (See operating expense instruction 3.)
This account shall include the cost of materials used and expenses incurred in the operation of other power generating stations.
1. Dynamo, motor, and generator brushes.
2. Lubricants and control system oils.
3. Water for cooling engines and generators.
4. Building service supplies.
5. First-aid supplies and safety equipment.
6. Communication service.
7. Employees’ service facilities expenses.
8. Office supplies, printing and stationery.
9. Transportation expense.
10. Meals, traveling and incidental expenses.
11. Fuel for heating.
12. Water for fire protection or general use.
13. Miscellaneous supplies, such as hand tools, drills, saw blades, files, etc.
This account shall include the cost of labor and expenses incurred in the general supervision and direction of the maintenance of other power generating stations. Direct field supervision of specific jobs shall be charged to the appropriate maintenance account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of facilities used in other power generation, the book cost of which is includible in account 341, Structures and Improvements, and account 342, Fuel Holders, Producers and Accessories. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of plant, the book cost of which is includible in account 343, Prime Movers, account 344. Generators, and account 345, Accessory Electric Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of energy storage equipment includible in Account 348, Energy Storage Equipment—Production, which are not specifically provided for or are readily assignable to other production maintenance expense accounts.
This account shall include the cost of labor, materials used and expenses incurred in maintenance of other power generation plant, the book cost of which is includible in account 346, Miscellaneous Power Plant Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of other power generation plant, the book cost of which is includible in plant accounts 341 to 346, inclusive. (See operating expense instruction 2.)
A. This account shall include the cost at point of receipt by the utility of electricity purchased for resale. It shall include, also, net settlements for exchange of electricity or power, such as economy energy, off-peak energy for on-peak energy, spinning reserve capacity, etc. In addition, the account shall include the net settlements for transactions under pooling or interconnection agreements wherein there is a balancing of debits and credits for energy, capacity, etc. Distinct purchases and sales shall not be recorded as exchanges and net amounts only recorded merely because debit and credit amounts are combined in the voucher settlement.
B. The records supporting this account shall show, by months, the demands and demand charges, kilowatt-hours and prices thereof under each purchase contract and the charges and credits under each exchange or power pooling contract.
A. This account shall include the cost at point of receipt by the utility of electricity purchased for use in storage operations, including power purchased and consumed or lost in energy storage operations during the provision of services, including but not limited to energy purchased and stored for resale. It shall also include but not be limited to net settlements for exchange of electricity or power, such as economy energy, off-peak energy for on-peak energy, and spinning reserve capacity. In addition, the account shall include the net settlements for transactions under pooling or interconnection agreements wherein there is a balancing of debits and credits for energy, capacity, and possibly other factors. Distinct purchases and sales shall not be recorded as exchanges and net amounts only recorded merely because debit and credit amounts are combined in the voucher settlement.
B. The records supporting this account shall show, by months, the kilowatt hours and prices thereof under each purchase contract and the charges and credits under each exchange or power pooling contract.
This account shall include the cost of labor and expenses incurred in load dispatching activities for system control. Utilities having an interconnected electric system or operating under a central authority which controls the production and dispatching of electricity may apportion these costs to this account and transmission expense Accounts 561.1 through 561.4, and Account 581, Load Dispatching-Distribution.
1. Allocating loads to plants and interconnections with others.
2. Directing switching.
3. Arranging and controlling clearances for construction, maintenance, test and emergency purposes.
4. Controlling system voltages.
5. Recording loadings, water conditions, etc.
6. Preparing operating reports and data for billing and budget purposes.
7. Obtaining reports on the weather and special events.
8. Communication service provided for system control purposes.
9. System record and report forms.
10. Meals, traveling and incidental expenses.
11. Obtaining weather and special events reports.
A. This account shall be charged with any production expenses including expenses incurred directly in connection with the purchase of electricity, which are not specifically provided for in other production expense accounts. Charges to this account shall be supported so that a description of each type of charge will be readily available.
B. Recoveries from insurance companies, under use and occupancy provisions of policies, of amounts in reimbursement of excessive or added production costs for which the insurance company is liable under the terms of the policy shall be credited to this account.
A. For Major utilities, this account shall include the cost of labor and expenses incurred in the general supervision and direction of the operation of the transmission system as a whole. Direct supervision of specific activities, such as station operation, line operation, etc., shall be charged to the appropriate account. (See operating expense instruction 1.)
B. For Nonmajor utilities, this account shall include the cost of supervision and labor in the operation of the transmission system.
1. Direct switching.
2. Arranging and controlling clearances for construction, maintenance, test and emergency purposes.
3. Controlling system voltages.
4. Obtaining reports on the weather and special events.
5. Preparing operating reports and data for billing and budget purposes.
6. Supervising station operation.
7. Adjusting station equipment where such adjustment primarily affects performance, such as regulating the flow of cooling water, adjusting current in fields of a machine or changing voltage of regulators changing station transformer taps.
8. Inspecting, testing and calibrating station equipment for the purpose of checking its performance.
9. Keeping station log and records and preparing reports on station operation.
10. Operating switching and other station equipment.
11. Standing watch, guarding and patrolling station and station yard.
12. Sweeping, mopping and tidying station.
13. Care of grounds, including snow removal, cutting grass, etc.
14. Supervising line operation.
15. Inspecting and testing lightning arresters, circuit breakers, switches and grounds.
16. Load tests of circuits.
17. Routine line patrolling.
18. Routine voltage surveys made to determine the condition of efficiency of transmission system.
19. Transferring loads, switching and reconnecting circuits and equipment for operating purposes. (Switching for construction or maintenance purposes is not includible in this account.)
20. Routine inspection and cleaning of manholes, conduit, network and transformer vaults.
21. Electrolysis surveys.
22. Inspecting and adjusting line testing equipment such as voltmeters, ammeters, wattmeters, etc.
23. Regulation and addition of oil or gas in high voltage cable systems.
24. General records of physical characteristics of lines and stations, such as capacities, etc.
25. Ground resistance records.
26. Janitorial work at transmission office buildings, including care of grounds, snow removal, cutting grass, etc.
27. Joint pole maps and prints.
28. Line load and voltage records.
29. Preparing maps and prints.
30. General clerical and stenographic work.
31. Miscellaneous labor.
This account shall include the cost of labor, materials used and expenses incurred by a regional transmission service provider or other transmission provider to manage the reliability coordination function as specified by the North American Electric Reliability Council (NERC) and individual reliability organizations. These activities shall include performing current and next day reliability analysis. This account shall include the costs incurred to calculate load forecasts, and performing contingency analysis.
This account shall include the costs of labor, materials used and expenses incurred by a regional transmission service provider or other transmission provider to monitor, assess and operate the power system and individual transmission facilities in real-time to maintain safe and reliable operation of the transmission system. This account shall also include the expense incurred to manage transmission facilities to maintain system reliability and to monitor the real-time flows and direct actions according to regional plans and tariffs as necessary.
1. Receive and analyze outage requests
2. Reschedule outage plans
3. Monitor solution quality field data values, providing model updates to NERC and coordinating network model changes across all systems
4. Conduct operating training related to NERC certification
5. Monitor generation resources and communicate expected dispatch actions
6. Ensure ancillary service requirements are met
7. Directing switching
8. Controlling system voltages
9. Obtaining reports on the weather and special events
10. Preparing operating reports and data for billing and budget purposes
This account shall include the costs of labor, materials used and expenses incurred by a regional transmission service provider or other transmission provider to process hourly, daily, weekly and monthly transmission service requests using an automated system such as an Open Access Same-Time Information System (OASIS). It shall also include the expenses incurred to operate the automated transmission service request system and to monitor the status of all scheduled energy transactions.
This account shall include the costs billed to the transmission owner, load serving entity or generator for scheduling, system control and dispatching service. Include in this account service billings for system control to maintain the reliability of the transmission area in accordance with reliability standards, maintaining defined voltage profiles, and monitoring operations of the transmission facilities.
This account shall include the cost of labor, materials used and expenses incurred for the system planning of the interconnected bulk electric transmission systems within a planning authority area.
1. Developing and maintaining transmission system models to evaluate transmission system performance.
2. Maintaining and applying methodologies and tools for the analysis and simulation of the transmission systems for the assessment and development of transmission expansion plans.
3. Assessing, developing and documenting transmission expansion plans.
4. Maintaining transmission system models (steady-state, dynamics, and short circuit).
5. Collecting transmission information and transmission facility characteristics and ratings.
6. Notifying participants of any planned transmission changes that may impact their facilities.
7. Developing and reporting on transmission expansion plans for assessment and compliance with reliability standards.
8. Developing reliability standards for the planning and operation of the interconnected bulk electric transmission systems that serve the United States, Canada, and Mexico.
9. Developing criteria and certification procedures for reliability authorities, transmission operators and others.
10. Outside services employed.
The cost of supervision, customer records and collection expenses, administrative and general salaries, office supplies and expenses, property insurance, injuries and damages, employee pension and benefits, regulatory commission expenses, general advertising, and rents shall be charged to the customer accounts, service, and administrative and general expense accounts contained in the Uniform System of Accounts.
This account shall include the cost of labor, materials used and expenses incurred to conduct transmission services studies for proposed interconnections with the transmission system. Detailed records shall be maintained for each study undertaken and all reimbursements received for conducting such a study.
This account shall include the cost of labor, materials used and expenses incurred to conduct generation interconnection studies for proposed interconnections with the transmission system. Detailed records shall be maintained for each study undertaken and all reimbursements received for conducting such a study.
This account shall include the costs billed to the transmission owner, load serving entity, or generator for system planning of the interconnected bulk electric transmission system. Include also the costs billed by the regional transmission service provider for system reliability and resource planning to develop long-term strategies to meet customer demand and energy requirements. This account shall also include fees and expenses for outside services incurred by the regional transmission service provider and billed to the load serving entity, transmission owner or generator.
This account shall include the cost of labor, materials used and expenses incurred in operating transmission substations and switching stations. If transmission station equipment is located in or adjacent to a generating station the expenses applicable to transmission station operations shall nevertheless be charged to this account.
1. Supervising station operation.
2. Adjusting station equipment where such adjustment primarily affects performance, such as regulating the flow of cooling water, adjusting current in fields of a machine or changing voltage of regulators, changing station transformer taps.
3. Inspecting, testing and calibrating station equipment for the purpose of checking its performance.
4. Keeping station log and records and preparing reports on station operation.
5. Operating switching and other station equipment.
6. Standing watch, guarding, and patrolling station and station yard.
7. Sweeping, mopping, and tidying station.
8. Care of grounds, including snow removal, cutting grass, etc.
9. Building service expenses.
10. Operating supplies, such as lubricants, commutator brushes, water, and rubber goods.
11. Station meter and instrument supplies, such as ink and charts.
12. Station record and report forms.
13. Tool expense.
14. Transportation expenses.
15. Meals, traveling, and incidental expenses.
This account shall include the cost of labor, materials used and expenses incurred in the operation of energy storage equipment includible in Account 351, Energy Storage Equipment—Transmission, which are not specifically provided for or are readily assignable to other transmission operation expense accounts.
A. These accounts shall include the cost of labor, materials used and expenses incurred in the operation of transmission lines.
B. If the expenses are not substantial for both overhead and underground lines, these accounts may be combined.
1. Supervising line operation.
2. Inspecting and testing lightning arresters, circuit breakers, switches, and grounds
3. Load tests of circuits.
4. Routine line patrolling.
5. Routine voltage surveys made to determine the condition or efficiency of transmission system.
6. Transferring loads, switching and reconnecting circuits and equipment for operating purposes. (Switching for construction or maintenance purposes is not includible in this account.)
7. Routine inspection and cleaning of manholes, conduit, network and transformer vaults.
8. Electrolysis surveys.
9. Inspecting and adjusting line-testing equipment, such as voltmeters, ammeters, wattmeters, etc.
10. Regulation and addition of oil or gas in high-voltage cable systems.
11. Transportation expenses.
12. Meals, traveling and incidental expenses.
13. Tool expenses.
14. Operating supplies, such as instrument charts, rubber goods, etc.
This account shall include amounts payable to others for the transmission of the utility’s electricity over transmission facilities owned by others.
This account shall include the cost of labor, materials used and expenses incurred in transmission map and record work, transmission office expenses, and other transmission expenses not provided for elsewhere.
1. General records of physical characteristics of lines and stations, such as capacities, etc.
2. Ground resistance records.
3. Janitor work at transmission office buildings, including care of grounds, snow removal, cutting grass, etc.
4. Joint pole maps and records.
5. Line load and voltage records.
6. Preparing maps and prints.
7. General clerical and stenographic work.
8. Miscellaneous labor.
9. Communication service.
10. Building service supplies.
11. Map and record supplies.
12. Transmission office supplies and expenses, printing and stationery.
13. First-aid supplies.
14. Research, development, and demonstration expenses.
This account shall include rents of property of others used, occupied, or operated in connection with the transmission system, including payments to the United States and others for use of public or private lands and reservations for transmission line rights of way. (See operating expense instruction 3.)
This account shall include the cost of materials used and expenses incurred in the operation of the transmission system.
1. Building service expenses.
2. Operating supplies, such as lubricants, commutator brushes, water, and rubber goods.
3. Station meter and instrument supplies, such as ink and charts.
4. Station record and report forms.
5. Communication service.
6. First-aid supplies.
7. Tool expense.
8. Transportation expenses.
9. Meals, traveling, and incidental expenses.
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of the transmission system. Direct field supervision of specific jobs shall be charged to the appropriate maintenance account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures, the book cost of which is includible in account 352, Structures and Improvements. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of computer hardware serving the transmission function.
This account shall include the cost of labor, materials used and expenses incurred for annual computer software license renewals, annual software update services and the cost of ongoing support for software products serving the transmission function.
1. Telephone support
2. Onsite support
3. Software updates and minor revisions
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of communication equipment serving the transmission function.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of miscellaneous regional transmission plant serving the transmission function.
This account shall include the cost of labor, materials used and expenses incurred in maintenance of station equipment the book cost of which is includible in account 353, Station Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of energy storage equipment includible in Account 351, Energy Storage Equipment—Transmission, which are not specifically provided for or are readily assignable to other transmission maintenance expense accounts.
This account shall include the cost of labor, materials used and expenses incurred in maintenance of transmission plant, the book cost of which is includible in accounts 354, Towers and Fixtures, 355, Poles and Fixtures, 356, Overhead Conductors and Devices, 359, Roads and Trails. (See operating expense instruction 2.)
1. Work of the following character on poles, towers and fixtures:
a. Installing or removing additional clamps or strain insulators on guys in place.
b. Moving line or guy pole in relocation of the same pole or section of line.
c. Painting poles, towers, crossarms or pole extensions.
d. Readjusting and changing position of guys or braces.
e. Realigning and straightening poles, cross arms braces, and other pole fixtures.
f. Reconditioning reclaimed pole fixtures.
g. Relocating crossarms, racks, brackets, and other fixtures on poles.
h. Repairing or realigning pins, racks, or brackets.
i. Repairing pole supported platform.
j. Repairs by others to jointly owned poles.
k. Shaving, cutting rot, or treating poles or crossarms in use or salvaged for reuse.
l. Stubbing poles already in service.
m. Supporting fixtures and conductors and transferring them to new pole during poles replacements.
n. Maintenance of pole signs, stencils, tags, etc.
2. Work of the following character on overhead conductors and devices:
a. Overhauling and repairing line cutouts, line switches, line breakers, etc.
b. Cleaning insulators and bushings.
c. Refusing cutouts.
d. Repairing line oil circuit breakers and associated relays and control wiring.
e. Repairing grounds.
f. Resagging, retying, or rearranging position or spacing of conductors.
g. Standing by phones, going to calls, cutting faulty lines clear, or similar activities at times of emergencies.
h. Sampling, testing, changing, purifying, and replenishing insulating oil.
i. Repairing line testing equipment.
j. Transferring loads, switching and reconnecting circuits and equipment for maintenance purposes.
k. Trimming trees and clearing brush.
l. Chemical treatment of right of way areas when occurring subsequent to construction of line.
3. Work of the following character on roads and trails:
a. Repairing roadway, bridges, etc.
b. Trimming trees and brush to maintain previous roadway clearance.
c. Snow removal from roads and trails.
d. Maintenance work on publicly owned roads and trails when done by utility at its expense.
This account shall include the cost of labor, materials used and expenses incurred in maintenance of transmission plant, the book cost of which is includible in accounts 357, Underground Conduit, and 358, Underground Conductors and Devices. (See operating expense instruction 2.)
1. Work of the following character on underground conduit:
a. Cleaning ducts, manholes, and sewer connections.
b. Minor alterations of handholes, manholes, or vaults.
c. Refastening, repairing, or moving racks, ladders, or hangers in manholes, or vaults.
d. Plugging and shelving or replugging ducts.
e. Repairs to sewers and drains, walls and floors, rings and covers.
2. Work of the following character on underground conductors and devices:
a. Repairing oil circuit breakers, switches, cutouts, and control wiring.
b. Repairing grounds.
c. Retraining and reconnecting cables in manhole, including transfer of cables from one duct to another.
d. Repairing conductors and splices.
e. Repairing or moving junction boxes and potheads.
f. Refireproofing of cables and repairing supports.
g. Repairing electrolysis preventive devices for cables.
h. Repairing cable bonding systems.
i. Sampling, testing, changing, purifying and replenishing insulating oil.
j. Transferring loads, switching and reconnecting circuits and equipment for maintenance purposes.
k. Repairing line testing equipment.
l. Repairs to oil or gas equipment in highvoltage cable system and replacement of oil or gas.
This account shall include the cost of labor, materials used and expenses incurred in maintenance of owned or leased plant which is assignable to transmission operations and is not provided for elsewhere. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of transmission plant the book cost of which is includible in plant accounts 351 to 359 inclusive. (See operating expense instruction 2.)
1. Work of the following character on poles, towers and fixtures:
a. Installing or removing additional clamps or strain insulators on guys in place.
b. Moving line or guy pole in relocation of the same pole or section of line.
c. Painting poles, towers, crossarms or pole extensions.
d. Readjusting and changing position of guys or braces.
e. Realigning and straightening poles, crossarms, braces and other pole fixtures.
f. Reconditioning reclaimed pole fixtures.
g. Relocating crossarms, racks, brackets, and other fixtures on poles.
h. Repairing or realigning pins, racks, or brackets.
i. Repairing pole supported platform.
j. Repairs by others to jointly owned poles.
k. Shaving, cutting rot, or treating poles or crossarms in use or salvaged for reuse.
l. Stubbing poles already in service.
m. Supporting fixtures and conductors and transferring them to new pole during pole replacement.
n. Maintenance of pole signs, stencils, tags, etc.
2. Work of the following character on overhead conductors and devices:
a. Overhauling and repairing line cutouts, line switches, line breakers, etc.
b. Cleaning insulators and bushings.
c. Refusing cutouts.
d. Repairing line oil circuit breakers and associated relays and control wiring.
e. Repairing grounds.
f. Resagging, retying, or rearranging position or spacing of conductors.
g. Standing by phones, going to calls, cutting faulty lines clear, or similar activities at times of emergencies.
h. Sampling, testing, changing, purifying, and replenishing insulating oil.
i. Repairing line testing equipment.
j. Transferring loads, switching and reconnecting circuits and equipment for maintenance purposes.
k. Trimming trees and clearing brush.
l. Chemical treatment of right of way areas when occurring subsequent to construction of line.
3. Work of the following character on roads and trails:
a. Repairing roadway, bridges, etc.
b. Trimming trees and brush to maintain previous roadway clearance.
c. Snow removal from roads and trails.
d. Maintenance work on publicly owned roads and trails when done by utility at its expense.
4. Work of the following character on underground conduit:
a. Cleaning ducts, manholes, and sewer connections.
b. Minor alterations of handholes, manholes, or vaults.
c. Refasting, repairing, or moving racks, ladders, or hangers in manholes, or vaults.
d. Plugging and shelving or replugging ducts.
e. Repairs to sewers and drains, walls and floors, rings and covers.
5. Work of the following character on underground conductors and devices:
a. Repairing oil circuit breakers, switches, cutouts, and control wiring.
b. Repairing grounds.
c. Retraining and reconnecting cables in manhole, including transfer of cables from one duct to another.
d. Repairing conductors and splices.
e. Repairing or moving junction boxes and potheads.
f. Refireproofing of cables and repairing supports.
g. Repairing electrolysis preventive devices for cables.
h. Repairing cable bonding systems.
i. Sampling, testing, changing, purifying and replenishing insulating oil.
j. Transferring loads, switching and reconnecting circuits and equipment for maintenance purposes.
k. Repairing line testing equipment.
l. Repairs to oil or gas equipment in high voltage cable system and replacement of oil or gas.
This account shall include the cost of labor and expenses incurred in the general supervision and direction of the regional energy markets.
This account shall include the cost of labor, materials used and expenses incurred to facilitate the Day-Ahead and Real-Time markets. This account shall also include the costs incurred to manage the real-time deployment of resources to meet generation needs and to provide capacity adequacy verification. Include in this account the costs incurred to maintain related sections of the tariff, market rules, operating procedures, and standards and coordinating with neighboring areas.
1. Consultant fees and expenses
2. System record and report forms
3. Meals, traveling and incidental expenses
The cost of supervision, customer records and collection expenses, administrative and general salaries, office supplies and expenses, property insurance, injuries and damages, employee pension and benefits, regulatory commission expenses, general advertising, and rents shall be charged to the customer accounts, service, and administrative and general expense accounts contained in the Uniform System of Accounts.
This account shall include the cost of labor, materials used and expenses incurred to manage the allocation and auction of transmission rights.
This account shall include the cost of labor, materials used and expenses incurred to manage the allocation of capacity rights.
This account shall include the cost of labor, materials used and expenses incurred to manage all other ancillary services market functions.
This account shall include the cost of labor, materials used and expenses incurred to review market data and operational decisions for compliance with market rules. It shall also include the costs incurred to interface with external market monitors.
This account shall include the costs billed to the transmission owner, load serving entity or generator for market administration, monitoring and compliance services.
This account shall include all rents of property of others used, occupied, or operated in connection with market administration and monitoring. (See operating expense instruction 3.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures used in market administration and monitoring. (See operating expense instruction 2.)
The account shall include the cost of labor, materials used and expenses incurred in the maintenance of computer hardware used in market administration and monitoring.
This account shall include the cost of labor, materials used and expenses incurred for annual computer software license renewals, annual software update services and the cost of ongoing support for software products used in market administration and monitoring.
1. Telephone support
2. Onsite support
3. Software updates and minor revisions
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of communication equipment used in market administration and monitoring.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of miscellaneous market operation plant used in market administration and monitoring.
This account shall include the cost of labor and expenses incurred in the general supervision and direction of the operation of the distribution system. Direct supervision of specific activities, such as station operation, line operation, meter department operation, etc., shall be charged to the appropriate account. (For Major utilities, see operating expense instruction 1.)
This account (the keeping of which is optional with the utility) shall include the cost of labor, materials used and expenses incurred in load dispatching operations pertaining to the distribution of electricity.
1. Directing switching.
2. Arranging and controlling clearances for construction, maintenance, test and emergency purposes.
3. Controlling system voltages.
4. Preparing operating reports.
5. Obtaining reports on the weather and special events.
6. Communication service provided for system control purposes.
7. System record and report forms.
8. Meals, traveling and incidental expenses.
Accounts 581.1 through 584 shall include, respectively, the cost of labor, materials used and expenses incurred in the operation of overhead and underground distribution lines and stations.
1. Supervising line operation.
2. Changing line transformer taps.
3. Inspecting and testing lightning arresters, line circuit breakers, switches and grounds.
4. Inspecting and testing line transformers for the purpose of determining load, temperature or operating performance.
5. Patrolling lines.
6. Load tests and voltages surveys of feeders, circuits and line transformers.
7. Removing line transformers and voltage regulators with or without replacements.
8. Installing line transformers or voltage regulators with or without change in capacity provided that the first installation of these items is included in account 368, Line transformers.
9. Voltage surveys, either routine or upon request of customers, including voltage tests at customers’ main switch.
10. Transferring loads, switching and reconnecting circuits and equipment for operation purposes.
11. Electrolysis surveys.
12. Inspecting and adjusting line testing equipment.
13. Tool expenses.
14. Transportation expenses.
15. Meals, traveling and incidental expense.
16. Operating supplies, such as instrument charts, rubber goods, etc.
1. Supervising station operation.
2. Adjusting station equipment where such adjustment primarily affects performance, such as regulating the flow of cooling water, adjusting current in fields of a machine, changing voltage of regulators or changing station transformer taps.
3. Keeping station log and records and preparing reports on station operation.
4. Inspecting, testing and calibrating station equipment for the purpose of checking its performance.
5. Operating switching and other station equipment.
6. Standing watch, guarding and patrolling station and station yard.
7. Sweeping, mopping and tidying station.
8. Care of grounds, including snow removal, cutting grass, etc.
9. Building service expenses.
10. Operating supplies, such as lubricants, commutator brushes, water and rubber goods.
11. Station meter and instrument supplies, such as ink and charts.
12. Station record and report forms.
13. Tool expenses.
14. Transportation expenses.
15. Meals, traveling and incidental expenses.
If the utility owns storage battery equipment used for supplying electricity to customers in periods of emergency, the cost of operating labor and of supplies, such as acid, gloves, hydrometers, thermometers, soda, automatic cell fillers, acid proof shoes, etc., shall be included in this account. If significant in amount, a separate subdivision shall be maintained for such expenses.
This account shall include the cost of labor, materials used and expenses incurred in the operation of energy storage equipment includible in Account 363, Energy Storage Equipment—Distribution, which are not specifically provided for or are readily assignable to other distribution operation expense accounts.
A. For Nonmajor utilities, this account shall include the cost of labor, materials used and expenses incurred in the operation of street lighting and signal system plant.
B. For Major utilities, this account shall include the cost of labor, materials used and expenses incurred in: (a) The operation of street lighting and signal system plant which is owned or leased by the utility; and (b) the operation and maintenance of such plant owned by customers where such work is done regularly as a part of the street lighting and signal system service.
1. Supervising street lighting and signal systems operation.
2. Replacing lamps and incidental cleaning of glassware and fixtures in connection therewith.
3. Routine patrolling for lamp outages, extraneous nuisances or encroachments, etc.
4. Testing lines and equipment including voltage and current measurement.
5. Winding and inspection of time switch and other controls.
6. Street lamp renewals.
7. Transportation and tool expense.
8. Meals, traveling, and incidental expenses.
This account shall include the cost of labor, materials used and expenses incurred in the operation of customer meters and associated equipment.
1. Supervising meter operation.
2. Clerical work on meter history and associated equipment record cards, test cards, and reports.
3. Disconnecting and reconnecting, removing and reinstalling, sealing and unsealing meters and other metering equipment in connection with initiating or terminating services including the cost of obtaining meter readings, if incidental to such operation.
4. Consolidating meter installations due to elimination of separate meters for different rates of service.
5. Changing or relocating meters, instrument transformers, time switches, and other metering equipment.
6. Resetting time controls, checking operation of demand meters and other metering equipment, when done as an independent operation.
7. Inspecting and adjusting meter testing equipment.
8. Inspecting and testing meters, instrument transformers, time switches, and other metering equipment on premises or in shops excluding inspecting and testing incidental to maintenance
9. Meter seals and miscellaneous meter supplies.
10. Transportation expenses.
11. Meals, traveling, and incidental expenses.
12. Tool expenses.
The cost of the first setting and testing of a meter is chargeable to utility plant account 370, Meters.
This account shall include the cost of labor, materials used and expenses incurred in work on customer installations in inspecting premises and in rendering services to customers of the nature of those indicated by the list of items hereunder.
1. Supervising customer installations work.
2. Inspecting premises, including check of wiring for code compliance.
3. Investigating, locating, and clearing grounds on customers’ wiring.
4. Investigating service complaints, including load tests of motors and lighting and power circuits on customers’ premises; field investigations of complaints on bills or of voltage.
5. Installing, removing, renewing, and changing lamps and fuses.
6. Radio, television and similar interference work including erection of new aerials on customers’ premises and patrolling of lines, testing of lightning arresters, inspection of pole hardware, etc., and examination on or off premises of customers’ appliances, wiring, or equipment to locate cause of interference.
7. Installing, connecting, reinstalling, or removing leased property on customers’ premises.
8. Testing, adjusting, and repairing customers’ fixtures and appliances in shop or on premises.
9. Cost of changing customers’ equipment due to changes in service characteristics.
10. Investigation of current diversion including setting and removal of check meters and securing special readings thereon; special calls by employees in connection with discovery and settlement of current diversion; changes in customer wiring and any other labor cost identifiable as caused by current diversion.
11. Lamp and fuse renewals.
12. Materials used in servicing customers’ fixtures, appliances and equipment.
13. Power, light, heat, telephone, and other expenses of appliance repair department.
14. Tool expense.
15. Transportation expense, including pickup and delivery charges.
16. Meals, traveling and incidental expenses.
17. Rewards paid for discovery of current diversion.
Amounts billed customers for any work, the cost of which is charged to this account, shall be credited to this account. Any excess over costs resulting therefrom shall be transferred to account 451, Miscellaneous Service Revenues.
Do not include in this account expenses incurred in connection with merchandising, jobbing and contract work.
This account shall include the cost of labor, materials used and expenses incurred in distribution system operation not provided for elsewhere.
1. General records of physical characteristics of lines and substations, such as capacities, etc.
2. Ground resistance records.
3. Joint pole maps and records.
4. Distribution system voltage and load records.
5. Preparing maps and prints.
6. Service interruption and trouble records.
7. General clerical and stenographic work except that chargeable to account 586, Meter expenses.
8. Operating records covering poles, transformers, manholes, cables, and other distribution facilities. Exclude meter records chargeable to account 586. Meter Expenses and station records chargeable to account 582, Station Expenses (For Nonmajor utilities, account 581.1, Line and Station Expenses), and stores records (For Nonmajor utilities, station records) chargeable to account 163, Stores Expense Undistributed (For Nonmajor utilities, account 581.1, Line and Station Expenses).
9. Janitor work at distribution office buildings including snow removal, cutting grass, etc.
10. Communication service.
11. Building service expenses.
12. Miscellaneous office supplies and expenses, printing, and stationery, maps and records and first-aid supplies.
13. Research, development, and demonstration expenses (Major only).
This account shall include rents of property of others used, occupied, or operated in connection with the distribution system, including payments to the United States and others for the use and occupancy of public lands and reservations for distribution line rights of way. (See operating expense instruction 3.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of the distribution system. Direct field supervision of specific jobs shall be charged to the appropriate maintenance account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of structures, the book cost of which is includible in account 361, Structures and Improvements. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of plant, the book cost of which is includible in account 362, Station Equipment, and account 363, Storage Battery Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of structures, the book cost of which is includible in account 361, Structures and Improvements, and account 362, Station Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of overhead distribution line facilities, the book cost of which is includible in account 364, Poles, Towers and Fixtures, account 365, Overhead Conductors and Devices, and account 369, Services. (See operating expense instruction 2.)
1. Work of the following character on poles, towers, and fixtures:
a. Installing additional clamps or removing clamps or strain insulators on guys in place.
b. Moving line or guy pole in relocation of pole or section of line.
c. Painting poles, towers, crossarms, or pole extensions.
d. Readjusting and changing position of guys or braces.
e. Realigning and straightening poles, crossarms, braces, pins, racks, brackets, and other pole fixtures.
f. Reconditioning reclaimed pole fixtures.
g. Relocating crossarms, racks, brackets, and other fixtures on poles.
h. Repairing pole supported platform.
i. Repairs by others to jointly owned poles.
j. Shaving, cutting rot, or treating poles or crossarms in use or salvaged for reuse.
k. Stubbing poles already in service.
l. Supporting conductors, transformers, and other fixtures and transferring them to new poles during pole replacements.
m. Maintaining pole signs, stencils, tags, etc.
2. Work of the following character on overhead conductors and devices:
a. Overhauling and repairing line cutouts, line switches, line breakers, and capacitor installations.
b. Cleaning insulators and bushings.
c. Refusing line cutouts.
d. Repairing line oil circuit breakers and associated relays and control wiring.
e. Repairing grounds.
f. Resagging, retying, or rearranging position or spacing of conductors.
g. Standing by phones, going to calls, cutting faulty lines clear, or similar activities at times of emergency.
h. Sampling, testing, changing, purifying, and replenishing insulating oil.
i. Transferring loads, switching, and reconnecting circuits and equipment for maintenance purposes.
j. Repairing line testing equipment.
k. Trimming trees and clearing brush.
l. Chemical treatment of right of way area when occurring subsequent to construction of line.
3. Work of the following character on overhead services:
a. Moving position of service either on pole or on customers’ premises.
b. Pulling slack in service wire.
c. Retying service wire.
d. Refastening or tightening service bracket.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of underground distribution line facilities, the book cost of which is includible in account 366, Underground Conduit, account 367, Underground Conductors and Devices, and account 369, Services. (See operating expense instruction 2.)
1. Work of the following character on underground conduit:
a. Cleaning ducts, manholes, and sewer connections.
b. Moving or changing position of conduit or pipe.
c. Minor alterations of handholes, manholes, or vaults.
d. Refastening, repairing, or moving racks, ladders, or hangers in manholes or vaults.
e. Plugging and shelving ducts.
f. Repairs to sewers, drains, walls, and floors, rings and covers.
2. Work of the following character on underground conductors and devices:
a. Repairing circuit breakers, switches, cutouts, network protectors, and associated relays and control wiring.
b. Repairing grounds.
c. Retraining and reconnecting cables in manholes including transfer of cables from one duct to another.
d. Repairing conductors and splices.
e. Repairing or moving junction boxes and potheads.
f. Refireproofing cables and repairing supports.
g. Repairing electrolysis preventive devices for cables.
h. Repairing cable bonding systems.
i. Sampling, testing, changing, purifying and replenishing insulating oil.
j. Transferring loads, switching and reconnecting circuits and equipment for maintenance purposes.
k. Repairing line testing equipment.
l. Repairing oil or gas equipment in high voltage cable systems and replacement of oil or gas.
3. Work of the following character on underground services:
a. Cleaning ducts.
b. Repairing any underground service plant.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of distribution line facilities, the book cost of which is includible in account 364, Poles, Towers and Fixtures, account 365, Overhead Conductors and Devices, account 366, Underground Conduit, account 367, Underground Conductors and Devices, and account 369, Services. (See operating expense instruction 2.)
1. Work of the following character on poles, towers, and fixtures:
a. Installing additional clamps or removing clamps or strain insulators on guys in place.
b. Moving line or guy pole in relocation of pole or section of line.
c. Painting poles, towers, crossarms, or pole extensions.
d. Readjusting and changing position of guys or braces.
e. Realigning and straightening poles, crossarms, braces, pins, racks, brackets, and other pole fixtures.
f. Reconditioning reclaimed pole fixtures.
g. Relocating crossarms, racks, brackets, and other fixtures on pole.
h. Repairing pole supported platform.
i. Repairs by others to jointly owned poles.
j. Shaving, cutting rot, or treating poles or crossarms in use or salvage for reuse.
k. Stubbing poles already in service.
l. Supporting conductors, transformers, and other fixtures and transferring them to new poles during pole replacement.
m. Maintaining pole signs, stencils, tags, etc.
2. Work of the following character on overhead conductors and devices:
a. Overhauling and repairing line cutouts, line switches, line breakers, and capacitor installations.
b. Cleaning insulators and bushings.
c. Refusing line cutouts.
d. Repairing line oil circuit breakers and associated relays and control wiring.
e. Repairing grounds.
f. Resagging, retying, or rearranging position or spacing of conductors.
g. Standing by phones, going to calls, cutting faulting lines clear, or similar activities at times of emergencies.
h. Sampling, testing, changing, purifying, and replenishing insulating oil.
i. Transferring loads, switching, and reconnecting circuits and equipment for maintenance purposes.
j. Repairing line testing equipment.
k. Trimming trees and clearing brush.
l. Chemical treatment of right of way area when occurring subsequent to construction of line.
3. Work of the following character on underground conduit:
a. Cleaning ducts, manholes, and sewer connections.
b. Moving or changing position of conduit or pipe.
c. Minor alterations of handholes, manholes, or vaults.
d. Refastening, repairing or moving racks, ladders, or hangers in manholes or vaults.
e. Plugging and shelving ducts.
f. Repairs to sewers, drains, walls and floors, rings and covers.
4. Work of the following character on underground conductors and devices:
a. Repairing circuit breakers, switches, cutouts, network protectors, and associated relays and control wiring.
b. Repairing grounds.
c. Retraining and reconnecting cables in manhole including transfer of cables from one duct to another.
d. Repairing conductors and splices.
e. Repairing or moving junction boxes and potheads.
f. Refireproofing cables and repairing supports.
g. Repairing electrolysis preventive devices for cables.
h. Repairing cable bonding systems.
i. Sampling, testing, changing, purifying and replenishing insulating oil.
j. Transferring loads, switching and reconnecting circuits and equipment for maintenance purposes.
k. Repairing line testing equipment.
l. Repairing oil or gas equipment in high voltage cable system and replacement of oil or gas.
5. Work of the following character on services:
a. Moving position of service either on pole or on customers’ premises.
b. Pulling slack in service wire.
c. Retying service wire.
d. Refastening or tightening service bracket.
e. Cleaning ducts.
This account shall include the cost of labor, materials used and expenses incurred in maintenance of distribution line transformers, the book cost of which is includible in account 368, Line Transformers. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of plant, the book cost of which is includible in account 373, Street Lighting and Signal Systems. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of meters and meter testing equipment, the book cost of which is includible in account 370, Meters, and account 395, Laboratory Equipment, respectively. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of plant, the book cost of which is includible in accounts 371, Installations on Customers’ Premises, and 372, Leased Property on Customers’ Premises, and any other plant the maintenance of which is assignable to the distribution function and is not provided for elsewhere. (See operating expense instruction 2.)
a. Work of similar nature to that listed in other distribution maintenance accounts.
b. Maintenance of office furniture and equipment used by distribution system department.
This account shall include the cost of labor and expenses incurred in the general direction and supervision of customer accounting and collecting activities. Direct supervision of a specific activity shall be charged to account 902, Meter Reading Expenses, or account 903, Customer Records and Collection Expenses, as appropriate. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in reading customer meters, and determining consumption when performed by employees engaged in reading meters.
1. Addressing forms for obtaining meter readings by mail.
2. Changing and collecting meter charts used for billing purposes.
3. Inspecting time clocks, checking seals, etc., when performed by meter readers and the work represents a minor activity incidental to regular meter reading routine.
4. Reading meters, including demand meters, and obtaining load information for billing purposes. Exclude and charge to account 586, Meter Expenses, or to account 903, Customer Records and Collection Expenses, as applicable, the cost of obtaining meter readings, first and final, if incidental to the operation of removing or resetting, sealing, or locking, and disconnecting or reconnecting meters.
5. Computing consumption from meter reader’s book or from reports by mail when done by employees engaged in reading meters.
6. Collecting from prepayment meters when incidental to meter reading.
7. Maintaining record of customers’ keys.
8. Computing estimated or average consumption when performed by employees engaged in reading meters.
9. Badges, lamps, and uniforms.
10. Demand charts, meter books and binders and forms for recording readings, but not the cost of preparation.
11. Postage and supplies used in obtaining meter readings by mail.
12. Transportation, meals, and incidental expenses.
This account shall include the cost of labor, materials used and expenses incurred in work on customer applications, contracts, orders, credit investigations, billing and accounting, collections and complaints.
1. Receiving, preparing, recording and handling routine orders for service, disconnections, transfers or meter tests initiated by the customer, excluding the cost of carrying out such orders, which is chargeable to the account appropriate for the work called for by such orders.
2. Investigations of customers’ credit and keeping of records pertaining thereto, including records of uncollectible accounts written off.
3. Receiving, refunding or applying customer deposits and maintaining customer deposit, line extension, and other miscellaneous records.
4. Checking consumption shown by meter readers’ reports where incidental to preparation of billing data.
5. Preparing address plates and addressing bills and delinquent notices.
6. Preparing billing data.
7. Operating billing and bookkeeping machines.
8. Verifying billing records with contracts or rate schedules.
9. Preparing bills for delivery, and mailing or delivering bills.
10. Collecting revenues, including collection from prepayment meters unless incidental to meter-reading operations.
11. Balancing collections, preparing collections for deposit, and preparing cash reports.
12. Posting collections and other credits or charges to customer accounts and extending unpaid balances.
13. Balancing customer accounts and controls.
14. Preparing, mailing, or delivering delinquent notices and preparing reports of delinquent accounts.
15. Final meter reading of delinquent accounts when done by collectors incidental to regular activities.
16. Disconnecting and reconnecting service because of nonpayment of bills.
17. Receiving, recording, and handling of inquiries, complaints, and requests for investigations from customers, including preparation of necessary orders, but excluding the cost of carrying out such orders, which is chargeable to the account appropriate for the work called for by such orders.
18. Statistical and tabulating work on customer accounts and revenues, but not including special analyses for sales department, rate department, or other general purposes, unless incidental to regular customer accounting routines.
19. Preparing and periodically rewriting meter reading sheets.
20. Determining consumption and computing estimated or average consumption when performed by employees other than those engaged in reading meters.
21. Address plates and supplies.
22. Cash overages and shortages.
23. Commissions or fees to others for collecting.
24. Payments to credit organizations for investigations and reports.
25. Postage.
26. Transportation expenses (Major only), including transportation of customer bills and meter books under centralized billing procedure.
27. Transportation, meals, and incidental expenses.
28. Bank charges, exchange, and other fees for cashing and depositing customers’ checks.
29. Forms for recording orders for services removals, etc.
30. Rent of mechanical equipment.
31. Communication service (Nonmajor only).
32. Miscellaneous office supplies and expenses and stationery and printing (Nonmajor only).
The cost of work on meter history and meter location records is chargeable to account 586, Meter Expenses.
This account shall be charged with amounts sufficient to provide for losses from uncollectible utility revenues. Concurrent credits shall be made to account 144, Accumulated Provision for Uncollectible Accounts—Cr. Losses from uncollectible accounts shall be charged to account 144.
This account shall include the cost of labor, materials used and expenses incurred not provided for in other accounts.
1. General clerical and stenographic work.
2. Miscellaneous labor.
3. Communication service.
4. Miscellaneous office supplies and expenses and stationery and printing other than those specifically provided for in accounts 902 and 903.
This account shall include the cost of supervision, labor, and expenses incurred in customer service and informational activities, the purpose of which is to encourage safe and efficient use of the utility’s service, to encourage conservation of the utility’s service, and to assist present customers in answering specific inquiries as to the proper and economic use of the utility’s service and the customer’s equipment utilizing the service.
This account shall include the cost of labor and expenses incurred in the general direction and supervision of customer service activities, the object of which is to encourage safe, efficient and economical use of the utility’s service. Direct supervision of a specific activity within customer service and informational expense classification shall be charged to the account wherein the costs of such activity are included. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in providing instructions or assistance to customers, the object of which is to encourage safe, efficient and economical use of the utility’s service.
1. Direct supervision of department.
2. Processing customer inquiries relating to the proper use of electric equipment, the replacement of such equipment and information related to such equipment.
3. Advice directed to customers as to how they may achieve the most efficient and safest use of electric equipment.
4. Demonstrations, exhibits, lectures, and other programs designed to instruct customers in the safe, economical or efficient use of electric service, and/or oriented toward conservation of energy.
5. Engineering and technical advice to customers, the object of which is to promote safe, efficient and economical use of the utility’s service.
6. Supplies and expenses pertaining to demonstrations, exhibits, lectures, and other programs.
7. Loss in value on equipment and appliances used for customer assistance programs.
8. Office supplies and expenses.
9. Transportation, meals, and incidental expenses.
Do not include in this account expenses that are provided for elsewhere, such as accounts 416, Costs and Expenses of Merchandising, Jobbing and Contract Work, 587, Customer Installations Expenses, and 912, Demonstrating and Selling Expenses.
This account shall include the cost of labor, materials used and expenses incurred in activities which primarily convey information as to what the utility urges or suggests customers should do in utilizing electric service to protect health and safety, to encourage environmental protection, to utilize their electric equipment safely and economically, or to conserve electric energy.
1. Direct supervision of informational activities.
2. Preparing informational materials for newspapers, periodicals, billboards, etc., and preparing and conducting informational motion pictures, radio and television programs.
3. Preparing informational booklets, bulletins, etc., used in direct mailings.
4. Preparing informational window and other displays.
5. Employing agencies, selecting media and conducting negotiations in connection with the placement and subject matter of information programs.
6. Use of newspapers, periodicals, billboards, radio, etc., for informational purposes.
7. Postage on direct mailings to customers exclusive of postage related to billings.
8. Printing of informational booklets, dodgers, bulletins, etc.
9. Supplies and expenses in preparing informational materials by the utility.
10. Office supplies and expenses.
Exclude from this account and charge to account 930.2, Miscellaneous General Expenses, the cost of publication of stockholder reports, dividend notices, bond redemption notices, financial statements, and other notices of a general corporate character. Exclude also all expenses of a promotional, institutional, goodwill or political nature, which are includible in such accounts as 913, Advertising Expenses, 930.1, General Advertising Expenses, and 426.4, Expenditures for Certain Civic, Political and Related Activities.
Entries relating to informational advertising included in this account shall contain or refer to supporting documents which identify the specific advertising message. If references are used, copies of the advertising message shall be readily available.
This account shall include the cost of labor, materials used and expenses incurred in connection with customer service and informational activities which are not includible in other customer information expense accounts.
1. General clerical and stenographic work not assigned to specific customer service and informational programs.
2. Miscellaneous labor.
3. Communication service.
4. Printing, postage and office supplies expenses.
This account shall include the cost of labor and expenses incurred in the general direction and supervision of sales activities, except merchandising. Direct supervision of a specific activity, such as demonstrating, selling, or advertising shall be charged to the account wherein the costs of such activity are included. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in promotional, demonstrating, and selling activities, except by merchandising, the object of which is to promote or retain the use of utility services by present and prospective customers.
1. Demonstrating uses of utility services.
2. Conducting cooking schools, preparing recipes, and related home service activities.
3. Exhibitions, displays, lectures, and other programs designed to promote use of utility services.
4. Experimental and development work in connection with new and improved appliances and equipment, prior to general public acceptance.
5. Solicitation of new customers or of additional business from old customers, including commissions paid employees.
6. Engineering and technical advice to present or prospective customers in connection with promoting or retaining the use of utility services.
7. Special customer canvasses when their primary purpose is the retention of business or the promotion of new business.
8. Supplies and expenses pertaining to demonstration, and experimental and development activities.
9. Booth and temporary space rental.
10. Loss in value on equipment and appliances used for demonstration purposes.
11. Transportation, meals, and incidental expenses.
This account shall include the cost of labor, materials used and expenses incurred in advertising designed to promote or retain the use of utility service, except advertising the sale of merchandise by the utility.
1. Direct supervision of department.
2. Preparing advertising material for newspapers, periodicals, billboards, etc., and preparing and conducting motion pictures, radio and television programs.
3. Preparing booklets, bulletins, etc., used in direct mail advertising.
4. Preparing window and other displays.
5. Clerical and stenographic work.
6. Investigating advertising agencies and media and conducting negotiations in connection with the placement and subject matter of sales advertising.
7. Advertising in newspapers, periodicals, billboards, radio, etc., for sales promotion purposes, but not including institutional or goodwill advertising includible in account 930.1, General Advertising Expenses.
8. Materials and services given as prizes or otherwise in connection with civic lighting contests, canning, or cooking contests, bazaars, etc., in order to publicize and promote the use of utility services.
9. Fees and expenses of advertising agencies and commercial artists.
10. Novelties for general distribution.
11. Postage on direct mail advertising.
12. Premiums distributed generally, such as recipe books, etc., when not offered as inducement to purchase appliances.
13. Printing booklets, dodgers, bulletins, etc.
14. Supplies and expenses in preparing advertising material.
15. Office supplies and expenses.
The cost of advertisements which set forth the value or advantages of utility service without reference to specific appliances or, if reference is made to appliances invites the reader to purchase appliances from his dealer or refer to appliances not carried for sale by the utility, shall be considered sales promotion advertising and charged to this account. However, advertisements which are limited to specific makes of appliances sold by the utility and prices, terms, etc., thereof, without referring to the value or advantages of utility service, shall be considered as merchandise advertising and the cost shall be charged to Costs and Expenses of Merchandising, Jobbing and Contract Work, Account 416.
Advertisements which substantially mention or refer to the value or advantages of utility service, together with specific reference to makes of appliances sold by the utility and the price, terms, etc., thereof and designed for the joint purpose of increasing the use of utility service and the sales of appliances, shall be considered as a combination advertisement and the costs shall be distributed between this account and Account 416 on the basis of space, time, or other proportional factors.
Exclude from this account and charge to Account 930.2, Miscellaneous General Expenses, the cost of publication of stockholder reports, dividend notices, bond redemption notices, financial statements, and other notices of a general corporate character. Exclude also all institutional or goodwill advertising. (See Account 930.1, General Advertising Expenses.)
This account shall include the cost of labor, materials used and expenses incurred in connection with sales activities, except merchandising, which are not includible in other sales expense accounts.
1. General clerical and stenographic work not assigned to specific functions.
2. Special analysis of customer accounts and other statistical work for sales purposes not a part of the regular customer accounting and billing routine.
3. Miscellaneous labor.
4. Communication service.
5. Printing, postage, and office supplies and expenses applicable to sales activities, except those chargeable to account 913, Advertising Expenses.
This account shall include the cost of labor and expenses incurred for the purpose of promoting the sale of electricity, other than merchandising, jobbing or contract work activities.
1. Advertising.
2. Demonstrating uses of utility service.
3. Home service activities.
4. Solicitation of new business.
A. This account shall include the compensation (salaries, bonuses, and other consideration for services, but not including directors’ fees) of officers, executives, and other employees of the utility properly chargeable to utility operations and not chargeable directly to a particular operating function.
B. This account may be subdivided in accordance with a classification appropriate to the departmental or other functional organization of the utility.
A. This account shall include office supplies and expenses incurred in connection with the general administration of the utility’s operations which are assignable to specific administrative or general departments and are not specifically provided for in other accounts. This includes the expenses of the various administrative and general departments, the salaries and wages of which are includible in account 920.
B. This account may be subdivided in accordance with a classification appropriate to the departmental or other functional organization of the utility.
Office expenses which are clearly applicable to any group of operating expenses other than the administrative and general group shall be included in the appropriate account in such group. Further, general expenses which apply to the utility as a whole rather than to a particular administrative function shall be included in account 930.2, Miscellaneous General Expenses.
1. Automobile service, including charges through clearing account.
2. Bank messenger and service charges.
3. Books, periodicals, bulletins and subscriptions to newspapers, newsletters, tax services, etc.
4. Building service expenses for customer accounts, sales, and administrative and general purposes.
5. Communication service expenses.
6. Cost of individual items of office equipment used by general departments which are of small value or short life.
7. Membership fees and dues in trade, technical, and professional associations paid by a utility for employees. (Company memberships are includible in account 930.2.)
8. Office supplies and expenses.
9. Payment of court costs, witness fees and other expenses of legal department.
10. Postage, printing and stationery.
11. Meals, traveling and incidental expenses.
This account shall be credited with administrative expenses recorded in accounts 920 and 921 which are transferred to construction costs or to nonutility accounts. (See electric plant instruction 4.)
A. This account shall include the fees and expenses of professional consultants and others for general services which are not applicable to a particular operating function or to other accounts. It shall include also the pay and expenses of persons engaged for a special or temporary administrative or general purpose in circumstances where the person so engaged is not considered as an employee of the utility.
B. This account shall be so maintained as to permit ready summarization according to the nature of service and the person furnishing the same.
1. Fees, pay and expenses of accountants and auditors, actuaries, appraisers, attorneys, engineering consultants, management consultants, negotiators, public relations counsel, tax consultants, etc.
2. Supervision fees and expenses paid under contracts for general management services.
Do not include inspection and brokerage fees and commissions chargeable to other accounts or fees and expenses in connection with security issues which are includible in the expenses of issuing securities.
A. This account shall include the cost of insurance or reserve accruals to protect the utility against losses and damages to owned or leased property used in its utility operations. It shall include also the cost of labor and related supplies and expenses incurred in property insurance activities.
B. Recoveries from insurance companies or others for property damages shall be credited to the account charged with the cost of the damage. If the damaged property has been retired, the credit shall be to the appropriate account for accumulated provision for depreciation.
C. Records shall be kept so as to show the amount of coverage for each class of insurance carried, the property covered, and the applicable premiums. Any dividends distributed by mutual insurance companies shall be credited to the accounts to which the insurance premiums were charged.
1. Premiums payable to insurance companies for fire, storm, burglary, boiler explosion, lightning, fidelity, riot, and similar insurance.
2. Amounts credited to account 228.1, Accumulated Provision for Property Insurance, for similar protection.
3. Special costs incurred in procuring insurance.
4. Insurance inspection service.
5. Insurance counsel, brokerage fees, and expenses.
The cost of insurance or reserve accruals capitalized shall be charged to construction either directly or by transfer to construction work orders from this account.
The cost of insurance or reserve accruals for the following classes of property shall be charged as indicated.
(1) Materials and supplies and stores equipment, to account 163, Stores Expense Undistributed (store expenses in the case of Nonmajor utilities), or appropriate materials account.
(2) For Major Utilities, transportation and other general equipment to appropriate clearing accounts that may be maintained. For Nonmajor utilities, transportation and garage equipment, to account 933, Transportation Expenses.
(3) Electric plant leased to others, to account 413, Expenses of Electric Plant Leased to Others.
(4) Nonutility property, to the appropriate nonutility income account.
(5) Merchandise and jobbing property, to Account 416, Costs and Expenses of Merchandising, Jobbing and Contract Work.
The cost of labor and related supplies and expenses of administrative and general employees who are only incidentally engaged in property insurance work may be included in accounts 920 and 921, as appropriate.
A. This account shall include the cost of insurance or reserve accruals to protect the utility against injuries and damages claims of employees or others, losses of such character not covered by insurance, and expenses incurred in settlement of injuries and damages claims. For Major utilities, it shall also include the cost of labor and related supplies and expenses incurred in injuries and damages activities.
B. Reimbursements from insurance companies or others for expenses charged hereto on account of injuries and damages and insurance dividends or refunds shall be credited to this account.
1. Premiums payable to insurance companies for protection against claims from injuries and damages by employees or others, such as public liability, property damages, casualty, employee liability, etc., and amounts credited to account 228.2, Accumulated Provision for Injuries and Damages, for similar protection.
2. Losses not covered by insurance or reserve accruals on account of injuries or deaths to employees or others and damages to the property of others.
3. Fees and expenses of claim investigators.
4. Payment of awards to claimants for court costs and attorneys’ services.
5. Medical and hospital service and expenses for employees as the result of occupational injuries, or resulting from claims of others.
6. Compensation payments under workmen’s compensation laws.
7. Compensation paid while incapacitated as the result of occupational injuries. (See Note A.)
8. Cost of safety, accident prevention and similar educational activities.
Payments to or in behalf of employees for accident or death benefits, hospital expenses, medical supplies or for salaries while incapacitated for service or on leave of absence beyond periods normally allowed, when not the result of occupational injuries, shall be charged to account 926, Employee Pensions and Benefits. (See also Note B of account 926.)
The cost of injuries and damages or reserve accruals capitalized shall be charged to construction directly or by transfer to construction work orders from this account.
Exclude herefrom the time and expenses of employees (except those engaged in injuries and damages activities) spent in attendance at safety and accident prevention educational meetings, if occurring during the regular work period.
The cost of labor and related supplies and expenses of administrative and general employees who are only incidentally engaged in injuries and damages activities may be included in accounts 920 and 921, as appropriate.
A. This account shall include pensions paid to or on behalf of retired employees, or accruals to provide for pensions, or payments for the purchase of annuities for this purpose, when the utility has definitely, by contract, committed itself to a pension plan under which the pension funds are irrevocably devoted to pension purposes, and payments for employee accident, sickness, hospital, and death benefits, or insurance therefor. Include, also, expenses incurred in medical, educational or recreational activities for the benefit of employees, and administrative expenses in connection with employee pensions and benefits.
B. The utility shall maintain a complete record of accruals or payments for pensions and be prepared to furnish full information to the Commission of the plan under which it has created or proposes to create a pension fund and a copy of the declaration of trust or resolution under which the pension plan is established.
C. There shall be credited to this account the portion of pensions and benefits expenses which is applicable to nonutility operations or which is charged to construction unless such amounts are distributed directly to the accounts involved and are not included herein in the first instance.
D. For Major utilities, records in support of this account shall be so kept that the total pensions expense, the total benefits expense, the administrative expenses included herein, and the amounts of pensions and benefits expenses transferred to construction or other accounts will be readily available.
1. Payment of pensions under a nonaccrual or nonfunded basis.
2. Accruals for or payments to pension funds or to insurance companies for pension purposes.
3. Group and life insurance premiums (credit dividends received).
4. Payments for medical and hospital services and expenses of employees when not the result of occupational injuries.
5. Payments for accident, sickness, hospital, and death benefits or insurance.
6. Payments to employees incapacitated for service or on leave of absence beyond periods normally allowed, when not the result of occupational injuries, or in excess of statutory awards.
7. Expenses in connection with educational and recreational activities for the benefit of employees.
The cost of labor and related supplies and expenses of administrative and general employees who are only incidentally engaged in employee pension and benefit activities may be included in accounts 920 and 921, as appropriate.
Salaries paid to employees during periods of nonoccupational sickness may be charged to the appropriate labor account rather than to employee benefits.
A. This account shall include payments to municipal or other governmental authorities, and the cost of materials, supplies and services furnished such authorities without reimbursement in compliance with franchise, ordinance, or similar requirements; provided, however, that the utility may charge to this account at regular tariff rates, instead of cost, utility service furnished without charge under provisions of franchises.
B. When no direct outlay is involved, concurrent credit for such charges shall be made to account 929, Duplicate Charges—Credit.
C. The account shall be maintained so as to readily reflect the amounts of cash outlays, utility service supplied without charge, and other items furnished without charge.
Franchise taxes shall not be charged to this account but to account 408.1, Taxes Other Than Income Taxes, Utility Operating Income.
Any amount paid as initial consideration for a franchise running for more than one year shall be charged to account 302, Franchises and Consents.
A. This account shall include all expenses (except pay of regular employees only incidentally engaged in such work) properly includible in utility operating expenses, incurred by the utility in connection with formal cases before regulatory commissions, or other regulatory bodies, or cases in which such a body is a party, including payments made to a regulatory commission for fees assessed against the utility for pay and expenses of such commission, its officers, agents, and employees, and also including payments made to the United States for the administration of the Federal Power Act.
B. Amounts of regulatory commission expenses which by approval or direction of the Commission are to be spread over future periods shall be charged to account 186, Miscellaneous Deferred Debits, and amortized by charges to this account.
C. The utility shall be prepared to show the cost of each formal case.
1. Salaries, fees, retainers, and expenses of counsel, solicitors, attorneys, accountants, engineers, clerks, attendants, witnesses, and others engaged in the prosecution of, or defense against petitions or complaints presented to regulatory bodies, or in the valuation of property owned or used by the utility in connection with such cases.
2. Office supplies and expenses, payments to public service or other regulatory commissions, stationery and printing, traveling expenses, and other expenses incurred directly in connection with formal cases before regulatory commissions.
Exclude from this account and include in other appropriate operating expense accounts, expenses incurred in the improvement of service, additional inspection, or rendering reports, which are made necessary by the rules and regulations, or orders, of regulatory bodies.
Do not include in this account amounts includible in account 302, Franchises and Consents, account 181, Unamortized Debt Expense, or account 214, Capital Stock Expense.
This account shall include concurrent credits for charges which may be made to operating expenses or to other accounts for the use of utility service from its own supply. Include, also, offsetting credits for any other charges made to operating expenses for which there is no direct money outlay.
This account shall include the cost of labor, materials used, and expenses incurred in advertising and related activities, the cost of which by their content and purpose are not provided for elsewhere.
1. Supervision.
2. Preparing advertising material for newspapers, periodicals, billboards, etc., and preparing or conducting motion pictures, radio and television programs.
3. Preparing booklets, bulletins, etc., used in direct mail advertising.
4. Preparing window and other displays.
5. Clerical and stenographic work.
6. Investigating and employing advertising agencies, selecting media and conducting negotiations in connection with the placement and subject matter of advertising.
7. Advertising in newspapers, periodicals, billboards, radio, etc.
8. Advertising matter such as posters, bulletins, booklets, and related items.
9. Fees and expenses of advertising agencies and commercial artists.
10. Postage and direct mail advertising.
11. Printing of booklets, dodgers, bulletins, etc.
12. Supplies and expenses in preparing advertising materials.
13. Office supplies and expenses.
Properly includible in this account is the cost of advertising activities on a local or national basis of a good will or institutional nature, which is primarily designed to improve the image of the utility or the industry, including advertisements which inform the public concerning matters affecting the company’s operations, such as, the cost of providing service, the company’s efforts to improve the quality of service, the company’s efforts to improve and protect the environment, etc. Entries relating to advertising included in this account shall contain or refer to supporting documents which identify the specific advertising message. If references are used, copies of the advertising message shall be readily available.
Exclude from this account and include in account 426.4, Expenditures for Certain Civic, Political and Related Activities, expenses for advertising activities, which are designed to solicit public support or the support of public officials in matters of a political nature.
This account shall include the cost of labor and expenses incurred in connection with the general management of the utility not provided for elsewhere.
1. Miscellaneous labor not elsewhere provided for.
2. Industry association dues for company memberships.
3. Contributions for conventions and meetings of the industry.
4. For Major utilities, research, development, and demonstration expenses not charged to other operation and maintenance expense accounts on a functional basis.
5. Communication service not chargeable to other accounts.
6. Trustee, registrar, and transfer agent fees and expenses.
7. Stockholders meeting expenses.
8. Dividend and other financial notices.
9. Printing and mailing dividend checks.
10. Directors’ fees and expenses.
11. Publishing and distributing annual reports to stockholders.
12. Public notices of financial, operating and other data required by regulatory statutes, not including, however, notices required in connection with security issues or acquisitions of property. For Nonmajor utilities, transportation and garage equipment, to account 933, Transportation Expenses.
This account shall include rents properly includible in utility operating expenses for the property of others used, occupied, or operated in connection with the customer accounts, customer service and informational, sales, and general and administrative functions of the utility. (See operating expense instruction 3.)
A. This account shall include the cost of labor, materials used and expenses incurred in the operation and maintenance of general transportation equipment of the utility.
B. This account may be used as a clearing account in which event the charges hereto shall be cleared by apportionment to the appropriate operating expense, electric plant, or other accounts on a basis which will distribute the expenses equitably. Credits to this account shall be made in such detail as to permit ready analysis.
1. Supervision.
2. Building service.
3. Care of grounds, including snow removal, cutting grass, etc.
4. Utility services.
5. Depreciation of transportation equipment.
6. Fuel and lubricants for vehicles (including sales and excise taxes thereon).
7. Insurance on garage equipment and transportation equipment, including public liability and property damage.
8. Maintenance of transportation and garage equipment.
9. Compensation of drivers, mechanics, clerks, and other garage employees.
10. Rent of garage buildings and grounds, vehicles or equipment.
11. Replacement of tires, tubes, batteries, etc.
12. Direct taxes, licenses, and permits.
13. Miscellaneous garage supplies, tools, and equipment.
14. Miscellaneous office supplies and expenses, printing, and stationery.
15. Transportation, meals, and incidental expenses.
The pay of employees driving trucks or other transportation equipment incidental to their regular occupation, shall not be included herein but charged directly to the appropriate expense or other account.
Transportation expenses applicable to construction shall not be included in operating expenses.
A. This account shall include the cost assignable to customer accounts, sales and administrative and general functions of labor, materials used and expenses incurred in the maintenance of property, the book cost of which is includible in account 390, Structures and Improvements, account 391, Office Furniture and Equipment, account 397, Communication Equipment, and account 398 Miscellaneous Equipment. For Nonmajor utilities, include also other general equipment accounts (not including transportation equipment). (See operating expense instruction 2.)
B. Maintenance expenses on office furniture and equipment used elsewhere than in general, commercial and sales offices shall be charged to the following accounts:
Steam Power Generation, Account 514.
Nuclear Power Generation, Account 532 (Major only).
Hydraulic Power Generation, Account 545.
Other Power Generation, Account 554.
Transmission, Account 573.
Distribution, Account 598.
Merchandise and Jobbing, Account 416.
Garages, Shops, etc., Appropriate clearing account, if used.
Maintenance of plant included in other general equipment accounts shall be included herein unless charged to clearing accounts or to the particular functional maintenance expense account indicated by the use of the equipment.
PART 104—RESERVED [NOTE]
For the Uniform System of Accounts for all Public Utilities, see part 101 of this subchapter.
PART 125—PRESERVATION OF RECORDS OF PUBLIC UTILITIES AND LICENSEES
§ 125.1 Promulgation.
This Part is prescribed and promulgated as the regulations governing the preservation of records by public utilities subject to the jurisdiction of the Commission and by licensees holding licenses issued by the Commission, to the extent and in the manner set forth therein.
§ 125.2 General instructions.
(a) Scope of this part. (1) The regulations in this part apply to all books of account and other records prepared by or on behalf of the public utility or licensee. See item 40 of the schedule (§ 125.3) for those records that come into possession of the public utility or licensee in connection with the acquisition of property, such as purchase, consolidation, merger, etc.
(2) The regulations in this part should not be construed as excusing compliance with other lawful requirements of any other governmental body, Federal or State, prescribing other record keeping requirements or for preservation of records longer than those prescribed in this part.
(3) To the extent that any Commission regulations may provide for a different retention period, the records should be retained for the longer of the retention periods.
(4) Records other than those listed in the schedule may be destroyed at the option of the public utility or licensee: Provided, however, That records which are used in lieu of those listed shall be preserved for the periods prescribed for the records used for substantially similar purposes. And, provided further, That retention of records pertaining to added services, functions, plant, etc., the establishment of which cannot be presently foreseen, shall conform to the principles embodied herein.
(5) Notwithstanding the provisions of the Records Retention Schedule, the Commission may, upon the request of the Company, authorize a shorter period of retention for any record listed therein upon a showing by the Company that preservation of such record for a longer period is not necessary or appropriate in the public interest or for the protection of investors or consumers.
(b) Designation of supervisory official. Each public utility or licensee subject to the regulations in this part shall designate one or more persons with official responsibility to supervise the utility’s or licensee’s program for preservation and the authorized destruction of its records.
(c) Protection and storage of records. The public utility or licensee shall provide reasonable protection for records subject to the regulations in this part from damage by fire, floods, and other hazards and, in the selection of storage spaces, safeguards the records from unnecessary exposure to deterioration from excessive humidity, dryness, or lack of proper ventilation.
(d) Record storage media. Each public utility and licensee has the flexibility to select its own storage media subject to the following conditions.
(1) The storage media must have a life expectancy at least equal to the applicable record retention period provided in § 125.3 unless there is a quality transfer from one media to another with no loss of data.
(2) Each public utility and licensee is required to implement internal control procedures that assure the reliability of, and ready access to, data stored on machine readable media. Internal control procedures must be documented by a responsible supervisory official.
(3) Each transfer of data from one media to another must be verified for accuracy and documented. Software and hardware required to produce readable records must be retained for the same period the media format is used.
(e) Destruction of records. At the expiration of the retention period, public utilities and licensees may use any appropriate method to destroy records.
(f) Premature destruction or loss of records. When records are destroyed or lost before the expiration of the prescribed period of retention, a certified statement listing, as far as may be determined, the records destroyed and describing the circumstances of accidental or other premature destruction or loss must be filed with the Commission within ninety (90) days from the date of discovery of the destruction.
(g) Schedule of records and periods of retention. (1) Records related to plant in service must be retained until the facilities are permanently removed from utility service, all removal and restoration activities are completed, and all costs are retired from the accounting records unless accounting adjustments resulting from reclassification and original costs studies have been approved by the regulatory commission having jurisdiction. If the plant is sold, the associated records or copies thereof, must be transferred to the new owners.
(2) Records related to hydroelectric facilities and additions, retirements, and betterments thereto must be retained until:
(i) The Commission has determined the actual legitimate original cost of the facilities, or the licenses are surrendered. If the plant is sold, the associated records or copies thereof, must be transferred to the new owners.
(ii) Records related to the determination of amortization reserves pursuant to section 10(d) of the Federal Power Act must be retained until a final determination and adjudication of the amortization reserves are made.
(h) Retention periods designated “Destroy at option”. “Destroy at option” constitutes authorization for destruction of records at managements’ discretion if it does not conflict with other legal retention requirements or usefulness of such records in satisfying pending regulatory actions or directives.
(i) Records of services performed by associated companies. Public utilities and licensees must assure the availability of records of services performed by and for associated or affiliated companies with supporting cost information for the periods indicated in § 125.3 as necessary to be able to readily furnish detailed information as to the nature of the transaction, the amounts involved, and the accounts used to record the transactions.
(j) Index of records. Public utilities and licensees must arrange, file, and index records so records may be readily identified and made available to Commission representatives.
(k) Rate case. Notwithstanding the minimum retention periods provided in these regulations, if a public utility or licensee wants to reflect costs in a current, future, or pending rate case, or if a public utility or licensee has abandoned or retired a plant subsequent to the test period of the utility’s rate case, the utility must retain the appropriate records to support the costs and adjustments proposed in the current or next rate case.
(l) Pending complaint litigation or governmental proceedings. Notwithstanding the minimum requirements, if a public utility or licensee is involved in pending litigation, complaint procedures, proceedings remanded by the court, or governmental proceedings, it must retain all relevant records.
(m) Life or mortality study data. Life or mortality study data for depreciation purposes must be retained for 25 years or for 10 years after plant is retired, whichever is longer.
§ 125.3 Schedule of records and periods of retention.
Schedule of Records and Periods of Retention
| Item No. and description | Retention period |
|---|---|
| 1. Reports to stockholders: Annual reports or statements to stockholders | 5 years. |
| 2. Organizational documents: | |
| (a) Minute books of stockholders’, directors’, and directors’ committee meetings | 5 years or termination of the corporation’s existence, whichever occurs first. |
| (b) Titles, franchises, and licenses: Copies of formal orders of regulatory commissions served upon the utility | 6 years after final non-appealable order. |
| 3. Contracts, including amendments and agreements (except contracts provided for elsewhere): | |
| (a) Service contracts, such as for management, accounting, and financial services | All contracts, related memoranda, and revisions should be retained for 4 years after expiration or until the conclusion of any contract disputes pertaining to such contracts, whichever is later. |
| (b) Contracts with others for transmission or the purchase, sale or interchange of product | All contracts, related memoranda, and revisions should be retained for 4 years after expiration or until the conclusion of any contract disputes or governmental proceedings pertaining to such contracts, whichever is later. |
| (c) Memoranda essential to clarifying or explaining provisions of contracts listed above, including requests for discounts | For the same periods as contracts to which they relate. |
| (d) Card or book records of contracts, leases, and agreements made, showing dates of expirations and of renewals, memoranda of receipts, and payments under such contracts | For the same periods as contracts to which they relate. |
| 4. Accountants’ and auditors’ reports: | |
| (a) Reports of examinations and audits by accountants and auditors not in the regular employ of the utility (such as reports of public accounting firms and commission accountants) | 5 years after the date of the report. |
| (b) Internal audit reports and working papers | 5 years after the date of the report. |
| 5. Automatic data processing records (retain original source data used as input for data processing and data processing report printouts for the applicable periods prescribed elsewhere in the schedule): Software program documentation and revisions thereto | Retain as long as it represents an active viable program or for periods prescribed for related output data, whichever is shorter. |
| 6. General and subsidiary ledgers: | |
| (a) Ledgers: | |
| (1) General ledgers | 10 years. |
| (2) Ledgers subsidiary or auxiliary to general ledgers except ledgers provided for elsewhere | 10 years. |
| (b) Indexes: | |
| (1) Indexes to general ledgers | 10 years. |
| (2) Indexes to subsidiary ledgers except ledgers provided for elsewhere | 10 years. |
| (c) Trial balance sheets of general and subsidiary ledgers | 2 years. |
| 7. Journals: General and subsidiary | 10 years. |
| 8. Journal vouchers and journal entries including supporting detail: | |
| (a) Journal vouchers and journal entries | 10 years. |
| (b) Analyses, summarization, distributions, and other computations which support journal vouchers and journal entries: | |
| (1) Charging plant accounts | 25 years. See § 125.2(g). |
| (2) Charging all other accounts | 6 years. |
| 9. Cash books: General and subsidiary or auxiliary books | 5 years after close of fiscal year. |
| 10. Voucher registers: Voucher registers or similar records when used as a source document | 5 years. See § 125.2(g). |
| 11. Vouchers: | |
| (a) Paid and canceled vouchers (one copy-analysis sheets showing detailed distribution of charges on individual vouchers and other supporting papers) | 5 years. See § 125.2(g). |
| (b) Original bills and invoices for materials, services, etc., paid by vouchers | 5 years. See § 125.2(g). |
| (c) Paid checks and receipts for payments of specific vouchers | 5 years. |
| (d) Authorization for the payment of specific vouchers | 5 years. See § 125.2(g). |
| (e) Lists of unaudited bills (accounts payable), list of vouchers transmitted, and memoranda regarding changes in audited bills | Destroy at option. |
| (f) Voucher indexes | Destroy at option. |
| 12. Insurance records: | |
| (a) Records of insurance policies in force, showing coverage, premiums paid, and expiration dates | Destroy at option after expiration of such policies. |
| (b) Records of amounts recovered from insurance companies in connection with losses and of claims against insurance companies, including reports of losses, and supporting papers | 6 years. See § 125.2(g). |
| 13.1 Production—Public utilities and licensees (less Nuclear): | |
| (a) Boiler-tube failure report | 3 years. |
| (b) Generation and output logs with supporting data: | 3 years. |
| (c) Station and system generation reports and clearance logs: | |
| (1) Hydro-electric | 25 years. See § 125.2(g). |
| (2) Steam and others | 6 years. See § 125.2(g). |
| (d) Generating high-tension and low-tension load records | 3 years. |
| (e) Load curves, temperature logs, coal, and water logs | 3 years. |
| (f) Gauge-reading reports | 2 years, except river flow data collected in connection with hydro operation must be retained for life of corporation. |
| (g) Recording instrumentation charts | 1 year, except where the basic chart information is transferred to another record, the charts need only be retained 6 months provided the record containing the basic data is retained 1 year. |
| 13.2 Production—Nuclear: | |
| For informational purposes, refer to the document retention requirements of the Nuclear Regulatory Commission. | |
| 14. Transmission and distribution—Public utilities and licensees. | |
| (a) Substation and transmission line logs | 3 years. |
| (b) System operator’s daily logs and reports of operation | 3 years. |
| (c) Transformer history records | For life of transformer. |
| (d) Records of transformer inspections, oil tests, etc. | Destroy at option. |
| 15. Maintenance work orders and job orders: | |
| (a) Authorizations for expenditures for maintenance work to be covered by work orders, including memoranda showing the estimates of costs to be incurred | 5 years. |
| (b) Work order sheets to which are posted in detail the entries for labor, material, and other charges in connection with maintenance, and other work pertaining to utility operations | 5 years. |
| (c) Summaries of expenditures on maintenance and job orders and clearances to operating other accounts (exclusive of plant accounts) | 5 years. |
| 16. Plant ledgers: | |
| (a) Ledgers of utility plant accounts including land and other detailed ledgers showing the cost of utility plant by classes | 25 years. See § 125.2(g). |
| (b) Continuing plant inventory ledger, book or card records showing description, location, quantities, cost, etc., of physical units (or items) of utility plant owned | 25 years. See § 125.2(g). |
| 17. Construction work in progress ledgers, work orders, and supplemental records: | |
| (a) Construction work in progress ledgers | 5 years after clearance to plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired. |
| (b) Work orders sheets to which are posted in summary form or in detail the entries for labor, materials, and other charges for utility plant additions and the entries closing the work orders to utility plant in service at completion | 5 years after clearance to plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired. |
| (c) Authorizations for expenditures for additions to utility plant, including memoranda showing the detailed estimates of cost, and the bases therefor (including original and revised or subsequent authorizations) | 5 years after clearance to plant account except where there are ongoing Commission proceedings. |
| (d) Requisitions and registers of authorizations for utility plant expenditures | 5 years after clearance to plant account except where there are ongoing Commission proceedings. |
| (e) Completion or performance reports showing comparison between authorized estimates and actual expenditures for utility plant additions | 5 years after clearance to plant account except where there are ongoing Commission proceedings. |
| (f) Analysis or cost reports showing quantities of materials used, unit costs, number of man-hours etc., in connection with completed construction project | 5 years after clearance to plant account except where there are ongoing Commission proceedings. |
| (g) Records and reports pertaining to progress of construction work, the order in which jobs are to be completed, and similar records which do not form a basis of entries to the accounts | Destroy at option. |
| 18. Retirement work in progress ledgers, work orders, and supplemental records: | |
| (a) Work order sheets to which are posted the entries for removal costs, materials recovered, and credits to utility plant accounts for cost of plant retirement | 5 years after plant is retired. |
| (b) Authorizations for retirement of utility plant, including memoranda showing the basis for determination to be retired and estimates of salvage and removal costs | 5 years after plant is retired. |
| (c) Registers of retirement work | 5 years. |
| 19. Summary sheets, distribution sheets, reports, statements, and papers directly supporting debits and credits to utility plant accounts not covered by construction or retirement work orders and their supporting records | 5 years. |
| 20. Appraisals and valuations: | |
| (a) Appraisals and valuations made by the company of its properties or investments or of the properties or investments of any associated companies. (Includes all records essential thereto.) | 3 years after appraisal. |
| (b) Determinations of amounts by which properties or investments of the company or any of its associated companies will be either written up or written down as a result of: | |
| (1) Mergers or acquisitions | 10 years after completion of transaction or as ordered by the Commission. |
| (2) Asset impairments | 10 years after recognition of asset impairment. |
| (3) Other bases | 10 years after the asset was written up or down. |
| 21. The original or reproduction of engineering records, drawings, and other supporting data for proposed or as-constructed utility facilities: Maps, diagrams, profiles, photographs, field survey notes, plot plan, detail drawings, records of engineering studies, and similar records showing the location of proposed or as-constructed facilities | Retain until retired. |
| 22. Contracts relating to utility plant: | |
| (a) Contracts relating to acquisition or sale of plant | 6 years after plant is retired or sold. |
| (b) Contracts and other agreements relating to services performed in connection with construction of utility plant (including contracts for the construction of plant by others for the utility and for supervision and engineering relating to construction work) | 6 years after plant is retired or sold. |
| 23. Records pertaining to reclassification of utility plant accounts to conform to prescribed systems of accounts including supporting papers showing the bases for such reclassifications | 6 years. |
| 24. Records of accumulated provisions for depreciation and depletion of utility plant and supporting computation of expense: | |
| (a) Detailed records or analysis sheets segregating the accumulated depreciation according to functional classification of plant | 25 years. |
| (b) Records reflecting the service life of property and the percentage of salvage and cost of removal for property retired from each account for depreciable utility plant | 25 years. |
| 25. Procurement: | |
| (a) Agreements entered into for the acquisition of goods or the performance of services. Includes all forms of agreements not specifically set forth in Subsection 7 such as but not limited to: Letters of intent, exchange of correspondence, master agreements, term contracts, rental agreements, and the various types of purchase orders: | |
| (1) For goods or services relating to plant construction | 6 years. See § 125.2(g). |
| (2) For other goods or services | 6 years. |
| (b) Supporting documents including accepted and unaccepted bids or proposals (summaries of unaccepted bids or proposals may be kept in lieu of originals) evidencing all relevant elements of the procurement | 6 years. See § 125.2(g). |
| 26. Material ledgers: Ledger sheets of materials and supplies received, issued, and on hand | 6 years after the date the records/ledgers were created. |
| 27. Materials and supplies received and issued: Records showing the detailed distribution of materials and supplies issued during accounting periods | 6 years. See § 125.2(g). |
| 28. Records of sales of scrap and materials and supplies: | |
| (a) Authorization for sale of scrap and materials and supplies | 3 years. |
| (b) Contracts for sale of scrap materials and supplies | 3 years. |
| 29. Customers’ service applications and contracts: Contracts, including amendments for extensions of service, for which contributions are made by customers and others | 4 years after expiration. |
| 30. Rate schedules: General files of published rate sheets and schedules of utility service. Including schedules suspended or superseded | 6 years after published rate sheets and schedules are superseded or no longer used to charge for utility service. |
| 31. Maximum demand, and demand meter record cards | 1 year, except where the basic chart information is transferred to another record the charts need only be retained 6 months, provided the basic data is retained 1 year. |
| 32. Miscellaneous billing data: Billing department’s copies of contracts with customers (other than contracts in general files) | Destroy at option. |
| 33. Revenue summaries: Summaries of monthly operating revenues according to classes of service. Including summaries of forfeited discounts and penalties | 5 years. |
| 34. Tax records: | |
| (a) Copies of tax returns and supporting schedules filed with taxing authorities, supporting working papers, records of appeals of tax bills, and receipts for payment. See Subsection 11(b) for vouchers evidencing disbursements: | |
| (1) Income tax returns | 2 years after final tax liability is determined. |
| (2) Property tax returns | 2 years after final tax liability is determined. |
| (3) Sales and other use taxes | 2 years. |
| (4) Other taxes | 2 years after final tax liability is determined. |
| (5) Agreements between associate companies as to allocation of consolidated income taxes | 2 years after final tax liability is determined. |
| (6) Schedule of allocation of consolidated Federal income taxes among associate companies | 2 years after final tax liability is determined. |
| (b) Filings with taxing authorities to qualify employee benefit plans | 5 years after discontinuance of plan. |
| (c) Information returns and reports to taxing authorities | 3 years after final tax liability is determined. |
| 35. Statements of funds and deposits | For nuclear decommissioning funds, retain records for all items listed for 3 years after final decommissioning is completed. If amortization reserve funds related to licensed projects are maintained, retain until the Commission makes a final determination of the disposition of amortization reserves. |
| (a) Statements of periodic deposits with fund administrators or trustees | Retain records for the most recent 3 years. |
| (b) Statements of periodic withdrawals from fund | Retain records for the most recent 3 years. |
| (c) Statements prepared by fund administrator or trustees of fund activity including: | Retain records until the fund is dissolved or terminated. |
| (1) Beginning of the year balance of fund; | |
| (2) Deposits with the fund; | |
| (3) Acquisition of investments held by the fund; | |
| (4) Disposition of investments held by the fund; | |
| (5) Disbursements from the fund, including party to whom disbursement was made; | |
| (6) End of year balance of fund. | |
| 36. Records of deposits with banks and others: | |
| (a) Statements from depositories showing the details of funds received, disbursed, transferred, and balances on deposit | Destroy at option after completion of audit by independent accountants. |
| (b) Check stubs, registers, or other records of checks issued | 3 years. |
| 37. [Reserved] | |
| 38. Statistics: Financial, operating and statistical reports used for internal administrative or operating purposes | 5 years. |
| 39. Budgets and other forecasts (prepared for internal administrative or operating purposes) of estimated future income, receipts and expenditures in connection with financing, construction and operations, including acquisitions and disposals of properties or investments | 3 years. |
| 40. Records of predecessor companies | Retain consistent with the requirements for the same types of records of the utility. |
| 41. Reports to Federal and State regulatory commissions including annual financial, operating and statistical reports | 5 years. |
| 42. Advertising: Copies of advertisements by or for the company on behalf of itself or any associate company in newspapers, magazines, and other publications, including costs and other records relevant thereto (excluding advertising of appliances, employment opportunities, routine notices, and invitations for bids all of which may be destroyed at option) | 2 years. |
SUBCHAPTER D—APPROVED FORMS, FEDERAL POWER ACT AND PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978
PART 131—FORMS
§ 131.20 Application for approval of transfer of license.
(See §§ 9.1 through 9.10 of this chapter.)
(1)__________________, licensee under the license for Project No. ______, issued by the Commission on __________________ (Month, day, year) and
(2) __________________, (hereinafter referred to as the Transferee).
(3) Hereby jointly and severally apply for the written approval by the Federal Energy Regulatory Commission of the transfer of the aforesaid license from the transferor to the transferee and request that the instrument of such approval by the Commission be made effective as of the date of conveyance of the project properties; and in support thereof show the Commission as follows:
(4) The said transferee is:
(a)
(b)
(c)
(d)
(5) The transferee submits as [partial] evidence of its compliance with all applicable State laws as required by section 9(a)(2) of the Federal Power Act __________________ submitted herewith as exhibits B–1, B–2, etc., and proposes to complete its showing of such compliance by submitting ____________
(6) The transferee will submit certified copies of all instruments of conveyance whereby title to the project properties is conveyed to it, upon the completion of such conveyance, if and when the Commission shall have given its approval to the proposed transfer;
(7) If and when the Commission shall have given its approval to the proposed transfer, and upon completion of conveyance of the project properties to the transferee, the transferor will deliver to the transferee and the transferee will accept and permanently retain all license instruments and all maps, plans, specifications, contracts, reports of engineers, accounts, books, records, and all other papers and documents relating to the original project and to all additions thereto and betterments thereof;
(8) The transferor certifies that it has fully complied with the terms and conditions of its license, as amended, and that it has fully satisfied and discharged all of its liabilities and obligations thereunder to the date hereof, and obligates itself to pay all annual charges accrued under the license to the date of transfer;
(9) Contingent upon the final written approval by the Commission of the transfer of the license, the transferee accepts all the terms and conditions of the said license [as amended] and the act, and agrees to be bound thereby to the same extent as though it were the original licensee thereunder;
(10) The name, title, and post-office address of the person or persons to whom correspondence in regard to this application shall be addressed are as follows:
In witness whereof the transferor has caused its name to be hereunto signed by ________________________ (Name), its ________________________ (Title—chief executive officer), and its corporate seal to be hereunto affixed by ________________________ (Name), its ________________________ (Title—custodian of seal), thereunto duly authorized, this ________________ day of ________________, 19____; and the transferee has caused its name to be hereunto signed by __________________ (Name), its __________________ (Title—chief executive officer), and its corporate seal to be hereunto affixed by __________________ (Name), its __________________ (Title—custodian of seal), thereunto duly authorized this ______________ day of ________________, 19____.
Subscribed and sworn to before me, a notary public of the State of ______________ this ______________ day of ______________, 19____.
____________________, ____________________ and ____________________, being duly sworn, each for himself, deposes and says that he is a citizen of the United States of America.
Subscribed and sworn to before me, a notary public of the State of ______________ this ______________ day of ______________, 19____.
§ 131.31 FERC Form No. 561, Annual report of interlocking positions.
(See section 46.4 of this chapter.)
1. Prepare this report in conformity with the requirements prescribed in 18 CFR 46.4.
2. Leave blank any columns that are not applicable.
§ 131.43 Report of securities issued.
(See § 34.10 of this chapter.)
(Submit an original and four copies.)
Report of Securities Issued
Description of security………………………………
| Description | Amount |
|---|---|
| 1. Face value or principal amount | |
| 2. Plus premium or less discount | |
| 3. Gross proceeds | |
| 4. Underwriter’s spread or commission | |
| 5. Securities and Exchange Commission registration fee | |
| 6. State mortgage registration tax | |
| 7. State commission fee | |
| 8. Fee for recording indenture | |
| 9. United States document tax | |
| 10. Printing and engraving expenses | |
| 11. Trustee’s charges | |
| 12. Counsel fees | |
| 13. Accountant’s fees | |
| 14. Cost of listing | |
| 15. Miscellaneous expenses of issue | |
| (Describe large items) | |
| 16. Total deductions | |
| 17. Net amount realized |
§ 131.43 Report of securities issued.
(See § 34.10 of this chapter)
(Submit in electronic format in accordance with § 385.2003 of this chapter.)
§ 131.50 Reports of proposals received.
No later than 30 days after the sale or placement of long-term debt or equity securities or the entry into guarantees or assumptions of liabilities (collectively referred to as “placement”) pursuant to authority granted under Part 34 of this chapter, the applicant must file a summary of each proposal or proposals received for the placement. The proposal or proposals accepted must be indicated. The information to be filed must include:
(a) Par or stated value of securities;
(b) Number of units (shares of stock, number of bonds) issued;
(c) Total dollar value of the issue;
(d) Life of the securities, including maximum life and average life of sinking fund issue;
(e) Dividend or interest rate;
(f) Call provisions;
(g) Sinking fund provisions;
(h) Offering price;
(i) Discount or premium;
(j) Commission or underwriter’s spread;
(k) Net proceeds to company for each unit of security and for the total issue;
(l) Net cost to the company for securities with a stated interest or dividend rate.
§ 131.50 Report of proposals received.
(a) No later than 30 days after the sale or placement of long-term debt or equity securities or the entry into guarantees or assumptions of liabilities (collectively referred to as “placement”) pursuant to authority granted under Part 34 of this chapter, the applicant must file, in electronic format, a summary of each proposal or proposals received for the placement. The proposal or proposals accepted must be indicated. The information to be filed must include:
(1) Par or stated value of securities;
(2) Number of units (shares of stock, number of bonds) issued;
(3) Total dollar value of the issue;
(4) Life of the securities, including maximum life and average life of sinking fund issue;
(5) Dividend or interest rate;
(6) Call provisions;
(7) Sinking fund provisions;
(8) Offering price;
(9) Discount or premium;
(10) Commission or underwriter’s spread;
(11) Net proceeds to company for each unit of security and for the total issue;
(12) Net cost to the company for securities with a stated interest or dividend rate.
(b) This report must be filed with the Commission as prescribed in § 385.2003 of this chapter and as indicated in the instructions set out in this report. This report is an electronic file that is classified as a “qualified document” in accordance with § 385.2003(c)(1) and (2). As a qualified document, no paper copy version of the filing is required unless there is a request for privileged or protected treatment or the document is combined with another document as provided in § 385.2003(c)(3) or (4).
§ 131.51 [Reserved]
§ 131.52 Certificate of concurrence.
(See §§ 35.1 through 35.21 of this chapter.)
This is to certify that__________________
Dated __________________ 19____.
§ 131.53 [Reserved]
§ 131.70 Form
12
(See § 11.6 of this chapter.) Application by State and municipal licensees for exemption from payment of annual charges must be prepared on this form. The form specifies that in filing application for exemption, the following data and schedules shall be submitted:
1. Name and address of correspondent;
2. Basis for claimed exemption;
3. Generating plants owned or operated by licensee;
4. Transmission lines and distribution lines;
5. KWH of power generated, purchased and interchanged;
6. Power sold or otherwise disposed of (kwh);
7. Power interchange (in detail);
8. Statement of unusual conditions attending the disposition of electric power;
9. Book cost of electric property;
10. Operating revenues;
11. Operating expenses and other deductions from revenues;
12. Affidavit.
§ 131.80 FERC Form No. 556, Certification of qualifying facility (QF) status for a small power production or cogeneration facility.
(a) Who must file. Any person seeking to certify a facility as a qualifying facility pursuant to sections 3(17) or 3(18) of the Federal Power Act, 16 U.S.C. 796(3)(17), (3)(18), unless otherwise exempted or granted a waiver by Commission rule or order pursuant to § 292.203(d), must complete and file the Form of Certification of Qualifying Facility (QF) Status for a Small Power Production or Cogeneration Facility, FERC Form No. 556. Every Form of Certification of Qualifying Status must be submitted on the FERC Form No. 556 then in effect and must be prepared in accordance with the instructions incorporated in that form.
(b) Availability of FERC Form No. 556. The currently effective FERC Form No. 556 shall be made available for download from the Commission’s Web site.
(c) How to file a FERC Form No. 556. All applicants must file their FERC Forms No. 556 electronically via the Commission’s eFiling Web site.
PART 141—STATEMENTS AND REPORTS (SCHEDULES)
§ 141.1 FERC Form No. 1, Annual report of Major electric utilities, licensees and others.
(a) Prescription. The Form of Annual Report for Major electric utilities, licensees and others, designated herein as FERC Form No. 1, is prescribed for the reporting year 1981 and each year thereafter.
(b) Filing requirements—(1) Who must file—(i) Generally. Each Major and each Nonoperating (formerly designated as Major) electric utility (as defined in part 101 of Subchapter C of this chapter) and each licensee as defined in section 3 of the Federal Power Act (16 U.S.C. 796), including any agency, authority or other legal entity or instrumentality engaged in generation, transmission, distribution, or sale of electric energy, however produced, throughout the United States and its possessions, having sales or transmission service equal to Major as defined above, must prepare and file electronically with the Commission the FERC Form 1 pursuant to the General Instructions as provided in that form.
(ii) Exceptions. This report form is not prescribed for any agency, authority or instrumentality of the United States, nor is it prescribed for municipalities as defined in section 3 of the Federal Power Act; (i.e., a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the laws thereof to carry on the business of developing, transmitting, utilizing, or distributing power).
(2) When to file and what to file. (i) The annual report for the year ending December 31, 2004, must be filed on April 25, 2005.
(ii) The annual report for each year thereafter must be filed on April 18.
(iii) This report must be filed with the Federal Energy Regulatory Commission as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in this form, and must be properly completed and verified. Filing on electronic media pursuant to § 385.2011 of this chapter is required.
§ 141.2 FERC Form No. 1–F, Annual report for Nonmajor public utilities and licensees.
(a) Prescription. The form of Annual Report for Nonmajor Public Utilities and Licensees, designated herein as FERC Form No. 1–F, is prescribed for the year 1980 and each year thereafter.
(b) Filing Requirements—(1) Who Must File—(i) Generally. Each Nonmajor and each Nonoperating (formerly designated as Nonmajor) public utility and licensee as defined in Part 101 of this chapter, shall prepare and file with the Commission FERC Form No. 1–F as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in this form, and must be properly completed and verified. Filing on electronic media pursuant to § 385.2011 of this chapter is required.
(ii) Exceptions. FERC Form No. 1–F is not prescribed for any municipality as defined in Section 3 of the Federal Power Act, i.e., a city, county, irrigation district, drainage district, or other political subdivision or agency of a State competent under the laws thereof to carry on the business of developing, transmitting, utilizing, or distributing power.
(2) When to file. (i) The annual report for the year ending December 31, 2004, must be filed on April 25, 2005.
(ii) The annual report for each year thereafter must be filed on April 18.
§ 141.15 Annual Conveyance Report.
If a licensee of a hydropower project is required by its license to file with the Commission an annual report of conveyances of easements or rights-of-way across, or leases of, project lands, the report must be filed only if such a conveyance or lease of project lands has occurred in the previous year.
§ 141.51 FERC Form No. 714, Annual Electric Balancing Authority Area and Planning Area Report.
(a) Who must file. (1) Any electric utility, as defined by section 3(4) of the Public Utility Regulatory Policies Act, 16 U.S.C. 2602, operating a balancing authority area, and any group of electric utilities, which by way of contractual arrangements operates as a single balancing authority area, must complete and file the applicable schedules in FERC Form No. 714 with the Federal Energy Regulatory Commission.
(2) Any electric utility, or group of electric utilities that constitutes a planning area and that has a peak load greater than 200 megawatts (MW) based on net energy for load for the reporting year, must complete applicable schedules in FERC Form No. 714.
(b) When to file. FERC Form No. 714 must be filed on or before each June 1 for the preceding calendar year.
(c) What to file. FERC Form No. 714, Annual Electric Balancing Authority Area and Planning Area Report, must be filed with the Federal Energy Regulatory Commission as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in this form.
§ 141.61 [Reserved]
§ 141.100 Original cost statement of utility property.
Any public utility or licensee becoming subject to the jurisdiction of the Commission shall file, insofar as applicable, the following statements properly sworn to by the officer in responsible charge of their compilation:
Statement A showing in outline the origin and development of the company including particularly a description (giving names of parties and dates) of each consolidation and merger to which the company, or a predecessor, was a party and each acquisition of an electric operating unit or system.
Statement B showing for each acquisition by the reporting company or any of its predecessors of an electric operating unit or system, the original cost, estimated, if not known, the cost of such company and the amount entered in the books in respect thereto as of the date of acquisition. If the depreciation, retirement, or amortization reserve was adjusted as of the date of acquisition and in connection therewith, a full disclosure of the pertinent facts should be made. The difference between the original cost and the amount entered in respect thereto of each acquisition of an electric operating unit or system, as of the date of acquisition, should be clearly stated, and a summary of all transactions affecting such difference through the end of the calendar year prior to the year in which the filing is made, and the resultant amount at the latter date, should be set forth. The amount to be included in account 114, Electric Plant Acquisition Adjustments, shall be subdivided so as to show the amounts applicable to (1) electric plant in service, (2) electric plant leased to others, and (3) electric plant held for future use. Whenever practical, such amount shall be classified according to nature, i.e., going value, structural value, etc.
Where estimates are used in arriving at original cost or the amount to be included in account 114, a full disclosure of the method and underlying facts should be given. The method of determining the original cost of the electric plant acquired as operating units or systems should be described in sufficient detail to permit a clear understanding of the nature of the investigations which were made for that purpose.
Statement C showing any amounts arrived at by appraisals in the electric plant accounts (and not eliminated) in lieu of cost to the reporting company. This statement should give the full journal entry at the time the appraisal was originally recorded and if the entry had the effect of appreciating or writing up the electric plant account, the amount of the appreciation of writeup should be traced, by proper description and explanation of changes, from the date recorded through the end of the calendar year prior to the year in which the filing is made.
Statement D showing electric plant as classified in the books of account immediately prior to reclassification in accordance with the Uniform System of Accounts, including, under a descriptive heading, any unclassified amounts applicable jointly to the electric department and other departments of the utility.
Statement E showing summary of adjustments necessary to state accounts 101, 103–107, 114, and 116, as prescribed in the Uniform System of Accounts.
Statement F showing electric plant classified according to the accounts prescribed in the Uniform System of Accounts, and showing also the amount includible in account 116, Other Electric Plant Adjustments.
Statement G giving a comparative balance sheet showing the accounts and amounts appearing in the books before the adjusting entries have been made and after such entries shall have been made.
Statement H giving a suggested plan for depreciating, amortizing, or otherwise disposing in whole or in part of the amounts includible in account 114, Electric Plant Acquisition Adjustments, and account 116, Other Electric Plant Adjustments.
Statement I giving the following statistical information relative to electric plant.
Steam production. Separately for each steam plant: Name of plant, date of construction, nameplate generating capacity (kw.) as originally constructed and as at present, also nameplate capacity and date of installation of each addition to generating capacity. The original cost, where available, by accounts 310 and 316, of each steam production plant.
Hydraulic production. Separately for each hydroplant: Name of plant, date of construction, capacity of reservoirs (acre-feet), nameplate generating capacity (kw.) as originally constructed and as at present, also nameplate capacity and date of installation of each addition to generating capacity. The original cost, where available, by accounts 330 and 336, of each hydraulic production plant.
Internal combustion engine production. For each internal combustion engine plant: Name of plant, date of construction, nameplate generating capacity (kw.) as originally constructed and as at present, also nameplate capacity and date of installation of each addition to generating capacity. The original cost, where available, by accounts 340 to 346, of each internal combustion engine production plant.
Overhead transmission lines. For each overhead transmission line or for each group of transmission lines of the same voltage, same general type of construction, and same number of circuits per structure; the voltage, length in miles, type of construction, kind and size of conductor. The original cost, where available, by accounts 350, 352, 354, 355, 356, and 359, of each such line or group of lines.
Underground transmission lines. For each underground transmission line or for each group of transmission lines of the same voltage, same general type of construction and same number of circuits per structure: The voltage length in miles and type of construction. The original cost, where available, by accounts 350, 352, 357, 358, and 359, of each such line or group of lines.
Transmission substations. For each substation: Function, capacity (kva), high and low voltages of transformers, description and capacity of special items of equipment.
Overhead system.
Underground system.
Distribution substation. General description of number, capacity (kva) and high and low voltages of transformers.
Line transformers. Number and capacity.
Street lighting and signal systems. Description and number of each type of street lighting standard, number and wattage of lamps, and description of signal system.
Description of principal structures and improvements.
Number and type of transportation vehicles and appurtenant equipment.
Description of store, shop, and laboratory equipment.
Description of communication equipment.
Description of miscellaneous equipment.
§ 141.300 FERC Form No. 715, Annual Transmission Planning and Evaluation Report.
(a) Who must file. Any transmitting utility, as defined in § 3(23) of the Federal Power Act, that operates integrated (that is, non-radial) transmission facilities at or above 100 kilovolts must complete FERC Form No. 715.
(b) When to file. FERC Form No. 715 must be filed on or before each April 1.
(c) What to file. FERC Form No. 715 must be filed with the Federal Energy Regulatory Commission in accordance with the instructions on that form.
(d) Critical Energy Infrastructure Information. (1) If the instructions in Form No. 715 require a utility to reveal Critical Energy Infrastructure Information (CEII), as defined in § 388.113(c) of this chapter, to any person, the utility shall omit the CEII from the information made available and insert the following in its place:
(i) A statement that CEII is being withheld;
(ii) A brief description of the omitted information that does not reveal any CEII; and
(iii) This statement: “Procedures for obtaining access to Critical Energy Infrastructure Information (CEII) may be found at 18 CFR 388.113. Requests for access to CEII should be made to the Commission’s CEII Coordinator.”
(2) The utility completing Form No. 715, in determining whether information constitutes CEII, shall treat the information in a manner consistent with any filings that utility has made with the Commission and shall to the extent practicable adhere to any previous determinations by the Commission or the CEII Coordinator involving the same or like information.
(3) The procedures contained in §§ 388.112 and 388.113 of this chapter regarding designation of, and access to, CEII, shall apply in the event of a challenge to a CEII designation or a request for access to CEII. If it is determined that information is not CEII or that a requester should be granted access to CEII, the utility will be directed to make the information available to the requester.
(4) Nothing in this section shall be construed to prohibit any persons from voluntarily reaching arrangements or agreements calling for the disclosure of CEII.
§ 141.400 FERC Form No. 3–Q, Quarterly financial report of electric utilities, licensees, and natural gas companies.
(a) Prescription. The quarterly report of electric utilities, licensees, and natural gas companies, designated as FERC Form No. 3–Q, is prescribed for the reporting quarter ending March 31, 2004, and each quarter thereafter.
(b) Filing requirements—(1) Who must file—(i) Generally. Each electric utility and each Nonoperating (formerly designated as Major or Nonmajor) electric utility (as defined in part 101 of subchapter C of this chapter) and other entity, i.e., each corporation, person, or licensee as defined in section 3 of the Federal Power Act (16 U.S.C. 792 et seq.), including any agency or instrumentality engaged in generation, transmission, distribution, or sale of electric energy, however produced, throughout the United States and its possessions, having sales or transmission service must prepare and file with the Commission FERC Form No. 3–Q pursuant to the General Instructions set out in that form.
(ii) Exceptions. This report form is not prescribed for any agency, authority or instrumentality of the United States, nor is it prescribed for municipalities as defined in section 3 of the Federal Power Act; (i.e. a city, county, irrigation district, or other political subdivision or agency of a State competent under the laws thereof to carry on the business of developing, transmitting, utilizing, or distributing power).
(2) Each Major and Nonoperating (formerly designated as Major) (as defined in part 101 of subchapter C of this chapter) public utility and licensee must file the quarterly financial report form as follows:
(i) The quarterly financial report for the period January 1 through March 31, 2004, must be filed on or before July 9, 2004.
(ii) The quarterly financial report for the period April 1 through June 30, 2004, must be filed on or before September 8, 2004.
(iii) The quarterly financial report for the period July 1 through September 30, 2004, must be filed on or before December 9, 2004.
(iv) The quarterly financial report for the period January 1 through March 31, 2005, must be filed on or before May 31, 2005.
(v) The quarterly financial report for the period April 1 through June 30, 2005, must be filed on or before August 29, 2005.
(vi) The quarterly financial report for the period July 1 through September 30, 2005 must be filed on or before November 29, 2005.
(vii) Subsequent quarterly financial reports must be filed within 60 days from the end of the reporting quarter.
(3) Nonmajor and Nonoperating (formerly designated as Nonmajor) public utilities and licensees must file the quarterly financial report form as follows:
(i) The quarterly financial report for the period January 1 through March 31, 2004, must be filed on or before July 23, 2004.
(ii) The quarterly financial report for the period April 1 through June 30, 2004, must be filed on or before September 22, 2004.
(iii) The quarterly financial report for the period July 1 through September 30, 2004, must be filed on or before December 23, 2004.
(iv) The quarterly financial report for the period January 1 through March 31, 2005, must be filed on or before June 13, 2005.
(v) The quarterly financial report for the period April 1 through June 30, 2005, must be filed on or before September 12, 2005.
(vi) The quarterly financial report for the period July 1 through September 30, 2005 must be filed on or before December 13, 2005.
(vii) Subsequent quarterly financial reports must be filed within 70 days from the end of the reporting quarter.
(4) This report must be filed as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in the quarterly financial report form, and must be properly completed and verified. Filing on electronic media pursuant to § 385.2011 of this chapter will be required commencing with the quarterly financial report ending March 31, 2004, due on or before July 9, 2004 for major public utilities and licensees, and due on or before July 23, 2004 for nonmajor public utilities and licensees.
§ 141.500 Cash management programs.
Public utilities and licensees subject to the provisions of the Commission’s Uniform System of Accounts prescribed in part 101 and § 141.1 or § 141.2 of this title that participate in cash management programs must file these agreements with the Commission. The documentation establishing the cash management program and entry into the program must be filed within 10 days of the effective date of the rule or entry into the program. Subsequent changes to the cash management agreement must be filed with the Commission within 10 days of the change.
PARTS 142–149 [RESERVED]
SUBCHAPTER E—REGULATIONS UNDER NATURAL GAS ACT
PART 152—APPLICATION FOR EXEMPTION FROM THE PROVISIONS OF THE NATURAL GAS ACT PURSUANT TO SECTION 1(c) THEREOF AND ISSUANCE OF BLANKET CERTIFICATES AUTHORIZING CERTAIN SALES FOR RESALE
§ 152.1 Exemption applications and blanket certificates.
(a) Application for exemption from the provisions of the Natural Gas Act and the rules and regulations of the Commission issued pursuant thereto may be made by any person as defined in the Natural Gas Act engaged in, or authorized to engage in the transportation in interstate commerce or the sale in interstate commerce for resale, of natural gas received by such applicant from another person within or at the boundary of a State, if all of the natural gas so received is ultimately consumed in such State: Provided, That the natural-gas rates (including rates for sales for resale) and service of the applicant and its natural-gas facilities are subject to regulation by a State Commission, as defined in the Natural Gas Act, and that such State Commission is exercising that jurisdiction.
(b)(1)(i) For purposes of the Commission’s regulations implementing the Natural Gas Act, “vehicular natural gas” or “VNG” means natural gas that will be used, in either a gaseous or liquefied state, as fuel in any self-propelled vehicle.
(ii) For purposes of the Commission’s regulations implementing the Natural Gas Act, vehicular natural gas, or VNG, is deemed to be ultimately consumed in the state in which the gas is physically delivered into the vehicle’s fuel tank regardless of whether the tank is attached to the vehicle at the time it is filled.
(2)(i) Blanket certificates of public convenience and necessity are issued pursuant to section 7(c) of the Natural Gas Act to all persons that engage in sales for resale of VNG that are subject to the Commission’s authority under section 1(b) of the NGA, such authorization to be effective upon that person’s engagement in the jurisdictional sale. A blanket certificate issued under this paragraph (b)(2)(i) is a certificate of limited jurisdiction which will not subject the certificate holder to any other regulation under the Natural Gas Act jurisdiction of the Commission by virtue of transactions under the certificate. Such certificate will not impair the continued validity of any Natural Gas Act exemption from Commission jurisdiction.
(ii) A blanket certificate issued under paragraph (b)(2)(i) of this section authorizes the holder to make sales of VNG for resale in interstate commerce at market rates.
(iii) Abandonment of the sales service authorized in paragraph (b)(2)(i) of this section is authorized pursuant to section 7(b) of the Natural Gas Act upon the expiration of the contractual term or upon termination of each individual sales arrangement.
§ 152.2 Form of application; service.
The application must be filed with the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov. A copy of the application shall be served on the State Commission which has jurisdiction over the applicant and upon each wholesale customer of the applicant.
§ 152.3 Contents of application.
Every application shall set forth in the order indicated, the following:
(a) The exact legal name of applicant.
(b) The name, title, and post office address of the person to whom correspondence in regard to the application shall be addressed.
(c) A statement of pertinent facts as to the existing service, if any, or authorized service by applicant, including a showing that all of the natural gas which applicant receives from out-of-State sources is and will be ultimately consumed within the State in which the operations sought to be exempted are conducted.
§ 152.4 Certificate from State Commission.
Applications for exemption under § 152.3 shall contain, or there shall be separately filed, a certificate from the appropriate State Commission that the natural-gas (a) rates (including rates for sales for resale), (b) service, and (c) facilities of the applicant are subject to the regulatory jurisdiction of the State Commission and that the State Commission is exercising such jurisdiction.
§ 152.5 Applicability of exemption.
Nothing in this part shall be construed to relieve any person exempted from the provisions of the Natural Gas Act by section 1(c) thereof from compliance with valid State regulatory requirements. If an exemption from the provisions of the Natural Gas Act is effective pursuant to section 1(c), the exempted person shall be responsible for calling to the attention of the State Commission by which it is regulated and of the Federal Energy Regulatory Commission any future operations in which it may engage which may make the exemption inapplicable to it. The exempted person shall also be responsible for calling to the attention of the Federal Energy Regulatory Commission any changes, amendment, or judicial or administrative interpretation of the State law pursuant to which it is regulated, which may make the exemption inapplicable to it.
PART 153—APPLICATIONS FOR AUTHORIZATION TO CONSTRUCT, OPERATE, OR MODIFY FACILITIES USED FOR THE EXPORT OR IMPORT OF NATURAL GAS
Subpart A—General Provisions
§ 153.1 Purpose and scope.
The purpose of this part is to implement the Commission’s delegated authorities under section 3 of the Natural Gas Act and Executive Order 10485, as amended by Executive Order 12038. Subpart B of this part establishes filing requirements an applicant must follow to obtain authorization under section 3 of the Natural Gas Act for the siting, construction, operation, place of entry for imports or place of exit for exports. Subpart C of this part establishes filing requirements an applicant must follow to apply for a Presidential Permit, or an amendment to an existing Presidential Permit, for border facilities at the international boundary between the United States and Canada or Mexico.
§ 153.2 Definitions.
(a) DOE/FE means the Department of Energy/Office of Fossil Energy or its successor office.
(b) Person means an individual or entity as defined in 10 CFR 590.102(m).
(c) LNG Terminal means all natural gas facilities located onshore or in state waters that are used to receive, unload, load, store, transport, gasify, liquefy, or process natural gas that is imported to the United States from a foreign country, exported to a foreign country from the United States, or transported in interstate commerce by a waterborne vessel, but does not include:
(1) Waterborne vessels used to deliver natural gas to or from any such facility; or
(2) Any pipeline or storage facility subject to the jurisdiction of the Commission under section 7 of the Natural Gas Act.
(d) For purposes of this part and § 157.21, related jurisdictional natural gas facilities means any pipeline or other natural gas facilities which are subject to section 7 of the NGA; will directly interconnect with the facilities of an LNG terminal, as defined in paragraph (d) of this section; and which are necessary to transport gas to or regasified LNG from:
(1) A planned but not yet authorized LNG terminal; or
(2) An existing or authorized LNG terminal for which prospective modifications are subject pursuant to section 157.21(e)(2) to a mandatory pre-filing process.
(e) Waterway Suitability Assessment (WSA) means a document used by the U.S. Coast Guard in assessing the suitability of a waterway for LNG marine traffic pursuant to 33 CFR 127.007. The Preliminary WSA initiates the process of analyzing the safety and security risks posed by proposed LNG tanker operations to a port and waterways, and the Follow-On WSA provides a detailed analysis of the same issues.
§ 153.3 Notice requirements.
All applications filed under this part are subject to the landowner notification requirements in § 157.6(d) of this chapter.
Subpart B—Application Under Section 3
§ 153.4 General requirements.
The procedures in §§ 157.5, 157.6, 157.8, 157.9, 157.10, 157.11, 157.12, 157.22, and 157.23 of this chapter are applicable to the applications described in this subpart.
§ 153.5 Who shall apply.
(a) Applicant. Any person proposing to site, construct, or operate facilities which are to be used for the export of natural gas from the United States to a foreign country or for the import of natural gas from a foreign country or to amend an existing Commission authorization, including the modification of existing authorized facilities, shall file with the Commission an application for authorization therefor under subpart B of this part and section 3 of the Natural Gas Act.
(b) Cross-reference. Any person applying under paragraph (a) of this section to construct facilities at the borders of the United States and Canada or Mexico must also simultaneously apply for a Presidential Permit under subpart C of this part.
§ 153.6 Time of filing.
(a) An application filed pursuant to § 153.5(a) shall state whether DOE/FE authorization for the import/export of natural gas is required and whether DOE/FE has granted all required authorizations for the import/export of natural gas.
(b) If all required DOE/FE authorizations have not been obtained prior to filing an application with the Commission, the applicant agrees, as a condition of its authorization, to file a statement that all required DOE/FE authorizations have been obtained prior to applicant’s construction of border facilities.
(c) When a prospective applicant for authorization for LNG terminal facilities, related jurisdictional natural gas facilities or modifications to existing LNG terminal facilities is required by § 157.21(a) to comply with that section’s pre-filing procedures, no application for such authorization may be made before 180 days after the date of issuance of the notice by the Director of the Office of Energy Projects, as provided in § 157.21(e), of the commencement of the prospective applicant’s pre-filing process under § 157.21.
§ 153.7 Contents of application.
Every application under subpart B of this part shall include, in the order indicated, the following:
(a) Information regarding applicant. (1) The exact legal name of applicant;
(2) The name, title, and post office address, telephone and facsimile numbers of the person to whom correspondence in regard to the application shall be addressed;
(3) If a corporation, the state or territory under the laws of which the applicant was organized, and the town or city where applicant’s principal office is located. If applicant is incorporated under the laws of, or authorized to operate in, more than one state, all pertinent facts should be stated. If applicant company is owned wholly or in part by any foreign government entity, or directly or indirectly subsidized by any foreign government entity; or, if applicant company has any agreement for such ownership or subsidization from any foreign government, provide full details of ownership and/or subsidies.
(b) Summary. A detailed summary of the proposal, including descriptions of the facilities utilized in the proposed export or import of natural gas; state, foreign, or other Federal governmental licenses or permits for the construction, operation, or modification of facilities in the United States, Canada, or Mexico; and the status of any state, foreign, or other Federal regulatory proceedings which are related to the proposal.
(c) Statements. (1) A statement demonstrating that the proposal or proposed construction is not inconsistent with the public interest, including, where applicable to the applicant’s operations and proposal, a demonstration that the proposal:
(i) Will improve access to supplies of natural gas, serve new market demand, enhance the reliability, security, and/or flexibility of the applicant’s pipeline system, improve the dependability of international energy trade, or enhance competition within the United States for natural gas transportation or supply;
(ii) Will not impair the ability of the applicant to render transportation service in the United States at reasonable rates to its existing customers; and,
(iii) Will not involve any existing contract(s) between the applicant and a foreign government or person concerning the control of operations or rates for the delivery or receipt of natural gas which may restrict or prevent other United States companies from extending their activities in the same general area, with copies of such contracts; and,
(2) A statement representing that the proposal will be used to render transportation services under parts 157 or 284 of this chapter, private transportation, or service that is exempt from the provisions of the Natural Gas Act pursuant to sections 1(b) or 1(c) thereof. The applicant providing transportation service under part 157 of this chapter must represent that the pipeline’s proposed increase in capacity at an existing import/export point is not exclusively reserved for part 157 users and that all new service made available as a result of a new or modified import/export facility will be under part 284 of this chapter.
§ 153.8 Required exhibits.
(a) An application must include the following exhibits:
(1) Exhibit A. A certified copy of articles of incorporation, partnership or joint venture agreements, and by-laws of applicant; the amount and classes of capital stock; nationality of officers, directors, and stockholders, and the amount and class of stock held by each;
(2) Exhibit B. A detailed statement of the financial and corporate relationship existing between applicant and any other person or corporation;
(3) Exhibit C. A statement, including signed opinion of counsel, showing that the construction, operation, or modification of facilities for the export or the import of natural gas is within the authorized powers of applicant, that applicant has complied with laws and regulations of the state or states in which applicant operates;
(4) Exhibit D. If the proposal is for a pipeline interconnection to import or export natural gas, a copy of any construction and operation agreement between the applicant and the operator(s) of border facilities in the United States and Canada or Mexico;
(5) Exhibit E. If the proposal is to import or export LNG, evidence that an appropriate and qualified concern will properly and safely receive or deliver such LNG, including a report containing detailed engineering and design information. The Commission staff’s “Guidance Manual for Environmental Report Preparation” may be obtained from the Commission’s Office of Energy Projects, 888 First Street, NE., Washington, DC 20426;
(6) Exhibit F. An environmental report as specified in §§ 380.3 and 380.12 of this chapter. Applicant must submit all appropriate revisions to Exhibit F whenever route or site changes are filed. These revisions should identify the specific differences resulting from the route or site changes, and not just provide revised totals for the resources affected;
(7) Exhibit G. A geographical map of a suitable scale and detail showing the physical location of the facilities to be utilized for the applicant’s proposed export or import operations The map should indicate with particularity the ownership of such facilities at or on each side of the border between the United States and Canada or Mexico, if applicable; and
(8) Exhibit H. A statement identifying each Federal authorization that the proposal will require; the Federal agency or officer, or State agency or officer acting pursuant to delegated Federal authority, that will issue each required authorization; the date each request for authorization was submitted; why any request was not submitted and the date submission is expected; and the date by which final action on each Federal authorization has been requested or is expected.
(b) The applicant may incorporate by reference any Exhibit required by paragraph (a) of this section already on file with the Commission.
§ 153.9 Transferability.
(a) Non-transferable. Authorizations under subpart B of this part and section 3 of the Natural Gas Act and related facilities shall not be transferable or assignable without prior Commission authorization.
(b) Involuntary transfer. A Commission order granting such authorization shall continue in effect temporarily for a reasonable time in the event of the involuntary transfer of facilities used thereunder by operation of law (including such transfers to receivers, trustees, or purchasers under foreclosure or judicial sale) pending the making of an application for permanent authorization and decision thereon, provided notice is promptly given in writing to the Commission accompanied by a statement that the physical facts relating to operations of the facilities remain substantially the same as before the transfer and as stated in the initial application for such authorization.
§ 153.10 Authorization not exclusive.
No authorization granted pursuant to subpart B of this part and section 3 of the Natural Gas Act shall be deemed to prevent the Commission from granting authorization under subpart B to any other person at the same general location, or to prevent any other person from making application for such authorization.
§ 153.11 Supplemental orders.
The Commission also may make, at any time subsequent to the original order of authorization, after opportunity for hearing, such supplemental orders implementing its authority under section 3 of the Natural Gas Act as it may find necessary or appropriate.
The definitions in § 157.1 and the pre-filing procedures in § 157.21 of this chapter are applicable to applications under section 3 of the Natural Gas Act filed pursuant to subpart B of this part.
§ 153.13 Emergency reconstruction.
The provisions of subpart F of part 157 of this chapter that permit reconstruction for the purpose of immediately restoring interrupted service for the protection of life or health or for maintenance of physical property in an emergency due to a sudden unanticipated loss of gas supply or capacity are applicable to facilities subject to section 3 of the Natural Gas Act.
Subpart C—Application for a Presidential Permit
§ 153.15 Who shall apply.
(a) Applicant. Any person proposing to construct, operate, maintain, or connect facilities at the borders of the United States and Canada or Mexico, for the export or import of natural gas to or from those countries, or to amend an existing Presidential Permit, shall file with the Commission an application for a Presidential Permit under subpart C of this part and Executive Order 10485, as amended by Executive Order 12038.
(b) Cross-reference. Any person applying under paragraph (a) of this section for a Presidential Permit for the construction and operation of border facilities must also simultaneously apply for authorization under subpart B of this part.
§ 153.16 Contents of application.
(a) Cross-reference. The submission of information under §§ 153.7 and 153.8 of subpart B of this part shall be deemed sufficient for purposes of applying for a Presidential Permit or an amendment to an existing Presidential Permit under subpart C of this part for the construction and operation of border facilities.
(b) Amendment not proposing construction. An applicant proposing to amend the article(s) of an existing Presidential Permit (other than facilities aspects) must file information pursuant to § 153.7(a) and a summary and justification of its proposal.
§ 153.17 Effectiveness of Presidential Permit.
A Presidential Permit, once issued by the Commission, shall not be effective until it has been accepted by the highest authority of the Permittee, as indicated by Permittee’s execution of a Testimony of Acceptance, and a certified copy of the accepted Presidential Permit and the executed Testimony of Acceptance has been filed with the Commission.
Subpart D—Paper Media and Other Requirements
§ 153.20 General rule.
(a) Filing procedures. Applications under Subparts B and C must be submitted to the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov.
(b) Certification. All applications must be signed in compliance with § 385.2005 of this chapter.
(1) The signature on an application constitutes a certification that: The signer has read the filing signed and knows the contents of the paper copies; and, the signer possesses the full power and authority to sign the filing.
(2) An application must be signed by one of the following:
(i) The person on behalf of whom the application is made;
(ii) An officer, agent, or employee of the governmental authority, agency, or instrumentality on behalf of which the filing is made; or,
(iii) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.
(c) Where to file. The paper copies and an accompanying transmittal letter must be submitted in one package to: Office of the Secretary, Federal Energy Regulatory Commission, Washington, DC 20426.
§ 153.21 Conformity with requirements.
(a) General Rule. Applications under subparts B and C of this part must conform with the requirements of this part.
(b) Rejection of applications. If an application patently fails to comply with applicable statutory requirements or with applicable Commission rules, regulations, and orders for which a waiver has not been granted, the Director of the Office of Energy Projects may reject the application within 10 days of filing as provided by § 385.2001(b) of this chapter. This rejection is without prejudice to an applicant’s refiling a complete application. However, an application will not be rejected solely on the basis of: Environmental reports that are incomplete because the company has not been granted access by the affected landowner(s) to perform required surveys, or environmental reports that are incomplete, but where the minimum checklist requirements of part 380, appendix A of this chapter have been met. An application that relates to an operation, service, or construction concerning which a prior application has been filed and rejected, shall be docketed as a new application. Such new application shall state the docket number of the prior rejected application.
§ 153.22 Amendments and withdrawals.
Amendments to or withdrawals of applications must conform to the requirements of §§ 385.215 and 385.216 of this chapter.
§ 153.23 Reporting requirements.
Each person authorized under this part 153 that is not otherwise required to file information concerning the start of construction or modification of import/export facilities, the completion of construction or modification, and the commencement of service must file such information with the Commission within 10 days after such event. Each person, other than entities without pipeline capacity, must also report by March 1 of each year the estimated peak day capacity and actual peak day usage of its import/export facilities.
PART 154—RATE SCHEDULES AND TARIFFS
Subpart A—General Provisions and Conditions
§ 154.1 Application; Obligation to file.
(a) The provisions of this part apply to filings pursuant to section 4 of the Natural Gas Act.
(b) Every natural gas company must file with the Commission and post in conformity with the requirements of this part, schedules showing all rates and charges for any transportation or sale of natural gas subject to the jurisdiction of the Commission, and the classifications, practices, rules, and regulations affecting such rates, charges, and services, together with all contracts related thereto.
(c) No natural gas company may file, under this part, any new or changed rate schedule or contract for the performance of any service for which a certificate of public convenience and necessity or certificate amendment must be obtained pursuant to section 7(c) of the Natural Gas Act, until such certificate has been issued.
(d) For the purposes of paragraph (b) of this section, any contract that conforms to the form of service agreement that is part of the pipeline’s tariff pursuant to § 154.110 does not have to be filed. Any contract or executed service agreement which deviates in any material aspect from the form of service agreement in the tariff is subject to the filing requirements of this part.
§ 154.2 Definitions.
(a) Contract means any agreement which in any manner affects or relates to rates, charges, classifications, practices, rules, regulations, or services for any transportation or sale of natural gas subject to the jurisdiction of the Commission. This term includes an executed service agreement.
(b) FERC Gas Tariff or tariff means a compilation, on electronic media, of all of the effective rate schedules of a particular natural gas company, and a copy of each form of service agreement.
(c) Form of service agreement means an unexecuted agreement for service included as an example in the tariff.
(d) Post means: to make a copy of a natural gas company’s tariff and contracts available during regular business hours for public inspection in a convenient form and place at the natural gas company’s offices where business is conducted with affected customers; and, to serve each affected customer and interested state Commission in accordance with § 154.208 of this Part.
(e) Rate schedule means a statement of a rate or charge for a particular classification of transportation or sale of natural gas subject to the jurisdiction of the Commission, and all terms, conditions, classifications, practices, rules, and regulations affecting such rate or charge.
(f) Filing date means the day on which a tariff, or part thereof, or a contract is received in the Office of the Secretary of the Commission for filing in compliance with the requirements of this part.
§ 154.3 Effective tariff.
(a) The effective tariff of a natural gas company is the tariff filed pursuant to the requirements of this part, and permitted by the Commission to become effective. A natural gas company must not directly or indirectly, demand, charge, or collect any rate or charge for, or in connection with, the transportation or sale of natural gas subject to the jurisdiction of the Commission, or impose any classifications, practices, rules, or regulations, different from those prescribed in its effective tariff and executed service agreements on file with the Commission, unless otherwise specifically permitted by order of the Commission.
(b) No tariff provision may purport to change an effective rate or charge except in the manner provided in section 4 of the Natural Gas Act, and the regulations in this part. The tariff may not provide for any rate or charge to be automatically changed by an index or other periodic adjustment, without filing for a rate change pursuant to these regulations.
(a) General rule. All filings made in proceedings initiated under this part must be made electronically, including tariffs, rate schedules, service agreements, and contracts, or parts thereof, and material that relates to or bears upon such documents, such as cancellations, amendments, withdrawals, termination, or adoption of tariffs, and motions relating to suspension.
(b) Requirement for signature. All filings must be signed in compliance with the following:
(1) The signature on a filing constitutes a certification that the contents are true to the best knowledge and belief of the signer, and that the signer possesses full power and authority to sign the filing.
(2) A filing must be signed by one of the following:
(i) The person on behalf of whom the filing is made;
(ii) An officer, agent, or employee of the company, governmental authority, agency, or instrumentality on behalf of which the filing is made; or,
(iii) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.
(3) All signatures on the filing or any document included in the filing must comply, where applicable, with the requirements in § 385.2005 of this chapter with respect to sworn declarations or statements and electronic signatures.
(c) Format requirements for electronic filing. The requirements and formats for electronic filing are listed in instructions for electronic filing and for each form. These formats are available through the Commission’s website, https://www.ferc.gov.
(d) Only filings filed and designated as filings with statutory action dates in accordance with these electronic filing requirements and formats will be considered to have statutory action dates. Filings not properly filed and designated as having statutory action dates will not become effective, pursuant to the Natural Gas Act, should the Commission not act by the requested action date.
§ 154.5 Rejection of filings.
A filing that fails to comply with this part may be rejected by the Director of the Office of Energy Market Regulation pursuant to the authority delegated to the Director in Part 375 of this chapter.
§ 154.6 Acceptance for filing not approval.
The acceptance for filing of any tariff, contract or part thereof does not constitute approval by the Commission. Any filing which does not comply with any applicable statute, rule, or order, may be rejected.
§ 154.7 General requirements for the submission of a tariff filing or executed service agreement.
The following must be included with the filing of any tariff, executed service agreement, or part thereof, or change thereto.
(a) A letter of transmittal containing:
(1) A list of the material enclosed,
(2) The name of a responsible company official to whom questions regarding the filing may be addressed, with a telephone number at which the official may be reached,
(3) The date on which such filing is proposed to become effective,
(4) Reference to the authority under which the filing is made, including the specific section of a statute, subpart of these regulations, order of the Commission, provision of the company’s tariff, or any other appropriate authority. If an order is referenced, the letter must include the citation to the FERC Reports, the date of issuance, and the lead docket number of the proceeding in which the order was issued.
(5) A list of the tariff sheets or sections enclosed,
(6) A statement of the nature, the reasons, and the basis for the filing. The statement must include a summary of the changes or additions made to the tariff or executed service agreement, as appropriate. The statement must include a quantified summary comparing the cost of service, rate base and throughput underlying each change in rate made to the tariff or executed service agreement compared to the same information underlying the last rate found by the Commission to be just and reasonable. A detailed explanation of the need for each change or addition to the tariff or executed service agreement must be included. The natural gas company also must note all relevant precedents relied upon to prepare its filing.
(7) Any requests for waiver. A request for waiver must include a reference to the specific section of the statute, regulations, or the company’s tariff from which waiver is sought, and a justification for the waiver.
(8) Where the natural gas company proposes a new rate, identification of the last rate, found by the Commission to be just and reasonable, that underlies the proposed rate.
(9) A motion, in case of minimal suspension, to place the proposed rates into effect at the end of the suspension period; or, a specific statement that the pipeline reserves its right to file a later motion to place the proposed rates into effect at the end of the suspension period.
(b) A certification of service to all customers and state commissions pursuant to § 154.2(d).
§ 154.8 Informal submission for staff suggestions.
Any natural gas company may informally submit a proposed tariff or any part thereof or material relating thereto for the suggestions of the Commission staff prior to filing. Opinions of the Commission staff are not binding upon the Commission.
Subpart B—Form and Composition of Tariff
§ 154.101 [Reserved]
§ 154.102 Requirements for filing rate schedules and tariffs.
(a) All rates schedules, tariffs, and service agreements may be filed either by dividing the rate schedule, tariff, or agreement into individual tariff sheets, or tariff sections, or as an entire document except as provided in paragraph (b) of this section.
(b) Open access transportation tariffs must be filed either as individual sheets or sections. If filed as sections, each section must include only material of related subject matter and must be of reasonable length and must include at a minimum a section for each item listed in the table of contents under § 154.103 of this section and each topic listed under General Terms and Conditions of Service.
(c) Individual negotiated rate agreements, non-conforming service agreements, or other agreements that are included in the tariff may be filed as entire documents.
(d) The first section or sheet of the tariff must include:
(1) The FERC Gas Tariff Volume Number and Name of the Natural Gas Company, for example
FERC Gas Tariff Volume No. [ ] of [Name of Natural Gas Company]
(2) The name, title, address, telephone number, e-mail address and facsimile number of a person to whom communications concerning the tariff should be sent.
§ 154.103 Composition of tariff.
(a) The tariff must contain sections, in the following order: A table of contents, a preliminary statement, a uniform resource locator for the Internet address of a map of the system, currently effective rates, composition of rate schedules, general terms and conditions, form of service agreement, and an index of customers.
(b) Rate schedules must be grouped according to class and numbered serially within each group, using letters before the serial number to indicate the class of service. For example: FT–1, FT–2 may be used for firm transportation service; IT–1, IT–2 may be used for interruptible transportation service; X–1, X–2 may be used for schedules for which special exception has been obtained.
§ 154.104 Table of contents.
The table of contents must contain a list of the rate schedules, sections of the general terms and conditions, and other sections in the order in which they appear, showing the sheet number of the first page of each section or the section number. The list of rate schedules must consist of: The alphanumeric designation of each rate schedule, a very brief description of the service, and the sheet number of the first page of each rate schedule or the section number.
§ 154.105 Preliminary statement.
The preliminary statement must contain a brief general description of the company’s operations and may also contain a general explanation of its policies and practices. General rules and regulations, and any material necessary for the interpretation or application of the rate schedules, may not be included in the preliminary statement.
§ 154.106 Map.
(a) The tariff must state a uniform resource locator on the pipeline’s Internet Web site, at which the general public may display and download system map(s).
(b) The map must show the general geographic location of the company’s principal pipeline facilities and of the points at which service is rendered under the tariff. The boundaries of any rate zones or rate areas must be shown and the areas or zones identified. The entire system should be displayed on a single map. In addition, a separate map should be provided for each zone.
(c) The map must be revised to reflect any major change no later than the end of the calendar quarter that immediately follows the calendar quarter in which the major change occurred.
§ 154.107 Currently effective rates.
(a) This section of the tariff must present the currently effective rates and charges under each rate schedule.
(b) All rates must be stated clearly in cents or dollars and cents per thermal unit. The unit of measure must be stated for each component of a rate.
(c) A rate having more than one part must have each component set out separately under appropriate headings (e.g., “Reservation Charge,” “Usage Charge.”)
(d) Where a component of a rate is adjusted pursuant to a mechanism approved under subpart E of this part, the adjustment must be stated in a separate column on the rate sheet or section.
(e) Exception to paragraph (d) of this section. Where the rate component is an Annual Charge Adjustment surcharge approved by the Commission, the adjustment or surcharge may be stated in a footnote on the rate sheet or section.
(f) A total rate, indicating the sum of the rate components under paragraph (c) of this section plus the adjustments under paragraph (d) of this section, must be shown in the last column at the end of a line for a rate, so that a reader can readily determine the separate components comprising the total rate for a service.
§ 154.108 Composition of rate schedules.
The rate schedule must contain a statement of the rate or charge and all terms and conditions governing its application, arranged as follows:
(a) Title. Each rate schedule must have a title consisting of a designation of the type or classification of service (see § 154.103(b)), and a statement of the type or classification of service to which the rate is applicable.
(b) Availability. This paragraph must describe the conditions under which the rate is offered, including any geographic zone limitations.
(c) Applicability and character of service. This paragraph must fully describe the kind or classification of service to be rendered.
(d) Summary of rates. This paragraph must briefly set forth all components of the rates, refer to the location of the rates in the Currently Effective Rates, and provide a description of the calculation of the monthly charges for each rate component.
(e) Other provisions. All other major provisions governing the application of the rate schedule, such as determination of billing demand, contract demand, heat content, and measurement base, must be set forth with appropriate headings or incorporated by reference to the applicable general terms and conditions.
(f) Applicable terms and conditions. This paragraph either states that all of the general terms and conditions set forth in the tariff apply to the rate schedule, or specifies which of the general terms and conditions do not apply.
§ 154.109 General terms and conditions.
(a) This section of the tariff contains terms and conditions of service applicable to all or any of the rate schedules. Subsections and paragraphs must be numbered for convenient reference.
(b) The general terms and conditions of the tariff must contain a statement of the company’s policy with respect to the financing or construction of laterals including when the pipeline will pay for or contribute to the construction cost. The term “lateral” means any pipeline extension (other than a mainline extension) built from an existing pipeline facility to deliver gas to one or more customers, including new delivery points and enlargements or replacements of existing laterals.
(c) The general terms and conditions of the tariff must contain a statement of the order in which the company discounts its rates and charges. The statement, specifying the order in which each rate component will be discounted, must be in accordance with Commission policy.
§ 154.110 Form of service agreement.
The tariff must contain an unexecuted pro forma copy of each form of service agreement. The form for each service must refer to the service to be rendered and the applicable rate schedule of the tariff; and, provide spaces for insertion of the name of the customer, effective date, expiration date, and term. Spaces may be provided for the insertion of receipt and delivery points, contract quantity, and other specifics of each transaction as appropriate.
§ 154.111 Index of customers.
(a) If a pipeline is in compliance with the reporting requirements of § 284.13(c) of this chapter, then an index of customers need not be provided in the tariff.
(b) If all of a pipeline’s jurisdictional transportation and sales are pursuant to part 157 of this chapter, then an index of customers must be provided that contains: a list of the pipeline’s firm transportation, storage, and sales customers, and the rate schedule number for the services for which the shippers are contracting; the effective date of the contract; the expiration date of the contract; if the service is transportation or sales, the maximum daily contract demand under the contract; and, if the service is storage, the maximum storage quantity. Specify units of measurement when reporting contract quantities.
(c) The index of customers must be kept current by filing new or revised sheets or sections, semi-annually. One filing must coincide with the filing of the natural gas company’s FERC Form No. 2 or 2–A with a proposed effective date of June 1. The other filing must be made six months later with a proposed effective date of December 1. The Index of Customers must contain a list of the contracts in effect as of the filing date.
§ 154.112 Exception to form and composition of tariff.
(a) The Commission may permit a special rate schedule to be filed in the form of an agreement in the case of a special operating arrangement, previously certificated pursuant to part 157 of this chapter, such as for the exchange of natural gas. The special rate schedule must contain a title page showing the parties to the agreement, the date of the agreement, a brief description of services to be rendered, and the designation: “Rate Schedule X-[number].” Special rate schedules may not contain any supplements. Modifications must be made by inserting revised sheets, sections or the entire document as appropriate. Special rate schedules must be included in a separate volume of the tariff. Each such separate volume must contain a table of contents which is incorporated as a sheet or section in the open access transmission tariff.
(b) Contracts for service pursuant to part 284 of this chapter that deviate in any material aspect from the form of service agreement must be filed. Such non-conforming agreements must be referenced in the open access transmission tariff.
Subpart C—Procedures for Changing Tariffs
§ 154.201 Filing requirements.
In addition to the requirements of subparts A and B of this part, the following must be included with the filing of any tariff, executed service agreement, or part thereof, that changes or supersedes any tariff, contract, or part thereof, on file with the Commission.
(a) A list in the transmittal letter of the tariff sheets or sections being revised and a marked version of the sheets or sections to be changed or superseded showing additions and deletions. New numbers and text must be marked by either highlight, background shading, bold, or underline. Deleted text and numbers must be indicated by strike-through. Only those revisions appropriately designated and marked constitute the filing. Revisions to unmarked portions of the rate schedule or tariff are not considered part of the filing nor will any acceptance of the filing by the Commission constitute acceptance of such unmarked changes.
(b) Documentation whether in the form of workpapers, or otherwise, sufficiently detailed to support the company’s proposed change.
(1) The documentation must include but is not limited to the schedules, workpapers, and supporting documentation required by these rules and regulations and the Commission’s orders.
(2) All rate changes in the filing must be supported by step-by-step mathematical calculations and sufficient written narrative to allow the Commission and interested parties to duplicate the company’s calculations.
(3) Any data or summaries included in the filing purporting to reflect the books of account must be supported by accounting workpapers setting forth all necessary particulars from which an auditor may readily verify that such data are in agreement with the company’s books of account. All statements, schedules, and workpapers must be prepared in accordance with the classifications of the Commission’s Uniform System of Accounts. Workpapers in support of all adjustments, computations, and other information, properly indexed and cross-referenced to the filing and other workpapers, must be available for Commission examination.
(4) Where a rate, cost, or volume is derived from another rate, cost, or volume, the derivation must be shown mathematically and be accompanied by a written narrative sufficient to allow the Commission and interested parties to duplicate the calculations. If the derivation is due to a load factor adjustment, application of a percentage, or other adjusting factor, the pipeline must also note or explain the origin of the adjusting factor.
(5) Where workpapers show progressive calculations, any discontinuity between one working paper and another must be explained.
§ 154.202 Filings to initiate a new rate schedule.
(a) When the filing is to initiate a new service authorized under a blanket authority in part 284 of this chapter, the filing must comply with the requirements of this paragraph.
(1) Filings under this paragraph must:
(i) Adhere to the requirements of subparts A, B, and C of this part;
(ii) Contain a description of the new service, including, but not limited to, the proposed effective date for commencement of service, applicability, whether the service is interruptible or firm, and the necessity for the service;
(iii) Explain how the new service will differ from existing services, including a concise description of the natural gas company’s existing operations;
(iv) Explain the impact of the new service on existing firm and interruptible customers, including but not limited to:
(A) The adequacy of existing capacity, if the proposed service is a firm service, and
(B) The effect on receipt and delivery point flexibility, nominating and scheduling priorities, allocation of capacity, operating conditions, and curtailment, for any new service;
(v) Include workpapers that detail the computations underlying the proposed rate under the new rate schedule; or, if the rate is a currently effective rate, include the appropriate reference and an explanation of why the rate is appropriate;
(vi) Give a justification, similar in form to filed testimony in a general section 4 rate case, explaining why the proposed rate design and proposed allocation of costs are just and reasonable;
(vii) If the costs relating to existing services are reallocated to new services, explain the method for allocating the costs and the impact on the existing customers;
(viii) Include workpapers showing the estimated effect on revenue and costs over the twelve-month period commencing on the proposed effective date of the filing.
(ix) List other filings pending before the Commission at the time of the filing which may significantly affect the filing. Explain how the instant filing would be affected by the outcome of each related pending filing;
(2) Any interdependent filings must be filed concurrently and contain a notice of the interdependence.
(b) If a new service, facility, or rate is specifically authorized by a Commission order pursuant to section 7 of the Natural Gas Act, with the filing of tariff sheets or sections to implement the new rate schedule, the natural gas company must:
(1) Comply with the requirements of § 154.203; and
(2) Where the rate or charge proposed differs from the rate or charge approved in the certificate order, the natural gas company must: Show that the change is due to a rate adjustment under a periodic rate change mechanism previously accepted under § 154.403 which has taken effect since the certificate order was issued; or, show that the rate change is in accordance with the terms of the certificate, and provide workpapers justifying the change.
§ 154.203 Compliance filings.
(a) In addition to the requirements of subparts A, B, and C of this part, filings made to comply with orders issued by the Commission, including those issued under delegated authority, must contain the following:
(1) A list of the directives with which the company is complying;
(2) Revised workpapers, data, or summaries with cross-references to the originally filed workpapers, data, or summaries;
(b) Filings made to comply with Commission orders must include only those changes required to comply with the order. Such compliance filings may not be combined with other rate or tariff change filings. A compliance filing that includes other changes or that does not comply with the applicable order in every respect may be rejected.
§ 154.204 Changes in rate schedules, forms of service agreements, or the general terms and conditions.
A filing to revise rate schedules, forms of service agreements, or the general terms and conditions, must:
(a) Adhere to the requirements of subparts A, B, and C, of this part;
(b) Contain a description of the change in service, including, but not limited to, applicability, necessity for the change, identification of services and types of customers that will be affected by the change;
(c) Explain how the proposed tariff provisions differ from those currently in effect, including an example showing how the existing and proposed tariff provisions operate. Explain why the change is being proposed at this time;
(d) Explain the impact of the proposed revision on firm and interruptible customers, including any changes in a customer’s rights to capacity in the manner in which a customer is able to use such capacity, receipt or delivery point flexibility, nominating and scheduling, curtailment, capacity release;
(e) Include workpapers showing the estimated effect on revenues and costs over the 12-month period commencing on the proposed effective date of the filing. If the filing proposes to change an existing penalty provision, provide workpapers showing the penalty revenues and associated quantities under the existing penalty provision during the latest 12-month period; and
(f) List other filings pending before the Commission which may significantly affect the filing.
§ 154.205 Withdrawals and amendments of tariff filings and executed service agreements.
(a) Withdrawals of tariff filings or service agreements prior to Commission action. (1) A natural gas company may withdraw in its entirety a tariff filing or executed service agreement that has not become effective and upon which no Commission or delegated order has been issued by filing a withdrawal motion with the Commission. Upon the filing of such motion, the proposed tariff sheets, sections or service agreements will not become effective under section 4(d) of the Natural Gas Act in the absence of Commission action making the rate schedule or tariff filing effective.
(2) The withdrawal motion will become effective, and the rate schedule or tariff filing will be deemed withdrawn, at the end of 15 days from the date of filing of the withdrawal motion, if no answer in opposition to the withdrawal motion is filed within that period and if no order disallowing the withdrawal is issued within that period. If an answer in opposition is filed within the 15 day period, the withdrawal is not effective until an order accepting the withdrawal is issued.
(b) Amendments or modifications to tariff sheets, sections or service agreements prior to Commission action on a tariff filing. A natural gas company may file to amend or modify a tariff or service agreement contained in a tariff filing upon which no Commission or delegated order has yet been issued. Such filing will toll the notice period in section 4(d) of the Natural Gas Act for the original filing, and establish a new date on which the entire filing will become effective, in the absence of Commission action, no earlier than 31 days from the date of the filing of the amendment or modification.
(c) Withdrawal of suspended tariffs, executed service agreements, or parts thereof. A natural gas company may not, within the period of suspension, withdraw a proposed tariff, executed service agreement, or part thereof, that has been suspended by order of the Commission, except by special permission of the Commission granted upon application therefor and for good cause shown.
(d) Changes in suspended tariffs, executed service agreements, or parts thereof. A natural gas company may not, within the period of suspension, file any change in a proposed tariff, executed service agreement, or part thereof, that has been suspended by order of the Commission, except by special permission of the Commission granted upon application therefor and for good cause shown.
(e) Changes in tariffs, executed service agreements, or parts thereof continued in effect, and which were to be changed by the suspended filing. A natural gas company may not, within the period of suspension, file any change in a tariff, executed service agreement, or part thereof, that is continued in effect by operation of the order of suspension, and that was proposed to be changed by the suspended filing, except:
(1) Under a previously approved tariff provision permitting a limited rate change, or
(2) By special permission of the Commission.
§ 154.206 Motion to place suspended rates into effect.
(a) If, prior to the end of the suspension period, the Commission has issued an order requiring changes in the filed rates, or the filed rates recover costs for facilities not certificated and in service as of the proposed effective date, in order to place the suspended rates into effect, the pipeline must file a motion at least one day prior to the effective date requested by the pipeline. The motion must be accompanied by revised tariff sheets or sections reflecting any changes ordered by the Commission or modifications approved by the Commission during the suspension period under § 154.205. The filing of the revised tariff sheets or sections must:
(1) Comply with the requirements of subparts A, B, and C of this part;
(2) Identify the Commission order directing the revision;
(3) List the modifications made to the currently effective rate during the suspension period, the docket number in which the modifications were filed, and identify the order permitting the modifications.
(b) Where the Commission has suspended the effective date of a change of rate, charge, classification, or service for a minimal period and the pipeline has not included a motion in its transmittal letter, or has specified in its transmittal letter pursuant to § 154.7(a)(9), that it reserves its right to file motion to place the proposed change of rate, charge, classification, or service into effect at the end of the suspension period, the change will go into effect, subject to refund, upon motion of the pipeline.
(c) Where the Commission has suspended the effective date of a change of rate, charge, classification, or service for a minimal period and the pipeline has included, in its transmittal letter pursuant to § 154.7(a)(9), a motion to place the proposed change of rate, charge, classification, or service into effect at the end of the suspension period, the change will go into effect, subject to refund, on the authorized effective date.
§ 154.207 Notice requirements.
All proposed changes in tariffs, contracts, or any parts thereof must be filed with the Commission and posted not less than 30 days nor more than 60 days prior to the proposed effective date thereof, unless a waiver of the time periods is granted by the Commission.
§ 154.208 Service of tariff filings on customers and other parties.
(a) On or before the filing date, the company must serve, upon all customers as of the date of the filing and all affected state regulatory commissions, an abbreviated form of the filing consisting of: The Letter of Transmittal; the Statement of Nature, Reason, and Basis; the changed tariff sheets or sections; a summary of the cost-of-service and rate base; and, summary of the magnitude of the change.
(b) On or before the filing date, the company must serve a full copy of the filing upon all customers and state regulatory commissions that have made a standing request for such service.
(c) Within two business days of receiving a request for a complete copy from any customer or state commission that has not made a standing request, the company must serve a full copy of any filing.
(d) A customer or other party may designate a recipient of service. The filing company must serve the designated recipient, in accordance with this section, instead of the customer or other party. For the purposes of this section, service upon the designated recipient will be deemed service upon the customer or other party.
(e) The company may choose to effect service either electronically or by paper. Such service must be made in accordance with the requirements of Part 385 of this chapter.
(f) Unless it seeks a waiver of electronic service, each customer or party entitled to service of initial tariff filings under this section must notify the company of the e-mail address to which service should be directed. A customer or party may seek a waiver of electronic service by filing a waiver request under Part 390 of this chapter, providing good cause for its inability to accept electronic service.
§ 154.209 [Reserved]
§ 154.210 Protests, interventions, and comments.
(a) Unless the notice issued by the Commission provides otherwise, any protest, intervention or comment to a tariff filing made pursuant to this part must be filed in accordance with § 385.211 of this chapter, not later than 12 days after the subject tariff filing. A protest must state the basis for the objection. A protest will be considered by the Commission in determining the appropriate action to be taken, but will not serve to make the protestant a party to the proceeding. A person wishing to become a party to the proceeding must file a motion to intervene.
(b) Any motion to intervene must be filed not later than 12 days after the subject tariff filing in accordance with § 385.214 of this chapter.
Subpart D—Material To Be Filed With Changes
§ 154.301 Changes in rates.
(a) Except for changes in rates pursuant to subparts E, F and G, of this part, any natural gas company filing for a change in rates or charges, except for a minor rate change, must submit, in addition to the material required by subparts A, B, and C of this part, the Statements and Schedules described in § 154.312.
(b) A natural gas company filing for a minor rate change must file the Statements and Schedules described in § 154.313.
(c) A natural gas company filing for a change in rates or charges must be prepared to go forward at a hearing and sustain, solely on the material submitted with its filing, the burden of proving that the proposed changes are just and reasonable. The filing and supporting workpapers must be of such composition, scope, and format as to comprise the company’s complete case-in-chief in the event that the change is suspended and the matter is set for hearing. If the change in rates or charges presented are not in full accord with any prior Commission decision directly involving the filing company, the company must include in its working papers alternate material reflecting the effect of such prior decision.
§ 154.302 Previously submitted material.
(a) If all, or any portion, of the information called for by this part has already been submitted to the Commission within six months of the filing date of this application, or is included in other data filed pursuant to this part, specific reference thereto may be made in lieu of resubmission.
(b) If a new FERC Form No. 2 or 2–A is required to be filed within 60 days from the end of the base period, the new FERC Form No. 2 or 2–A must be filed concurrently with the rate change filing. There must be furnished to the Director, Office of Energy Market Regulation, with the rate change filing, one copy of the FERC Form No. 2 or 2–A.
§ 154.303 Test periods.
Statements A through M, O, P, and supporting schedules, in § 154.312 and § 154.313, must be based upon a test period.
(a) If the natural gas company has been in operation for 12 months on the filing date, then the test period consists of a base period followed by an adjustment period.
(1) The base period consists of 12 consecutive months of the most recently available actual experience. The last day of the base period may not be more than 4 months prior to the filing date.
(2) The adjustment period is a period of up to 9 months immediately following the base period.
(3) The test period may not extend more than 9 months beyond the filing date.
(4) The rate factors (volumes, costs, and billing determinants) established during the base period may be adjusted for changes in revenues and costs which are known and measurable with reasonable accuracy at the time of the filing and which will become effective within the adjustment period. The base period factors must be adjusted to eliminate nonrecurring items. The company may adjust its base period factors to normalize items eliminated as nonrecurring.
(b) If the natural gas company has not been in operation for 12 months on the filing date, then the test period must consist of 12 consecutive months ending not more than one year after the filing date. Rate factors may be adjusted as in paragraph (a)(4) of this section but must not be adjusted for occurrences anticipated after the 12-month period.
(c)(1) Adjustments to base period experience, or to estimates where 12 months’ experience is not available, may include the costs for facilities for which either a permanent or temporary certificate has been granted, provided such facilities will be in service within the test period; or a certificate application is pending. The filing must identify facilities, related costs and the docket number of each such outstanding certificate. Subject to paragraph (c)(2) of this section, adjustments to base period experience, or to estimates where 12 months’ experience is not available, may include any amounts for facilities that require a certificate of public convenience and necessity, where a certificate has not been issued by the filing date but is expected to be issued before the end of the test period. Adjustments to base period may include costs for facilities that do not require a certificate and are in service by the end of the test period.
(2) When a pipeline files a motion to place the rates into effect, the filing must be revised to exclude the costs associated with any facilities that will not be in service as of the end of the test period, or for which certificate authorization is required but will not be granted as of the end of the test period. At the end of the test period, the pipeline must remove from its rates costs associated with any facility that is not in service or for which certificate authority is required but has not been granted.
(d) The Commission may allow reasonable deviation from the prescribed test period.
§ 154.304 Format of statements, schedules, workpapers and supporting data.
(a) All statements, schedules, and workpapers must be prepared in accordance with the Commission’s Uniform System of Accounts.
(b) The data in support of the proposed rate change must include the required particulars of book data, adjustments, and other computations and information on which the company relies, including a detailed narrative explanation placed at the beginning of the specific statement or schedule to which they apply, explaining each proposed adjustment to base period actual volumes and costs.
(c) Book data included in statements and schedules required to be prepared or submitted as part of the filing must be reported in a separate column or columns. All adjustments to book data must also be reported in a separate column or columns so that book amounts, adjustments thereto, and adjusted amounts will be clearly disclosed. All adjustments must be supported by a narrative explanation placed at the beginning of the specific statement or schedule to which they apply.
(d) Certain of the statements and schedules of § 154.313 are workpapers. Any data or summaries reflecting the books of account must be supported by accounting workpapers setting forth all necessary particulars from which an auditor may readily identify the book data included in the filing and verify that such data are in agreement with the company’s books of account.
§ 154.305 Tax normalization.
(a) Applicability. An interstate pipeline must compute the income tax component of its cost-of-service by using tax normalization for all transactions.
(b) Definitions. (1) Tax normalization means computing the income tax component as if transactions recognized in each period for ratemaking purposes are also recognized in the same amount and in the same period for income tax purposes.
(2) Commission-approved ratemaking method means a ratemaking method approved by the Commission in a final decision. This includes a ratemaking method that is part of an approved settlement or arbitration providing that the ratemaking method is to be effective beyond the term of the settlement or arbitration.
(3) Income tax purposes means for the purpose of computing actual income tax under the provisions of the Internal Revenue Code or the income tax provisions of the laws of a State or political subdivision of a State (including franchise taxes).
(4) Income tax component means that part of the cost-of-service that covers income tax expenses allowable by the Commission.
(5) Ratemaking purposes means for the purpose of fixing, modifying, accepting, approving, disapproving, or rejecting rates under the Natural Gas Act.
(6) Tax effect means the tax reduction or addition associated with a specific expense or revenue transaction.
(7) Transaction means an activity or event that gives rise to an accounting entry.
(c) Reduction of, and addition to, Rate Base. (1) The rate base of an interstate pipeline using tax normalization under this section must be reduced by the balances that are properly recordable in Account 281, “Accumulated deferred income taxes-accelerated amortization property”; Account 282, “Accumulated deferred income taxes—other property”: and Account 283, “Accumulated deferred income taxes—other.” Balances that are properly recordable in Account 190, “Accumulated deferred income taxes,” must be treated as an addition to rate base. Include, as an addition or reduction, as appropriate, amounts in Account 182.3, Other regulatory assets, and Account 254, Other regulatory liabilities, that result from a deficiency or excess in the deferred tax accounts (see paragraph (d) of this section) and which have been, or are soon expected to be, authorized for recovery or refund through rates.
(2) Such rate base reductions or additions must be limited to deferred taxes related to rate base, construction, or other costs and revenues affecting jurisdictional cost-of-service.
(d) Special rules. (1) This paragraph applies:
(i) If the rate applicant has not provided deferred taxes in the same amount that would have accrued had tax normalization always been applied; or
(ii) If, as a result of changes in tax rates, the accumulated provision for deferred taxes becomes deficient in, or in excess of, amounts necessary to meet future tax liabilities.
(2) The interstate pipeline must compute the income tax component in its cost-of-service by making provision for any excess or deficiency in deferred taxes.
(3) The interstate pipeline must apply a Commission-approved ratemaking method made specifically applicable to the interstate pipeline for determining the cost-of-service provision described in paragraph (d)(2) of this section. If no Commission-approved ratemaking method has been made specifically applicable to the interstate pipeline, then the interstate pipeline must use some ratemaking method for making such provision, and the appropriateness of such method will be subject to case-by-case determination.
(4) An interstate pipeline must continue to include, as an addition or reduction to rate base, any deficiency or excess attributable to prior flow-through or changes in tax rates (paragraphs (d)(1)(i) and (d)(1)(ii) of this section), until such deficiency or excess is fully amortized in accordance with a Commission approved ratemaking method.
§ 154.306 Cash working capital.
A natural gas company that files a tariff change under this part may not receive a cash working capital adjustment to its rate base unless the company or other participant in a rate proceeding under this part demonstrates, with a fully developed and reliable lead-lag study, a net revenue receipt lag or a net expense payment lag (revenue lead). Any demonstrated net revenue receipt lag will be credited to rate base; and, any demonstrated net expense payment lag will be deducted from rate base.
§ 154.307 Joint facilities.
The Statements required by § 154.312 must show all costs (investment, operation, maintenance, depreciation, taxes) that have been allocated to the natural gas operations involved in the subject rate change and are associated with joint facilities. The methods used in making such allocations must be provided.
§ 154.308 Representation of chief accounting officer.
The filing must include a statement executed by the chief accounting officer or other authorized accounting representative of the filing company representing that the cost statements, supporting data, and workpapers, that purport to reflect the books of the company do, in fact, set forth the results shown by such books.
§ 154.309 Incremental expansions.
(a) For every expansion for which incremental rates are charged, the company must provide a summary with applicable cross-references to § 154.312 and § 154.313, of the costs and revenues associated with the expansion, until the Commission authorizes the costs of the incremental facilities to be rolled-in to the pipeline’s rates. For every expansion that has an at-risk provision in the certificate authorization, the costs and revenues associated with the facility must be shown in summary format with applicable cross-references to § 154.312 and § 154.313, until the Commission removes the at-risk condition.
(b) The summary statements must provide the formulae and explain the bases used in the allocation of common costs to each incremental facility.
§ 154.310 Zones.
If the company maintains records of costs by zone, and proposes a zone rate methodology based on these costs, the statements and schedules in § 154.312 and § 154.313 must reflect costs detailed by zone.
§ 154.311 Updating of statements.
(a) Certain statements and schedules in § 154.312, that include test period data, must be updated with actual data by month and must be resubmitted in the same format and with consecutive monthly totals for each month of the adjustment period with a single set of updates encompassing a 12-month period. The updated statements or schedules must be filed 45 days after the end of the test period. The updated filing must be provided to parties specifically requesting them. The updated filing must reference the associated docket number and must be filed in the same format, form, and number as the original filing.
(b) The statements and schedules in § 154.312 to be updated are: Statements C, D and H–4; Schedules B–1, B–2, C–3, D–2, E–2, E–4, G–1, G–4, G–5, G–6, H–1 (1)(a), H–1 (1)(b), H–1 (1)(c), H–1 (2)(a) through H–1 (2)(k), H–2 (1), H–3 (3), I–4, and I–6.
(c) This requirement to file updates may be extended by the Secretary pursuant to § 375.302 of this chapter.
§ 154.312 Composition of Statements.
(a) Statement A. Cost-of-service Summary. Summarize the overall gas utility cost-of-service: operation and maintenance expenses, depreciation, taxes, credits to cost-of-service, and return as developed in other statements and schedules.
(b) Statement B. Rate Base and Return Summary. Summarize the overall gas utility rate base shown in Statements C, D, E, and Schedules B–1 and B–2. Show the application of the claimed rate of return to the overall rate base.
(1) Schedule B–1. Accumulated Deferred Income Taxes (Account Nos. 190, 282, and 283). Show monthly book balances of accumulated deferred income taxes for each of the 12 months during the base period. List all items for which the accumulated deferred income taxes are calculated. In adjoining columns, show additions and reductions for the adjustment period balance and the total adjusted balance. Separately identify the individual components and the amounts in these accounts that the company seeks to include in its rate base.
(2) Schedule B–2. Regulatory Asset and Liability. If the pipeline seeks recovery of such balances in rate base, show monthly book balances of regulatory assets (Account 182.3) and liabilities (Account 254) for each of the 12 months during the base period. In adjoining columns, show additions and reductions for the adjustment period balance and the total adjusted balance. Separately identify the individual components and the amounts in these accounts that the company seeks to include in its rate base. Identify any specific Commission authority that required the establishment of these amounts. Regulatory asset or liability net of deferred tax amounts should be included. Also, separately state the gross amounts of the regulatory asset and liability.
(c) Statement C. Cost of Plant Summary. Show the amounts of gas utility plant classified by Accounts 101, 102, 103, 104, 105, 106, 107, 117.1, and 117.2 as of the beginning of the 12 months of actual experience, the book additions and reductions (in separate columns) during the 12 months, and the book balances at the end of the 12-month period. In adjoining columns, show the claimed adjustments, if any, to the book balances and the total cost of plant to be included in rate base. For Account 117, also provide the volumes by subaccount. State the method used for accounting for system gas recorded in Account 117.2. Explain all adjustments in the following schedules.
(1) Schedule C–1. End of Base and Test Period Plant Functionalized. Demonstrate the ending base and test period balances for Plant in Service, in columnar form, by detailed plant account prescribed by the Commission’s Uniform System of Accounts for Natural Gas Companies (part 201 of this chapter) with subtotals by functional classifications, e.g., Intangible Plant, Manufactured Gas Production Plant, Natural Gas Production and Gathering Plant, Products Extraction Plant, Storage Plant, Transmission Plant, Distribution Plant, and General Plant. Show zones, to the extent required by § 154.310, and expansions, to the extent required by § 154.309. Separately identify those facilities and associated costs claimed for the test period that require certificate authority but such authority has not been obtained at the time of filing. Give the docket number of the certificate proceeding.
(2) Schedule C–2. Show, for Accounts 106 and 107, a list of work orders claimed in the rate base. Give the work order number, docket number, description, amount of each work order, and the amounts of each type of undistributed construction overhead. Work orders amounting to $500,000 or less may be grouped by category of items.
(3) Schedule C–3. A cross-reference to updated information in the company’s FERC Form No. 2 may be substituted for this Schedule. Give details of each storage project owned and storage projects under contract to the company, showing cost by major functions. Show base and system gas storage quantities and associated costs by account for the test period and for the 12 months of actual experience with monthly inputs and outputs to system gas.
(4) Schedule C–4. This schedule is part of the workpapers. State the methods and procedures followed in capitalizing the allowance for funds used during construction and other construction overheads. This schedule must be provided only in situations when the pipeline has changed any of its procedures since the last filed FERC Forms No. 2 or 2–A.
(5) Schedule C–5. This schedule is part of the workpapers. Set forth the cost of Plant in Service carried on the company’s books as gas utility plant which was not being used in rendering gas service. Describe the plant. This schedule must be provided only if there is a significant change of $500,000 or more since the end of the year reported in the company’s last FERC Form No. 2 or 2–A.
(d) Statement D. Accumulated Provisions for Depreciation, Depletion, and Amortization. Show the accumulated provisions for depreciation, depletion, amortization, and abandonment (Account 108, detailed by functional plant classification, and Account 111), as of the beginning of the 12 months of actual experience, the book additions and reductions during the 12 months, and the balances at the end of the 12-month period. In adjoining columns, show adjustments to these ending book balances and the total adjusted balances. All adjustments must be explained in the supporting material. Any authorized negative salvage must be maintained in a separate subaccount of account 108, and shall not include any amounts related to asset retirement obligations. For each functional plant classification, show depreciation reserve associated with offshore and onshore plant separately. The following schedules and additional material must be submitted as part of Statement D:
(1) Schedule D–1. This schedule is part of the workpapers. Show the depreciation reserve book balance applicable to that portion of the depreciation rate not yet approved by the Commission, the depreciation rates, the docket number of the order approving such rate, and an explanation of any difference. Reflect actual end of base period depreciation reserve functionalized and test period depreciation reserve functionalized. Show accumulated depreciation and amortization, in columnar form, for the ending base and test period balances by functional classifications of Accumulated Depreciation reserve. (Examples are provided in Schedule C–1). For each functional plant classification, show depreciation reserve associated with offshore and onshore plant separately.
(2) Schedule D–2. This schedule is part of the workpapers. Give a description of the methods and procedures used in depreciating, depleting, and amortizing plant and in recording abandonments. This schedule must be filed only if a policy change has been made effective since the period covered by the last annual report on FERC Form No. 2 or 2–A was filed with the Commission.
(e) Statement E. Working Capital. Show the components of working capital in sufficient detail to explain how the amount of each component was computed. Components of working capital, other than cash working capital, may include an allowance for the average of 13 monthly balances of materials and supplies and prepayments actually expended and gas for resale. To the extent the applicant files to adjust the average of any 13 monthly balances, workpapers must be submitted that support the adjustment(s). Show the computations, cross-references, and sources from which the data used in computing claimed working capital are derived. The following schedules and material must be submitted as part of Statement E:
(1) Schedule E–1. Show the computation of cash working capital claimed as an adjustment to the gas company’s rate base. Any adjustment to rate base requested must be based on a fully-developed and reliable lead-lag study. The components of the lead-lag study must include actual total company revenues, purchased gas costs, storage expense, transportation and compression of gas by others, salaries and wages, administrative and general expenses, income taxes payable, taxes other than income taxes, and any other operating and maintenance expenses for the base period. Cash working capital allowances in the form of additions to rate base may not exceed one-eighth of the annual operating expenses, as adjusted, net of non-cash items.
(2) Schedule E–2. Set forth monthly balances for materials, supplies, and prepayments in such detail as to disclose, either by subaccounts regularly maintained on the books or by analysis of the principal items included in the main account, the nature of such charges.
(3) Schedule E–3. For FERC Accounts 117.3, 164.1, 164.2 and 164.3, show the quantities and the respective costs of natural gas stored at the beginning of the test period, the input, output and balance remaining in Dth and associated costs by months. The method of pricing input, output and balance, and the claimed adjustments shall be disclosed and clearly and fully explained. Pipelines using the inventory method for system gas should not include any system gas inventory balances in this schedule.
(f) Statement F–1. Rate of Return Claimed. Show the percentage rate of return claimed and the general reasons therefor. Where any component of the capital of the filing company is not primarily obtained through its own financing, but is primarily obtained from a company by which the filing company is controlled, as defined in the Commission’s Uniform System of Accounts, then the data required by these statements must be submitted with respect to the debt capital, preferred stock capital, and common stock capital of such controlling company or any intermediate company through which such funds have been secured. Furnish the Commission staff a copy of the latest prospectus issued by the filing natural gas company, any superimposed holding company, or subsidiary companies.
(g) Statement F–2. Show
(1) The capitalization, capital structure, cost of debt capital, preferred stock capital, and the claimed return on stockholders’ equity;
(2) The weighted cost of each capital class based on the capital structure; and,
(3) The overall rate of return claimed.
(h) Statement F–3. Debt Capital. Show the weighted average cost of debt capital based upon the following data for each class and series of long-term debt outstanding according to the balance sheet, as of the end of the 12-month base period of actual experience and as of the end of the 9-month test period.
(1) Title.
(2) Date of issuance and date of maturity.
(3) Interest rate.
(4) Principal amount of issue: Gross proceeds; Underwriters’ discount or commission: Amount; Percent gross proceeds; Issuance expense: Amount; Percent gross proceeds; Net proceeds; Net proceeds per unit.
(5) Cost of money: Yield to maturity based on the interest rate and net proceeds per unit outstanding determined by reference to any generally accepted table of bond yields. The yield to maturity is to be expressed as a nominal annual interest rate. For example, for bonds having semiannual payments, the yield to maturity is twice the semiannual rate.
(6) If the issue is owned by an affiliate, state the name and relationship of the owner.
(7) If the filing company has acquired, at a discount or premium, some part of its outstanding debt which could be used in meeting sinking fund requirements, or for other reasons, separately show: The annual amortization of the discount or premium for each series of debt from the date of reacquisition over the remaining life of the debt being retired; and, the total discount and premium, as a result of such amortization, applicable to the test period.
(i) Statement F–4. Preferred Stock Capital. Show the weighted average cost of preferred stock capital based upon the following data for each class and series of preferred stock outstanding according to the balance sheet, as of the end of the 12-month base period of actual experience and as of the end of the nine-month test period.
(1) Title.
(2) Date of issuance.
(3) If callable, call price.
(4) If convertible, terms of conversion.
(5) Dividend rate.
(6) Par or stated amount of issue: Gross proceeds; Underwriters’ discount or commission: Amount; Percent gross proceeds; Issuance expenses: Amount; Percent gross proceeds; Net proceeds; Net proceeds per unit.
(7) Cost of money: Annual dividend rate divided by net proceeds per unit.
(8) State whether the issue was offered to stockholders through subscription rights or to the public.
(9) If the issue is owned by an affiliate, state the name and relationship of the owner.
(j) Statement G. Revenues, Credits, and Billing Determinants.
(1) Show in summary format the information requested below on revenues, credits and billing determinants for the base period and the base period as adjusted. Explain the basis for adjustment to the base period. The level of billing determinants should not be adjusted for discounting.
(i) Revenues. Provide the total revenues, from jurisdictional and non-jurisdictional services, classified in accordance with the Commission’s Uniform System of Accounts for the base period and for the base period as adjusted. Separate operating revenues by major rate component (e.g., reservation charges, demand charges, usage charges, commodity charges, injection charges, withdrawal charges, etc.) from revenues received from penalties, surcharges or other sources (e.g., ACA, GRI, transition costs). Show revenues by rate schedule and by receipt and delivery rate zones, if applicable. Show separately the revenues for firm services under contracts with a primary term of less than one year. For services provided through released capacity, identify total revenues by rate schedule and by receipt and delivery rate zones, if applicable.
(ii) Credits. Show the principal components comprising each of the various items which are reflected as credits to the cost-of-service in preparing Statement A, Overall Cost-of-service for the base period and the base period as adjusted. Any transition cost component of interruptible transportation revenue must not be treated as operating revenues as defined above.
(iii) Billing Determinants. Show total reservation and usage billing determinants for the base period and the base period as adjusted, by rate schedule by receipt and delivery rate zones, if applicable. Show separately the billing determinants for firm services under contracts with a primary term of less than one year. For services provided through released capacity, identify billing determinants by rate schedule and by receipt and delivery rate zones, if applicable.
(2) The Schedules G–1 through G–6 must be filed at the FERC and served on all state commissions having jurisdiction over the affected customers within fifteen days after the rate case is filed. Schedules G–1 through G–6 must also be served on parties that request such service within 15 days of the filing of the rate case.
(i) Schedule G–1. Base Period Revenues. For the base period, show total actual revenues and billing determinants by month by customer name, by rate schedule, by receipt and delivery zone, if applicable, by major rate component (e.g., reservation charges) and totals. Billing determinants must not be adjusted for discounting. Provide actual throughput (i.e., usage or commodity quantities, unadjusted for discounting) and actual contract demand levels (unadjusted for discounting). Provide this information separately for firm service under contracts with a primary term of less than one year. Separate operating revenues from revenues received from surcharges or other sources (e.g., ACA, GRI, transition costs). Identify customers who are affiliates. Identify rate schedules under which costs are allocated and rate schedules under which revenues are credited for the base period with cross-references to the other filed statements and schedules.
(ii) Schedule G–2. Adjustment Period Revenues.
(A) Show revenues and billing determinants by month, by customer name, by rate schedule, by receipt and delivery zone, if applicable, by major rate component (e.g., reservation charges) and totals for the base period adjusted for known and measurable changes which are expected to occur within the adjustment period computed under the rates expected to be charged. Billing determinants must not be adjusted for discounting. Provide projected throughput (i.e., usage or commodity quantities, unadjusted for discounting) and projected contract demand levels (unadjusted for discounting). Provide this information separately for firm service under contracts with a primary term of less than one year. Separate operating revenues from revenues received from surcharges or other sources (e.g., ACA, GRI, transition costs). Identify customers who are affiliates. Identify rate schedules under which costs are allocated and rate schedules under which revenues are credited for the adjustment period with cross-references to the other filed statements and schedules.
(B) Provide a reconciliation of the base period revenues and billing determinants and the revenues and billing determinants for the base period as adjusted.
(iii) Schedule G–3. Specify, quantify, and justify each proposed adjustment (capacity release, plant closure, contract termination, etc.) to base period actual billing determinants, and provide a detailed explanation for each factor contributing to the adjustment. Include references to any certificate docket authorizing changes. Submit workpapers with all formulae.
(iv) Schedule G–4. At-Risk Revenue. For each instance where there is a separate cost-of-service associated with facilities for which the applicant is “at risk,” show the base period and adjustment period revenue by customer or customer code, by rate schedule, by receipt and delivery zone, if applicable, and as 12-month totals. Provide this information by month unless otherwise agreed to by interested parties and if monthly reporting is consistent with past practice of the pipeline. However, if seasonal services are involved, or if billing determinants vary from month to month, the information must be provided monthly. Provide projected throughput (i.e., usage or commodity quantities, unadjusted for discounting) and projected contract demand levels (unadjusted for discounting).
(v) Schedule G–5. Other Revenues.
(A) Describe and quantify, by month, the types of revenue included in Account Nos. 490–495 for the base and test periods. Show revenues applicable to the sale of products. Show the principal components comprising each of the various items which are reflected as credits to cost-of-service in Statement A.
(B) To the extent the credits to the cost-of-service reflected in Statement A differ from the amounts shown on Schedule G–5, compare and reconcile the two statements. Quantify and explain each proposed adjustment to base period actuals. For Account No. 490, show the name and location of each product extraction plant processing gas for the applicant, and the inlet and outlet monthly dth of the pipeline’s gas at each plant. Show the revenues received by the applicant by product by month for each extraction plant for the base period and proposed for the test period.
(C) Separately state each item and revenue received for the transportation of liquids, liquefiable hydrocarbon, or nonhydrocarbon constituents owned by shippers. For both the base and test periods, indicate by shipper contract: The quantity transported and the revenues received.
(D) Separately state the revenues received from the release by the pipeline of transportation and compression capacity it holds on other pipeline systems. The revenues must equal the revenues reflected on Schedule I–4(iv).
(vi) Schedule G–6. Miscellaneous Revenues. Separately state by month the base and adjustment period revenues and the associated quantities received as penalties from jurisdictional customers; the revenues received from cash outs and other imbalance adjustments; and, the revenues received from exit fees.
(k) Statement H–1. Operation and Maintenance Expenses. Show the gas operation and maintenance expenses according to each applicable account of the Commission’s Uniform System of Accounts for Natural Gas Companies. Show the expenses under columnar headings, with subtotals for each functional classification, as follows: Operation and maintenance expense by months, as booked, for the 12 months of actual experience, and the 12-month total; adjustments, if any, to expenses as booked; and, total adjusted operation and maintenance expenses. Provide a detailed narrative explanation of, and the basis and supporting workpapers for, each adjustment. The following schedules and additional material must be submitted as part of Statement H–1:
(1) Schedule H–1 (1). This schedule is part of the workpapers. Show the labor costs, materials and other charges (excluding purchased gas costs) and expenses associated with Accounts 810, 811, and 812 recorded in each gas operation and maintenance expense account of the Uniform System of Accounts. Show these expenses, under the columnar headings, with subtotals for each functional classification, as follows: operation and maintenance expenses by months, as booked, for the 12 months of actual experience, and the 12-month total; adjustments, if any, to expenses as booked; and total adjusted operation and maintenance expenses. Disclose and explain all accrual on the books at the end of the base period or other normalizing accounting entries for internal purposes reflected in the monthly expenses presented per book. Explain any amounts not currently payable, except depreciation charged through clearing accounts, included in operation and maintenance expenses.
(2) Schedule H–1 (1)(a). Labor Costs.
(3) Schedule H–1 (1)(b). Materials and Other Charges (Excluding Purchased Gas Costs and items shown in Schedule H–1 (1)(c)).
(4) Schedule H–1 (1)(c). Quantities Applicable to Accounts Nos. 810, 811, and 812. Show the quantities for each of the contra-accounts for both base and test periods.
(5) Schedule H–1 (2). This schedule is part of the workpapers. Show, for the 12 months of actual experience and claimed adjustments: A classification of principal charges, credits and volumes; particulars of supporting computations and accounting bases; a description of services and related dollar amounts for which liability is incurred or accrued; and, the name of the firm or individual rendering such services. Expenses reported in Schedules H–1 (2)(a) through H–1 (2)(k) of $100,000 or less per type of service may be grouped.
(6) Schedule H–1 (2)(a). Accounts 806, 808.1, 808.2, 809.1, 809.2, 813, 823, and any other account used to record fuel use or gas losses. Provide details of each type of expense.
(7) Schedule H–1 (2)(b). Accounts 913 and 930.1. Advertising Expenses. Disclose principal types of advertising such as TV, newspaper, etc.
(8) Schedule H–1 (2)(c). Account 921. Office Supplies and Expenses.
(9) Schedule H–1 (2)(d). Account 922. Administrative Expenses Transferred Credit.
(10) Schedule H–1 (2)(e). Account 923. Outside Services Employed.
(11) Schedule H–1 (2)(f). Account 926. Employee Pensions and Benefits.
(12) Schedule H–1 (2)(g). Account 928. Regulatory Commission Expenses.
(13) Schedule H–1 (2)(h). Account 929. Duplicate Charges. Credit.
(14) Schedule H–1 (2)(i). Account 930.2. Miscellaneous General Expenses.
(15) Schedule H–1 (2)(j). Intercompany and Interdepartmental Transactions. Provide a complete disclosure of all corporate overhead allocated to the company. If the expense accounts contain charges or credits to and from associated or affiliated companies or nonutility departments of the company, submit a schedule, or schedules, as to each associated or affiliated company or nonutility department showing:
(i) The amount of the charges, or credits, during each month and in total for the base period and the adjustment period.
(ii) The FERC Account No. charged (or credited).
(iii) Descriptions of the specific services performed for, or by, the associated/affiliated company or nonutility department.
(iv) The bases used in determining the amounts of the charges (credits). Explain and demonstrate the derivation of the allocation bases with underlying calculations used to allocate costs among affiliated companies, and identify (by account number) all costs paid to, or received from affiliated companies which are included in a pipeline’s cost-of-service for both the base and test periods.
(16) Schedule H–1 (2)(k). Show all lease payments applicable to gas operation contained in the operation and maintenance accounts. Leases of $500,000 or less may be grouped by type of lease.
(l) Statement H–2. Depreciation, Depletion, Amortization and Negative Salvage Expenses. Show, separately, the gas plant depreciation, depletion, amortization, and negative salvage expenses by functional classifications. For each functional plant classification, show depreciation reserve associated with offshore and onshore plant separately. Show, in separate columns: expenses for the 12 months of actual experience; adjustments, if any, to such expense; and, the total adjusted expense claimed. Explain the bases, methods, essential computations, and derivation of unit rates for the calculation of depreciation, depletion, and amortization expense for the 12 months of actual experience and for the adjustments. The amounts of depreciable plant must be shown by the functions specified in paragraph C of Account 108, Accumulated Provisions for Depreciation of Gas Utility Plant, and Account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant, of the Commission’s Uniform System of Accounts for Natural Gas Companies, and, if available, for each detailed plant account (300 Series) together with the rates used in computing such expenses. Explain any deviation from the rates determined to be just and reasonable by the Commission. Show the rate or rates previously used together with supporting data for the new rate or rates used for this filing. The following schedule and additional material must be submitted as a part of Statement H–2:
(1) Schedule H–2 (1). Depreciable Plant.
(i) Reconcile the depreciable plant shown in Statement H–2 with the aggregate investment in gas plant shown in Statement C, and the expense charged to other than prescribed depreciation, depletion, amortization, and negative salvage expense accounts. Identify the amounts of plant costs and associated plant accounts used as the bases for depreciation expense charged to clearing accounts. For each functional plant classification, show depreciation reserve associated with offshore and onshore plant separately.
(ii) Schedule H–2 (1) must be updated, as set forth in § 154.310, with actual depreciable plant and reconciled with updated Statement C.
(m) Statement H–3. Income Taxes. Show the computation of allowances for Federal and State income taxes for the test period based on the claimed return applied to the overall gas utility rate base. To indicate the accounting classification applicable to the amount claimed, the computation of the Federal income tax allowance must show, separately, the amounts designated as current tax and deferred tax. Section 154.306, Tax Normalization, is incorporated in these instructions by reference. All the requirements of this section apply to Schedule H–3. The following schedules and additional material must be submitted as a part of Statement H–3:
(1) Schedule H–3 (1). This schedule is part of the workpapers. Show the income tax paid each State in the current and/or previous year covered by the test period.
(2) Schedule H–3 (2). This schedule is part of the workpapers. Show the computation of an updated reconciliation between book depreciable plant and tax depreciable plant and accumulated provision for deferred income taxes, for the base period or latest calendar or fiscal year (depending on the company’s reporting period). Regulatory asset or liability net of deferred tax amounts should be included in this reconciliation. Also, separately state the gross amounts of the regulatory asset and liability.
(n) Statement H–4. Other Taxes. Show the gas utility taxes, other than Federal or state income taxes, in separate columns, as follows: Tax expense per books for the 12 months of actual experience (separately identify the amounts expensed or accrued during the period); adjustments, if any, to amounts booked; and, the total adjusted taxes claimed. Show the kind and amount of taxes paid under protest or in connection with taxes under litigation. Show taxes by state and by type of tax. The following schedules and additional material must be submitted as a part of Statement H–4:
(1) Schedule H–4. This schedule is part of the workpapers. Show the computations of adjusted taxes claimed in Statement H(4).
(o) Statement I. Statement I consists of the following Schedules:
(1) Schedule I–1. Functionalization of Cost-of-service. Show the overall cost-of-service contained in Statement A as supported by Statements B, C, D, E, G (revenue credits), and H:
(i) Schedule I–1(a). Separate overall cost-of-service by function of facility.
(ii) Schedule I–1(b). Separate the transmission, storage, and gathering facilities between incremental and non-incremental facilities. If the pipeline proposes to directly assign the costs of specific facilities, it must provide a separate cost-of-service for every directly assigned facility (e.g., lateral or storage field).
(iii) Schedule I–1(c). If the pipeline maintains records of costs by zone and proposes a zone rate methodology based on those costs separately state transmission, storage, and gathering costs, for each zone.
(iv) Schedule I–1(d). Show the method used to allocate common and joint costs to various functions including the allocation of A&G. Provide the factors underlying the allocation of general costs (e.g., miles of pipe, cost of plant, labor). Show the formulae used and explain the bases for the allocation of common and joint costs.
(2) Schedule I–2. Classification of Cost-of-service.
(i) For each functionalized cost-of-service provided in Schedule I–1 (a), (b), and (c), show the classification of costs between fixed costs and variable costs and between reservation costs and usage costs. The classification must be for each element of the cost-of-service (e.g., depreciation expenses, state income taxes, revenue credits). For operation and maintenance expenses and revenue credits, the classification must be provided by account and by total.
(ii) Explain the basis for the classification of costs.
(iii) Explain any difference between the method for classifying costs and the classification method underlying the pipeline’s currently effective rates.
(3) Schedule I–3. Allocation of Cost-of-service.
(i) If the company provides gas sales and transportation as a bundled service, show the allocation of costs between direct sales or distribution sales and the other services. If the company provides unbundled transportation, show the allocation of costs between services with cost-of-service rates and services with market-based rates, including products extraction, sales, and company-owned production. If the cost-of-service is allocated among rate zones, show how the classified cost-of-service is allocated among rate zones by function. If the pipeline proposes to establish rate zones for the first time, or to change existing rate zone boundaries, explain how the rate zone boundaries are established.
(ii) Show how the classified costs of service provided in Schedule I–2 or Schedule I–3 (i) are allocated among the pipeline’s services and rate schedules.
(iii) Provide the formulae used in the allocation of the cost-of-service. Provide the factors underlying the allocation of the cost-of-service (e.g., contract demand, annual billing determinants, three-day peak). Provide the load factor or other basis for any imputed demand quantities.
(iv) Explain any changes in the basis for the allocation of the cost-of-service from the allocation methodologies underlying the currently effective rates.
(4) Schedule I–4. Transmission and Compression of Gas by Others (Account 858). Provide the following information for each transaction for the base and adjustment period:
(i) The name of the transporter.
(ii) The name of the rate schedule under which service is provided, and the expiration date of the contract.
(iii) Monthly usage volumes.
(iv) Monthly costs.
(v) The monthly revenues for volumes flowing under released capacity. The revenues in Schedule I–4 (iv) must also be reflected, separately, as a credit in Schedule G–5.
(5) Schedule I–5. Gas Balance. Show by months and total, for the 12 months of actual experience, the company’s Gas Account, in the form required by FERC Form No. 2 pages 520 and 521. Show corresponding estimated data, if claimed to be different from actual experience. Provide the basis for any variation between estimated and actual base period data.
(p) Statement J. Comparison and Reconciliation of Estimated Operating Revenues With Cost-of-service. Compare the total revenues by rate schedule (Schedule G–2) to the allocated cost-of-service (Statement I). Identify any surcharges that are reflected in Statement N or in Statement I.
(1) Schedule J–1. Summary of Billing Determinants. Provide a summary of all billing determinants used to derive rates. Provide a reconciliation of customers’ total billing determinants as shown on Schedule G–2 with those used to derive rates in Schedule J–2. Provide an explanation of how any discount adjustment is developed. If billing determinants are imputed for interruptible service, explain the method for calculating the billing determinants.
(2) Schedule J–2. Derivation of Rates. Show the derivation of each rate component of each rate. For each rate component of each rate schedule, include:
(i) A reference (by page, line, and column) to the allocated cost-of-service in Statement I.
(ii) A reference to the appropriate billing determinants in Schedule J–1.
(iii) Explain any changes in the method used for the derivation of rates from the method used in developing the underlying rates.
(q) Statement K. [Reserved]
(r) Statement L. Balance Sheet. Provide a balance sheet in the form prescribed by the Commission’s Uniform System of Accounts for Natural Gas Companies as of the beginning and end of the base period. Include any notes. If the natural gas company is a member of a group of companies, also provide a balance sheet on a consolidated basis.
(s) Statement M. Income Statement. Provide an income statement, including a section on earnings, in the form prescribed by the Commission’s Uniform System of Accounts for Natural Gas Companies for the base period. Include any notes. If the natural gas company is a member of a system group of companies, provide an income statement on a consolidated basis.
(t) Statement N. [Reserved]
(u) Statement O. Description of Company Operations. Provide a description of the company’s service area and diversity of operations. Include the following:
(1) Only if significant changes have occurred since the filing of the last FERC Form No. 2 or 2–A, provide a detailed system map.
(2) A list of each major expansion and abandonment since the company’s last general rate case. Provide brief descriptions, approximate dates of operation or retirement from service, and costs classified by functions.
(3) A detailed description of how the company designs and operates its systems. Include design temperature.
(v) Statement P. Explanatory Text and Prepared Testimony. Provide copies of prepared testimony indicating the line of proof which the company would offer for its case-in-chief in the event that the rates are suspended and the matter set for hearing. Name the sponsoring witness of all text and testimony. Statement P must be filed concurrently with the other schedules.
§ 154.313 Schedules for minor rate changes.
(a) A change in a rate or charge that, for the test period, does not increase the company’s revenues by the smaller of $1,000,000 or 5 percent is a minor rate change. A change in a rate level that does not directly or indirectly result in an increased rate or charge to any customer or class of customers is a minor rate change.
(b) In addition to the schedules in this section, filings for minor rate changes must include Statements L, M, O, P, I–1 through I–4, and J of § 154.312.
(c) The schedules of this section must contain the principal determinants essential to test the reasonableness of the proposed minor rate change. Any adjustments to book figures must be separately stated and the basis for the adjustment must be explained.
(d) Schedules B–1, B–2, C, D, E, H, H–2, and H–4 of § 154.313, must be updated with actual data by month and must be resubmitted in the same format and with consecutive 12 month running totals, for each month of the adjustment period. The updated statements or schedules must be filed 45 days after the end of the test period. The updated filing must reference the associated docket number and must be filed in the same format, form, and number as the original filing.
(e) Composition of schedules for minor rate changes.
(1) Schedule A. Overall Cost-of-service by Function. Summarize the overall cost-of-service (operation and maintenance expenses, depreciation, taxes, return, and credits to cost-of-service) developed from the supporting schedules below.
(2) Schedule B. Overall Rate Base and Return. Summarize the overall gas utility rate base by function. Include the claimed rate of return and show the application of the claimed rate of return to the overall rate base.
(3) Schedule B–1. Accumulated Deferred Income Taxes (Account Nos. 190, 281, 282, and 283). Show monthly book balances of accumulated deferred income taxes for each of the 12 months during the base period. In adjoining columns, show additions and reductions for the adjustment period balance and the total adjusted balance.
(4) Schedule B–2. Regulatory Asset and Liability. Show monthly book balances of regulatory asset (Account 182.3) and liability (Account 254) for each of the 12 months during the base period. In adjoining columns, show additions and reductions for the adjustment period balance and the total adjusted balance. Only include these accounts if recovery of these balances are reflected in the company’s costs. Identify the specific Commission authority which required the establishment of these accounts.
(5) Schedule C. Cost of Plant by Functional Classification as of the End of the Base and Adjustment Periods.
(6) Schedule D. Accumulated Provisions for Depreciation, Depletion, Amortization, and Abandonment by Functional Classifications as of the Beginning and as of the End of the Test Period.
(7) Schedule E. Working Capital. Show the various components provided for in § 154.312, Statement E.
(8) Schedule F. Show the rate of return claimed with a brief explanation of the basis.
(9) Schedule G. Revenues and Billing Determinants.
(i) Show in summary format the information requested below on revenues and billing determinants for the base period and the base period as adjusted. Schedule G must be submitted to all customers of the pipeline that received service during the base period or are expected to receive service during the base period as adjusted and on State commissions having jurisdiction over the affected customers.
(A) Revenues. Provide the total revenues by rate schedule from jurisdictional services, classified in accordance with the Commission’s Uniform System of Accounts for the base period and for the base period as adjusted. Separate operating revenues by major rate component (e.g., reservation charges, demand charges, usage charges, commodity charges, injection charges, withdrawal charges, etc.) from revenues received from penalties, surcharges or other sources (e.g., ACA, GRI, transition costs). For services provided through released capacity, identify total revenues by rate schedule and by receipt and delivery rate zones, if applicable.
(B) Billing Determinants. Show total reservation and usage billing determinants by rate schedule for the base period and the base period as adjusted. For services provided through released capacity, identify total billing determinants by rate schedule and by receipt and delivery rate zones, if applicable.
(ii) Schedule G–1 must be filed at the Commission and on all state commissions having jurisdiction over the affected customers within 15 days after the rate case is filed. Schedule G–1 must also be served on parties that request such service within 15 days of the filing of the rate case.
(A) Schedule G–1. Adjustment Period Revenues.
(1) Show revenues and billing determinants by month, by customer name, by rate schedule, by major rate component (e.g., reservation charges) and totals for the base period adjusted for known and measurable changes which are expected to occur within the adjustment period computed under the rates expected to be charged. Show commodity billing determinants by rate schedule. Billing determinants must not be adjusted for discounting. Provide projected throughput (i.e., usage or commodity quantities, unadjusted for discounting) and projected contract demand levels (unadjusted for discounting). Separate operating revenues from revenues received from surcharges or other sources (e.g., ACA, GRI, transition costs). Identify customers who are affiliates. Identify rate schedules under which costs are allocated and rate schedules under which revenues are credited for the adjustment period with cross-references to the other filed statements and schedules.
(2) Provide a reconciliation of the base period revenues and billing determinants and the revenues and billing determinants for the base period as adjusted.
(10) Schedule H. Operation and Maintenance Expenses. Show the gas operation and maintenance expenses according to each applicable account of the Commission’s Uniform System of Accounts for Natural Gas Companies. The expenses must be shown under appropriate columnar-headings, by labor, materials and other charges, and purchased gas costs, with subtotals for each functional classification: Operation and maintenance expense by months, as booked, for the 12 months of actual experience, and the total thereof; adjustments, if any, to expenses as booked; and, total adjusted operation and maintenance expenses claimed. Explain all adjustments. Specify the month or months during which the adjustments would be applicable.
(11) Schedule H–1. Workpapers for Expense Accounts. Furnish workpapers for the 12 months of actual experience and claimed adjustments and analytical details as set forth in § 154.312, Schedule H–1 (3).
(12) Schedule H–2. Depreciation, Depletion, Amortization and Negative Salvage Expenses. Show, separately, the gas plant depreciation, depletion, amortization, and negative salvage expenses by functional classifications. For each functional plant classification, show depreciation reserve associated with offshore and onshore plant separately. The bases, methods, essential computations, and derivation of unit rates for the calculation of depreciation, depletion, amortization, and negative salvage expenses for actual experience must be explained.
(13) Schedule H–3. Income Tax Allowances Computed on the Basis of the Rate of Return Claimed. Show the computation of allowances for Federal and State income taxes based on the claimed return applied to the overall gas utility rate base.
(14) Schedule H–3 (1). This schedule is part of the workpapers. Show the computation of an updated reconciliation between book depreciable plant and tax depreciable plant and accumulated provision for deferred income taxes, for the base period or latest calendar or fiscal year (depending on the company’s reporting period).
(15) Schedule H–4. Other Taxes. Show the gas utility taxes, other than Federal or state income taxes in separate columns, as follows: Tax expense per books for the 12 months of actual experience;) adjustments, if any, to amounts booked; and, the total adjusted taxes claimed. Provide the details of the kind and amount of taxes paid under protest or in connection with taxes under litigation. The taxes must be shown by states and by kind of taxes. Explain all adjustments.
§ 154.314 Other support for a filing.
(a) Any company filing for a rate change is responsible for preparing prior to filing, and maintaining, workpapers sufficient to support the filing.
(b) If the natural gas company has relied upon data other than those in Statements A through P in § 154.312 in support of its general rate change, such other data must be identified and submitted.
§ 154.315 Asset retirement obligations.
(a) A natural gas company that files a tariff change under this part and has recorded an asset retirement obligation on its books must provide a schedule, as part of the supporting workpapers, identifying all cost components related to the asset retirement obligations that are included in the book balances of all accounts reflected in the cost of service computation supporting the proposed rates. However, all cost components related to asset retirement obligations that would impact the calculation of rate base, such as gas plant and related accumulated depreciation and accumulated deferred income taxes, may not be reflected in rates and must be removed from the rate base calculation through a single adjustment.
(b) A natural gas company seeking to recover nonrate base costs related to asset retirement obligations in rates must provide, with its filing under § 154.312 or § 154.313, a detailed study supporting the amounts proposed to be collected in rates.
(c) A natural gas company who has recorded asset retirement obligations on its books but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations related cost components from the cost of service supporting its proposed rates.
Subpart E—Limited Rate Changes
§ 154.400 Additional requirements.
In addition to the requirements of subparts A, B, and C of this part, any proposal to implement a limited rate change must comply with this subpart.
§ 154.401 RD&D expenditures.
(a) Requirements. Upon approval by the Commission, a natural gas company may file to recover research, development, and demonstration (RD&D) expenditures in its rates under this subpart.
(b) Applications for rate treatment approval. (1) An application for advance approval of rate treatment may be filed by a natural gas company for RD&D expenditures related to a project or group of projects undertaken by the company or as part of a project undertaken by others. When more than one company supports an RD&D organization, the RD&D organization may submit an application that covers the organization’s RD&D program. Approval by the Commission of such an RD&D application and program will constitute approval of the individual companies’ contributions to the RD&D organization.
(2) An application for advance approval of rate treatment must include a 5-year program plan and must be filed at least 180 days prior to the commencement of the 5-year period of the plan.
(3) A 5-year program plan must include at a minimum:
(i) A statement of the objectives for the 5-year period that relates the objectives to the interests of ratepayers, the public, and the industry and to the objectives of other major research organizations.
(ii) Budget, technical, and schedule information in sufficient detail to explain the work to be performed and allow an assessment of the probability of success and a comparison with other organizations’ research plans.
(iii) The commencement date, expected termination date, and expected annual costs for individual RD&D projects to be initiated during the first year of the plan.
(iv) A discussion of the RD&D efforts and progress since the preparation of the program plan submitted the previous year and an explanation of any changes that have been made in objectives, priorities, or budgets since the plan of the previous year.
(v) A statement identifying all jurisdictional natural gas companies that will support the program and specifying the amounts of their budgeted support.
(vi) A statement identifying those persons involved in the development, review, and approval of the plan and specifying the amount of effort contributed and the degree of control exercised by each.
(c) Applications must describe the RD&D projects in such detail as to satisfy the Commission that the RD&D expenditures qualify as valid, justifiable, and reasonable.
(d) Within 120 days of the filing of an application for rate treatment approval and a 5-year program plan, the Commission will state its decision with respect to acceptance, partial acceptance, or rejection of the plan, or, when the complexity of issues in the plan so requires, will set a date certain by which a final decision will be made, or will order the matter set for hearing. Partial rejection of a plan by the Commission will be accompanied by a decision as to the partial level of acceptance which will be proportionally applied to all contributions listed for jurisdictional companies in the plan. Approval by the Commission of a 5-year plan constitutes approval for rate treatment of all projects identified as starting during the first year of the approved plan. Continued rate treatment will depend upon review and evaluation of subsequent annual applications and 5-year program plans.
§ 154.402 ACA expenditures.
(a) Requirements. Upon approval by the Commission, a natural gas pipeline company may adjust its rates, annually, to recover from its customers annual charges assessed by the Commission under part 382 of this chapter pursuant to an annual charge adjustment clause (ACA clause). Prior to the start of each fiscal year, the Commission will post on its Web site the amount of annual charges to be flowed through per unit of energy sold or transported (ACA unit charge) for that fiscal year. A company’s ACA clause must be filed with the Commission and must incorporate by reference the ACA unit charge for the upcoming fiscal year as posted on the Commission’s Web site. A company must incorporate by reference the ACA unit charge posted on the Commission’s Web site in each of its rate schedules applicable to sales or transportation deliveries. The company must apply the ACA unit charge posted on the Commission’s Web site to the usage component of rate schedules with two-part rates. A company may recover annual charges through an ACA unit charge only if its rates do not otherwise reflect the costs of annual charges assessed by the Commission under § 382.106(a) of this chapter. The applicable annual charge, required by § 382.103 of this chapter, must be paid before the company applies the ACA unit charge. Upon payment to the Commission of its annual charges, the ACA unit charge for that fiscal year will be incorporated by reference into the company’s tariff, effective throughout that fiscal year.
(b) Application for rate treatment authorization. A company seeking authorization to use an ACA unit charge must file with the Commission a separate ACA tariff record containing:
(1) A statement that the company is collecting an ACA unit charge, as calculated by the Commission, applicable to all the pipeline’s sales and transportation rate schedules,
(2) A statement that the ACA unit charge, as revised annually and posted on the Commission’s Web site, is incorporated by reference into the company’s tariff,
(3) For companies with existing ACA clauses, a proposed effective date of the tariff change of October 1 of the fiscal year; for companies seeking to utilize an ACA clause after October 1 of the fiscal year, a proposed effective date 30 days after the filing of the tariff record, unless a shorter period is specifically requested in a waiver petition and approved), and
(4) A statement that the pipeline will not recover any annual charges recorded in FERC Account 928 in a proceeding under subpart D of this part.
(c) Changes to the ACA unit charge must be filed annually, to reflect the annual charge unit rate authorized by the Commission each fiscal year.
§ 154.403 Periodic rate adjustments.
(a) This section applies to the passthrough, on a periodic basis, of a single cost item or revenue item for which passthrough is not regulated under another section of this subpart, and to revisions on a periodic basis of a gas reimbursement percentage.
(b) Where a pipeline recovers fuel use and unaccounted-for natural gas in kind, the fuel reimbursement percentage must be stated in the tariff either on the tariff sheet stating the currently effective rate or on a separate tariff sheet or section in such a way that it is clear what amount of natural gas must be tendered in kind for each service rendered.
(c) A natural gas company that passes through a cost or revenue item or adjusts its fuel reimbursement percentage under this section, must state within the general terms and conditions of its tariff, the methodology and timing of any adjustments. The following must be included in the general terms and conditions:
(1) A statement of the nature of the revenue or costs to be flowed through to the customer;
(2) A statement of the manner in which the cost or revenue will be collected or returned, whether through a surcharge, offset, or otherwise;
(3) A statement of which customers are recipients of the revenue credit and which rate schedules are subject to the cost or fuel reimbursement percentage;
(4) A statement of the frequency of the adjustment and the dates on which the adjustment will become effective;
(5) A step-by-step description of the manner in which the amount to be flowed through is calculated and a step-by-step description of the flowthrough mechanism, including how the costs are classified and allocated. Where the adjustment modifies a rate established under subpart D of this part, the methodology must be consistent with the methodology used in the proceeding under subpart D of this part;
(6) Where costs or revenue credits are accumulated over a past period for periodic recovery or return, the past period must be defined and the mechanism for the recovery or return must be detailed on a step-by-step basis. Where the natural gas company proposes to use a surcharge to clear an account in which the difference between costs or revenues, recovered through rates, and actual costs and revenues accumulate, a statement must be included detailing, on a step-by-step basis, the mechanism for calculating the entries to the account and for passing through the account balance.
(7) Where carrying charges are computed, the calculations must be consistent with the methodology and reporting requirements set forth in § 154.501 using the carrying charge rate required by that section. A natural gas company must normalize all income tax timing differences which are the result of differences between the period in which expense or revenue enters into the determination of taxable income and the period in which the expense or revenue enters into the determination of pre-tax book income. Any balance upon which the natural gas company calculates carrying charges must be adjusted for any recorded deferred income taxes.
(8) Where the natural gas company discounts the rate component calculated pursuant to this section, explain on a step-by-step basis how the natural gas company will adjust for rate discounts in its methodology to reflect changes in costs under this section.
(9) If the costs passed through under a mechanism approved under this section are billed by an upstream natural gas company, explain how refunds received from upstream natural gas companies will be passed through to the natural gas company’s customers, including the allocation and classification of such refunds;
(10) A step-by-step explanation of the methodology used to reflect changes in the fuel reimbursement percentage, including the allocation and classification of the fuel use and unaccounted-for natural gas. Where the adjustment modifies a fuel reimbursement percentage established under subpart D of this part, the methodology must be consistent with the methodology used in the proceeding under subpart D of this part;
(11) A statement of whether the difference between quantities actually used or lost and the quantities retained from the customers for fuel use and loss will be recovered or returned in a future surcharge. Include a step-by-step explanation of the methodology used to calculate such surcharge. Any period during which these differences accumulate must be defined.
(d) Filing requirements. (1) Filings under this section must include:
(i) A summary statement showing the rate component added to each rate schedule with workpapers showing all mathematical calculations.
(ii) If the filing establishes a new fuel reimbursement percentage or surcharge, include computations for each fuel reimbursement or surcharge calculated, broken out by service, classification, area, zone, or other subcategory.
(iii) Workpapers showing the allocation of costs or revenue credits by rate schedule and step-by-step computations supporting the allocation, segregated into reservation and usage amounts, where appropriate.
(iv) Where the costs, revenues, rates, quantities, indices, load factors, percentages, or other numbers used in the calculations are publicly available, include references by source.
(v) Where a rate or quantity underlying the costs or revenue credits is supported by publicly available data (such as another natural gas company’s tariff or EBB), the source must be referenced to allow the Commission and interested parties to review the source. If the rate or quantity does not match the rate or quantity from the source referenced, provide step-by-step instructions to tie the rate in the referenced source to the rate in the filing.
(vi) Where a number is derived from another number by applying a load factor, percentage, or other adjusting factor not referenced in paragraph (d)(1)(i) of this section, include workpapers and a narrative to explain the calculation of the adjusting factor.
(2) If the natural gas company is adjusting its rates to reflect changes in transportation and compression costs paid to others:
(i) The changes in transportation and compression costs must be based on the rate on file with the Commission. If the rate is not on file with the Commission or a discounted rate is paid, the rate reflected in the filing must be the rate the natural gas company is contractually obligated to pay;
(ii) The filing must include appropriate credits for capacity released under § 284.243 of this chapter with workpapers showing the quantity released, the revenues received from the release, the time period of the release, and the natural gas pipeline on which the release took place; and,
(iii) The filing must include a statement of the refunds received from each upstream natural gas company which are included in the rate adjustment. The statement must conform to the requirements set forth in § 154.501.
(3) If the natural gas company is reflecting changes in its fuel reimbursement percentage, the filing must include:
(i) A summary statement of actual gas inflows and outflows for each month used to calculate the fuel reimbursement percentage or surcharge. For purposes of establishing the surcharge, the summary statement must be included for each month of the period over which the differences defined in paragraph (c) of this section accumulate.
(ii) Where the fuel reimbursement percentage is calculated based on estimated activity over a future period, the period must be defined and the estimates used in the calculation must be justified. If any of the estimates are publicly available, include a reference to the source.
(4) The natural gas company must not recover costs and is not obligated to return revenues which are applicable to the period pre-dating the effectiveness of the tariff language setting forth the periodic rate change mechanism, unless permitted or required to do so by the Commission.
Subpart F—Refunds and Reports
§ 154.501 Refunds.
(a) Refund Obligation. (1) Any natural gas company that collects rates or charges pursuant to this chapter must refund that portion of any increased rates or charges either found by the Commission not to be justified, or approved for refund by the Commission as part of a settlement, together with interest as required in paragraph (d) of this section. The refund plus interest must be distributed as specified in the Commission order requiring or approving the refund, or if no date is specified, within 60 days of a final order. For purposes of this paragraph, a final order is an order no longer subject to rehearing. The pipeline is not required to make any refund until it has collected the refundable money through its rates.
(2) Any natural gas company must refund to its jurisdictional customers the jurisdictional portion of any refund it receives which is required by prior Commission order to be flowed through to its jurisdictional customers or represents the refund of an amount previously included in a filing under § 154.403 and charged and collected from jurisdictional customers within thirty days of receipt or other time period established by the Commission or as established in the pipeline’s tariff.
(b) Costs of Refunding. Any natural gas company required to make refunds pursuant to this section must bear all costs of such refunding.
(c) Supplier Refunds. The jurisdictional portion of supplier refunds (including interest received), applicable to periods in which a purchased gas adjustment clause was in effect, must be flowed through to the natural gas company’s jurisdictional gas sales customers during that period with interest as computed in paragraph (d) of this section.
(d) Interest on Refunds. Interest on the refund balance must be computed from the date of collection from the customer until the date refunds are made as follows:
(1) At an average prime rate for each calendar quarter on all excessive rates or charges held (including all interest applicable to such rates and charges) on or after October 1, 1979. The applicable average prime rate for each calendar quarter must be the arithmetic mean, to the nearest one-hundredth of one percent, of the prime rate values published in the Federal Reserve Bulletin, or in the Federal Reserve’s “Selected Interest Rates” (Statistical Release G, 13), for the fourth, third, and second months preceding the first month of the calendar quarter.
(2) The interest required to be paid under paragraph (d)(1) of this section must be compounded quarterly.
(3) The refund balance must be either:
(i) The revenues resulting from the collection of the portion of any increased rates or charges found by the Commission not to be justified; or
(ii) An amount agreed upon in a settlement approved by the Commission; or
(iii) The jurisdictional portion of a refund the natural gas company receives.
(e) Unless otherwise provided by the order, settlement or tariff provision requiring the refund, the natural gas company must file a report of refunds, within 30 days of the date the refund was made, which complies with § 154.502 and includes the following:
(1) Workpapers and a narrative sufficient to show how the refunds for jurisdictional services were calculated;
(2) Workpapers and a narrative sufficient to determine the origin of the refund, including step-by-step calculations showing the derivation of the refund amount described in paragraph (d)(3) of this section, if necessary;
(3) References to any publicly available sources which confirm the rates, quantities, or costs, which are used to calculate the refund balance or which confirm the refund amount itself. If the rate, quantity, cost or refund does not directly tie to the source, a workpaper must be included to show the reconciliation between the rate, quantity, cost, or refund in the natural gas company’s report and the corresponding rate, quantity, cost or refund in the source document;
(4) Workpapers showing the calculation of interest on a monthly basis, including how the carrying charges were compounded quarterly;
(5) Workpapers and a narrative explaining how the refund was allocated to each jurisdictional customer. Where the numbers used to support the allocation are publicly available, a reference to the source must be included. Where the allocation methodology has been approved previously, a reference to the order or tariff provision approving the allocation methodology must be included.
(6) A letter of transmittal containing:
(i) A list of the material enclosed;
(ii) The name and telephone number of a company official who can answer questions regarding the filing;
(iii) A statement of the date the refund was disbursed;
(iv) A reference to the authority by which the refund is made, including the specific subpart of these regulations, an order of the Commission, a provision of the company’s tariff, or any other appropriate authority. If a Commission order is referenced, include the citation to the FERC Reports, the date of issuance, and the docket number;
(v) Any requests for waiver. Requests must include a reference to the specific section of the statute, regulations, or the company’s tariff from which waiver is sought, and a justification for the waiver.
(7) A certification of service to all affected customers and interested state commissions.
(f) Each report filed under paragraph (e) of this section must be posted no later than the date of filing. Each report must be posted to all recipients of a share of the refund and all state commissions whose jurisdiction includes the location of any recipient of a refund share that have made a standing request for such full report.
(g) Recipients of refunds and state commissions that have not made a standing request for such full report shall receive an abbreviated report consisting of the items listed in § 154.501 (e)(5) and (e)(6).
§ 154.502 Reports.
(a) When the natural gas company is required, either by a Commission order or as a part of a settlement in a proceeding initiated under this part 154 or part 284 of this chapter, to make a report on a periodic basis, details about the nature and contents of the report must be provided in an appropriate section of the general terms and conditions of its tariff.
(b) The details in the general terms and conditions of the tariff must include the frequency and timing of the report. Explain whether the report is filed annually, semi-annually, monthly, or is triggered by an event. If triggered by an event, explain how soon after the event the report must be filed. If the report is periodic, state the dates on which the report must be filed.
(c) Each report must include:
(1) A letter of transmittal containing:
(i) A list of the material enclosed;
(ii) The name and telephone number of a company official who can answer questions regarding the filing;
(iii) A reference to the authority by which the report is made, including the specific subpart of these regulations, an order of the Commission, a provision of the company’s tariff, or any other appropriate authority. If a Commission order is referenced, include the citation to the FERC Reports, the date of issuance, and the docket number;
(iv) Any requests for waiver. Requests must include a reference to the specific section of the statute, regulations, or the company’s tariff from which waiver is sought, and a justification for the waiver.
(2) A certification of service to all affected customers and interested state commissions.
(d) Each report filed under paragraph (b) of this section must be posted no later than the date of filing.
Subpart G—Other Tariff Changes
§ 154.600 Compliance with other subparts.
Any proposal to implement a tariff change other than in rate level must comply with subparts A, B, and C of this part.
§ 154.601 Change in executed service agreement.
Agreements intended to effect a change or revision of an executed service agreement on file with the Commission must be in the form of a superseding executed service agreement only. Service agreements may not contain any supplements, but may contain exhibits which may be separately superseded. The exhibits may show, among other things, contract demand delivery points, delivery pressures, names of industrial customers of the distributor-customer, or names of distributors (with one distributor named as agent where delivery to several distributors is effected at the same delivery points).
§ 154.602 Cancellation or termination of a tariff, executed service agreement or part thereof.
When an effective tariff, contract, or part thereof on file with the Commission, is proposed to be canceled or is to terminate by its own terms and no new tariff, executed service agreement, or part thereof, is to be filed in its place, the natural gas company must notify the Commission of the proposed cancellation or termination , at least 30 days prior to the proposed effective date of such cancellation or termination. With such notice, the company must submit a statement showing the reasons for the cancellation or termination, a list of the affected customers and the contract demand provided to the customers under the service to be canceled. A copy of the notice must be duly posted tariff filing in the electronic format required by § 154.4.
§ 154.603 Adoption of the tariff by a successor.
Whenever the tariff or contracts of a natural gas company on file with the Commission is to be adopted by another company or person as a result of an acquisition, or merger, authorized by a certificate of public convenience and necessity, or for any other reason, the succeeding company must file with the Commission, and post within 30 days after such succession, a tariff filing in the electronic format required by § 154.4 bearing the name of the successor company.
PART 156—APPLICATIONS FOR ORDERS UNDER SECTION 7(a) OF THE NATURAL GAS ACT
§ 156.1 Who may apply.
Any person or municipality as defined in section 2 of the Natural Gas Act engaged or legally authorized to engage in the local distribution of natural or artificial gas to the public may file with the Commission an application pursuant to the provisions of section 7(a) of the Natural Gas Act for an order of the Commission directing a natural gas company to extend or improve its transportation facilities, to establish physical connection of its transportation facilities with the facilities of, and sell natural gas to such person or municipality, and for such purpose to extend its transportation facilities to communities immediately adjacent to such facilities or to territory served by such natural gas company.
§ 156.2 Purpose and intent of rules.
(a) Applications filed pursuant to the provisions of section 7(a) of the Natural Gas Act shall contain all information necessary to advise the Commission fully concerning the applicant, the service which applicant requests the Commission to direct the natural gas company to render together with a description of any improvement or extension of facilities which the natural gas company would be required to make in connection with the rendition of the service, applicant’s present and proposed operations, construction, service, and sales together with a description of any extension or improvement of facilities by applicant which would be required to enable applicant to engage in the local distribution of natural gas.
(b) Every requirement of this part shall be considered as an obligation upon the applicant which can be avoided only by a definite and positive showing that the information or data required by the applicable section of the regulations is not necessary to the consideration and ultimate determination of the application.
(c) This part will be strictly applied to all applications as submitted and the burden of adequate presentation in understandable form as well as justification for omitted data or information rests with the applicant.
(d) Under this part, the natural gas company from which applicant is seeking the service is a party respondent to the proceeding.
§ 156.3 Applications; general requirements.
(a) Applicable rules. The application must be filed with the Secretary of the Commission in accordance with filing procedures posted on the Commission’s Web site at http://www.ferc.gov. In all other respects applications shall conform to the requirements of §§ 156.1 through 156.5. Amendments to or withdrawals of applications shall be filed in accordance with the requirements of §§ 385.213 and 385.214 of this chapter.
(b) General content of application; filing fee. Except as provided in paragraph (d) of this section, each application shall set forth the following information:
(1) The exact legal name of the applicant; the name of the natural gas company (respondent) from which applicant is seeking an extension or improvement of transportation facilities, physical connection of facilities or service of natural gas together with a concise description of the extension, improvement, physical connection of facilities or service sought from such company including the estimated volumes of natural gas involved to meet annual and maximum day requirements for the estimated first three years of proposed operation.
(2) Applicant’s principal place of business; whether applicant is an individual, corporation or municipality as defined in section 2 of the Natural Gas Act; State under the laws of which applicant is incorporated, organized or authorized; and the name, title, and mailing address of the person or persons to whom communications concerning the application are to be addressed.
(3) The facts relied upon by applicant to show that the proposed extension or improvement of transportation facilities, physical connection of facilities or service and sale of natural gas are necessary or desirable in the public interest.
(4) A concise description of applicant’s operations, if any, at the time the application is filed.
(5) A concise description of applicant’s proposed operations, construction, service and sales together with a description of any extension or improvement of facilities by applicant which would be required to enable applicant to engage in the local distribution of natural gas and including the proposed dates for the beginning and completion of construction and commencement of operations.
(6) A full statement concerning and description of any certificate of public convenience and necessity, franchise or other authorization which applicant has applied for or received from any State commission or municipality covering its proposed operations.
(7) A full statement as to whether any other application must be or is to be filed by applicant with any other Federal or State body, or other political subdivision or agency of a State to enable applicant to engage in the local distribution of natural gas in the territory it proposes to serve.
(8) Each application shall contain a table of contents which shall list all exhibits and documents filed in compliance with §§ 156.1 through 156.2, as well as other documents and exhibits filed therewith, identifying them by their appropriate titles and alphabetical letter designations specified in § 156.5. The alphabetical designation specified in § 156.5 must be adhered to strictly and any additional exhibits submitted on applicant’s own volition, pursuant to § 156.5(b) shall be designated in sequence under the letter designation Z (Z1, Z2, Z3, etc.). Together with each exhibit applicant shall set forth a full and complete explanation of the data submitted, the manner in which it was obtained, and the reasons for the conclusions which are derived therefrom.
(c) Incorporation by reference. Any information required by this part which is already on file with the Commission may be incorporated by reference.
(d) Small distributors. A distributor requesting natural gas service of less than 2000 Mcf per day to serve a single community may file the information required by the form of application represented in § 250.6 of this chapter.
§ 156.4 Form of exhibits to be attached to applications.
(a) General requirements. Each exhibit shall contain a title page showing applicant’s name, Docket No. CP– ______ (number designation to be left blank), title of exhibit, and if exhibit consists of 10 or more pages a table of contents citing by page, section number or subdivision the component elements or matters contained therein.
(b) Measurement base. All gas volumes shall be stated upon a uniform basis of measurement, and, in addition, if the uniform basis of measurement used in any application is other than 14.73 p.s.i.a., then the volume or volumes of natural gas to be received from any source and delivered by applicant shall also be stated upon a basis of 14.73 p.s.i.a. Similarly, total volumes on all summary sheets, as well as grand totals of volumes in any exhibit, shall also be stated upon a basis of 14.73 p.s.i.a. if the basis of measurement used is other than 14.73 p.s.i.a.
§ 156.5 Exhibits.
(a) Exhibits to be submitted with application. All of the following exhibits shall be submitted with the application when tendered for filing. Such exhibits may be attached to the application or furnished in a separate volume or separate volumes designated “Exhibits to Application.” Such separate volume or volumes shall indicate on the cover thereof applicant’s name and bear Docket No. CP– ______ (number designation to be left blank).
(1) Exhibit A—Articles of incorporation and bylaws. If applicant is not an individual, a conformed copy of its articles of incorporation and bylaws, or other similar documents. One certified copy shall be submitted with the original application.
(2) Exhibit B—State and local authorizations. (i) A copy of any certificate of public convenience and necessity or similar authorization which applicant has obtained from the State commission or commissions of each of the States in which applicant engages or proposes to engage in the local distribution of natural gas; (ii) a copy of any franchise or similar authorization which applicant has obtained from each of the municipalities in which applicant engages or proposes to engage in the local distribution of natural gas; and (iii) a copy of any other authorization or form of consent which applicant has obtained from any State, State commission, municipality or from any agency of the Federal government necessary or incidental to applicant’s proposal to engage in the local distribution of natural gas. One certified copy of each of the documents specified in paragraphs (a)(2) (i), (ii), and (iii) of this section shall be submitted as exhibits to the original application.
(3) Exhibit C—Officials. A list of the names and business addresses of applicant’s officers and directors, or similar officials if applicant is not a corporation.
(4) Exhibit D—Subsidiaries and affiliation. If applicant or any of its officers or directors, directly or indirectly, owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of any other person or organized group of persons engaged in production, transportation, distribution, or sale of natural gas, or of any person or organized group of persons engaged in the construction or financing of such enterprises or operations, a detailed explanation of each such relationship, including the percentage of voting strength represented by such ownership of securities. If any persons or organized group of persons, directly or indirectly, owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of applicant—give a detailed explanation of each such relationship.
(5) Exhibit F—Location of facilities. A geographical map of suitable scale and detail showing all of the transmission facilities proposed to be installed and operated by Applicant between distribution systems of Applicant and the transmission pipeline system of the proposed supplier (respondent), and include:
(i) Location, length, and size of applicant’s transmission pipelines.
(ii) Location and size (related horsepower) of applicant’s transmission compressor stations.
(iii) Location and designation of each point of connection of applicant’s proposed transmission facilities with (a) proposed pipeline supplier (respondent) main line industrial customers, gas pipeline or distribution systems, showing towns and communities to be served, and (b) gas producing and storage filed, or other sources of supply.
(iv) Location, length and size of facilities required to be installed by the proposed supplier (respondent) necessary for the rendition of service requested by the applicant.
(6) Exhibit G—Flow diagram showing daily design capacity and reflecting operation with proposed transmission facilities. A flow diagram showing daily design capacity of all transmission facilities proposed to be installed and operated by applicant between distribution facilities of applicant and the transmission pipeline system of the proposed supplier (respondent) including the following:
(i) Diameter, wall thickness, and length of pipe to be installed.
(ii) For each transmission compressor station, the size, type, and number of compressor units, horsepower required, horsepower to be installed, volume of gas to be used as fuel, suction and discharge pressures, and compression ratio.
(iii) Pressures and volumes of gas at the main line inlet and outlet connections at each compressor station.
(iv) Pressures and volumes of gas at each intake and takeoff point and at the beginning and terminus of all proposed transmission facilities.
(7) Exhibit G-I—Flow diagram reflecting maximum capabilities. If Exhibit G does not reflect the maximum deliveries of all transmission facilities, proposed to be installed and operated by applicant between distribution facilities of applicant and the transmission pipeline system of the proposed supplier (respondent), under most favorable operating conditions, without installation of any facilities in addition to those proposed in the application, include an additional diagram or diagrams to depict such maximum capabilities.
(8) Exhibit G-II—Flow diagram data. Exhibits G and G-I shall be accompanied by a statement of engineering design data in explanation and support of the diagrams and the proposed project, setting forth:
(i) Assumption, bases, formulae, and methods used in the development and preparation of such diagrams and accompanying data.
(ii) A description of the transmission pipe and fittings to be installed, specifying the diameter, wall thickness, yield point, ultimate tensile strength, method of fabrication, and methods of testing proposed.
(iii) Type, capacity, and location of each natural gas storage field or facility, or other similar plant or facility directly attached to the applicant’s transmission system.
(9) Exhibit H—Total gas supply data. A statement of the total gas supply committed to, controlled by, or possessed by an applicant which is available to it for the acts and the services proposed, together with:
(i) The estimated total volume of proven reserves in place for each reservoir in each field from which applicant takes natural gas, giving names and location of fields (state, county, or parish).
(ii) The estimated total volumes of proven reserves available to applicant by fee or under lease, segregated by gas fields and reservoirs thereof, giving names and locations of fields (state, county, or parish).
(iii) The names and addresses of persons with whom applicant has gas purchase contracts, the effective dates and remaining terms in years of such contracts.
(iv) A study, showing the daily volumes of natural gas which can and are proposed to be obtained each year from each source of supply.
(v) Estimate of the Btu content of the gas available to or requested by applicant for proposed service.
(vi) A study of each proposed gas storage field showing: Location; geology; original and present reserves for each reservoir; original and present pressure of each reservoir; proposed top and base storage pressures; proposed top and base gas volumes to be stored; a deliverability study, including daily and annual injection and withdrawal rates and pressures; and maximum daily deliverability and maximum storage capacity under the proposed plan of development.
(10) Exhibit I—Market data. An estimate by distribution systems of the volumes of gas to be delivered during the year in which proposed service is estimated to begin and during each of the first 3 full years of operation of the proposed facilities, and actual data of like import for each of the 3 years next preceding the filing of the application, together with:
(i) Names and locations of areas to be served, showing the number of residential, commercial, firm industrial, interruptible industrial, residential space heating, commercial space heating, and other types of customers for each distribution system to be served; and the names and locations of each firm and interruptible direct industrial customer whose estimated consumption totals 10,000 Mcf or more in any calendar month or 100,000 Mcf or more per year.
(ii) Applicant’s total annual and peak day gas requirements by classification of service in paragraph (a)(10)(i) of this section, divided as follows: Gas requirements (a) for each distribution area where gas is sold or to be sold by applicant at retail; (b) for all main-line direct industrial customers and (c) company use and unaccounted-for gas.
(iii) Total past and expected curtailments of service by the applicant in each distribution area proposed to be supplied with gas from the project, all to be listed by the classifications of service as indicated in paragraph (a)(10)(i) of this section.
(iv) Explanation of basic factors used in estimating future requirements, including, for example: Peak day and annual degree day deficiencies, annual load factors of applicant’s deliveries to its proposed customers; derivation of numbers of customers proposed to be served; individual consumer peak day and annual consumption factors for each class of consumers, with supporting historical data; forecasted saturation of space heating as related to past experience; and full detail as to all other sources of gas supply available to applicant and to each of its customers, including manufacturing facilities and liquid petroleum gas.
(v) A full description of all facilities, other than transmission facilities, necessary to provide service in the communities to be served.
(vi) A copy of each market survey made within the past 3 years for the markets proposed to be served.
(11) Exhibit J—Conversion to natural gas. If it is assumed that proposed customers in new areas or firm and interruptible direct industrial customers whose estimated consumption totals 10,000 Mcf or more in any calendar month or 100,000 Mcf or more in any calendar year will convert from other fuels to natural gas, state the basis for such assumption and include a study showing estimated cost of converting customers’ facilities to natural gas. The study should indicate the number of customers of each of the other fuels who applicant anticipates will convert to natural gas and the current cost of fuel to be displaced compared to the cost of natural gas on an equivalent Btu basis.
(12) Exhibit K—Cost of facilities. A detailed estimate of total capital cost of the proposed facilities involved in the application, showing cost of construction by operating units such as distribution facilities, compressor stations, transmission pipelines and laterals, measuring and regulating stations, and separately stating the cost of rights-of-way, damages, surveys, materials, labor, engineering and inspection, administrative overhead, fees for legal and other services, allowance for funds used during construction, and contingencies. Detailed estimates of cost of facilities required to be installed by the pipeline supplier shall be separately stated.
(13) Exhibit L—Financing. Plans for financing the proposed facilities for which the application is filed, together with:
(i) A detailed description of applicant’s outstanding and proposed securities and liabilities, showing amount (face value and number), interest or dividend rate, dates of issue and maturity, voting privileges, and principal terms and conditions applicable to each.
(ii) The manner in which applicant proposes to dispose of securities by private sale, competitive bidding or otherwise; the persons, if known, to whom they will be sold or issued, and evidence that such persons having agreed to purchase the securities, and if not known, the class or classes of such persons.
(iii) A statement showing for each proposed issue, by total amount and by unit, the estimated sale price and estimated net proceeds to the applicant.
(iv) A statement as to the extent to which the applicant will rely on temporary financing in connection with the proposed construction, and statements tending to substantiate the fact that such temporary loans will be made available.
(v) Statement of anticipated cash flow, including provision during the period of construction and the first 3 full years of proposed operation for interest requirements, dividends, and capital retirements.
(vi) Statement showing, over the life of each issue, the annual amount of securities which applicant expects to retire through operation of a sinking fund or other extinguishment of the obligation.
(vii) A balance sheet and income statement (12 months) of most recent date available.
(viii) Comparative pro forma balance sheets and income statements for the period of construction and each of the first 3 full years of operation, giving effect to the proposed construction and proposed financing of the project.
(ix) Any additional data and information upon which applicant proposes to rely in showing the adequacy and availability to it of resources for financing its proposed project.
(14) Exhibit M—Construction, operation, and management. A concise statement setting forth arrangements for supervision, management, engineering, accounting, legal, or other similar service to be rendered in connection with the construction or operation of the project if not to be performed by employees of applicant, including reference to any existing or contemplated agreements therefor.
(15) Exhibit N—Revenues, expenses income. Applicant shall submit pro forma statements for each of the first 3 full years of operation of all the proposed facilities, showing:
(i) Gas system annual revenues and volumes of natural gas related thereto subdivided by classes of service and further subdivided by sales to direct industrial customers, sales to other utilities (if any), transportation for other gas utilities and other sales.
(ii) Gas system annual operating expenses, cost of gas purchased, depreciation, depletion, taxes, utility income and resulting rate of return on net investment in gas plant, including working capital, or in the case of a municipality applicant similar data and amortization-interest schedule for life of each bond issue related to the proposed project. Cost of gas purchased shall be at the currently effective applicable rate of the pipeline supplier or applicable rate filed by such pipeline supplier, but not effective at date of filing, whichever is the higher.
(iii) The information required by paragraphs (a)(15)(i) and (ii) of this section need not be furnished when the applicant furnishes as a part of its application a pro forma copy of a certificate of convenience and necessity or similar authorization issued to it by the local State commission having jurisdiction over its proposed operations.
(16) Exhibit P—Rates. (i) A statement of the rates proposed to be charged for the proposed services to be rendered. Indicate whether rates are subject to regulation by the State or local authorities.
(ii) Identification of the rate schedule of the natural gas company (respondent) under which gas is proposed to be purchased.
(b) Additional exhibits. Applicant shall submit additional exhibits necessary to support or clarify its application. Such exhibits shall be identified and designated as provided by § 156.3(b)(8).
(c) Additional information. Upon request by the Secretary, prior to or during hearing upon the application, applicant shall submit such additional data, information, exhibits, or other detail as may be specified.
§ 156.6 Acceptance for filing or rejection of application.
Applications will be docketed when received and the applicant so advised. Any application which does not conform to the requirements of §§ 156.1 through 156.5 will be rejected by the Secretary. All but one copy of a rejected application will be returned. An application which relates to an operation concerning which a prior application has been filed and rejected, shall be docketed as a new application. Such new application shall state the docket number of the prior rejected application.
§ 156.7 Service of application.
After an application has been accepted for filing, the Secretary will cause a copy thereof to be served upon the natural gas company (respondent) against which an order pursuant to section 7(a) of the Natural Gas Act has been requested. The natural gas company shall, within 30 days after the date of service of such application file its answer (an original and 7 conformed copies) to such application in which it shall state whether it has any objection to the grant of the application. If the natural gas company objects to the grant of the relief sought by the application, it shall fully state the grounds and reasons for its objections. The answer shall be verified and shall be signed by an executive of the natural gas company. In the event that the respondent natural gas company fails to file a timely response to the application it shall be deemed to have agreed to the grant thereof.
§ 156.8 Notice of application.
Notice of each application filed, except when rejected in accordance with § 156.6, will be published in the
§ 156.9 Protests and interventions.
Notices of applications, as provided by § 156.8 will fix the time within which any person desiring to participate in the proceeding or to file a protest regarding the application, may file a petition to intervene or protest, and within which any interested regulatory agency desiring to intervene may file its notice of intervention. Failure to make timely filing will constitute ground for denial of participation, in the absence of extraordinary circumstances for good cause shown.
§ 156.10 Hearings.
The Commission will schedule each application for public hearing at the earliest possible date giving due consideration of statutory requirements and other matters pending, with notice thereof as provided by § 385.2009 of this chapter: Provided, however, That where no protests or petitions to intervene have been received and accepted, the Commission may, after the due date for such protests or petitions to intervene, issue the requested order without hearing.
§ 156.11 Dismissal of application.
Except for good cause shown, failure of an applicant to go forward on the date set for hearing and present its full case in support of its application will constitute ground for the summary dismissal of the application and the termination of the proceedings.
PART 157—APPLICATIONS FOR CERTIFICATES OF PUBLIC CONVENIENCE AND NECESSITY AND FOR ORDERS PERMITTING AND APPROVING ABANDONMENT UNDER SECTION 7 OF THE NATURAL GAS ACT
Subpart A—Applications for Certificates of Public Convenience and Necessity and for Orders Permitting and Approving Abandonment under Section 7 of the Natural Gas Act, as Amended, Concerning Any Operation, Sales, Service, Construction, Extension, Acquisition or Abandonment
§ 157.1 Definitions.
For the purposes of this part—
For the purposes of § 157.21 of this part, Director means the Director of the Commission’s Office of Energy Projects.
Indian tribe means, in reference to a proposal or application for a certificate or abandonment, an Indian tribe which is recognized by treaty with the United States, by federal statute, or by the U.S. Department of the Interior in its periodic listing of tribal governments in the
Resource agency means a Federal, state, or interstate agency exercising administration over the areas of recreation, fish and wildlife, water resource management, or cultural or other relevant resources of the state or states in which the facilities or services for which a certificate or abandonment is proposed are or will be located.
§ 157.5 Purpose and intent of rules.
(a) Applications under section 7 of the Natural Gas Act shall set forth all information necessary to advise the Commission fully concerning the operation, sales, service, construction, extension, or acquisition for which a certificate is requested or the abandonment for which permission and approval is requested. Some applications may be of such character that an abbreviated application may be justified under the provisions of § 157.7. Applications for permission and approval to abandon pursuant to section 7(b) of the Act shall conform to § 157.18 and to such other requirements of this part as may be pertinent. However, every applicant shall file all pertinent data and information necessary for a full and complete understanding of the proposed project, including its effect upon applicant’s present and future operations and whether, and at what docket, applicant has previously applied for authorization to serve any portion of the market contemplated by the proposed project and the nature and disposition of such other project.
(b) Every requirement of this part shall be considered as a forthright obligation of the applicant which can only be avoided by a definite and positive showing that the information or data called for by the applicable rules is not necessary for the consideration and ultimate determination of the application.
(c) This part will be strictly applied to all applications as submitted and the burden of adequate presentation in intelligible form as well as justification for omitted data or information rests with the applicant.
§ 157.6 Applications; general requirements.
(a) Applicable rules—(1) Submission required to be furnished by applicant under this subpart. Applications, amendments thereto, and all exhibits and other submissions required to be furnished by an applicant to the Commission under this subpart must be submitted in an original and 7 conformed copies. To the extent that data required under this subpart has been provided to the Commission, this data need not be duplicated. The applicant must, however, include a statement identifying the forms and records containing the required information and when that form or record was submitted.
(2) Maps and diagrams. An applicant required to submit a map or diagram under this subpart must submit one paper copy of the map or diagram.
(3) The following must be submitted in electronic format as prescribed by the Commission:
(i) Applications filed under this part 157 and all attached exhibits;
(ii) Applications covering acquisitions and all attached exhibits;
(iii) Applications for temporary certificates and all attached exhibits;
(iv) Applications to abandon facilities or services and all attached exhibits;
(v) The progress reports required under § 157.20(c) and (d);
(vi) Applications submitted under subpart E of this part and all attached exhibits;
(vii) Applications submitted under subpart F of this part and all attached exhibits;
(viii) Requests for authorization under the notice procedures established in § 157.205 and all attached exhibits;
(ix) The annual report required by § 157.207;
(x) The report required under § 157.214 when storage capacity is increased;
(xi) Amendments to any of the foregoing.
(4) All filings must be signed in compliance with the following.
(i) The signature on a filing constitutes a certification that: The signer has read the filing signed and knows the contents of the paper copies and electronic filing; the paper copies contain the same information as contained in the electronic filing; the contents as stated in the copies and in the electronic filing are true to the best knowledge and belief of the signer; and the signer possesses full power and authority to sign the filing.
(ii) A filing must be signed by one of the following:
(A) The person on behalf of whom the filing is made;
(B) An officer, agent, or employee of the governmental authority, agency, or instrumentality on behalf of which the filing is made; or,
(C) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.
(5) Other requirements. Applications under section 7 of the Natural Gas Act must conform to the requirements of §§ 157.5 through 157.14. Amendments to or withdrawals of applications must conform to the requirements of §§ 385.215 and 385.216 of this chapter. If the application involves an acquisition of facilities, it must conform to the additional requirements prescribed in §§ 157.15 and 157.16. If the application involves an abandonment of facilities or service, it must conform to the additional requirements prescribed in § 157.18.
(b) General content of application. Each application filed other than an application for permission and approval to abandon pursuant to section 7(b) shall set forth the following information:
(1) The exact legal name of applicant; its principal place of business; whether an individual, partnership, corporation, or otherwise; State under the laws of which organized or authorized; and the name, title, and mailing address of the person or persons to whom communications concerning the application are to be addressed.
(2) The facts relied upon by applicant to show that the proposed service, sale, operation, construction, extension, or acquisition is or will be required by the present or future public convenience and necessity.
(3) A concise description of applicant’s existing operations.
(4) A concise description of the proposed service, sale, operation, construction, extension, or acquisition, including the proposed dates for the beginning and completion of construction, the commencement of operations and of acquisition, where involved.
(5) A full statement as to whether any other application to supplement or effectuate applicant’s proposals must be or is to be filed by applicant, any of applicant’s customers, or any other person, with any other Federal, State, or other regulatory body; and if so, the nature and status of each such application.
(6) A table of contents which shall list all exhibits and documents filed in compliance with §§ 157.5 through 157.18, as well as all other documents and exhibits otherwise filed, identifying them by their appropriate titles and alphabetical letter designations. The alphabetical letter designations specified in §§ 157.14, 157.16, and 157.18 must be strictly adhered to and extra exhibits submitted at the volition of applicant shall be designated in sequence under the letter Z (Z1, Z2, Z3, etc.).
(7) A form of notice of the application suitable for publication in the
(8) For applications to construct new facilities, detailed cost-of-service data supporting the cost of the expansion project, a detailed study showing the revenue responsibility for each firm rate schedule under the pipeline’s currently effective rate design and under the pipeline’s proposed rates, a detailed rate impact analysis by rate schedule (including by zone, if applicable), and an analysis reflecting the impact of the fuel usage resulting from the proposed expansion project (including by zone, if applicable).
(c) Requests for shortened procedure. If shortened procedure is desired a request therefor shall be made in conformity with § 385.802 of this chapter and may be included in the application or filed separately.
(d) Landowner notification. (1) For all applications filed under this subpart which include construction of facilities or abandonment of facilities (except for abandonment by sale or transfer where the easement will continue to be used for transportation of natural gas), the applicant shall make a good faith effort to notify all affected landowners and towns, communities, and local, state and federal governments and agencies involved in the project:
(i) By certified or first class mail, sent within 3 business days following the date the Commission issues a notice of the application; or
(ii) By hand, within the same time period; and
(iii) By publishing notice twice of the filing of the application, no later than 14 days after the date that a docket number is assigned to the application, in a daily or weekly newspaper of general circulation in each county in which the project is located.
(2) All affected landowners includes owners of property interests, as noted in the most recent county/city tax records as receiving the tax notice, whose property:
(i) Is directly affected (i.e., crossed or used) by the proposed activity, including all facility sites (including compressor stations, well sites, and all above-ground facilities), rights of way, access roads, pipe and contractor yards, and temporary workspace;
(ii) Abuts either side of an existing right-of-way or facility site owned in fee by any utility company, or abuts the edge of a proposed facility site or right-of-way which runs along a property line in the area in which the facilities would be constructed, or contains a residence within 50 feet of the proposed construction work area;
(iii) Is within one-half mile of proposed compressors or their enclosures or LNG facilities; or
(iv) Is within the area of proposed new storage fields or proposed expansions of storage fields, including any applicable buffer zone.
(3) The notice shall include:
(i) The docket number of the filing;
(ii) The most recent edition of the Commission’s pamphlet that explains the Commission’s certificate process and addresses the basic concerns of landowners. Except: pipelines are not required to include the pamphlet in notifications of abandonments or in the published newspaper notice. Instead, they should provide the title of the pamphlet and indicate its availability at the Commission’s Internet address;
(iii) A description of the applicant and the proposed project, its location (including a general location map), its purpose, and the timing of the project;
(iv) A general description of what the applicant will need from the landowner if the project is approved, and how the landowner may contact the applicant, including a local or toll-free phone number and a name of a specific person to contact who is knowledgeable about the project;
(v) A brief summary of what rights the landowner has at the Commission and in proceedings under the eminent domain rules of the relevant state. Except: pipelines are not required to include this information in the published newspaper notice. Instead, the newspaper notice should provide the Commission’s Internet address and the telephone number for the Commission’s Office of External Affairs; and
(vi) Information on how the landowner can get a copy of the application from the company or the location(s) where a copy of the application may be found as specified in § 157.10.
(vii) A copy of the Commission’s notice of application, specifically stating the date by which timely motions to intervene are due, together with the Commission’s information sheet on how to intervene in Commission proceedings. Except: pipelines are not required to include the notice of application and information sheet in the published newspaper notice. Instead, the newspaper notice should indicate that a separate notice is to be mailed to affected landowners and governmental entities.
(4) If the notice is returned as undeliverable, the applicant will make a reasonable attempt to find the correct address and notify the landowner.
(5) Within 30 days of the date the application was filed, applicant shall file an updated list of affected landowners, including information concerning notices that were returned as undeliverable.
(6) If paragraph (d)(3) of this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 157.10(d).
§ 157.7 Abbreviated applications.
(a) General. When the operations sales, service, construction, extensions, acquisitions or abandonment proposed by an application do not require all the data and information specified by this part to disclose fully the nature and extent of the proposed undertaking, an abbreviated application may be filed in the manner prescribed in § 385.2011 of this chapter, provided it contains all information and supporting data necessary to explain fully the proposed project, its economic justification, its effect upon applicant’s present and future operations and upon the public proposed to be served, and is otherwise in conformity with the applicable requirements of this part regarding form, manner of presentation, and filing. Such an application shall (1) state that it is an abbreviated application; (2) specify which of the data and information required by this part are omitted; and (3) relate the facts relied upon to justify separately each such omission.
§ 157.8 Acceptance for filing or rejection of applications.
Applications will be docketed when received and the applicant so advised.
(a) If an application patently fails to comply with applicable statutory requirements or with applicable Commission rules, regulations, and orders for which a waiver has not been granted, the Director of the Office of Energy Projects or the Director of the Office of Energy Market Regulation may reject the application within 10 business days of filing as provided by § 385.2001(b) of this chapter. This rejection is without prejudice to an applicant’s refiling a complete application. However, an application will not be rejected solely on the basis of:
(1) Environmental reports that are incomplete because the company has not been granted access by the affected landowner(s) to perform required surveys; or,
(2) Environmental reports that are incomplete, but where the minimum checklist requirements of part 380, appendix A of this chapter have been met.
(b) An application which relates to an operation, sale, service, construction, extension, acquisition, or abandonment concerning which a prior application has been filed and rejected, shall be docketed as a new application. Such new application shall state the docket number of the prior rejected application.
(c) The Director of the Office of Energy Projects or the Director of the Office of Energy Market Regulation may also reject an application after it has been noticed, at any time, if it is determined that such application does not conform to the requirements of this part.
§ 157.9 Notice of application and notice of schedule for environmental review.
(a) Notice of each application filed, except when rejected in accordance with § 157.8, will be issued within 10 business days of filing, and subsequently will be published in the
(b) For each application that will require an environmental assessment or an environmental impact statement, notice of a schedule for the environmental review will be issued within 90 days of the notice of the application, and subsequently will be published in the
§ 157.10 Interventions and protests.
(a) Notices of applications, as provided by § 157.9, will fix the time within which any person desiring to participate in the proceeding may file a petition to intervene, and within which any interested regulatory agency, as provided by § 385.214 of this chapter, desiring to intervene may file its notice of intervention.
(1) Any person filing a petition to intervene or notice of intervention shall state specifically whether he seeks formal hearing on the application.
(2) Any person may file to intervene on environmental grounds based on the draft environmental impact statement as stated at § 380.10(a)(1)(i) of this chapter. In accordance with that section, such intervention will be deemed timely as long as it is filed within the comment period for the draft environmental impact statement.
(3) Failure to make timely filing will constitute grounds for denial of participation in the absence of extraordinary circumstances or good cause shown.
(4) Protests may be filed in accordance with § 385.211 of this chapter within the time permitted by any person who does not seek to participate in the proceeding.
(b) A copy of each application, supplement and amendment thereto, including exhibits required by §§ 157.14, 157.16, and 157.18, shall upon request be promptly supplied by the applicant to anyone who has filed a petition for leave to intervene or given notice of intervention.
(1) An applicant is not required to serve voluminous or difficult to reproduce material, such as copies of certain environmental information, to all parties, as long as such material is publicly available in an accessible central location in each county throughout the project area.
(2) An applicant shall make a good faith effort to place the materials in a public location that provides maximum accessibility to the public.
(c) Complete copies of the application must be available in accessible central locations in each county throughout the project area, either in paper or electronic format, within three business days of the date a filing is issued a docket number. Within five business days of receiving a request for a complete copy from any party, the applicant must serve a full copy of any filing on the requesting party. Such copy may exclude voluminous or difficult to reproduce material that is publicly available. Pipelines must keep all voluminous material on file with the Commission and make such information available for inspection at buildings with public access preferably with evening and weekend business hours, such as libraries located in central locations in each county throughout the project area.
(d) Critical Energy Infrastructure Information. (1) If this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined in § 388.113(c) of this chapter, to the public, the applicant shall omit the CEII from the information made available and insert the following in its place:
(i) A statement that CEII is being withheld;
(ii) A brief description of the omitted information that does not reveal any CEII; and
(iii) This statement: “Procedures for obtaining access to Critical Energy Infrastructure Information (CEII) may be found at 18 CFR 388.113. Requests for access to CEII should be made to the Commission’s CEII Coordinator.”
(2) The applicant, in determining whether information constitutes CEII, shall treat the information in a manner consistent with any filings that applicant has made with the Commission and shall to the extent practicable adhere to any previous determinations by the Commission or the CEII Coordinator involving the same or like information.
(3) The procedures contained in §§ 388.112 and 388.113 of this chapter regarding designation of, and access to, CEII, shall apply in the event of a challenge to a CEII designation or a request for access to CEII. If it is determined that information is not CEII or that a requester should be granted access to CEII, the applicant will be directed to make the information available to the requester.
(4) Nothing in this section shall be construed to prohibit any persons from voluntarily reaching arrangements or agreements calling for the disclosure of CEII.
§ 157.11 Hearings.
(a) General. The Commission will schedule each application for public hearing at the earliest date possible giving due consideration to statutory requirements and other matters pending, with notice thereof as provided by § 1.19(b) of this chapter: Provided, however, That when an application is filed less than fifteen days prior to the commencement of a hearing theretofore ordered on a pending application and seeks authority to serve some or all of the markets sought in such pending application or is otherwise competitive with such pending application, the Commission will not schedule the new application for hearing until it has rendered its final decision on such pending application, except when, on its own motion, or on appropriate application, it finds that the public interest requires otherwise.
(b) Shortened procedure. If no protest or petition to intervene raises an issue of substance, the Commission may upon request of the applicant dispose of an application in accordance with the provisions of § 385.802 of this chapter.
§ 157.12 Dismissal of application.
Except for good cause shown, failure of an applicant to go forward on the date set for hearing and present its full case in support of its application will constitute ground for the summary dismissal of the application and the termination of the proceedings.
§ 157.13 Form of exhibits to be attached to applications.
Each exhibit attached to an application must conform to the following requirements:
(a) General requirements. Each exhibit must be submitted in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter and contain a title page showing applicant’s name, docket number (to be left blank), title of the exhibit, the proper letter designation of the exhibit, and, if of 10 or more pages, a table of contents, citing by page, section number or subdivision, the component elements or matters therein contained.
(b) Reference to annual reports and previous applications. An application may refer to annual reports and previous applications filed with the Commission and shall specify the exact pages or exhibit numbers of the filing to which reference is made, including the page numbers in any exhibit to which reference is made. When reference is made to a previous application the docket number shall be stated. No part of a rejected application may be incorporated by reference.
(c) Interdependent applications. When an application considered alone is incomplete and depends vitally upon information in another application, it will not be accepted for filing until the supporting application has been filed. When applications are interdependent, they shall be filed concurrently.
(d) Measurement base. All gas volumes, including gas purchased from producers, shall be stated upon a uniform basis of measurement, and, in addition, if the uniform basis of measurement used in any application is other than 14.73 p.s.i.a., then any volume or volumes delivered to or received from any interstate natural-gas pipeline company shall also be stated upon a basis of 14.73 p.s.i.a.; similarly, total volumes on all summary sheets, as well as grand totals of volumes in any exhibit, shall also be stated upon a basis of 14.73 p.s.i.a. if the uniform basis of measurement used is other than 14.73 p.s.i.a.
§ 157.14 Exhibits.
(a) To be attached to each application. All exhibits specified must accompany each application when tendered for filing. Together with each exhibit applicant must provide a full and complete explanation of the data submitted, the manner in which it was obtained, and the reasons for the conclusions derived from the exhibits. If the Commission determines that a formal hearing upon the application is required or that testimony and hearing exhibits should be filed, the Secretary will promptly notify the applicant that submittal of all exhibits and testimony of all witnesses to be sponsored by the applicant in support of his case-in-chief is required. Submittal of these exhibits and testimony must be within 20 days from the date of the Secretary’s notice, or any other time as the Secretary will specify. Exhibits, except exhibits F, F– 1, G, G–I, and G–II, must be submitted to the Commission on electronic media as prescribed in § 385.2011 of this chapter. Receipt and delivery point information required in various exhibits must be labeled with a location point name and code in conformity with the location name and code the pipeline has adopted in conformance with § 284.13(f) of this chapter. Intervenors and persons becoming intervenors after the date of the Secretary’s notice must be advised by the applicant of the afore-specified exhibits and testimony, and must be furnished with copies upon request. If this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 157.10(d).
(1) Exhibit A—Articles of incorporation and bylaws. If applicant is not an individual, a conformed copy of its articles of incorporation and bylaws, or other similar documents.
(2) Exhibit B—State authorization. For each State where applicant is authorized to do business, a statement showing the date of authorization, the scope of the business applicant is authorized to carry on and all limitations, if any, including expiration dates and renewal obligations. A conformed copy of applicant’s authorization to do business in each State affected shall be supplied upon request.
(3) Exhibit C—Company officials. A list of the names and business addresses of applicant’s officers and directors, or similar officials if applicant is not a corporation.
(4) Exhibit D—Subsidiaries and affiliation. If applicant or any of its officers or directors, directly or indirectly, owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of any other person or organized group of persons engaged in production, transportation, distribution, or sale of natural gas, or of any person or organized group of persons engaged in the construction or financing of such enterprises or operations, a detailed explanation of each such relationship, including the percentage of voting strength represented by such ownership of securities. If any person or organized group of persons, directly or indirectly, owns, controls, or holds with power to vote, 10 percent or more of the outstanding voting securities of applicant—a detailed explanation of each such relationship.
(5) Exhibit E—Other pending applications and filings. A list of other applications and filings under sections 1, 3, 4 and 7 of the Natural Gas Act filed by the applicant which are pending before the Commission at the time of the filing of an application and which directly and significantly affect the application filed, including an explanation of any material effect the grant or denial of those other applications and filings will have on the application and of any material effect the grant or denial of the application will have on those other applications and filings.
(6) Exhibit F—Location of facilities. Unless shown on Exhibit G or elsewhere, a geographical map of suitable scale and detail showing, and appropriately differentiating between all of the facilities proposed to be constructed, acquired or abandoned and existing facilities of applicant, the operation or capacity of which will be directly affected by the proposed facilities or the facilities proposed to be abandoned. This map, or an additional map, shall clearly show the relationship of the new facilities to the applicant’s overall system and shall include:
(i) Location, length, and size of pipelines.
(ii) Location and size (rated horsepower) of compressor stations.
(iii) Location and designation of each point of connection of existing and proposed facilities with:
(A) Main-line industrial customers, gas pipeline or distribution systems, showing towns and communities served and to be served at wholesale and retail, and
(B) Gas-producing and storage fields, or other sources of gas supply.
(7) Exhibit F–I—Environmental report. An environmental report as specified in §§ 380.3 and 380.12 of this chapter. Applicant must submit all appropriate revisions to Exhibit F–I whenever route or site changes are filed. These revisions should identify the locations by mile post and describe all other specific differences resulting from the route or site changes, and should not simply provide revised totals for the resources affected.
(8) Exhibit G—Flow diagrams showing daily design capacity and reflecting operation with and without proposed facilities added. A flow diagram showing daily design capacity and reflecting operating conditions with only existing facilities in operation. A second flow diagram showing daily design capacity and reflecting operating conditions with both proposed and existing facilities in operation. Both flow diagrams shall include the following for the portion of the system affected:
(i) Diameter, wall thickness, and length of pipe installed and proposed to be installed and the diameter and wall thickness of the installed pipe to which connection is proposed.
(ii) For each proposed new compressor station and existing station, the size, type and number of compressor units, horsepower required, horsepower installed and proposed to be installed, volume of gas to be used as fuel, suction and discharge pressures, and compression ratio.
(iii) Pressures and volumes of gas at the main line inlet and outlet connections at each compressor station.
(iv) Pressures and volumes of gas at each intake and take-off point and at the beginning and terminus of the existing and proposed facilities and at the intake or take-off point of the existing facilities to which the proposed facilities are to be connected.
(9) Exhibit G–I—Flow diagrams reflecting maximum capabilities. If Exhibit G does not reflect the maximum deliveries which applicant’s existing and proposed facilities would be capable of achieving under most favorable operating conditions with utilization of all facilities, include an additional diagram or diagrams to depict such maximum capabilities. If the horsepower, pipelines, or other facilities on the segment of applicant’s system under consideration are not being fully utilized due, e.g., to capacity limitation of connecting facilities or because of the need for standby or spare equipment, the reason for such nonutilization shall be stated.
(10) Exhibit G–II—Flow diagram data. Exhibits G and G–I shall be accompanied by a statement of engineering design data in explanation and support of the diagrams and the proposed project, setting forth:
(i) Assumptions, bases, formulae, and methods used in the development and preparation of such diagrams and accompanying data.
(ii) A description of the pipe and fittings to be installed, specifying the diameter, wall thickness, yield point, ultimate tensile strength, method of fabrication, and methods of testing proposed.
(iii) When lines are looped, the length and size of the pipe in each loop.
(iv) Type, capacity, and location of each natural gas storage field or facility, and of each dehydration, desulphurization, natural gas liquefaction, hydrocarbon extraction, or other similar plant or facility directly attached to the applicant’s system, indicating which of such plants are owned or operated by applicant, and which by others, giving their names and addresses.
(v) If the daily design capacity shown in Exhibit G is predicated upon an ability to meet each customer’s maximum contract quantity on the same day, explain the reason for such coincidental peak-day design. If the design day capacity shown in Exhibit G is predicated upon an assumed diversity factor, state that factor and explain its derivation.
(vi) The maximum allowable operating pressure of each proposed facility for which a certificate is requested, as permitted by the Department of Transportation’s safety standards. The applicant shall certify that it will design, install, inspect, test, construct, operate, replace, and maintain the facilities for which a certificate is requested in accordance with Federal safety standards and plans for maintenance and inspection or shall certify that it has been granted a waiver of the requirements of the safety standards by the Department of Transportation in accordance with the provisions of section 3(e) of the Natural Gas Pipeline Safety Act of 1968. Pertinent details concerning the waiver shall be set forth.
(11) Exhibit H—Total gas supply data. A statement by applicant describing:
(i) Those production areas accessible to the proposed construction that contain sufficient existing or potential gas supplies for the proposed project; and
(ii) How those production areas are connected to the proposed construction.
(12) Exhibit I—Market data. A system-wide estimate of the volumes of gas to be delivered during each of the first 3 full years of operation of the proposed service, sale, or facilities and during the years when the proposed facilities are under construction, and actual data of like import for each of the 3 years next preceding the filing of the application, together with:
(i) Names and locations of customer companies and municipalities, showing the number of residential, commercial, firm industrial, interruptible industrial, residential space-heating, commercial space-heating, and other types of customers for each distribution system to be served at retail or wholesale; and the names and locations of each firm and interruptible direct industrial customer whose estimated consumption totals 10,000 Mcf or more in any calendar month or 100,000 Mcf or more per year together with an explanation of the end use to which each of these industrial customers will put the gas.
(ii) Applicant’s total annual and peak day gas requirements by classification of service in paragraph (a)(11)(i) of this section, divided as follows: Gas requirements for each distribution area where gas is sold by applicant at retail; for each wholesale customer; for all main line direct industrial customers; and company use and unaccounted-for gas, for both the applicant and each wholesale customer.
(iii) Total past and expected curtailments of service by the applicant and each wholesale customer proposing to receive new or additional supplies of gas from the project, all to be listed by the classifications of service in paragraph (a)(12)(i) of this section.
(iv) Explanation and derivation of basic factors used in estimating future requirements, including, for example: Peak-day and annual degree-day deficiencies, annual load factors of applicant’s system and of its deliveries to its proposed customers; individual consumer peak-day and annual consumption factors for each class of consumers, with supporting historical data; forecasted saturation of space-heating as related to past experience; and full detail as to all other sources of gas supply available to applicant and to each of its customers, including manufacturing facilities and liquid petroleum gas.
(v) Conformed copy of each contract, letter of intent or other agreement for sale or transportation of natural gas proposed by the application. Indicate the rate to be charged. If no agreements have been made, indicate the basis for assuming that contracts will be consummated and that service will be rendered under the terms contemplated in the application.
(vi) A full description of all facilities, other than those covered by the application, necessary to provide service in the communities to be served, the estimated cost of such facilities, by whom they are to be constructed, and evidence of economic feasibility.
(vii) A copy of each market survey made within the past three years for such markets as are to receive new or increased service from the project applied for.
(viii) A statement showing the franchise rights of applicant or other person to distribute gas in each community in which service is proposed.
(ix) When an application requires a statement of total peak-day or annual market requirements of affiliates, whose operations are integrated with those of applicant, to demonstrate applicant’s ability to provide the service proposed or to establish a gas supply, estimates and data required by this paragraph (a)(12)(ix) shall also be stated in like detail for such affiliates.
(x) When the proposed project is for service which would not decrease the life index of the total system gas supply by more than one year, the data required in paragraphs (a)(12)(i) to (ix), inclusive, of this section need be submitted only as to the particular market to receive new or additional service.
(13) Exhibit J—Federal authorizations. A statement identifying each Federal authorization that the proposal will require; the Federal agency or officer, or State agency or officer acting pursuant to delegated Federal authority, that will issue each required authorization; the date each request for authorization was submitted; why any request was not submitted and the date submission is expected; and the date by which final action on each Federal authorization has been requested or is expected.
(14) Exhibit K—Cost of facilities. A detailed estimate of total capital cost of the proposed facilities for which application is made, showing cost of construction by operating units such as compressor stations, main pipelines, laterals, measuring and regulating stations, and separately stating the cost of right-of-way, damages, surveys, materials, labor, engineering and inspection, administrative overhead, fees for legal and other services, allowance for funds used during construction, and contingencies. Include a brief statement indicating the source of information used as the basis for the above estimate. If not otherwise set forth, submit data on preliminary bids, if any, for the proposed facilities and recent experienced cost data for facilities of similar character.
(15) Exhibit L—Financing. Plans for financing the proposed facilities for which the application is filed, together with:
(i) A description of the class (e.g., commercial paper, long-term debt, preferred stock) and cost rates for securities expected to be issued with construction period and post- operational sources of financing separately identified.
(ii) Statement of anticipated cash flow, including provision during the period of construction and the first 3 full years of operation of proposed facilities for interest requirements, dividends, and capital requirements.
(iii) A balance sheet and income statement (12 months) of most recent data available.
(iv) Comparative pro forma balance sheets and income statements for the period of construction and each of the first 3 full years of operation, giving effect to the proposed construction and proposed financing of the project.
(v) Any additional data and information upon which applicant proposes to rely in showing the adequacy and availability of resources for financing its proposed project.
(vi) In instances for which principal operations of the company have not commenced or where proposed rates for services are developed on an incremental basis, a brief statement explaining how the applicant will determine the actual allowance for funds used during construction (AFUDC) rate, or if a rate is not to be used, how the applicant will determine the actual amount of AFUDC to be capitalized as a component of construction cost, and why the method is appropriate under the circumstances.
(16) Exhibit M—Construction, operation, and management. A concise statement setting forth arrangements for supervision, management, engineering, accounting, legal, or other similar service to be rendered in connection with the construction or operation of the project, if not to be performed by employees of applicant, including reference to any existing or contemplated agreements therefor, together with:
(i) A statement showing affiliation between applicant and any parties to such agreements or arrangements. See Exhibit D, paragraph (a)(4) of this section.
(ii) Conformed copies of all construction, engineering, management, and other similar service agreements or contracts in any way operative with respect to construction, operation, or financing of facilities which are the subject of the application or will be applicable under system operations.
(17) Exhibit N—Revenues—Expenses—Income. When the estimated revenues and expenses related to a proposed facility will significantly affect the operating revenues or operating expenses of an applicant, there shall be submitted a system-wide statement for the last year preceding the proposed construction or service and pro forma system-wide and incremental statements for each of the first three full years of operation of the proposed facilities, showing:
(i) Gas system annual revenues and volumes of natural gas related thereto, subdivided by classes of service, and further subdivided by sales to direct industrial customers, sales to other gas utilities, and other sales, indicating billing quantities used for computing charges, e.g., actual demands, billing demands, volumes, heat-content adjustment or other determinants. In addition, if enlargement or extension of facilities is involved, the revenues attributable solely to the proposed facilities shall be stated separately, and the basis and data used in such computation shall be clearly shown.
(ii) Gas system annual operating expenses classified in accordance with the Commission’s Uniform System of Accounts for Natural Gas Companies; the annual depreciation, depletion, taxes, utility income, and resulting rate of return on net investment in gas plant including working capital. In addition if enlargement or extension of facilities is involved, the cost of service attributable solely to the proposed facilities shall be stated separately with supporting data.
(iii) When the data required in paragraphs (a)(17)(i) and (ii) of this section is not submitted, applicant shall provide in lieu thereof a statement in sufficient detail to show clearly the effect on the operating revenues and operating expenses of the estimated revenues and expenses related to the proposed facility.
(18) Exhibit O—Depreciation and depletion. Depreciation and depletion rates to be established, the method of determination and the justification therefor.
(19) Exhibit P—Tariff. (i) A statement of the rates to be charged for the proposed sales or service, including:
(A) Identification of the applicable presently effective rate schedules, when no additional tariff filings will be required, or
(B) When changes are required in applicant’s presently effective tariff, or if applicant has no tariff, pro forma copies of appropriate changes in or additions to the effective tariff or a pro forma copy of the new gas tariff proposed, or
(C) When a new rate is proposed, a statement explaining the basis used in arriving at the proposed rate. Such statement shall clearly show whether such rate results from negotiation, cost-of-service determination, competitive factors or others, and shall give the nature of any studies which have been made in connection therewith.
(ii) When new rates or changes in present rates are proposed or when the proposed facilities will result in a material change in applicant’s average cost of service, such statement shall be accompanied by supporting data showing:
(A) System cost of service for the first calendar year of operation after the proposed facilities are placed in service.
(B) An allocation of such costs to each particular service classification, with the basis for each allocation clearly stated.
(C) The proposed rate base and rate of return.
(D) Gas operating expenses, segregated functionally by accounts.
(E) Depletion and depreciation.
(F) Taxes with the basis upon which computed.
(b) Additional exhibits. Applicant shall submit additional exhibits necessary to support or clarify its application. Such exhibits shall be identified and designated as provided by § 157.6(b)(6).
(c) Additional information. Upon request by the Secretary, prior to or during hearing upon the application, applicant shall submit such additional data, information, exhibits, or other detail as may be specified. An original and 7 conformed copies of such additional information shall be furnished to the Commission. The Commission reserves the right to request additional copies.
(d) Availability of Commission staff for advice prior to formal filing. Prior to filing an application, any person may informally confer with the staff of the Commission to obtain advice on any problem of statement or presentation of an application or any part thereof.
§ 157.15 Requirements for applications covering acquisitions.
An application for a certificate authorizing acquisition of facilities, in addition to complying with the applicable provisions of §§ 157.5 through 157.14, shall include a statement showing:
(a) The exact legal name of the vendor, lessor, or other party in interest (hereinafter referred to as “vendor”) the State or other laws under which vendor was organized, location of vendor’s principal place of business, and a description of the business, operation or property of vendor covered by the application.
(b) Any certificate from the Commission, held by vendor, relating directly to the facilities which applicant seeks to acquire, citing the order, date thereof, docket designation, and title of the proceeding; reference to and designation of any companion applications by vendor for permission and approval pursuant to section 7(b) of the Natural Gas Act.
(c) The manner in which the facilities are to be acquired, the consideration to be paid, the method of arriving at the amount thereof, and anticipated expenses in addition to the consideration.
(d) The facilities to be acquired, their present use, their proposed use after acquisition, and whether they constitute all of vendor’s facilities.
(e) Any franchise, license, or permit respecting the facilities involved, showing expiration date thereof, and the effect of the proposed acquisition thereon.
§ 157.16 Exhibits relating to acquisitions.
In addition to the exhibits required by § 157.14, every application involving acquisition of facilities must be accompanied by the exhibits listed below. Together with each exhibit applicant must provide a full and complete explanation of the data submitted, the manner in which it was obtained, and the reasons for the conclusions derived from the exhibits, unless the applicant includes a statement identifying the schedule and rate containing the required information and data filed as prescribed in § 385.2011 of this chapter. If the Commission determines that a formal hearing upon the application is required or that testimony and hearing exhibits should be filed, the Secretary will promptly notify the applicant that submittal of all the exhibits and testimony of all witnesses to be sponsored by the applicant in support of his case-in-chief is required. Submittal of these exhibits and testimony must be within 20 days from the date of the Secretary’s notice, or any other time specified by the Secretary in the notice. Sections 157.6(a) and 385.2011 of this chapter will govern the submissions required to be furnished to the Commission. Interveners and persons becoming interveners after the date of the Secretary’s notice must be advised by the applicant of the afore-specified exhibits and testimony, and must be furnished with copies upon request. If this section requires an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 157.10(d).
(a) Exhibit Q—Effect of acquisition on existing contracts and tariffs. A statement showing the effect of the proposed transaction upon any agreements for the purchase, sale, or interchange of natural gas, and upon any rate schedules or tariffs on file with this Commission, together with pro forma rate schedule sheets, notices of cancellation, or other tariff filings required to be made with this Commission.
(b) Exhibit R—Acquisition contracts. A summary statement of all contracts, agreements or undertakings relating to the proposed acquisition, including:
(1) A conformed copy of each contract or other agreement covering or relating to the acquisition of the facilities.
(2) The names and addresses of all persons employed or to be employed concerning the transaction, including engineering, financial accounting, legal, or other services, and the compensation, fees, or other payments, paid or payable, to such persons.
(3) A disclosure of affiliation between applicant and vendor or between either of them and any other party in interest in the proposed acquisition. See Exhibit D, § 157.14(a)(4).
(c) Exhibit S—Accounting. A statement showing:
(1) The amounts recorded upon the books of the vendor, as being applicable to the facilities to be acquired, and the related depreciation, depletion, and amortization reserves. Include a brief statement explaining the basis or methods used to derive the related depreciation, depletion and amortization reserves.
(2) The original cost of the facilities to be acquired, segregated by accounts prescribed in the Commission’s Uniform System of Accounts for Natural Gas Companies; the method by which the original cost was determined; and whether such statement of original cost has been approved by any regulatory body.
(3) If the original cost has not been determined, an estimate thereof, based upon records or data of vendor or its predecessors, together with an explanation of the manner in which such estimate was made and the name and address of the present custodian of all existing pertinent records and data.
(4) The depreciation, depletion, and amortization reserve requirements applicable to the original cost of the facilities to be acquired, estimated service lives, the approximate average age of the facilities to which the depreciation reserve applies, the amortization period, and the depletion rates and estimated gas reserves upon which accruals to the depletion reserve are based.
(5) The amount at which applicant proposes to record the facilities upon its books; the amount of the original cost to be recorded, the depreciation, depletion, and amortization reserves; and the acquisition adjustments, if any, together with applicant’s proposed disposition of all adjustments.
(6) Duplicate facilities to be acquired and retired, property which must be extensively rehabilitated, including a clear description of such property, the additional costs to be incurred, and the accounting therefor proposed.
(7) A balance sheet of the company to be acquired as of the most recent date available, if the acquisition involved is by purchase of capital stock and liquidation of the acquired company.
(8) A pro forma consolidating balance sheet, as of the date of the merger if the acquisition is by merger, showing the merging of the accounts and the adjustments relating thereto.
§ 157.17 Applications for temporary certificates in cases of emergency.
In cases of emergency and pending the determination of any application on file with the Commission for a certificate of public convenience and necessity pursuant to section 7 of the Natural Gas Act, application may be made for a temporary certificate authorizing the construction and operation of extensions of existing facilities, interconnections of pipeline systems, or sales of natural gas that may be required to assure maintenance of adequate service, or to service particular customers. This application must be submitted in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter.
(a) Whenever the waiver provisions of § 385.2011 of this chapter apply, the application must be submitted in writing, must be subscribed and verified by a responsible officer of applicant having knowledge of the facts, and must state clearly and specifically the exact character of the emergency, the proposed method of meeting it, and the facts claimed to warrant issuance of a temporary certificate.
(b) The application must be submitted on electronic media as prescribed in § 385.2011 of this chapter, must be subscribed and verified by a responsible officer of applicant having knowledge of the facts, and must state clearly and specifically the exact character of the emergency, the proposed method of meeting it, and the facts claimed to warrant issuance of a temporary certificate.
§ 157.18 Applications to abandon facilities or service; exhibits.
Applications for an order authorizing abandonment of facilities or service pursuant to section 7(b) of the Natural Gas Act must contain a statement providing in detail the reasons for the abandonment and must contain the exhibits listed below, unless the applicant includes a statement identifying the schedule and rate containing the required information and data filed as prescribed in § 385.2011 of this chapter. Any application for an abandonment that is not excluded by § 380.4(a)(28) or (29), must include an environmental report as specified by § 380.3(c)(2). Sections 157.6(a) and 385.2011 of this chapter will govern the submission of applications and exhibits required to be furnished. Together with each exhibit, applicant must provide a full and complete explanation of the data submitted, the manner in which it was obtained, and the reasons for the conclusions derived from the data. The Secretary may, in addition, require that the testimony of all witnesses to be presented by the applicant be filed together with all exhibits upon which applicant will base its case-in-chief.
(a) Exhibit T—Related applications. A statement showing:
(1) The docket numbers of the prior proceedings in which the facilities or services sought to be abandoned were certificated.
(2) The docket numbers of related applications pending before or which have been authorized by the Commission with an explanation of the interrelationship of those applications with the instant application.
(b) Exhibit U—Contracts and other agreements. A conformed copy of each contract or other agreement pertaining directly or indirectly to the abandonment of facilities or service, including all agreements which influenced applicant to seek the abandonment and all agreements which are dependent upon the approval of the proposed abandonment.
(c) Exhibit V—Flow diagram showing daily design capacity and reflecting operation of applicant’s system after abandonment. Receipt and delivery point information required in various exhibits must be labeled with a location point name and code in accordance with the location name and code the pipeline has adopted in conformance with § 284.13(f) of this chapter. A flow diagram showing daily design capacity and reflecting operating conditions of applicant’s system after abandonment of facilities on that segment of the system affected by the abandonment, including the following:
(1) Diameter, wall thickness, and length of pipe remaining.
(2) For each remaining compressor station, the size, type and number of compressor units, horsepower required, horsepower installed, volume of gas to be used as fuel, suction and discharge pressures, and compression ratio.
(3) Pressures and volumes of gas at the main line inlet and outlet connections at each compressor station.
(4) Pressures and volumes of gas at each intake and takeoff point and at the beginning and terminus of all remaining facilities.
(d) Exhibit W—Impact on customers whose service will be terminated. A statement indicating the availability of natural gas from other sources to applicant’s customers whose service will be terminated by the abandonment and a statement showing the economic effect of the abandonment on applicant’s customers. If no other natural gas is available, indicate the availability of other fuels to those customers and explain why the abandonment of service to each customer is permitted by the public convenience and necessity.
(e) Exhibit X—Effect of the abandonment on existing tariffs. A statement showing the effect of the proposed abandonment upon any rate schedules or tariffs on file with this Commission, together with pro forma rate schedule sheets, notices of cancellation, or other tariff filings required to be made with this Commission.
(f) Exhibit Y—Accounting treatment of abandonment. Concisely describe the changes of property, indicating the cost of property to be abandoned in place, the cost of property to be removed and salvaged, the proposed disposition of salvaged material, and a description of equipment to be relocated setting forth its cost, its proposed new location, and the extent of rehabilitation required. Include the information required below.
(1) State the proposed accounting treatment for property changes, showing, for example, retirements by primary plant accounts, cost of removal, salvage realized for materials and equipment sold, original cost of reusable materials and equipment recovered (see Account 154 of the Uniform System of Accounts), and maintenance costs for reconditioning of reusable materials and equipment.
(2) If the abandonment will be by sale of property, describe the property to be sold, together with the proposed accounting treatment as required by paragraph F of Gas Plant Instruction 5 of the Uniform System of Accounts. Include a brief statement explaining the basis or methods used to derive the accumulated depreciation related to the property to be disposed of. Applicant may use pro forma accounting entries based on estimated amounts, provided that upon consummation of the sale he must file proposed accounting entries in conformity with the requirements of the Uniform System of Accounts. If the proposed sale will result in a taxable gain to the applicant, indicate the amount of federal and state income taxes to be allocated to the gain. If no allocation is to be made, explain the reasons.
(3) State the amount of accumulated deferred income taxes attributable to the property to be abandoned and the tax basis of the property. Indicate the proposed accounting treatment of those accumulated deferred taxes.
(g) Exhibit Z—Location of facilities. Unless shown on Exhibit V or elsewhere, a geographic map of suitable scale and detail showing, and appropriately differentiating between, all of the facilities proposed to be abandoned and the other existing facilities of applicant, the operation or capacity of which will be directly affected by the facilities to be abandoned. This map shall clearly show the relationship of the facilities to be abandoned to the applicant’s overall system and shall include:
(1) Location, length and size of pipelines.
(2) Location and size (rated horsepower) of compressor stations.
(3) Location and designation of each point of connection of existing facilities with (i) main line industrial and other consumers, pipeline or distribution companies and municipalities, indicating towns and communities served at wholesale or retail and (ii) gas-producing and storage fields, or other sources of gas supply. Designate on the map those facilities and services proposed to be abandoned.
§ 157.20 General conditions applicable to certificates.
Such of the following terms and conditions, among others, as the Commission shall find is required by the public convenience and necessity, shall attach to the issuance of each certificate and to the exercise of the rights granted thereunder.
(a) The certificate shall be void and without force or effect unless accepted in writing by applicant within 30 days from the issue date of the order issuing such certificate: Provided, however, That when an application for rehearing of such order is filed in accordance with section 19 of the Natural Gas Act, such acceptance shall be filed within 30 days from the issue date of the order of the Commission upon the application for rehearing or within 30 days from the date on which such application may be deemed to have been denied when the Commission has not acted on such application within 30 days after it has been filed: Provided further, That when a petition for review is filed in accordance with the provisions of section 19 of the Natural Gas Act, such acceptance shall be filed within 30 days after final disposition of the judicial review proceedings thus initiated.
(b) Any authorized construction, extension, or acquisition shall be completed and made available for service by applicant and any authorized operation, service, or sale shall be available for regular performance by applicant within (period of time to be specified by the Commission in each order) from the issue date of the Commission’s order issuing the certificate. Applicant shall notify the Commission in writing no later than 10 days after expiration of this time period that the end-user/shipper is unable to meet the imposed timetable to commence service.
(c) Applicant must file with the Commission, in writing and under oath, an original and four conformed copies, as prescribed in § 385.2011 of this chapter and, upon request must furnish an intervener with a single copy, of the following:
(1) Within ten days after the bona fide beginning of construction, notice of the date of such beginning;
(2) Within ten days after authorized facilities have been constructed and placed in service or any authorized operation, sale, or service has commenced, notice of the date of such placement and commencement and
(3) Within six months after authorized facilities have been constructed, a statement showing, on the basis of all costs incurred to that date and estimated to be incurred for final completion of the project, the cost of constructing authorized facilities, such total costs to be classified according to the estimates submitted in the certificate proceeding and compared therewith and any significant differences explained.
(d) With respect to an acquisition authorized by the certificate, applicant must file with the Commission, in writing and under oath, an original and four conformed copies as prescribed in § 385.2011 of this chapter the following:
(1) Within 10 days after acquisition and the beginning of authorized operations, notice of the dates of acquisition and the beginning of operations; and
(2) Within 10 days after authorized facilities have been constructed and within 10 days after such facilities have been placed in service or any authorized operation, sale, or service has commenced, notice of the date of such completion, placement, and commencement, and
(e) The certificate issued to applicant is not transferable in any manner and shall be effective only so long as applicant continues the operations authorized by the order issuing such certificate and in accordance with the provisions of the Natural Gas Act, as well as applicable rules, regulations, and orders of the Commission.
(f) In the interest of safety and reliability of service, facilities authorized by the certificate shall not be operated at pressures exceeding the maximum operating pressure set forth in Exhibit G-II to the application as it may be amended prior to issuance of the certificate. In the event the applicant thereafter wishes to change such maximum operating pressure it shall file an appropriate petition for amendment of the certificate. Such petition shall include the reasons for the proposed change. Nothing contained herein authorizes a natural gas company to operate any facility at a pressure above the maximum prescribed by state law, if such law requires a lower pressure than authorized hereby.
§ 157.21 Pre-filing procedures and review process for LNG terminal facilities and other natural gas facilities prior to filing of applications.
(a) LNG terminal facilities and related jurisdictional natural gas facilities. A prospective applicant for authorization to site, construct and operate facilities included within the definition of “LNG terminal,” as defined in § 153.2(d), and any prospective applicant for related jurisdictional natural gas facilities must comply with this section’s pre-filing procedures and review process. These mandatory pre-filing procedures also shall apply when the Director finds in accordance with paragraph (e)(2) of this section that prospective modifications to an existing LNG terminal are modifications that involve significant state and local safety considerations that have not been previously addressed. Examples of such modifications include, but are not limited to, the addition of LNG storage tanks; increasing throughput requiring additional tanker arrivals or the use of larger vessels; or changing the purpose of the facility from peaking to base load. When a prospective applicant is required by this paragraph to comply with this section’s pre-filing procedures:
(1) The prospective applicant must make a filing containing the material identified in paragraph (d) of this section and concurrently file a Letter of Intent pursuant to 33 CFR 127.007, and a Preliminary Waterway Suitability Assessment (WSA) with the U.S. Coast Guard (Captain of the Port/Federal Maritime Security Coordinator). The latest information concerning the documents to be filed with the Coast Guard should be requested from the U.S. Coast Guard. For modifications to an existing or approved LNG terminal, this requirement can be satisfied by the prospective applicant’s certifying that the U.S. Coast Guard did not require such information.
(2) An application:
(i) Shall not be filed until at least 180 days after the date that the Director issues notice pursuant to paragraph (e) of this section of the commencement of the prospective applicant’s pre-filing process; and
(ii) Shall contain all the information specified by the Commission staff after reviewing the draft materials filed by the prospective applicant during the pre-filing process, including required environmental material in accordance with the provisions of part 380 of this chapter, “Regulations Implementing the National Environmental Policy Act.”
(3) The prospective applicant must provide sufficient information for the pre-filing review of any pipeline or other natural gas facilities, including facilities not subject to the Commission’s Natural Gas Act jurisdiction, which are necessary to transport regassified LNG from the subject LNG terminal facilities to the existing natural gas pipeline infrastructure.
(b) Other natural gas facilities. When a prospective applicant for authorization for natural gas facilities is not required by paragraph (a) of this section to comply with this section’s pre-filing procedures, the prospective applicant may file a request seeking approval to use the pre-filing procedures.
(1) A request to use the pre-filing procedures must contain the material identified in paragraph (d) of this section unless otherwise specified by the Director as a result of the Initial Consultation required pursuant to paragraph (c) of this subsection; and
(2) If a prospective applicant for non-LNG terminal facilities is approved to use this section’s pre-filing procedures:
(i) The application will normally not be filed until at least 180 days after the date that the Director issues notice pursuant to paragraph (e)(3) of this section approving the prospective applicant’s request to use the pre-filing procedures under this section and commencing the prospective applicant’s pre-filing process. However, a prospective applicant approved by the Director pursuant to paragraph (e)(3) of this section to undertake the pre-filing process is not prohibited from filing an application at an earlier date, if necessary; and
(ii) The application shall contain all the information specified by the Commission staff after reviewing the draft materials filed by the prospective applicant during the pre-filing process, including required environmental material in accordance with the provisions of part 380 of this chapter, “Regulations Implementing the National Environmental Policy Act.”
(c) Initial consultation. A prospective applicant required or potentially required or requesting to use the pre-filing process must first consult with the Director on the nature of the project, the content of the pre-filing request, and the status of the prospective applicant’s progress toward obtaining the information required for the pre-filing request described in paragraph (d) of this section. This consultation will also include discussion of the specifications for the applicant’s solicitation for prospective third-party contractors to prepare the environmental documentation for the project, and whether a third-party contractor is likely to be needed for the project.
(d) Contents of the initial filing. A prospective applicant’s initial filing pursuant to paragraph (a)(1) of the section for LNG terminal facilities and related jurisdictional natural gas facilities or paragraph (b)(1) of this section for other natural gas facilities shall include the following information:
(1) A description of the schedule desired for the project including the expected application filing date and the desired date for Commission approval.
(2) For LNG terminal facilities, a description of the zoning and availability of the proposed site and marine facility location.
(3) For natural gas facilities other than LNG terminal facilities and related jurisdictional natural gas facilities, an explanation of why the prospective applicant is requesting to use the pre-filing process under this section.
(4) A detailed description of the project, including location maps and plot plans to scale showing all major plant components, that will serve as the initial discussion point for stakeholder review.
(5) A list of the relevant federal and state agencies in the project area with permitting requirements. For LNG terminal facilities, the list shall identify the agency designated by the governor of the state in which the project will be located to consult with the Commission regarding state and local safety considerations. The filing shall include a statement indicating:
(i) That those agencies are aware of the prospective applicant’s intention to use the pre-filing process (including contact names and telephone numbers);
(ii) Whether the agencies have agreed to participate in the process;
(iii) How the applicant has accounted for agency schedules for issuance of federal authorizations; and
(iv) When the applicant proposes to file with these agencies for their respective permits or other authorizations.
(6) A list and description of the interest of other persons and organizations who have been contacted about the project (including contact names and telephone numbers).
(7) A description of what work has already been done, e.g., contacting stakeholders, agency consultations, project engineering, route planning, environmental and engineering contractor engagement, environmental surveys/studies, and open houses. This description shall also include the identification of the environmental and engineering firms and sub-contractors under contract to develop the project.
(8) For LNG terminal projects, proposals for at least three prospective third-party contractors from which Commission staff may make a selection to assist in the preparation of the requisite NEPA document.
(9) For natural gas facilities other than LNG terminal facilities and related jurisdictional natural gas facilities, proposals for at least three prospective third-party contractors from which Commission staff may make a selection to assist in the preparation of the requisite NEPA document, or a proposal for the submission of an applicant-prepared draft Environmental Assessment as determined during the initial consultation described in paragraph (c) of this section.
(10) Acknowledgement that a complete Environmental Report and complete application are required at the time of filing.
(11) A description of a Public Participation Plan which identifies specific tools and actions to facilitate stakeholder communications and public information, including a project website and a single point of contact. This plan shall also describe how the applicant intends to respond to requests for information from federal and state permitting agencies, including, if applicable, the governor’s designated agency for consultation regarding state and local safety considerations with respect to LNG facilities.
(12) Certification that a Letter of Intent and a Preliminary WSA have been submitted to the U.S. Coast Guard or, for modifications to an existing or approved LNG terminal, that the U.S. Coast Guard did not require such information.
(e) Director’s notices. (1) When the Director finds that a prospective applicant for authority to site and construct a new LNG terminal has adequately addressed the requirements of paragraphs (a), (c) and (d) of this section, the Director shall issue a notice of such finding. Such notice shall designate the third-party contractor. The pre-filing process shall be deemed to have commenced on the date of the Director’s notice, and the date of such notice shall be used in determining whether the date an application is filed is at least 180 days after commencement of the pre-filing process.
(2) When the Director finds that a prospective applicant for authority to make modifications to an existing or approved LNG terminal has adequately addressed the requirements of paragraphs (a), (c) and (d) of this section, the Director shall issue a notice making a determination whether prospective modifications to an existing LNG terminal shall be subject to this section’s pre-filing procedures and review process. Such notice shall designate the third-party contractor, if appropriate. If the Director determines that the prospective modifications are significant modifications that involve state and local safety considerations, the Director’s notice will state that the pre-filing procedures shall apply, and the pre-filing process shall be deemed to have commenced on the date of the Director’s notice in determining whether the date an application is filed is at least 180 days after commencement of the pre-filing process.
(3) When a prospective applicant requests to use this section’s pre-filing procedures and review for facilities not potentially subject to this section’s mandatory requirements, the Director shall issue a notice approving or disapproving use of the pre-filing procedures of this section and determining whether the prospective applicant has adequately addressed the requirements of paragraphs (b), (c) and (d) of this section. Such notice shall designate the third-party contractor, if appropriate. The pre-filing process shall be deemed to have commenced on the date of the Director’s notice, and the date of such notice shall be used in determining whether the date an application is filed is at least 180 days after commencement of the pre-filing process.
(f) Upon the Director’s issuance of a notice commencing a prospective applicant’s pre-filing process, the prospective applicant must:
(1) Within seven days and after consultation with Commission staff, establish the dates and locations at which the prospective applicant will conduct open houses and meetings with stakeholders (including agencies) and Commission staff.
(2) Within 14 days, conclude the contract with the selected third-party contractor.
(3) Within 14 days, contact all stakeholders not already informed about the project, including all affected landowners as defined in paragraph § 157.6(d)(2) of this section.
(4) Within 30 days, submit a stakeholder mailing list to Commission staff.
(5) Within 30 days, file a draft of Resource Report 1, in accordance with § 380.12(c), and a summary of the alternatives considered or under consideration.
(6) On a monthly basis, file status reports detailing the applicant’s project activities including surveys, stakeholder communications, and agency meetings.
(7) Be prepared to provide a description of the proposed project and to answer questions from the public at the scoping meetings held by OEP staff.
(8) Be prepared to attend site visits and other stakeholder and agency meetings arranged by the Commission staff, as required.
(9) Within 14 days of the end of the scoping comment period, respond to issues raised during scoping.
(10) Within 60 days of the end of the scoping comment period, file draft Resource Reports 1 through 12.
(11) At least 60 days prior to filing an application, file revised draft Resource Reports 1 through 12, if requested by Commission staff.
(12) At least 90 days prior to filing an application, file draft Resource Report 13 (for LNG terminal facilities).
(13) Certify that a Follow-on WSA will be submitted to the U.S. Coast Guard no later than the filing of an application with the Commission (for LNG terminal facilities and modifications thereto, if appropriate). The applicant shall certify that the U.S. Coast Guard has indicated that a Follow-On WSA is not required, if appropriate.
(g) Commission staff and third-party contractor involvement during the pre-filing process will be designed to fit each project and will include some or all of the following:
(1) Assisting the prospective applicant in developing initial information about the proposal and identifying affected parties (including landowners, agencies, and other interested parties).
(2) Issuing an environmental scoping notice and conducting such scoping for the proposal.
(3) Facilitating issue identification and resolution.
(4) Conducting site visits, examining alternatives, meeting with agencies and stakeholders, and participating in the prospective applicant’s public information meetings.
(5) Reviewing draft Resource Reports.
(6) Initiating the preparation of a preliminary Environmental Assessment or Draft Environmental Impact Statement, the preparation of which may involve cooperating agency review.
(h) A prospective applicant using the pre-filing procedures of this section shall comply with the procedures in § 388.112 of this chapter for the submission of documents containing privileged materials or critical energy infrastructure information.
(a) For an application under section 3 or 7 of the Natural Gas Act that requires a Federal authorization—i.e., a permit, special use authorization, certification, opinion, or other approval—from a Federal agency or officer, or State agency or officer acting pursuant to delegated Federal authority, a final decision on a request for a Federal authorization is due no later than 90 days after the Commission issues its final environmental document, unless a schedule is otherwise established by Federal law.
(b) For requests for a water quality certification submitted pursuant to section 401(a)(1) of the Federal Water Pollution Control Act (Clean Water Act) in connection with a project for which authorization is sought from the Commission under section 3 or 7 of the Natural Gas Act, the reasonable period of time during which the certifying agency may act on the water quality certification request is one year from the certifying agency’s receipt of the request. A certifying agency is deemed to have waived the certification requirements of section 401(a)(1) of the Clean Water Act if the certifying agency has not denied or granted certification by one year after the date the certifying agency received a written request for certification.
§ 157.23 Authorizations to Proceed with Construction Activities.
With respect to orders issued pursuant to 15 U.S.C. 717b or 15 U.S.C. 717f(c) authorizing the construction of new natural gas transportation, export, or import facilities, no authorization to proceed with construction activities will be issued:
(a) Until the time for the filing of a request for rehearing under 15 U.S.C. 717r(a) has expired with no such request being filed, or
(b) If a timely request for rehearing raising issues reflecting opposition to project construction, operation, or need is filed, until:
(1) The request is no longer pending before the Commission;
(2) The record of the proceeding is filed with the court of appeals; or
(3) 90 days has passed after the date that the request for rehearing may be deemed to have been denied under 15 U.S.C. 717r(a).
Subpart B—Open Seasons for Alaska Natural Gas Transportation Projects
§ 157.30 Purpose.
This subpart establishes the procedures for conducting open seasons for the purpose of making binding commitments for the acquisition of initial or voluntary expansion capacity on Alaska natural gas transportation projects, as defined herein.
§ 157.31 Definitions.
(a) “Alaska natural gas transportation project” means any natural gas pipeline system that carries Alaska natural gas to the international border between Alaska and Canada (including related facilities subject to the jurisdiction of the Commission) that is authorized under the Alaska Natural Gas Transportation Act of 1976 or section 103 of the Alaska Natural Gas Pipeline Act.
(b) “Commission” means the Federal Energy Regulatory Commission.
(c) “Voluntary expansion” means any expansion in capacity of an Alaska natural gas transportation project above the initial certificated capacity, including any increase in mainline capacity, any extension of mainline pipeline facilities, and any lateral pipeline facilities beyond those certificated in the initial certificate order, voluntarily made by the pipeline. An expansion done pursuant to section 105 of the Alaska Natural Gas Pipeline Act is not a voluntary expansion.
§ 157.32 Applicability.
These regulations shall apply to any application to the Commission for a certificate of public convenience and necessity or other authorization for an Alaska natural gas transportation project, whether filed pursuant to the Natural Gas Act, the Alaska Natural Gas Transportation Act of 1976, or the Alaska Natural Gas Pipeline Act, and to applications for expansion of such projects. Absent a Commission order to the contrary, these regulations are not applicable in the case of an expansion ordered by the Commission pursuant to section 105 of the Alaska Natural Gas Pipeline Act.
§ 157.33 Requirement for open season.
(a) Any application for a certificate of public convenience and necessity or other authorization for a proposed Alaska natural gas transportation project must include a demonstration that the applicant has conducted an open season for capacity on its proposed project, in accordance with the requirements of this subpart. Failure to provide the requisite demonstration will result in an application being rejected as incomplete.
(b) Initial capacity on a proposed Alaska natural gas transportation project may be acquired prior to an open season through pre-subscription agreements, provided that in any open season as required in paragraph (a) of this section, capacity is offered to all prospective bidders at the same rates and on the same terms and conditions as contained in the pre-subscription agreements. All pre-subscription agreements shall be made public by posting on Internet websites and press releases within ten days of their execution. In the event there is more than one such agreement, all prospective bidders shall be allowed the option of selecting among the several agreements all of the rates, terms and conditions contained in any one such agreement.
§ 157.34 Notice of open season.
(a) Notice. A prospective applicant must provide reasonable public notice of an open season through methods including postings on Internet Web sites, press releases, direct mail solicitations, and other advertising. In addition, a prospective applicant must provide actual notice of an open season to the State of Alaska and to the Federal Coordinator for Alaska Natural Gas Transportation Projects.
(b) In-State Needs Study. A prospective applicant must conduct or adopt a study of gas consumption needs and prospective points of delivery within the State of Alaska and rely upon such study to develop the contents of the notice required in paragraph (a) of this section. Such study shall be identified in the notice and if practicable, shall include or consist of a study conducted, approved, or otherwise sanctioned by an appropriate governmental agency, office or commission of the State of Alaska. In its open season proposal, a prospective applicant shall include an estimate based upon the study, of how much capacity will be used in-state.
(c) Contents of notice. Notice of the open season required in paragraph (a) of this section, shall contain at least the following information; however, to the extent that any item of such information is not known or determined at the time the notice is issued, the prospective applicant shall make a good faith estimate based on the best information available of all such unknown or undetermined items of required information and further, must identify the source of information relied on, explain why such information is not presently known, and update the information when and if it is later determined during the open season period:
(1) The general route of the proposed project, including receipt and delivery points, and any alternative routes under consideration; delivery points must include those within the State of Alaska as determined by the In-State Study in paragraph (b) of this section.
(2) Size and design capacity (including proposed certificate capacity at the delivery points named in paragraph (c)(1) of this section to the extent that it differs from design capacity), a description of possible designs for expanded capacity beyond initial capacity, together with any estimated date when such expansions designs may be considered;
(3) Maximum allowable operating pressure and expected actual operating pressure;
(4) Delivery pressure at all delivery points named in paragraph (c)(1) of this section;
(5) Projected in-service date;
(6) An estimated unbundled transportation rate for each delivery point named in paragraph (c)(1) of this section, stated on a volumetric or thermal basis, for each service offered, including reservation rates for pipeline capacity, interruptible transportation rates, usage rates, fuel retention percentages, and other applicable charges, or surcharges, such as the Annual Charge Adjustment (ACA); (if rates are estimated on a volumetric basis then the notice must inform bidders that final pro forma service agreements and the sponsor’s proposed FERC tariff will have to be submitted with rates based on a thermal basis.)
(7) The estimated cost of service (i.e., estimated cost of facilities, depreciation, rate of return and capitalization, taxes and operational and maintenance expenses), and estimated cost allocations, rate design volumes and rate design;
(8) Based on the In-State Study and the delivery points within the State of Alaska identified in paragraph (c)(1) of this section, there must be an estimated transportation rate for such deliveries, based on the amount of in-state needs shown in the study. Such estimated transportation rate must be based on the costs to make such in-state deliveries and shall not include costs to make deliveries outside the State of Alaska;
(9) Negotiated rate and other rate options under consideration, including any rates and terms of any precedent agreements with prospective anchor shippers that have been negotiated or agreed to outside of the open season process prescribed in this section;
(10) Quality specifications and any other requirements applicable to gas to be delivered to the project; provided that a prospective applicant shall not require that potential shippers process or treat their gas at any designated plant or facility;
(11) Terms and conditions for each service offered;
(12) Creditworthiness standards to be applied to, and any collateral requirements for, prospective shippers;
(13) The date, if any, by which potential shippers and the prospective applicant must execute precedent agreements;
(14) A detailed methodology for determining the value of bids for deliveries within the State of Alaska and for deliveries outside the State of Alaska;
(15) The methodology by which capacity will be awarded, in the case of over-subscription, clearly stating all terms that will be considered, except that if any capacity is acquired through pre-subscription agreements as provided in § 157.33(b) and the prospective applicant does not redesign the project to accommodate all capacity requests, only that capacity that was acquired through pre-subscription or was bid in the open season on the same rates, terms, and conditions as any one of the pre-subscription agreements shall be allocated on a pro rata basis and no other capacity acquired through the open season shall be allocated.
(16) Required bid information, whether bids are binding or non-binding, receipt and delivery point requirements, the form of a precedent agreement and time of execution of the precedent agreement, definition and treatment of non-conforming bids;
(17) The projected date for filing an application with the Commission;
(18) All information that the prospective applicant has in its possession pertaining to the proposed service to be offered, projected pipeline capacity and design, proposed tariff provisions, and cost projections, or that the prospective applicant has made available to, or obtained from, any potential shipper, including any affiliates of the project sponsor and any shippers with pre-subscribed capacity, prior to the issuance of the public notice of open season;
(19) A list of the names and addresses of the prospective applicant’s affiliated sales and marketing units and affiliates involved in the production of natural gas in the State of Alaska. Affiliated unit means “Affiliate” as defined in § 358.3(a) of this chapter. Marketing units and or affiliates are those conducting a “marketing function” as defined in § 358.3(c) of this chapter, except that the exemption in § 358.3(c)(2)(iii) shall not apply;
(20) A comprehensive organizational chart showing:
(i) The organizational structure of the prospective applicant’s parent corporation(s) with the relative position in the corporate structure of marketing and sales units and any affiliates involved in the production of natural gas in the State of Alaska.
(ii) The job titles and descriptions, and chain of command for all officers and directors of the prospective applicant’s marketing and sales units and any affiliates involved in the production of natural gas in the State of Alaska; and
(21) A statement that any officers and directors of the prospective applicant’s affiliated sales and marketing units and affiliates involved in the production of natural gas in the State of Alaska named in paragraph (c)(19) of this section will be prohibited from obtaining information about the conduct of the open season or allocation of capacity that is not posted on the open season Internet Web site or that is otherwise also available to the general public or other participants in the open season.
(d) Timing. (1) A prospective applicant must provide prospective shippers at least 90 days from the date on which notice of the open season is given within which to submit requests for transportation services. No bid shall be rejected because a prospective shipper has submitted another bid in another open season conducted under this subpart.
(2) A prospective applicant must consider any bids tendered after the expiration of the open season by qualifying bidders and may reject them only if they cannot be accommodated due to economic, engineering, design, capacity or operational constraints, or accommodating the request would otherwise adversely impact the timely development of the project, and a detailed explanation must accompany the rejection. Any bids tendered after the expiration of the open season must contain a good faith showing, including a statement of the circumstances which prevented the late bidder from tendering a timely bid and how those circumstances have changed. If a prospective applicant determines at any time that, based on the criteria stated in this paragraph, no further late bids for capacity can be accommodated, it may request Commission approval to summarily reject any further requests.
(3) Within 10 days after precedent agreements have been executed for capacity allocated in the open season, the prospective applicant shall make public on the Internet and through press releases the results of the open season, at least including the name of the prospective shipper, amount of capacity awarded, and term of agreement.
(4) Within 20 days after precedent agreements have been executed for capacity allocated in the open season, the prospective applicant must submit copies of all such precedent agreements to the Commission and copies of any relevant correspondence with bidders for capacity who were not allocated capacity that identifies why such bids were not accepted (all documents identified in this paragraph (d)(4) may be filed seeking privileged treatment pursuant to § 388.112 of this chapter.
§ 157.35 Undue discrimination or preference.
(a) All binding open seasons shall be conducted without undue discrimination or preference in the rates, terms or conditions of service and all capacity allocated as a result of any open season shall be awarded without undue discrimination or preference of any kind.
(b) Any complaint filed pursuant to § 385.206 of this chapter alleging non-compliance with any of the requirements of this subpart shall be processed under the Commission’s Fast Track Processing procedures contained in § 385.206(h).
(c) Each prospective applicant conducting an open season under this subpart must function independent of the other divisions of the prospective applicant as well as the prospective applicant’s “affiliates” performing a “marketing function” as those terms are defined in § 358.3(a) and (c) of the Commission’s regulations, except that the exemption in § 358.3(c)(2)(iii) shall not apply. In instances in which the prospective applicant is not an entity created specifically to conduct an open season under this subpart, the prospective applicant must create or designate a unit or division to conduct the open season that must function independent of the other divisions of the project applicant as well as the project applicant’s “affiliates” performing a “marketing function” as those terms are defined in § 358.3(a) of this chapter, except that the exemption in 358.3(c)(2)(iii) shall not apply.
(d) Each project applicant conducting an open season under this subpart that is not otherwise subject to the provisions of part 358 of this chapter must comply with the following sections of that part: §§ 358.4(c) and (d), 358.5, 358.6, 358.7(a), (b), and (c), and 358.8 (b) and (c) of this chapter.
§ 157.36 Open seasons for expansions.
Any open season for capacity exceeding the initial capacity of an Alaska natural gas transportation project must provide the opportunity for the transportation of gas other than Prudhoe Bay or Point Thomson production. In considering a proposed voluntary expansion of an Alaska natural gas pipeline project, the Commission will consider the extent to which the expansion will be utilized by shippers other than those who are the initial shippers on the project and, in order to promote competition and open access to the project, may require design changes to ensure that some portion of the expansion capacity be allocated to new shippers willing to sign long-term firm transportation contracts, including shippers seeking to transport natural gas from areas other than Prudhoe Bay and Point Thomson.
§ 157.37 Project design.
In reviewing any application for an Alaska natural gas pipeline project, the Commission will consider the extent to which a proposed project has been designed to accommodate the needs of shippers who have made conforming bids during an open season, as well as the extent to which the project can accommodate low-cost expansion, and may require changes in project design necessary to promote competition and offer a reasonable opportunity for access to the project.
§ 157.38 Pre-approval procedures.
No later than 90 days prior to providing the notice of open season required by § 157.34(a), a prospective applicant must file, for Commission approval, a detailed plan for conducting an open season in conformance with this subpart. The prospective applicant’s plan shall include the proposed notice of open season. Upon receipt of a request for such a determination, the Secretary of the Commission shall issue a notice of the request, which will then be published in the
§ 157.39 Rate treatment of pipeline expansions.
There shall be a rebuttable presumption that rates for any expansion of an Alaska natural gas transportation project shall be determined on a rolled-in basis.
Subpart C [Reserved]
Subpart D—Exemption of Natural Gas Service for Drilling, Testing, or Purging from Certificate Requirements
§ 157.53 Testing.
(a) Construction and operation of facilities necessary to render direct natural gas service for use in the testing and purging of new natural gas pipeline facilities are exempted from the certificate requirements of section 7(c) of the Natural Gas Act, when the construction and operation of such facilities are conducted in accordance with paragraph (b) of this section.
(b) Operations undertaken to render direct natural gas service shall be terminated upon the completion of the purging or testing of the pipeline facilities. Persons undertaking any construction or operation of facilities or service under this section shall file an original and two copies of an annual statement, by February 1 of each year, describing their activities hereunder.
Subpart E [Reserved]
Subpart F—Interstate Pipeline Blanket Certificates and Authorization Under Section 7 of the Natural Gas Act for Certain Transactions and Abandonment
§ 157.201 Applicability.
(a) Scope. This subpart establishes a procedure whereby an interstate pipeline may obtain a blanket certificate authorizing certain construction and operation of facilities and certain certificate amendments and abandonment under section 7 of the Natural Gas Act.
(b) Who may apply. This procedure is only applicable to interstate pipelines.
(c) Cross-reference. The procedures applicable to transportation by interstate pipelines under blanket certificates are set forth in subpart G of part 284 of this chapter.
(d) Availability of case-specific certificates. Nothing in this subpart shall preclude an interstate pipeline from proceeding under any other provision of the Commission’s regulations to obtain Commission approval of abandonments or a temporary or permanent certificate of public convenience and necessity.
§ 157.202 Definitions.
(a) General rule. Terms defined in the Natural Gas Policy Act of 1978 (NGPA) shall have the same meaning for the purposes of this subpart as they have under the Natural Gas Policy Act of 1978.
(b) Subpart F definitions. For purposes of this subpart:
(1) Certificate holder means any interstate pipeline with an effective blanket certificate issued pursuant to this subpart.
(2)(i) Eligible facility means, except as provided in paragraph (b)(2)(ii) of this section, any facility subject to the Natural Gas Act jurisdiction of the Commission that is necessary to provide service within existing certificated levels. Eligible facility also includes any gas supply facility or any facility, including receipt points, needed by the certificate holder to receive gas into its system for further transport or storage, and interconnecting facilities between transporters that transport natural gas under part 284 of this chapter. Further, eligible facility includes main line, lateral, and compressor replacements that do not qualify under § 2.55(b) of this chapter because they will result in an incidental increase in the capacity of main line facilities, or because they will not satisfy the location or work space requirements of § 2.55(b). Replacements must be done for sound engineering purposes. Replacements for the primary purpose of creating additional main line capacity are not eligible facilities; however, replacements and the modification of facilities to rearrange gas flows or increase compression for the primary purpose of restoring service in an emergency due to sudden unforeseen damage to main line facilities are eligible facilities. Eligible facility also includes auxiliary installations and observation wells which do not qualify under § 2.55(a) of this chapter because they will not satisfy the location or work space requirements of § 2.55(a). Finally, for purposes of abandonment under § 157.216, eligible facilities include auxiliary installations that do not qualify for pre-granted abandonment authority under § 2.55(a)(3) and replacement facilities constructed under § 2.55(b).
(ii) Exclusions: “Eligible facility” does not include:
(A) A main line of a transmission system, except replacement facilities covered under § 157.202(b)(2)(i).
(B) An extension of a main line, except replacement facilities covered under § 157.202(b)(2)(i).
(C) A facility, including compression and looping, that alters the capacity of a main line, except replacement facilities and facility modifications covered under paragraph (b)(2)(i) of this section;
(D) A facility required to test or develop an underground storage field or that alters the certificated capacity, deliverability, or storage boundary, or a facility required to store gas above ground in either a gaseous or liquified state, or a facility used to receive gas from plants manufacturing synthetic gas or from plants gasifying liquefied natural gas, or wells needed to utilize an underground storage field.
(E) Delivery points under § 157.211.
(F) Temporary compression under § 157.209;
(G) A facility that crosses a state line and is constructed for the primary purpose of transporting gas which is also transported by an intrastate pipeline under section 311(a)(2) of the NGPA;
(3) Facility, for purposes of construction under this subpart, does not include an auxiliary facility that qualifies for construction under § 2.55(a) of this chapter or a replacement facility that qualifies for construction under § 2.55(b).
(4) Temporary compression means compressor facilities installed and operated at existing compressor locations for the limited purpose of temporarily replacing existing permanent compressor facilities that are undergoing maintenance or repair or that are pending permanent replacement.
(5) Main line means the principal transmission facilities of a pipeline system extending from supply areas to market areas and does not include small diameter supply or delivery laterals or gathering lines.
(6) Miscellaneous rearrangement of any facility means any rearrangement of a facility, excluding underground storage injection/withdrawal wells, that does not result in any change of service rendered by means of the facilities involved, including changes in existing field operations or relocation of existing facilities:
(i) On the same property;
(ii) When required by highway construction, dam construction, encroachment of residential, commercial, or industrial areas, erosion, or the expansion or change of course of rivers, streams or creeks, or
(iii) To respond to other natural forces beyond the certificate holder’s control when necessary to ensure safety or maintain the operational integrity of the certificate holder’s facilities.
(7) Project means a unit of improvement or construction that is used and useful upon completion.
(8) Project cost means the total actual cost of constructing the jurisdictional portions of a project. In the case of a project constructed jointly by more than one interstate pipeline, the project cost is the total cost, irrespective of the amount paid by each pipeline.
(9) Right-of-way grantor means (i) a person who grants a right-of-way easement to the certificate holder; or (ii) any successor to an interest which is subject to the easement.
(10) Delivery point means a tap and/or metering and appurtenant facilities, such as heaters, minor gas conditioning, treatment, odorization, and similar equipment, necessary to enable the certificate holder to deliver gas to any party.
(11) Sensitive environmental area means:
(i) The habitats of species which have been identified as endangered or threatened under the Endangered Species Act (Pub. L. 93–205, as amended) and essential fish habitat as identified under the Magnuson-Stevens Fishery Conservation and Management Act (16 U.S.C. 1801, et seq.);
(ii) National or State Forests or Parks;
(iii) Properties listed on, or eligible for inclusion in, the National Register of Historic Places, or the National Register of Natural Landmarks;
(iv) Floodplains and wetlands;
(v) Designated or proposed wilderness areas, national or state wild and scenic rivers, wildlife refuges and management areas and sanctuaries;
(vi) Prime agricultural lands, designated by the Department of Agriculture; or
(vii) Sites which are subject to use by American Indians and other Native Americans for religious purposes.
(12) Interconnection facilities means the interconnecting point, which includes the tap, metering, and M&R facilities and the related interconnecting pipeline.
(13) Emergency means a sudden unanticipated loss of gas supply or capacity that requires an immediate restoration of interrupted service for protection of life or health or for maintenance of physical property.
§ 157.203 Blanket certification.
(a) Effect. A blanket certificate issued pursuant to this subpart authorizes the certificate holder, in accordance with the provisions of this subpart, to engage in any of the activities specified in § 157.208 through § 157.218 (as may be amended from time to time).
(b) Automatic authorization. A blanket certificate issued pursuant to this subpart authorizes the certificate holder to engage in transactions described in § 157.208(a), § 157.209(a), § 157.211(a)(1), § 157.213(a), § 157.215, § 157.216(a), or § 157.218 without further Commission approval.
(c) Prior notice required. A blanket certificate issued pursuant to this subpart authorizes the certificate holder to engage in activities described in § 157.208(b), § 157.210,§ 157.211(a)(2), § 157.212, § 157.213(b), § 157.214, or § 157.216(b), if the requirements of § 157.205 have been fulfilled.
(d) Landowner notification. (1) Except as identified in paragraph (d)(3) of this section, no activity described in paragraph (b) of this section is authorized unless the company makes a good faith effort to notify, in writing all affected landowners, as defined in § 157.6(d)(2), at least 45 days prior to commencing construction or at the time it initiates easement negotiations, whichever is earlier. A landowner may waive the 45-day prior notice requirement in writing as long as the notice has been provided. For activity required to restore service in an emergency, the 45-day prior notice period is satisfied in the event a company obtains all necessary easements. The notification shall include at least:
(i) A brief description of the facilities to be constructed or replaced and the effect the construction activity will have on the landowner’s property;
(ii) The name and phone number of a company representative who is knowledgeable about the project;
(iii) A description of the company’s environmental complaint resolution procedure that must:
(A) Provide landowners with clear and simple directions for identifying and resolving their environmental mitigation problems and concerns during construction of the project and restoration of the right-of way;
(B) Provide a local or toll-free phone number and a name of a specific person to be contacted by landowners and with responsibility for responding to landowner problems and concerns, and who will indicate when a landowner should expect a response;
(C) Instruct landowners that if they are not satisfied with the response, they may call the company’s Hotline; and
(D) Instruct landowners that, if they are still not satisfied with the response, they may contact the Commission’s Landowner Helpline at the current telephone number and email address, which is to be provided in the notification.
(2) For activities described in paragraph (c) of this section, the company shall make a good faith effort to notify in writing all affected landowners, as defined in § 157.6(d)(2), within at least three business days following the date that a docket number is assigned to the application or at the time it initiates easement negotiations, whichever is earlier. The notice should include at least:
(i) A brief description of the company and the proposed project, including the facilities to be constructed or replaced and the location (including a general location map), the purpose, and the timing of the project and the effect the construction activity will have on the landowner’s property;
(ii) A general description of what the company will need from the landowner if the project is approved, and how the landowner may contact the company, including a local or toll-free phone number and a name of a specific person to contact who is knowledgeable about the project;
(iii) The docket number (if assigned) for the company’s application;
(iv) A general description of the blanket certificate program and procedures, as posted on the Commission’s Web site at the time the landowner notification is prepared, and the link to the information on the Commission’s Web site;
(v) A brief summary of the rights the landowner has in Commission proceedings and in proceedings under the relevant eminent domain rules; and
(vi) The following paragraph: This project is being proposed under the prior notice requirements of the blanket certificate program administered by the Federal Energy Regulatory Commission. Under the Commission’s regulations, you have the right to protest this project within 60 days of the date the Commission issues a notice of the pipeline’s filing. If you file a protest, you should include the docket number listed in this letter and provide the specific reasons for your protest. The protest should be mailed to the Secretary of the Federal Energy Regulatory Commission, 888 First St., NE., Room 1A, Washington, DC 20426. A copy of the protest should be mailed to the pipeline at [pipeline address]. If you have any questions concerning these procedures you can call the Commission’s Office of External Affairs at (202) 208–1088; and
(vii) The description of the company’s environmental complaint resolution procedure as described in paragraph (d)(1)(iii) of this section.
(3) Exceptions. (i) No landowner notice is required for replacements which would have been done under § 2.55 of this chapter but for the fact that the replacement facilities are not of the same capacity as long as they meet the location requirements of § 2.55(b)(1)(ii) of this chapter and do not cause any ground disturbance; or any replacement done for safety, DOT compliance, environmental, or unplanned maintenance reasons that are not foreseen and that require immediate attention by the certificate holder.
(ii) No landowner notice is required for abandonments which involve only the sale or transfer of the facilities, and the easement will continue to be used for transportation of natural gas.
(iii) No landowner notice is required if there is only one landowner and that landowner has requested the service or facilities.
(iv) No landowner notice is required for activities that do not involve ground disturbance or changes to operational air and noise emissions.
(4) If paragraphs (d)(1) or (d)(2) of this section require an applicant to reveal Critical Energy Infrastructure Information (CEII), as defined by § 388.113(c) of this chapter, to any person, the applicant shall follow the procedures set out in § 157.10(d).
§ 157.204 Application procedure.
(a) Who may apply. Any interstate pipeline which has been issued a certificate other than a limited-jurisdiction certificate, pursuant to section 7 of the Natural Gas Act and had rates accepted by the Commission may apply for a blanket certificate under this subpart in the manner prescribed in §§ 157.6(a), 157.14(a) and 385.2011 of this chapter.
(b) Hearing procedure. Upon receiving an application for a blanket certificate under this subpart, the Commission will conduct a hearing pursuant to section 7(c) of the Natural Gas Act and §§ 1.32 and 157.11 of this chapter.
(c) Issuance. If required by the present or future public convenience and necessity, the Commission will issue a blanket certificate to the applicant.
(d) Application contents. Applications for blanket certificates shall contain:
(1) Information indicating the exact legal name of the applicant; its principal place of business; whether the applicant is an individual, partnership, corporation or otherwise; citation to the certificate proceeding in which the applicant was found to be a natural gas company; the state under the laws of which the applicant is organized or authorized to do business; and the name, title, and mailing address and telephone number of the person or persons to whom communications concerning the application are to be addressed;
(2) A statement that the applicant will comply with the terms, conditions and procedures specified in this subpart.
§ 157.205 Notice procedure.
(a) Applicability. No activity described in §§ 157.208(b), § 157.210, § 157.211(a)(2), § 157.212, § 157.213(b), 157.214 or 157.216(b), except for activity required to restore service in an emergency, is authorized by a blanket certificate granted under this subpart, unless, prior to undertaking such activity:
(1) The notice requirements have been fulfilled in accordance with the provisions of this section; and
(2) Either (i) no protest has been filed pursuant to paragraph (e) of this section or, (ii) if a protest has been filed, it has been withdrawn or dismissed pursuant to paragraph (g) of this section.
(b) Contents. For any activity subject to the requirements of this section, the certificate holder must file with the Secretary of the Commission an original and seven copies, as prescribed in §§ 157.6(a) and 385.2011 of this chapter, a request for authorization under the notice procedures of this section that contains:
(1) The exact legal name of the certificate holder and mailing address and telephone number of the person or persons to whom communications concerning the request are to be addressed;
(2) The docket number in which its blanket certificate was issued;
(3) Any information required in §§ 157.208 through 157.218 of this chapter for the particular activity;
(4) A verified statement that the proposed activity complies with the requirements of this subpart;
(5) A form of notice of the application suitable for publication in the
(6) Identities and docket numbers of other applications related to the transaction. All related filings must be made within 10 days of the first filing. Otherwise the applications on file will be rejected under paragraph (c) of this section without prejudice to refiling when all parties are ready to proceed.
(c) Rejection of request. The Director of the Office of Energy Projects shall reject within 10 days of the date of filing a request which patently fails to comply with the provisions of paragraph (b) of this section, without prejudice to the pipeline’s refiling a complete application.
(d) Publication of notice of request. (1) Unless the request has been rejected pursuant to paragraph (c) of this section, the Secretary of the Commission shall issue a notice of the request within 10 days of the date of the filing, which will then be published in the
(2) [Reserved]
(e) Protests. (1) Any person or the Commission’s staff may file a protest prior to the deadline. Copies of the protest must be served on the Secretary of the Commission and the certificate holder.
(2) Protests shall be filed in the following form:
(Name of Protestor) hereby protests the request filed by (Name of pipeline) to conduct a (construction of facilities, abandonment, etc.) under § 157.____ of the Commission’s regulations. Protestor seeks to have this request processed as a separate application.
(Include a detailed statement of Protestor’s interest in the activity and the specific reasons and rationale for the objection and whether the protestor seeks to be an intervener.)
(f) Effect of protest. If a protest is filed in accordance with paragraph (e) of this section, then the certificate holder, the person who filed the protest, any intervenors, and staff shall have 30 days from the deadline determined in accordance with paragraph (d) of this section, to resolve the protest, and to file a withdrawal of the protest pursuant to paragraph (g) of this section. Informal settlement conferences may be convened by the Director of the Office of Energy Projects or his designee. If a protest is not withdrawn or dismissed pursuant to paragraph (g) of this section, the activity shall not be deemed authorized by the blanket certificate. Instead, the request filed by the certificate holder shall be treated as an application for section 7 authorization for the particular activity. The
(g) Withdrawal or dismissal of protests. The protestor may withdraw a protest within the 30 day period following the deadline determined in accordance with paragraph (d) of this section by submitting written notice of withdrawal to the Secretary of the Commission and serving a copy on the certificate holder, any intervenors and any other party requesting service. The withdrawal must state that the certificate holder and the protestor concur in the withdrawal. Within 10 days of the filing of a protest, the Director of the Office of Energy Projects will dismiss that protest if it does not raise a substantive issue and fails to provide any specific detailed reason or rationale for the objection. If a protest is dismissed, the notice requirements of this section will not be fulfilled until the earlier of: (1) a 30 day period following the deadline determined in paragraph (d) of this section has run; or the dismissed protesting party notifying the Secretary of the Commission that its concerns have been resolved.
(h) Final authorization. (1) If no protest is filed within the time allowed by the Secretary, the certificate holder is authorized to conduct the activity under its blanket certificate, effective on the day after time expires for filing protests and interventions unless, during that time, the certificate holder withdraws its application in accordance with § 385.216 of this chapter.
(2) If any protest is filed within the time allowed for protest and interventions and is subsequently withdrawn under paragraph (g) of this section, the certificate holder is authorized to conduct the activity under its blanket certificate, effective upon the day after the withdrawal of all protests, unless the certificate holder withdraws its application in accordance with § 385.216 of this chapter prior to that date.
§ 157.206 Standard conditions.
Any activity authorized under a blanket certificate issued under this subpart is subject to the following conditions:
(a) Revisions. (1) The Commission reserves the right to amend the requirements of this subpart from time to time.
(2) The blanket certificate is not transferable in any manner and shall be effective only so long as the certificate holder continues the activities authorized by the order issuing such certificate and does so in accordance with the provisions of the Natural Gas Act, as well as applicable rules, regulations, and orders of the Commission.
(b) Environmental compliance. This paragraph only applies to activities that involve ground disturbance or changes to operational air and noise emissions.
(1) The certificate holder shall adopt the requirements set forth in § 380.15(a) and (b) of this chapter for all activities authorized by the blanket certificate and shall issue the relevant portions thereof to construction personnel, with instructions to use them.
(2) All activities shall be consistent with all applicable law including the provisions of the following statutes and regulations or compliance plans developed to implement these statutes:
(i) Clean Water Act, as amended (33 U.S.C. 1251 et seq.) and the National Pollution Discharge Elimination System Program, 40 CFR part 122 et seq.;
(ii) Clean Air Act, as amended (42 U.S.C. 1801 et seq.) and air quality regulations and state implementation plans adopted pursuant to 40 CFR parts 50–99;
(iii) National Historic Preservation Act of 1966 (16 U.S.C. 470 et seq.);
(iv) Archeological and Historic Preservation Act of 1974 (Pub. L. 93–291);
(v) Coastal Zone Management Act of 1972, as amended (16 U.S.C. 1451 et seq.);
(vi) Endangered Species Act of 1973, Pub. L. 93–205, as amended (16 U.S.C. 1531 et seq.);
(vii) Executive Order 11988, May 24, 1977 requiring Federal agencies to evaluate the potential effects of any actions it may take on a floodplain;
(viii) Executive Order 11990, May 24, 1977 requiring an evaluation of the potential effects of construction on wetland;
(ix) Wild and Scenic Rivers Act (16 U.S.C. 1274 et seq.);
(x) National Wilderness Act (16 U.S.C. 1133 et seq.);
(xi) National Parks and Recreation Act of 1978 (16 U.S.C. 1 and 230 et seq.).
(xii) Magnuson-Stevens Fishery Conservation and Management Act (16 U.S.C. 1801, et seq.)
(3) The certificate holder shall be deemed in compliance with:
(i) Paragraph (b)(2)(vi) of this section only if it adheres to the procedures in appendix I of this subpart in which case the Commission finds that endangered species and their critical habitat are protected in accordance with 16 U.S.C. 1536;
(ii) Paragraph (b)(2)(iii) of this section only if it adheres to the procedures in appendix II of this subpart in which case the Commission finds that there is no effect on any property protected by 16 U.S.C. 470f;
(iii) Paragraph (b)(2)(v) of this section only if the appropriate state agency designated to administer the state’s coastal zone management plan, prior to construction of the project, waives its right of review or determines that the project complies with the state’s coastal zone management plan.
(iv) Paragraphs (b)(2)(i) and (viii) of this section only if it adheres to Commission staff’s current “Upland Erosion Control, Revegetation and Maintenance Plan” and “Wetland and Waterbody Construction and Mitigation Procedures” which are available on the Commission Internet home page or from the Commission staff, or gets written approval from the staff or the appropriate Federal or state agency for the use of project-specific alternatives to clearly identified portions of those documents.
(4) Any transaction authorized under a blanket certificate shall not have a significant adverse impact on a sensitive environmental area.
(5)(i) The noise attributable to any new compressor station, compression added to an existing station, or any modification, upgrade or update of an existing station, must not exceed a day-night level (L
(ii) A compressor facility installed under this section must be designed to meet the following noise emissions criteria. For each new compressor station facility, and for each addition or modification to an existing compression station, the blanket certificate holder must file a noise survey with the Secretary within 60 days of placing the facility in service.
(A) If noise emitted from a new compressor facility operating at full load exceeds an L
(B) If an addition or modification to an existing compressor station operating at full load above an L
(C) If the initial noise survey demonstrates a need to take action to mitigate noise, within 60 days of completing such action, the blanket certificate holder must file a subsequent noise survey with the Secretary demonstrating that each new compressor station facility, and each addition or modification to an existing compressor station, complies with the noise level limits.
(iii) Any horizontal directional drilling or drilling of wells which will occur between 10 p.m. and 7 a.m. local time must be conducted with the goal of keeping the perceived noise from the drilling at any pre-existing noise-sensitive area (such as schools, hospitals, or residences) at or below a night level (L
(6)(i) Any activity otherwise subject to authorization under § 157.208 shall not be authorized if the activity is located within 0.5 mile of a nuclear power plant which is either operating or under construction, or for which a construction permit has been filed with the Nuclear Regulatory Commission.
(ii) Any activity otherwise subject to authorization under § 157.215 shall not be authorized if the activity is located within 2.0 miles of a nuclear power plant which is either operating or under construction, or for which a construction permit has been filed with the Nuclear Regulatory Commission.
(7) The certificate holder shall act as the Commission’s non-Federal representative upon acceptance of the blanket certificate for purposes of complying with the Endangered Species Act of 1973.
(c) Commencement. Any authorized construction, extension, or acquisition shall be completed and made available for service by the certificate holder and any authorized operation, or service, shall be available within one year of the date the activity is authorized pursuant to § 157.205(h). The certificate holder may apply to the Director of the Office of Energy Projects for an extension of this deadline. However, if the request for extension is due to the end-user/shipper not being ready to accept service, the certificate holder must so notify the Commission in writing no later than 10 days after expiration of the one-year period.
(d) Reports. The certificate holder shall file reports as required by this subpart.
§ 157.207 General reporting requirements.
On or before May 1, or each year, or in the case of emergency reconstruction activity, prior to any activity, the certificate holder must file, in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter, an annual report signed under oath by a senior official of the company, that lists for the previous calendar year:
(a) For each new facility authorized by §§ 157.208, 157.210, 157.212, or 157.213, the information specified in § 157.208(e);
(b) For each delivery point authorized under § 157.211(a)(1), the information required by § 157.211(c);
(c) for each temporary compressor facility under § 157.209, the information required by § 157.209(b);
(d) For each storage project tested or developed under § 157.215, the information specified in § 157.215(b)(1);
(e) For each abandonment authorized under § 157.216(a), the information specified in § 157.216(d);
(f) For each change in rate schedule authorized under § 157.217, the information specified in § 157.217(b);
(g) For each change in customer name authorized under § 157.218, the information specified in § 157.218(b); and
(h) If any activity required to be reported under this section was not undertaken, a statement to that effect.
§ 157.208 Construction, acquisition, operation, replacement, and miscellaneous rearrangement of facilities.
(a) Automatic authorization. If the project cost does not exceed the cost limitations set forth in column 1 of table 1 to paragraph (d) of this section, or if the project is required to restore service in an emergency, the certificate holder is authorized to make miscellaneous rearrangements of any facility, or acquire, construct, replace, or operate any eligible facility. The certificate holder shall not segment projects in order to meet the cost limitations set forth in column 1 of table 1 to paragraph (d).
(b) Prior notice. If the project cost is greater than the amount specified in column 1 of table 1 to paragraph (d) of this section, but less than the amount specified in column 2 of table 1 to paragraph (d), the certificate holder is authorized to make miscellaneous rearrangements of any facility, or acquire, construct, replace, or operate any eligible facility. The certificate holder shall not segment projects in order to meet the cost limitations set forth in column 2 of table 1 to paragraph (d).
(c) Contents of request. In addition to the requirements of § 157.205(b), requests filed for activities described under paragraph (b) of this section shall contain:
(1) A description of the purpose of the proposed facilities including their relationship to other existing or planned facilities;
(2) A detailed description of the proposed facilities specifying length, diameter, wall thickness and maximum operating pressure for pipeline; and for compressors, the size, type, and number of compressor units, horsepower required, horsepower existing and proposed, volume of fuel gas, suction and discharge pressure and compression ratio;
(3) A USGS 7
(4) A map showing the relationship of the proposed facilities to the applicant’s existing facilities;
(5) A flow diagram or comparative study showing daily design capacity, daily maximum capacity and operating pressures with and without the proposed facilities for that portion of the certificate holder’s system affected by the proposal;
(6) The estimated cost and method of financing the proposed facilities;
(7) A statement explaining how the public convenience and necessity requires the approval of the project;
(8) For acquisitions of facilities:
(i) A statement referencing the date of issuance, docket number and title of the proceeding for any certificate issued by the Commission authorizing the facilities proposed to be acquired; and
(ii) The amounts recorded in the accounts of the vendor (seller or lessor) that apply to the facilities proposed to be acquired and the accumulated provisions for depreciation, depletion, and amortization;
(9) A concise analysis discussing the relevant issues outlined in § 380.12 of this chapter. The analysis must identify the existing environmental conditions and the expected significant impacts that the proposed action, including proposed mitigation measures, will cause to the quality of the human environment, including impact expected to occur to sensitive environmental areas. When compressor facilities are proposed, the analysis must also describe how the proposed action will be made to comply with applicable State Implementation Plans developed under the Clean Air Act. The analysis must also include a description of the contacts made, reports produced, and results of consultations which took place to ensure compliance with the Endangered Species Act, National Historic Preservation Act and the Coastal Zone Management Act. Include a copy of the agreements received for compliance with the Endangered Species Act, National Historic Preservation Act, and Coastal Zone Management Act, or if no written concurrence is issued, a description of how the agency relayed its opinion to the company. Describe how drilling for wells or horizontal direction drilling would be designed to meet the goal of limiting the perceived noise at NSAs to an L
(10) A commitment to having the Environmental Inspector’s report filed every week.
(d) Limits and inflation adjustment. The limits specified in table 1 to this paragraph (d) and table 1 to § 157.215(a)(5) shall be adjusted each calendar year to reflect the “GDP implicit price deflator” published by the Department of Commerce for the previous calendar year. The Director of the Office of Energy Projects is authorized to compute and publish limits for future calendar years as a part of table 1 to this paragraph (d) and table 1 to § 157.215(a)(5), pursuant to § 375.308(x)(1) of this chapter.
Table 1 to Paragraph (
| Year | Limit | |
|---|---|---|
| Auto. proj. cost limit (col. 1) | Prior notice proj. cost limit (col. 2) | |
| 1982 | $4,200,000 | $12,000,000 |
| 1983 | 4,500,000 | 12,800,000 |
| 1984 | 4,700,000 | 13,300,000 |
| 1985 | 4,900,000 | 13,800,000 |
| 1986 | 5,100,000 | 14,300,000 |
| 1987 | 5,200,000 | 14,700,000 |
| 1988 | 5,400,000 | 15,100,000 |
| 1989 | 5,600,000 | 15,600,000 |
| 1990 | 5,800,000 | 16,000,000 |
| 1991 | 6,000,000 | 16,700,000 |
| 1992 | 6,200,000 | 17,300,000 |
| 1993 | 6,400,000 | 17,700,000 |
| 1994 | 6,600,000 | 18,100,000 |
| 1995 | 6,700,000 | 18,400,000 |
| 1996 | 6,900,000 | 18,800,000 |
| 1997 | 7,000,000 | 19,200,000 |
| 1998 | 7,100,000 | 19,600,000 |
| 1999 | 7,200,000 | 19,800,000 |
| 2000 | 7,300,000 | 20,200,000 |
| 2001 | 7,400,000 | 20,600,000 |
| 2002 | 7,500,000 | 21,000,000 |
| 2003 | 7,600,000 | 21,200,000 |
| 2004 | 7,800,000 | 21,600,000 |
| 2005 | 8,000,000 | 22,000,000 |
| 2006 | 9,600,000 | 27,400,000 |
| 2007 | 9,900,000 | 28,200,000 |
| 2008 | 10,200,000 | 29,000,000 |
| 2009 | 10,400,000 | 29,600,000 |
| 2010 | 10,500,000 | 29,900,000 |
| 2011 | 10,600,000 | 30,200,000 |
| 2012 | 10,800,000 | 30,800,000 |
| 2013 | 11,000,000 | 31,400,000 |
| 2014 | 11,200,000 | 31,900,000 |
| 2015 | 11,400,000 | 32,400,000 |
| 2016 | 11,600,000 | 32,800,000 |
| 2017 | 11,800,000 | 33,200,000 |
| 2018 | 12,000,000 | 33,800,000 |
| 2019 | 12,300,000 | 34,600,000 |
| 2020 | 12,500,000 | 35,200,000 |
| 2021 | 12,600,000 | 35,600,000 |
| 2022 | 13,100,000 | 37,100,000 |
| 2023 | 14,000,000 | 39,700,000 |
| 2024 | 14,500,000 | 41,100,000 |
(e) Reporting requirements. For each facility completed during the calendar year pursuant to paragraph (a) of this section and § 157.213(a), the certificate holder shall file in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter as part of the required annual report under § 157.207(a) the information described in paragraphs (e)(1)–(5) of this section. For each facility completed during the calendar year pursuant to paragraph (b) of this section, and §§ 157.210, 157.212, and 157.213(b), the certificate holder shall file in the manner prescribed above only the information described in paragraph (e)(3) of this section.
(1) A description of the facilities installed pursuant to this section, including a description of the length and size of pipelines, compressor horsepower, metering facilities, taps, valves, and any other facilities constructed;
(2) The specific purpose, location, and beginning and completion date of construction of the facilities installed, the date service commenced, and, if applicable, a statement indicating the extent to which the facilities were jointly constructed;
(3) The actual installed cost of each facility item listed pursuant to paragraph (e)(1), separately stating the cost of materials and labor as well as other costs allocable to the facilities;
(4)(i) A description of the contacts made, reports produced, and results of consultations which took place to ensure compliance with the Endangered Species Act, the National Historic Preservation Act and the Coastal Zone Management Act;
(ii) Documentation, including images, that restoration of work areas is progressing appropriately;
(iii) A discussion of problems or unusual construction issues, including those identified by affected landowners, and corrective actions taken or planned; and
(iv) For new or modified compression, a noise survey verifying compliance with § 157.206(b)(5).
(5) For acquisitions of facilities:
(i) A statement referencing the date of issuance, docket number and title of the proceeding for any certificate issued by the Commission authorizing the facilities acquired; and
(ii) The amounts recorded in the accounts of the vendor (seller or lessor) that apply to the facilities acquired and the accumulated provisions for depreciation, depletion, and amortization.
(f) Special conditions. (1) For purposes of comparing the project cost of leased facilities with the per-project cost limitations in table 1 to paragraph (d) of this section, the project cost of leased facilities shall be the annual lease charge multiplied by the number of years of the lease.
(2) In the interest of safety and reliability of service, facilities authorized by the certificate shall not be operated at pressures exceeding the maximum operating pressure set forth in the request. In the event that the certificate holder thereafter wishes to change the maximum operating pressure of supply or delivery lateral facilities constructed under section 7(c) of the Natural Gas Act or facilities constructed under this section, it shall file an appropriate request pursuant to the procedures set forth in § 157.205(b). Such request shall include the reasons for the proposed change. Nothing contained herein authorizes the certificate holder to operate any facility at a pressure above the maximum prescribed by State law, if such law requires a lower pressure than authorized hereby.
(g) If the actual cost of the project exceeds the per-project cost authorized under a blanket certificate in table 1 to paragraph (d) of this section, the certificate holder shall apply to the Director of the Office of Energy Projects for a waiver of those project cost limits.
§ 157.209 Temporary compression facilities.
(a) Automatic authorization. If the cost does not exceed the cost limitations set forth in column 1 of table 1 to § 157.208(d), the certificate holder may install, operate and remove temporary facilities provided that the temporary compressor facilities shall not be used to increase the volume or service above that rendered by the involved existing permanent compressor unit(s).
(b) Reporting requirements. As part of the certificate holder’s annual report of projects authorized under paragraph (a) of this section, the certificate holder must report the following in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter;
(1) A description of the temporary compression facility, including the size, type and number of compressor units;
(2) The location at which temporary compression was installed, operated and removed, including its location relative to existing facilities;
(3) A description of the permanent compression facility which was unavailable, and a statement explaining the reason for the temporary compression;
(4) The dates for which the temporary compression was installed, operated and removed; and
(5) If applicable, the information required in § 157.208(e)(4).
§ 157.210 Mainline natural gas facilities.
Subject to the notice requirements of §§ 157.205(b) and 157.208(c), the certificate holder is authorized to acquire, construct, modify, replace, and operate natural gas mainline facilities, including compression and looping, that are not eligible facilities under § 157.202(b)(2)(i). The cost of a project may not exceed the cost limitation provided in column 2 of table 1 to § 157.208(d). The certificate holder must not segment projects in order to meet this cost limitation.
§ 157.211 Delivery points.
(a) Construction and operation—(1) Automatic authorization. The certificate holder may acquire, construct, replace, modify, or operate any delivery point, excluding the construction of certain delivery points subject to the prior notice provisions in paragraph (a)(2) of this section if:
(i) The natural gas is being delivered to, or for the account of, a shipper for whom the certificate holder is, or will be, authorized to transport gas; and
(ii) The certificate holder’s tariff does not prohibit the addition of new delivery points.
(2) Prior notice. Subject to the notice procedure in § 157.205, the certificate holder may acquire, construct, replace, modify, or operate any delivery point if:
(i) The natural gas is being delivered to, or for the account of, an end-user that is currently being served by a local distribution company; and
(ii) The natural gas is being delivered to a shipper for whom the certificate holder is, or will be, authorized to transport gas; and
(iii) The certificate holder’s tariff does not prohibit the addition of new delivery points.
(b) Contents of request. In addition to the requirements of § 157.205(b), requests for activities authorized under paragraph (a)(2) must contain:
(1) The name of the end-user, the location of the delivery point, and the distribution company currently serving the end-user;
(2) A description of the facility and any appurtenant facilities;
(3) A USGS 7
(4) The quantity of gas to be delivered through the proposed facility;
(5) A description, with supporting data, of the impact of the service rendered through the proposed delivery tap upon the certificate holder’s peak day and annual deliveries.
(c) Reporting requirements. As part of the certificate holder’s annual report of projects authorized under paragraph (a) of this section, the certificate holder must report in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter:
(1) A description of the facilities acquired, constructed, replaced, modified or operated pursuant to this section;
(2) The location and maximum quantities delivered at such delivery point;
(3) The actual cost and the completion date of the delivery point; and
(4) The date of each agreement obtained pursuant to § 157.206(b)(3) and the date construction began.
§ 157.212 Synthetic and liquefied natural gas facilities.
Subject to the notice requirements of §§ 157.205(b) and 157.208(c), the certificate holder is authorized to acquire, construct, modify, replace, and operate natural gas facilities that are used to transport either a mix of synthetic and natural gas or exclusively revaporized liquefied natural gas and that are not “related jurisdictional natural gas facilities” as defined in § 153.2(e) of this chapter. The cost of a project may not exceed the cost limitation provided in column 2 of table 1 to § 157.208(d). The certificate holder must not segment projects in order to meet this cost limitation.
§ 157.213 Underground storage field facilities.
(a) Automatic authorization. If the project cost does not exceed the cost limitations provided in column 1 of table 1 to § 157.208(d), the certificate holder may acquire, construct, modify, replace, and operate facilities for the remediation and maintenance of an existing underground storage facility, provided the storage facility’s certificated physical parameters—including total inventory, reservoir pressure, reservoir and buffer boundaries, and certificated capacity remain unchanged—and provided compliance with environmental and safety provisions is not affected. The certificate holder must not alter the function of any well that is drilled into or is active in the management of the storage facility. The certificate holder must not segment projects in order to meet this cost limitation.
(b) Prior Notice. Subject to the notice requirements of §§ 157.205(b) and 157.208(c), the certificate holder is authorized to acquire, construct, modify, replace, and operate natural gas underground storage facilities, provided the storage facility’s certificated physical parameters—including total inventory, reservoir pressure, reservoir and buffer boundaries, and certificated capacity remain unchanged—and provided compliance with environmental and safety provisions is not affected. The cost of a project may not exceed the cost limitation provided in column 2 of table 1 to § 157.208(d). the certificate holder must not segment projects in order to meet this cost limitation.
(c) Contents of request. In addition to the requirements of §§ 157.206(b) and 157.208(c), requests for activities authorized under paragraph (b) of this section must contain, to the extent necessary to demonstrate that the proposed project will not alter a storage reservoir’s total inventory, reservoir pressure, reservoir or buffer boundaries, or certificated capacity:
(1) A description of the current geological interpretation of the storage reservoir, including both the storage formation and the caprock, including summary analysis of any recent cross-sections, well logs, quantitative porosity and permeability data, and any other relevant data for both the storage reservoir and caprock;
(2) The latest isopach and structural maps of the storage field, showing the storage reservoir boundary, as defined by fluid contacts or natural geological barriers; the protective buffer boundary; the surface and bottomhole locations of the existing and proposed injection/withdrawal wells and observation wells; and the lengths of open-hole sections of existing and proposed injection/withdrawal wells;
(3) Isobaric maps (data from the end of each injection and withdrawal cycle) for the last three injection/withdrawal seasons, which include all wells, both inside and outside the storage reservoir and within the buffer area;
(4) A detailed description of present storage operations and how they may change as a result of the new facilities or modifications. Include a detailed discussion of all existing operational problems for the storage field, including but not limited to gas migration and gas loss;
(5) Current and proposed working gas volume, cushion gas volume, native gas volume, deliverability (at maximum and minimum pressure), maximum and minimum storage pressures, at the present certificated maximum capacity or pressure, with volumes and rates in MMcf and pressures in psia;
(6) The latest field injection/withdrawal capability studies including curves at present and proposed working gas capacity, including average field back pressure curves and all other related data;
(7) The latest inventory verification study for the storage field, including methodology, data, and work papers;
(8) The shut-in reservoir pressures (average) and cumulative gas-in-place (including native gas) at the beginning of each injection and withdrawal season for the last 10 years; and
(9) A detailed analysis, including data and work papers, to support the need for additional facilities (wells, gathering lines, headers, compression, dehydration, or other appurtenant facilities) for the modification of working gas/cushion gas ratio and/or to improve the capability of the storage field.
§ 157.214 Increase in storage capacity.
(a) Prior notice. Subject to the notice requirements of § 157.205, the certificate holder is authorized to increase the maximum volume of natural gas authorized to be stored in a storage field to the extent that geological data and operating experience have demonstrated that a volume of natural gas greater than that currently certificated may be safely stored without the construction of additional facilities.
(b) Contents of request. In addition to the requirements of § 157.205(b), requests filed for activities described in paragraph (a) shall contain:
(1) Current and requested maximum storage capacity;
(2) Current and requested maximum storage pressure;
(3) Average depth of the storage formation;
(4) Copies of any geological or engineering studies that demonstrate the feasibility of the increase in storage volume; and
(5) A statement setting forth the purpose of the proposed increased capacity.
(c) Reporting requirements. For any storage facility whose capacity is increased pursuant to this section, the certificate holder shall submit, in the manner prescribed in § 385.2011 of this chapter, semi-annual reports (to coincide with the termination of the injection and withdrawal cycles) containing the information listed in subdivisions (1) through (8) of this paragraph. The certificate holder shall continue to file semi-annual reports until the storage inventory volume has reached, or closely approximates, the maximum specified in the request. Thereafter, the reports shall continue on a semi-annual basis for a period of one year. The filing of reports shall be discontinued thereafter unless otherwise ordered by the Commission. (Volumes shall be stated at 14.73 psia and 60 °F, and pressures shall be stated in psia.)
(1) The daily volume of natural gas injected into and withdrawn from the storage reservoir.
(2) The volume of natural gas in the reservoir at the end of the reporting period.
(3) The maximum daily injection or withdrawal rate experienced during the reporting period and the average working pressure on such maximum days taken at a central measuring point where the total volume injected or withdrawn is measured.
(4) Results of any tracer program by which the leakage of injected gas may be determined. If the leakage of gas exists, the report should show the estimated total volume of gas leakage, the volume of recycled gas and the remaining inventory of gas in the reservoir at the end of the reporting period.
(5) Any surveys of pressures in gas wells, water levels in observation wells, pump test results for the aquifer-type reservoirs, and the results of back-pressure tests conducted during the reporting period.
(6) The latest revised structure and isopachous contour maps showing the location of the wells, the location and extent of the gas bubble in the storage reservoir for aquifer-type reservoirs and in any other reservoirs of the project in which gas bubbles are known to exist. This map need not be filed if there is no material change from the map previously filed.
(7) Discussion of current operating problems and conclusions.
(8) Such other data or reports which may aid the Commission in the evaluation of the storage project.
§ 157.215 Underground storage testing and development.
(a) Automatic authorization. The certificate holder is authorized to acquire, construct and operate natural gas pipeline and compression facilities, including injection, withdrawal, and observation wells for the testing or development of underground reservoirs for the possible storage of gas, if:
(1) The testing and development of a particular storage project will be completed within a three-year-period;
(2) The quantity of natural gas injected into the prospective storage fields pursuant to the blanket certificate does not exceed a total of 10,000,000 Mcf at any time in all fields with no more than 2,000,000 Mcf injected into any single field;
(3) Gas will be injected for testing purposes only during off-peak periods;
(4) The storage field developed pursuant to this section will not be utilized to render service without further authorization from the Commission, except that gas may be withdrawn on occasion for testing purposes; and
(5) The total expenditures per calendar year pursuant to this section do not exceed the amount specified in table 1 to this paragraph (a)(5) as adjusted pursuant to § 157.208(d). These costs shall include expenditures for leases, wells, pipeline, compressors, and related facilities, but shall exclude the cost of the natural gas to be used for testing purposes.
Table 1 to Paragraph (
| Year | Limit |
|---|---|
| 1982 | $2,700,000 |
| 1983 | 2,900,000 |
| 1984 | 3,000,000 |
| 1985 | 3,100,000 |
| 1986 | 3,200,000 |
| 1987 | 3,300,000 |
| 1988 | 3,400,000 |
| 1989 | 3,500,000 |
| 1990 | 3,600,000 |
| 1991 | 3,800,000 |
| 1992 | 3,900,000 |
| 1993 | 4,000,000 |
| 1994 | 4,100,000 |
| 1995 | 4,200,000 |
| 1996 | 4,300,000 |
| 1997 | 4,400,000 |
| 1998 | 4,500,000 |
| 1999 | 4,550,000 |
| 2000 | 4,650,000 |
| 2001 | 4,750,000 |
| 2002 | 4,850,000 |
| 2003 | 4,900,000 |
| 2004 | 5,000,000 |
| 2005 | 5,100,000 |
| 2006 | 5,250,000 |
| 2007 | 5,400,000 |
| 2008 | 5,550,000 |
| 2009 | 5,600,000 |
| 2010 | 5,700,000 |
| 2011 | 5,750,000 |
| 2012 | 5,850,000 |
| 2013 | 6,000,000 |
| 2014 | 6,100,000 |
| 2015 | 6,200,000 |
| 2016 | 6,300,000 |
| 2017 | 6,400,000 |
| 2018 | 6,500,000 |
| 2019 | 6,600,000 |
| 2020 | 6,700,000 |
| 2021 | 6,800,000 |
| 2022 | 7,100,000 |
| 2023 | 7,600,000 |
| 2024 | 7,900,000 |
(b) Reporting requirements—(1) Annual reports. For any storage project tested or developed pursuant to this section, the certificate holder shall file, in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter as part of the annual report required under § 157.207(a), the following information:
(i) A description of the facilities constructed and the type of storage reservoir, i.e., gas expansion or dry gas, water-drive or aquifer;
(ii) The location of the facilities;
(iii) The cost of such facilities, the date construction began, and the date they were placed in service;
(iv) The monthly volumes of gas injected into and withdrawn from each reservoir;
(v) An estimate of the storage capacity and daily deliverability of each project; and
(vi) A description of the contacts made, reports produced, and results of consultations which took place to ensure compliance with the Endangered Species Act, the National Historic Preservation Act and the Coastal Zone Management Act.
(2) Quarterly reports. If the reservoir to be tested and developed is an aquifer-type reservoir, the certificate holder shall file, in the manner prescribed in §§ 157.6(a) and 385.2011 of this chapter unless otherwise ordered by the commission, for each such project quarterly reports, under oath, until the project is either certificated for regular service or abandoned. The quarterly report shall contain the following information in addition to the data required by paragraph (b)(1) of this section:
(i) The daily volumes of natural gas injected into and withdrawn from the aquifer during the quarter and the volume of gas in the aquifer at the end of each month;
(ii) The maximum daily injection or withdrawal rate experienced during the quarter and the average working pressure on such maximum days taken at a central measuring point where the total volume injected or withdrawn is measured;
(iii) Results of any tracer program by which leakage of gas may be determined;
(iv) Any pressure surveys of gas wells and water levels in observation wells conducted during the quarter by individual well, and copies of any core analyses, gamma ray, neutron or other electric log surveys and back-pressure tests taken during the quarter;
(v) A map of the storage project showing the location of the wells, the latest revised structure contours, and the location and extent of the gas bubble. This map need not be filed if there is no material change from the map previously filed; and
(vi) Such other data or reports which may aid the Commission in the evaluation of the project.
(c) Accounting. The cost of any project ultimately determined to be infeasible for storage shall be charged to Account No. 822 of part 201, Underground Storage Exploration and Development Expenses.
§ 157.216 Abandonment.
(a) Automatic authorization. The certificate holder is authorized pursuant to section 7(b) of the Natural Gas Act to abandon gas supply facilities, and:
(1) A receipt or delivery point, or related supply or delivery lateral, provided the facility has not been used to provide:
(i) Interruptible transportation service during the one year period prior to the effective date of the proposed abandonment, or
(ii) Firm transportation service during the one year period prior to the effective date of the proposed abandonment, provided the point is no longer covered under a firm contract; or
(2)(i) An auxiliary facility as described in § 2.55(a) of this chapter when the abandonment:
(A) Will not exceed the cost limit in § 157.208(d) for activities under the automatic provisions;
(B) Will have no adverse impact on customers’ certificated services; and
(C) Cannot satisfy the right-of-way, facility site, and work space limitations for the pre-granted abandonment authority in § 2.55(a)(3);
(ii) A replacement facility that was or could have been constructed under § 2.55(b) of this chapter, provided the current cost to construct the facilities would not exceed the cost limit in § 157.208(d) for activities under the automatic provisions and the certificate holder obtains the written consent of each customer served using the facility during the past 12 months;
(iii) Any other facility that did or could now qualify for automatic authorization as described in § 157.203(b), provided the certificate holder obtains the written consent of each customer served using the facility during the past 12 months.
(b) Prior notice. Subject to the notice requirements of § 157.205, the certificate holder is authorized pursuant to section 7(b) of the Natural Gas Act to abandon:
(1) Any receipt or delivery point if all of the existing customers of the pipeline served through the receipt or delivery point consent in writing to the abandonment. When filing a request for authorization of the proposed abandonment under the notice procedures of § 157.205, the certificate holder shall notify, in writing, the State public service commission having regulatory authority over retail service to the customers served through the delivery point.
(2)(i) An auxiliary facility as described in § 2.55(a) of this chapter when the abandonment:
(A) Will not exceed the cost limit in § 157.208(d) for activities under the prior notice provisions;
(B) Will have no adverse impact on customers’ certificated services; and
(C) Cannot satisfy the right-of-way, facility site, and work space limitations for the pre-granted abandonment authority in § 2.55(a)(3).
(ii) A replacement facility that was or could have been constructed under § 2.55(b) of this chapter, provided the current cost to construct the facilities would not exceed the cost limit in § 157.208(d) for activities under the prior notice provisions and the certificate holder obtains the written consent of each customer served using the facility during the past 12 months;
(iii) Any other facility that did or could now qualify for prior notice authorization as described in § 157.203(c), provided the certificate holder obtains the written consent of each customer served using the facility during the past 12 months.
(c) Contents of request. In addition to the requirements of § 157.205(b), requests filed for activities described under paragraph (b) shall describe:
(1) The location, type, size, and length of the subject facilities. For facilities not constructed or acquired under blanket certificate authority, an estimate of the current cost to replicate such facilities;
(2) The docket authorizing the construction and operation of the facilities to be abandoned;
(3) For each facility an oath statement that all of the customers served during the past year by the subject facilities have consented to the abandonment, or an explanation of why the customers’ consent is not available;
(4) A proposed accounting treatment of any facilities to be abandoned.
(5) For any abandonment resulting in earth disturbance, a USGS 7
(d) Reporting requirements. The annual report filed by the certificate holder shall contain, for each abandonment authorized under paragraph (a) of this section:
(1) A description of the facilities abandoned under this section. For facilities not constructed or acquired under blanket certificate authority, an estimate of the current cost to replicate such facilities;
(2) The docket number(s) of the certificate(s) authorizing the construction and operation of the facilities to be abandoned;
(3) The accounting treatment of the facilities abandoned; and
(4) The date earth disturbance, if any, related to the abandonment began and the date the facilities were abandoned; and
(5) The date of the agreements obtained pursuant to § 157.206(b)(3), if earth disturbance was involved.
§ 157.217 Changes in rate schedules.
(a) Automatic authorization. The certificate holder is authorized to permit an existing customer, at the customer’s request, to change from part 157 individually certificated transportation or storage service to part 284 transportation or storage service, and to abandon the part 157 service, if:
(1) The combined volumetric limitations on deliveries to the customer under both rate schedules are not increased, for either annual or peak day limitations;
(2) The conversion will reflect all the maximum rates and charges associated with the service;
(3) The changes are consistent with the terms of the effective tariffs on file with the Commission. The certificate holder is granted a limited waiver of its tariff requiring posting of available capacity.
(4) The certificate holder shall make a filing to reflect removal of the part 157 rate schedule from its tariff. This tariff filing must be filed in the electronic format required by § 154.4 of this chapter.
(b) Reporting requirements. In the annual report for any year in which the certificate holder has permitted an existing customer to change from one rate schedule to another pursuant to this section, the certificate holder shall state:
(1) The name of the customer;
(2) The rate schedules and associated rates involved; and
(3) The effective date of the change.
§ 157.218 Changes in customer name.
(a) Automatic authorization. The effective certificates of the certificate holder may be amended to the extent necessary to reflect the change in the name of an existing customer, if the certificate holder has filed any necessary conforming changes in its Index of Customers, including the customer’s old name.
(b) Reporting requirements. For each customer name change authorized during a calendar year, the certificate holder shall include as a part of its annual report:
(1) The old and new names of the customer; and
(2) A brief explanation of the reason for the name change.
Appendix I to Subpart F of Part 157—Procedures for Compliance With the Endangered Species Act of 1973 Under § 157.206(b )(3)(i )
The following procedures apply to any certificate holder which undertakes a project to be authorized under a blanket certificate issued pursuant to subparts E or F of part 157 and to any other service subject to § 157.206(b) of the Federal Energy Regulatory Commission’s (Commission) regulations.
Pursuant to § 157.206(b)(7) of the Commission’s regulations, the certificate holder shall, upon acceptance of its blanket certificate, be designated as the Commission’s non-Federal representative to the U.S. Fish and Wildlife Service (FWS) and the National Marine Fisheries Service (NMFS) in order to conduct informal consultations with those agencies. For purposes of this appendix, “listed species” and “critical habitat” shall have the same meanings as set forth in 50 CFR 402.02. The certificate holder shall be deemed in compliance with § 157.206(b)(2)(vi) of the Commission’s regulations only if, prior to constructing facilities or abandoning facilities by removal under the blanket certificate, it complies with the following procedures:
1. The certificate holder shall contact the appropriate regional office of either the FWS or the NMFS (or both the FWS and the NMFS, if appropriate) as determined pursuant to 50 CFR 402.01 for the purpose of initiating informal consultations.
2. The certificate holder shall be deemed in compliance with § 157.206(b)(2)(vi) of the Commission’s regulations if the consulted agency (either the FWS or NMFS, or both if appropriate) initially determines, pursuant to the informal consultations:
(a) That no listed species or its critical habitat occur in the project area; and
(b) That no species proposed to be listed under 16 U.S.C. 1533 or its critical habitat occur in the project area.
3. If the consulted agency, pursuant to the informal consultations, initially determines that any species proposed to be listed under 16 U.S.C. 1533 or its critical habitat occur in the project area, then the certificate holder shall confer with the consulted agency on how potential impact can be avoided or reduced. Upon completion of the conference and the implementation of any mitigating measures the certificate holder elects to implement, and compliance with paragraph 4 of this Appendix, if applicable, the certificate holder shall be deemed in compliance with § 157.206(b)(2)(vi) of the Commission’s regulations.
4. (a) If the consulted agency initially determines, pursuant to the informal consultations, that a listed species or its critical habitat may occur in the project area, then the certificate holder shall continue informal consultation with the consulted agency to determine if the proposed project may affect such species or habitat. Continued informal consultations may include discussions with experts (including experts provided by the consulted agency), field surveys, biological assessments, and formulation of mitigation measures.
(b) The certificate holder shall be deemed in compliance with § 157.206(b)(2)(vi) of the Commission’s regulations if the consulted agency agrees with the certificate holder’s determination resulting from the continued informal consultations, that the proposed project is not likely to adversely affect a listed species or critical habitat, or that no further consultation is necessary.
(c) If the consulted agency does not agree with such determination by the certificate holder, or if the certificate holder concludes that the proposed project may affect listed species or the critical habitat of such species, then the certificate holder may not proceed with the proposed project under the blanket certificate.
Appendix II to Subpart F of Part 157—Procedures for Compliance With the National Historic Preservation Act of 1966 Under § 157.206(b )(3)(ii )
The following procedures apply to any certificate holder which undertakes a project under the authority of a blanket certificate issued pursuant to subparts E or F of part 157 and to any other service subject to § 157.206(b) of the Federal Energy Regulatory Commission’s (Commission) regulations. For the purposes of this appendix, the following definitions apply:
(a) “Listed property” means any district, site, building, structure or object which is listed (1) on the National Register of Historic Places, or (2) in the
(b) “SHPO” means the State Historic Preservation Officer or any alternative person duly designated, in accordance with section (1)(b) of Appendix II to Subpart F, to advise on cultural resource matters.
(c) “Unlisted property” means any district, site, building, structure or object which is not a listed property.
(d) “THPO” means the Tribal Historic Preservation Officer, as defined at 36 CFR 800.2(c)(2).
The certificate holder shall be deemed to be in compliance with § 157.206(b)(2)(iii) of the Commission’s regulations only if, prior to constructing facilities or abandoning facilities by removal under the blanket certificate, it complies with the following procedures:
(1)(a) If federally administered land would be directly affected by the project, then the procedures used by the appropriate Tribal or Federal land managing agency to comply with section 106 of the National Historic Preservation Act of 1966, 16 U.S.C. 470f, shall take precedence over these procedures. The procedures in this appendix apply to State and private lands, and Federal lands for which there are no other Federal procedures.
(b) If there is no SHPO, or THPO, if appropriate, or if the SHPO, or THPO, as appropriate, declines to consult with the certificate holder, the certificate holder shall so inform the environmental staff of the Office of Energy Projects and shall not proceed with these procedures or the project until an alternate consultant has been duly designated.
(2) It shall be the certificate holder’s responsibility to identify or cause to be identified listed properties and unlisted properties that satisfy the National Register Criteria for Evaluation (36 CFR 1202.6), that are located within the area of the project’s potential environmental impact and that may be affected by the undertaking.
(3) The certificate holder shall:
(a) Check the National Register of Historic Places and consult with the SHPO, or THPO, as appropriate, to identify all listed properties within the area of the project’s potential environmental impact;
(b) Consult with the SHPO, or THPO, as appropriate, and to the extent deemed appropriate by the SHPO, or THPO, as appropriate, check public records and consult with other individuals and organizations with historical and cultural expertise, to determine whether unlisted properties that satisfy the National Register Criteria for Evaluation are known or likely to occur within the area of the project’s potential environmental impact; and
(c) Consult with the SHPO, or THPO, as appropriate, to determine the need for surveys to identify unknown unlisted properties. The certificate holder shall evaluate the eligibility of any known unlisted properties located within the area of the project’s potential environmental impact according to the National Register Criteria for Evaluation.
(4) The certificate holder shall be deemed in compliance with § 157.206(b)(2)(iii) of the Commission’s regulations if the SHPO, or THPO, as appropriate, agrees with the certificate holder that no survey is required, and that no listed properties or unlisted properties that satisfy the National Register Criteria for Evaluation occur in the area of the project’s potential environmental impact.
(5) If the SHPO, or THPO, as appropriate, determines that surveys are required to ensure that no listed properties, or unlisted properties that satisfy the National Register Criteria for Evaluation, occur within the area of the project’s potential environmental impact, the certificate holder shall perform surveys deemed by the SHPO, or THPO, as appropriate, to be of sufficient scope and intensity to identify and evaluate such properties. The certificate holder shall submit the results of the surveys including a statement as to which unlisted properties satisfy the National Register Criteria for Evaluation, to the SHPO and solicit comments on the surveys and the conclusions.
(6) The certificate holder shall be deemed in compliance with § 157.206(b)(2)(iii) of the Commission’s regulations if, upon conclusion of the surveys, the certificate holder and the SHPO, or THPO, as appropriate, agree that no listed properties, and no unlisted properties which satisfy the National Register Criteria for Evaluation, occur in the area of the project’s potential environmental impact.
(7) For each listed property, and each unlisted property which satisfies the National Register Criteria for Evaluation, which is located within the area of the project’s potential environmental impact, the certificate holder, in consultation with the SHPO, or THPO, as appropriate, shall apply the Criteria of Effect (36 CFR 800.5) to determine whether the project will have an effect upon the historical, architectural, archeological, or cultural characteristics of the property that qualified it to meet National Register Criteria for Evaluation. The certificate holder shall be deemed in compliance with § 157.206(b)(2)(iii) of the Commission’s regulations if the certificate holder and the SHPO, or THPO, as appropriate, agree that the project will not affect these characteristics.
(8) If either the certificate holder or the SHPO, or THPO, as appropriate, finds that the project may affect a listed property or an unlisted property which satisfies the National Register Criteria for Evaluation, located within the area of the project’s potential environmental impact, then the project shall not be authorized under the blanket certificate unless such properties can be avoided by relocation of the project to an area where the SHPO, or THPO, as appropriate, agrees that no listed properties or unlisted properties that satisfy the National Register Criteria for Evaluation occur. The certificate holder shall be deemed in compliance with § 157.206(b)(2)(iii) of the Commission’s regulations if the project is relocated as described above.
(9) If the certificate holder and the SHPO, or THPO, as appropriate, are unable to agree upon the need for a survey, the adequacy of a survey, or the results of application of the National Register Criteria for Evaluation to an unlisted property, the project shall not be authorized under the blanket certificate.
Subpart G—Natural Gas Producer Blanket Authorization for Sales and Abandonment [Reserved]
PART 158—ACCOUNTS, RECORDS, MEMORANDA AND DISPOSITION OF CONTESTED AUDIT FINDINGS AND PROPOSED REMEDIES
Disposition of Contested Audit Findings and Proposed Remedies
§ 158.1 Notice to audited person.
An audit conducted by the Commission’s staff under authority of the Natural Gas Act may result in a notice of deficiency or audit report or similar document containing a finding or findings that the audited person has not complied with a requirement of the Commission with respect to, but not limited to, the following: A filed tariff or tariffs, contracts, data, records, accounts, books, communications or papers relevant to the audit of the audited person; matters under the Standards of Conduct or the Code of Conduct; and the activities or operations of the audited person. The notice of deficiency, audit report or similar document may also contain one or more proposed remedies that address findings of noncompliance. Where such findings, with or without proposed remedies, appear in a notice of deficiency, audit report or similar document, such document shall be provided to the audited person, and the finding or findings, and any proposed remedies, shall be noted and explained. The audited person shall timely indicate in a written response any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees. The audited person shall have 15 days from the date it is sent the notice of deficiency, audit report or similar document to provide a written response to the audit staff indicating any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees, and such further time as the audit staff may provide in writing to the audited person at the time the document is sent to the audited person. The audited person may move the Commission for additional time to provide a written response to the audit staff and such motion shall be granted for good cause shown. Any initial order that the Commission subsequently may issue with respect to the notice of deficiency, audit report or similar document shall note, but not address on the merits, the finding or findings, or the proposed remedy or remedies, or both, in any combination, with which the audited person disagreed. The Commission shall provide the audited person 30 days to respond to the initial Commission order concerning a notice of deficiency, audit report or similar document with respect to the finding or findings or any proposed remedy or remedies, or both, in any combination, with which it disagreed.
§ 158.2 Response to notification.
Upon issuance of a Commission order that notes a finding or findings, or proposed remedy or remedies, or both, in any combination, with which the audited person has disagreed, the audited person may: Acquiesce in the findings and/or proposed remedies by not timely responding to the Commission order, in which case the Commission may issue an order approving them or taking other action; or challenge the finding or findings and/or any proposed remedies, with which it disagreed by timely notifying the Commission in writing that it requests Commission review by means of a shortened procedure or, if there are material facts in dispute which require cross-examination, a trial-type hearing.
§ 158.3 Shortened procedure.
If the audited person subject to a Commission order described in § 158.1 notifies the Commission that it seeks to challenge one or more audit findings, or proposed remedies, or both, in any combination, by the shortened procedure, the Commission shall thereupon issue a notice setting a schedule for the filing of memoranda. The person electing the use of the shortened procedure, and any other interested entities, including the Commission staff, shall file, within 45 days of the notice, an initial memorandum that addresses the relevant facts and applicable law that support the position or positions taken regarding the matters at issue. Reply memoranda shall be filed within 20 days of the date by which the initial memoranda are due to be filed. Only participants who filed initial memoranda may file reply memoranda. Subpart T of part 385 of this chapter shall apply to all filings. Within 20 days after the last date that reply memoranda under the shortened procedure may be timely filed, the audited person who elected the shortened procedure may file a motion with the Commission requesting a trial-type hearing if new issues are raised by a party. To prevail in such a motion, the audited person must show that a party to the shortened procedure raised one or more new issues of material fact relevant to resolution of a matter in the shortened procedure such that fundamental fairness requires a trial-type hearing to resolve the new issue or issues so raised. Parties to the shortened procedure and the Commission staff may file responses to the motion. In ruling upon the motion, the Commission may determine that some or all of the issues be litigated in a trial-type hearing.
§ 158.4 Form and style.
Each memoranda must be complete in itself. All pertinent data should be set forth fully, and each memorandum should set out the facts and argument as prescribed for briefs in § 385.706 of this chapter.
§ 158.5 Verification.
The facts stated in the memorandum must be sworn to by persons having knowledge thereof, which latter fact must affirmatively appear in the affidavit. Except under unusual circumstances, such persons should be those who would appear as witnesses if hearing were had to testify as to the facts stated in the memorandum.
§ 158.6 Determination.
If no formal hearing is had the matter in issue will be determined by the Commission on the basis of the facts and arguments submitted.
§ 158.7 Assignment for oral hearing.
In case consent to the shortened procedure is not given, or if at any stage of the proceeding prior to the submission of the case to the Commission any party in interest requests a hearing, the proceeding will be assigned for hearing as provided for by subpart E of part 385 of this chapter. The Commission may also in its discretion set the proceeding for hearing on its own motion at any stage thereof.
§ 158.8 Burden of proof.
The burden of proof to justify every accounting entry shall be on the person making, authorizing, or requiring such entry.
§ 158.10 Examination of accounts.
All natural gas companies not classified as Class C or Class D prior to January 1, 1984 shall secure for each year, the services of an independent certified public accountant, or independent licensed public accountant (licensed on or before December 31, 1970), certified or licensed by a regulatory authority of a State or other political subdivision of the United States, to test compliance in all material respects of those schedules that are indicated in the General Instructions set out in the applicable Annual Report, Form No. 2 or Form No. 2–A, with the Commission’s Uniform System of Accounts and published accounting releases. The Commission expects that identification of questionable matters by the independent accountant will facilitate their early resolution and that the independent accountant will seek advisory rulings by the Commission on such items. This examination shall be deemed supplementary to periodic Commission examinations of compliance.
§ 158.11 Report of certification.
Each natural gas company not classified as Class C or Class D prior to January 1, 1984 must file with the Commission by May 18 of the following calendar year, a letter or report of the independent accountant certifying approval, covering the subjects and in the format prescribed in the General Instructions of the applicable Form No. 2 or Form No. 2–A. The letter or report must also identify which, if any, of the examined schedules do not conform to the Commission’s requirements and must describe the discrepancies that exist. The Commission will not be bound by the certification of compliance made by an independent accountant under this paragraph.
§ 158.12 Qualifications of accountants.
The Commission will recognize only independent certified public accountants, or independent licensed public accountants who were licensed on or before December 31, 1970, who are in fact independent. For example, an accountant will not be considered independent with respect to any person or any of its parents or subsidiaries in who he has, or had during the period of report, any direct financial interest. The Commission will determine the fact of independence by considering all the relevant circumstances including evidence bearing on the relationships between the accountant and that person or any affiliate thereof.
SUBCHAPTER F—ACCOUNTS, NATURAL GAS ACT
PART 201—UNIFORM SYSTEM OF ACCOUNTS PRESCRIBED FOR NATURAL GAS COMPANIES SUBJECT TO THE PROVISIONS OF THE NATURAL GAS ACT
Order 141, 12 FR 8504, Dec. 19, 1947, provides in part as follows: Prescribing a system of accounts for natural gas companies under the Natural Gas Act. The Federal Power Commission acting pursuant to authority granted by the Natural Gas Act (58) Stat. 821, as amended; 15 U.S.C. and Sup. 717 et seq.), particularly sections 8(a), 10(a) and 16 thereof, and finding such action necessary and appropriate for carrying out the provisions of said Act, ordered that: (a) The accompanying system of accounts, entitled “Uniform System of Accounts Prescribed for Natural Gas Companies Subject to the Provisions of the Natural Gas Act,” and the rules and regulations contained therein, be adopted; (b) Said system of accounts and said rules and regulations contained therein be and the same are hereby prescribed and promulgated as the system of accounts and rules and regulations of the Commission to be kept and observed by natural gas companies subject to the jurisdiction of the Commission, to the extent and in the manner set forth therein; (c) Said system of accounts and rules and regulations therein contained as to all natural gas companies now subject to the jurisdiction of the Commission, became effective on January 1, 1940, and as to any natural gas company which may hereafter become subject to the jurisdiction of the Commission, they shall become effective as of the date when such natural gas company becomes subject to the jurisdiction of the Commission.
When used in this system of accounts:
1. Accounts means the accounts prescribed in this system of accounts.
2. Actually issued, as applied to securities issued or assumed by the utility, means those which have been sold to bona fide purchasers for a valuable consideration, those issued as dividends on stock, and those which have been issued in accordance with contractual requirements direct to trustees of sinking funds.
3. Actually outstanding, as applied to securities issued or assumed by the utility, means those which have been actually issued and are neither retired nor held by or for the utility; provided, however, that securities held by trustees shall be considered as actually outstanding.
4. Amortization means the gradual extinguishment of an amount in an account by distributing such amount over a fixed period, over the life of the asset or liability to which it applies, or over the period during which it is anticipated the benefit will be realized.
5. A. Associated (affiliated) companies means companies or persons that directly or indirectly, through one or more intermediaries, control, or are controlled by, or are under common control with the accounting company.
B. Control (including the terms “controlling,” “controlled by,” and “under common control with”) means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a company, whether such power is exercised through one or more intermediary companies, or alone, or in conjunction with, or pursuant to an agreement, and whether such power is established through a majority or minority ownership or voting of securities, common directors, officers, or stockholders, voting trusts, holding trusts, associated companies, contract or any other direct or indirect means.
6. Book cost means the amount at which property is recorded in these accounts without deduction of related provisions for accrued depreciation, depletion, amortization, or for other purposes.
7. Commission, means the Federal Energy Regulatory Commission.
8. Continuing plant inventory record means company plant records for retirement units and mass property that provide, as either a single record, or in separate records readily obtainable by references made in a single record, the following information:
A. For each retirement unit;
(1) The name or description of the unit, or both;
(2) The location of the unit;
(3) The date the unit was placed in service;
(4) The cost of the unit as set forth in Plant Instructions 2 and 3 of this part; and
(5) The plant control account to which the cost of the units is charged; and
B. For each category of mass property;
(1) A general description of the property and quantity;
(2) The quantity placed in service by vintage year;
(3) The average cost as set forth in Plant Instructions 2 and 3 of this part; and
(4) The plant control account to which the costs are charged.
9. Cost means the amount of money actually paid for property or services. When the consideration given is other than cash in a purchase and sale transaction, as distinguished from a transaction involving the issuance of common stock in a merger or a pooling of interest, the value of such consideration shall be determined on a cash basis.
10. Cost of removal means the cost of demolishing, dismantling, tearing down or otherwise removing gas plant, including the cost of transportation and handling incidental thereto. It does not include the cost of removal activities associated with asset retirement obligations that are capitalized as part of the tangible long-lived assets that give rise to the obligation. (See General Instruction 24).
11. Debt expense means all expenses in connection with the issuance and initial sale of evidences of debt, such as fees for drafting mortgages and trust deeds; fees and taxes for issuing or recording evidences of debt; cost of engraving and printing bonds and certificates of indebtedness; fees paid trustees; specific costs of obtaining governmental authority; fees for legal services; fees and commissions paid underwriters, brokers, and salesmen for marketing such evidences of debt; fees and expenses of listing on exchanges; and other like costs.
12. A. Depletion, as applied to natural gas producing land and land rights, means the loss in service value incurred in connection with the exhaustion of the natural resource in the course of service.
B. Depreciation, as applied to depreciable gas plant, means the loss in service value not restored by current maintenance, incurred in connection with the consumption or prospective retirement of gas plant in the course of service from causes which are known to be in current operation and against which the utility is not protected by insurance. Among the causes to be given consideration are wear and tear, decay, action of the elements, inadequacy, obsolescence, changes in the art, changes in demand and requirements of public authorities, and, in the case of natural gas companies, the exhaustion of natural resources.
13. Development costs, when used with respect to hydrocarbons, include all costs incurred in the readying of hydrocarbon deposits for commercial production including developmental well drilling costs.
14. Discount, as applied to the securities, issued or assumed by the utility, means the excess of the par (stated value of no-par stocks) or fact value of the securities plus interest or dividends accrued at the date of the sale over the cash value of the consideration received from their sale.
15. Exploration costs, include all costs incurred in proving the existence of hydrocarbon deposits including geological, geophysical, lease acquisition (including delay rentals), administrative and general, and exploratory well drilling costs.
16. Full-cost accounting for exploration and development costs, means the capitalization of all exploration and development costs incurred on or related to hydrocarbon leases, on properties in the contiguous 48 States and the State of Alaska, acquired after October 7, 1969.
17. Investment advances means advances, represented by notes or by book accounts only, with respect to which it is mutually agreed or intended between the creditor and debtor that they shall be settled by the issuance of securities or shall not be subject to current settlement.
18. Lease, capital means a lease of property used in utility or non-utility operations, which meets one or more of the criteria stated in General Instruction 19.
19. Lease, operating means a lease of property used in utility or non-utility operations, which does not meet any of the criteria stated in General Instruction 19.
20. Minor items of property means the associated parts or items of which retirement units are composed.
21. Natural gas means either natural gas unmixed, or any mixture of natural and artificial gas.
22. Natural gas company means a person engaged in the transportation of natural gas in interstate commerce, or the sale in interstate commerce of such gas for resale.
23. Net salvage value means the salvage value of property retired less the cost of removal.
24. Nominally issued, as applied to securities issued or assumed by the utility, means those which have been signed, certified, or otherwise executed, and placed with the proper officer for sale and delivery, or pledged, or otherwise placed in some special fund of the utility, but which have not been sold, or issued direct to trustees of sinking funds in accordance with contractual requirements.
25. Nominally outstanding, as applied to securities issued or assumed by the utility, means those which, after being actually issued, have been reacquired by or for the utility under circumstances which require them to be considered as held alive and not retired, provided, however, that securities held by trustees shall be considered as actually outstanding.
26. Original cost, as applied to gas plant, means the cost of such property to the person first devoting it to public service.
27. Person means an individual, a corporation, a partnership, an association, a joint stock company, a business trust, or any organized group of persons, whether incorporated or not, or any receiver or trustee.
28. Premium, as applied to securities issued or assumed by the utility, means the excess of the cash value of the consideration received from their sale over the sum of their par (stated value of no-par stocks) or face value and interest or dividends accrued at the date of sale.
29. Production, transmission, and distribution plant. For the purposes of this system of accounts:
A. Production system shall consist of plant and equipment used in the production of gas. It shall include producing lands and leaseholds, gas rights, other land rights, structures, drilling and clearing equipment, gas wells, well head equipment, separation and other facilities used in the production of natural gas. The production system ends where the gas enters a gathering system, transmission system or distribution system, as applicable, in accordance with the practices in the pricing area where such system is located.
B. Transmission system means the land, structures, mains, valves, meters, boosters, regulators, tanks, compressors, and their driving units and appurtenances, and other equipment used primarily for transmitting gas from a production plant, delivery point of purchased gas, gathering system, storage area, or other wholesale source of gas, to one or more distribution areas. The transmission system begins at the outlet side of the valve at the connection to the last equipment in a manufactured gas plant, the connection to gathering lines or delivery point of purchased gas, and includes the equipment at such connection that is used to bring the gas to transmission pressure, and ends at the outlet side of the equipment which meters or regulates the entry of gas into the distribution system or into a storage area. It does not include storage land, structures or equipment. Pipeline companies, including those companies which measure deliveries of gas to their own distribution systems, shall include city gate and main line industrial measuring and regulating stations in the transmission function.
C. Distribution system means the mains which are provided primarily for distributing gas within a distribution area, together with land, structures, valves, regulators, services and measuring devices, including the mains for transportation of gas from production plants or points of receipt located within such distribution area to other points therein. The distribution system owned by companies having no transmission facilities connected to such distribution system begins at the inlet side of the distribution system equipment which meters or regulates the entry of gas into the distribution system and ends with and includes property on the customer’s premises. For companies which own both transmission and distribution facilities on a continuous line, the distribution system begins at the outlet side of the equipment which meters or regulates the entry of gas into the distribution system and ends with and includes property on the customer’s premises. The distribution system does not include storage land, structures, or equipment.
D. Distribution area means a metropolitan area or other urban area comprising one or more adjacent or nearby cities, villages or unincorporated areas, including developed areas contiguous to main highways.
30. Property retired, as applied to gas plant, means property which has been removed, sold, abandoned, destroyed, or which for any cause has been withdrawn from service.
31. Regulatory Assets and Liabilities are assets and liabilities that result from rate actions of regulatory agencies. Regulatory assets and liabilities arise from specific revenues, expenses, gains, or losses that would have been included in net income determinations in one period under the general requirements of the Uniform System of Accounts but for it being probable: 1) that such items will be included in a different period(s) for purposes of developing the rates the utility is authorized to charge for its utility services; or 2) in the case of regulatory liabilities, that refunds to customers, not provided for in other accounts, will be required.
32. A. Replacing or replacement, when not otherwise indicated in the context, means the construction or installation of gas plant in place of property retired, together with the removal of the property retired.
B. Research, Development, and Demonstration (RD&D), means expenditures incurred by natural gas companies either directly or through another person or organization (such as research institute, industry association, foundation, university, engineering company, or similar contractor) in pursuing research, development, and demonstration activities including experiment, design, installation, construction, or operation. This definition includes expenditures for the implementation or development of new and/or existing concepts until technically feasible and commercially feasible operations are verified. Such research, development, and demonstration costs should be reasonably related to the existing or future utility business, broadly defined, of the public utility or licensee or in the environment in which it operates or expects to operate. The term includes, but is not limited to: All such costs incidental to the design, development or implementation of an experimental facility, a plant process, a product, a formula, an invention, a system or similar items, and the improvement of already existing items of a like nature; amounts expended in connection with the proposed development and/or proposed delivery of substitute or synthetic gas supplies (alternate fuel sources for example, an experimental coal gasification plant or an experimental plant synthetically producing gas from liquid hydrocarbons); and the costs of obtaining its own patent, such as attorney’s fees expended in making and perfecting a patent application. The term includes preliminary investigations and detailed planning of specific projects for securing for customers non-conventional pipeline gas supplies that rely on technology that has not been verified previously to be feasible. The term does not include expenditures for efficiency surveys; studies of management, management techniques and organization; consumer surveys, advertising, promotions, or items of a like nature.
33. Retained earnings (formerly earned surplus) means the accumulated net income of the utility less distribution to stockholders and transfers to other capital accounts.
34. Retirement units means those items of gas plant which, when retired, with or without replacement, are accounted for by crediting the book cost thereof to the gas plant account in which included.
35. Salvage value means the amount received for property retired, less any expenses incurred in connection with the sale or in preparing the property for sale; or, if retained, the amount at which the material recoverable is chargeable to Materials and Supplies, or other appropriate account.
36. Service life means the time between the date gas plant is includible in gas plant in service, or gas plant leased to others, and the date of its retirement. If depreciation is accounted for on a production basis rather than on a time basis, then service life should be measured in terms of the appropriate unit of production.
37. Service value means the difference between original cost and net salvage value of gas plant.
38. Unsuccessful exploration and development costs, means exploration and development costs related to efforts which do not directly result in the discovery of commercially recoverable hydrocarbon reserves.
39. Subsidiary company, means a company which is controlled by the utility through ownership of voting stock. (See “Definitions”—item 5B “Control”). A corporate joint venture in which a corporation is owned by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group is a subsidiary company for the purposes of this system of accounts.
40. Utility, as used herein and when not otherwise indicated in the context, means any natural gas company to which this system of accounts is applicable.
1. Applicability. Each natural gas company must apply the system of accounts prescribed by the Commission.
Major —Each natural gas company as defined in the Natural Gas Act, whose combined gas sold for resale and gas transported or stored for a fee exceeds 50 million Mcf at 14.73 psi (60 °F) in each of the three previous calendar years.
Nonmajor—Natural gas companies that are not classified as a “major company” (as defined above), and had total gas sales or volume transactions exceeding 200,000 Mcf at 14.73 psi (60 °F) in each of the three previous calendar years.
B. This system applies to both Major and Nonmajor natural gas companies. Provisions have been incorporated into this system for those entities which prior to January 1, 1984, were applying the Commission’s Uniform System of Accounts Prescribed for Class C and Class D (part 104 of this chapter) now revoked. The notations “(Nonmajor)” and “(Major)” have been used to indicate those instructions and accounts from the previous systems and classifications, which by definition, are not interchangeable without causing a loss of detail for the Major (previous Class A and Class B) or an increase in detail burden for the Nonmajor (previous Class C and Class D).
C. The class to which any natural gas company belongs shall originally be determined by its annual gas volume in each of the last three consecutive years, or, in the case of a newly established entity, the projected data shall be the basis. Subsequent changes in classification shall be made when the volume for each of the three immediately preceding years exceeds the upper limit, or is less than the lower limit of the classification previously applicable to the natural gas company.
D. Any utility may, at its option, adopt the system of accounts prescribed by the Commission for any larger class of utilities.
2. Records. A. Each utility shall keep its books of account, and all other books, records, and memoranda which support the entries in such books of account so as to be able to furnish readily full information as to any item included in any account. Each entry shall be supported by such detailed information as will permit ready identification, analysis, and verification of all facts relevant thereto.
B. The books and records referred to herein include not only accounting records in a limited technical sense, but all other records, such as minute books, stock books, reports, correspondence, memoranda, etc., which may be useful in developing the history of or facts regarding any transaction.
C. No utility shall destroy any such books or records unless the destruction thereof is permitted by rules and regulations of the Commission.
D. In addition to prescribed accounts, clearing accounts, temporary or experimental accounts, and subdivisions of any accounts, may be kept, provided the integrity of the prescribed accounts is not impaired.
E. All amounts included in the accounts prescribed herein for gas plant and operating expenses shall be just and reasonable and any payments or accruals by the utility in excess of just and reasonable charges shall be included in account 426.5, Other Deductions.
F. The arrangement or sequence of the accounts prescribed herein shall not be controlling as to the arrangement or sequence in report forms which may be prescribed by the Commission.
3. Numbering system. A. The account numbering plan used herein consists of a system of three-digit whole numbers as follows:
B. In certain instances, numbers have been skipped in order to allow for possible later expansion or to permit better coordination with the numbering system for other utility departments.
C. The numbers prefixed to account titles are to be considered as part of the titles. Each utility, however, may adopt for its own purposes a different system of account numbers (See also general instruction 2D) provided that the numbers herein prescribed shall appear in the descriptive headings of the ledger accounts and in the various sources of original entry; however, if a utility uses a different group of account numbers and it is not practicable to show the prescribed account numbers in the various sources of original entry, such reference to the prescribed account numbers may be omitted from the various sources of original entry. Moreover, each utility using different account numbers for its own purposes shall keep readily available a list of such account numbers which it uses and a reconciliation of such account numbers with the account numbers provided herein. It is intended that the utility’s records shall be so kept as to permit ready analysis by prescribed accounts (by direct reference to sources of original entry to the extent practicable) and to permit preparation of financial and operating statements directly from such records at the end of each accounting period according to the prescribed accounts.
4. Accounting period. Each utility shall keep its books on a monthly basis so that for each month all transactions applicable thereto, as nearly as may be ascertained, shall be entered in the books of the utility. Amounts applicable or assignable to specific utility departments shall be so segregated monthly. Each utility shall close its books at the end of each calendar year unless otherwise authorized by the Commission.
5. Submittal of questions. To maintain uniformity of accounting, utilities shall submit questions of doubtful interpretation to the Commission for consideration and decision.
6. Item lists. Lists of “items” appearing in the texts of the accounts or elsewhere herein are for the purpose of more clearly indicating the application of the prescribed accounting. The lists are intended to be representative, but not exhaustive. The appearance of an item in a list warrants the inclusion of the item in the account mentioned only when the text of the account also indicates inclusion inasmuch as the same item frequently appears in more than one list. The proper entry in each instance must be determined by the texts of the accounts.
7. Extraordinary items. It is the intent that net income shall reflect all items of profit and loss during the period with the exception of prior period adjustments as described in paragraph 7.1 and long-term debt as described in paragraph 17 below. Those items related to the effects of events and transactions which have occurred during the current period and which are of unusual nature and infrequent occurrence shall be considered extraordinary items. Accordingly, they will be events and transactions of significant effect which are abnormal and significantly different from the ordinary and typical activities of the company, and which would not reasonably be expected to recur in the foreseeable future. (In determining significance, items should be considered individually and not in the aggregate. However, the effects of a series of related transactions arising from a single specific and identifiable event or plan of action should be considered in the aggregate.) To be considered as extraordinary under the above guidelines, an item should be more than approximately 5 percent of income, computed before extraordinary items. Commission approval must be obtained to treat an item of less than 5 percent, as extraordinary. (See accounts 434 and 435.)
7.1 Prior period items. A. Items of profit and loss related to the following shall be accounted for as prior period adjustments and excluded from the determination of net income for the current year.
(1) Correction of an error in the financial statements of a prior year.
(2) Adjustments that result from realization of income tax benefits of pre-acquisition operating loss carryforwards of purchased subsidiaries.
B. All other items of profit and loss recognized during the year shall be included in the determination of net income for that year.
8. Unaudited items. Whenever a financial statement is required by the Commission, if it is known that a transaction has occurred which affects the accounts but the amount involved in the transaction and its effect upon the accounts cannot be determined with absolute accuracy, the amount shall be estimated and such estimated amount included in the proper accounts. The utility is not required to anticipate minor items which would not appreciably affect the accounts.
9. Distribution of pay and expenses of employees. The charges to gas plant, operating expense and other accounts for services and expenses of employees engaged in activities chargeable to various accounts, such as construction, maintenance, and operations, shall be based upon the actual time engaged in the respective classes of work, or in case that method is impracticable, upon the basis of a study of the time actually engaged during a representative period.
10. Payroll distribution. Underlying accounting data shall be maintained so that the distribution of the cost of labor charged direct to the various accounts will be readily available. Such underlying data shall permit a reasonably accurate distribution to be made of the cost of labor charged initially to clearing accounts so that the total labor cost may be classified among construction, cost of removal, gas operating functions (manufactured gas production, natural gas production and gathering, products extraction, underground storage, transmission, distribution, etc.), and nonutility operations.
11. Accounting to be on accrual basis. A. The utility is required to keep its accounts on the accrual basis. This requires the inclusion in its accounts of all known transactions of appreciable amount which affect the accounts. If bills covering such transactions have not been received or rendered, the amounts shall be estimated and appropriate adjustments made when the bills are received.
B. When payments are made in advance for items such as insurance, rents, taxes or interest, the amount applicable to future periods shall be charged to account 165, Prepayments, and spread over the periods to which applicable by credits to account 165, and charges to the accounts appropriate for the expenditure.
12. Records for each plant. A. Separate records shall be maintained by gas plant accounts of the book cost of each plant owned, including additions by the utility to plant leased from others, and of the cost of operating and maintaining each plant owned or operated. The term “plant,” as here used, means each manufactured gas production plant, the wells and gathering lines of each distinct production area, each system of interconnected transmission mains, each system of wells and lines of an underground storage project, each large purification or dehydration plant, each compressor station, other than a distribution compressor station, and each products extraction plant.
B. A natural gas company may, with the approval of the Commission, group certain of its systems of gathering lines and wells, small compressor stations, systems of underground storage lines and wells, and systems of interconnected transmission mains for the purpose of complying with the portion of this instruction requiring a segregation of the cost of operating and maintaining each plant.
Where manufactured gas is produced by two or more processes at one location, each process shall be accounted for separately.
Each natural gas company shall maintain operating or accounting records for each well showing (a) acreage on which drilled, (b) dates of drilling period, (c) cost of drilling, (d) depth of well, (e) particulars and depth of each stratum drilled through, (f) geological formation from which gas is obtained, (g) initial rock pressure and open flow capacity, (h) sizes of casing used and the lengths of each size, (i) total cost of well as recorded in gas plant accounts, (j) date well abandoned, for wells once productive, (k) date transferred to underground storage plant, for wells converted to storage use, and (l) date drilling discontinued, for wells determined to be nonproductive. The foregoing data, as appropriate, shall also be maintained for each subsequent change in the depth of each well.
13. Accounting for other departments. If the utility also operates other utility departments, such as electric, water, etc., it shall keep such accounts for the other departments as may be prescribed by proper authority and in the absence of prescribed accounts, it shall keep such accounts as are proper or necessary to reflect the results of operating each such department. It is not intended that proprietary and similar accounts which apply to the utility as a whole shall be departmentalized.
14. Transactions with associated companies. Each utility shall keep its accounts and records so as to be able to furnish accurately and expeditiously statements of all transactions with associated companies. The statements may be required to show the general nature of the transactions, the amounts involved therein and the amounts included in each account prescribed herein with respect to such transactions. Transactions with associated companies shall be recorded in the appropriate accounts for transactions of the same nature. Nothing herein contained, however, shall be construed as restraining the utility from subdividing accounts for the purpose of recording separately transactions with associated companies.
15. Contingent assets and liabilities. Contingent assets represent a possible source of value to the utility contingent upon the fulfillment of conditions regarded as uncertain. Contingent liabilities include items which may under certain conditions become obligations of the utility but which are neither direct nor assumed liabilities at the date of the balance sheet. The utility shall be prepared to give a complete statement of significant contingent assets and liabilities (including cumulative dividends on preference stock) in its annual report and at such other times as may be requested by the Commission.
16. [Reserved]
17. Long-term debt: Premium, discount and expense, and gain or loss on reacquisition— A. Premium, discount and expense. A separate premium, discount and expense account shall be maintained for each class and series of long-term debt (including receivers’ certificates) issued or assumed by the utility. The premium will be recorded in account 225, Unamortized Premium on Long-Term Debt, the discount will be recorded in account 226, Unamortized Discount on Long-Term Debt—Debit, and the expense of issuance shall be recorded in account 181, Unamortized Debt Expense.
The premium, discount and expense shall be amortized over the life of the respective issues under a plan which will distribute the amounts equitably over the life of the securities. The amortization shall be on a monthly basis, and amounts thereof relating to discount and expense shall be charged to account 428, Amortization of Debt Discount and Expense. The amounts relating to premium shall be credited to account 429, Amortization of Premium on Debt—Credit.
B. Reacquisition, without refunding. When long-term debt is reacquired or redeemed without being converted into another form of long-term debt and when the transaction is not in connection with a refunding operation (primarily redemptions for sinking fund purposes), the difference between the amount paid upon reacquisition and the face value; plus any un- amortized premium less any related unamortized debt expense and reacquisition costs; or less any unamortized discount, related debt expense and reacquisition costs applicable to the debt redeemed, retired and canceled, shall be included in account 189, Unamortized Loss on Reacquired Debt, or account 257, Unamortized Gain on Reacquired Debt, as appropriate. The utility shall amortize the recorded amounts equally on a monthly basis over the remaining life of the respective security issues (old original debt). The amounts so amortized shall be charged to account 428.1, Amortization of Loss on Reacquired Debt, or credited to account 429.1, Amortization of Gain on Reacquired Debt—Credit, as appropriate.
C. Reacquisition, with refunding. When the redemption of one issue or series of bonds or other long-term obligations is financed by another issue or series before the maturity date of the first issue, the difference between the amount paid upon refunding and the face value; plus any unamortized premium less related debt expense or less any unamortized discount and related debt expense, applicable to the debt refunded, shall be included in account 189, Unamortized Loss on Reacquired Debt, or account 257, Unamortized Gain on Reacquired Debt, as appropriate. The utility may elect to account for such amounts as follows:
(1) Write them off immediately when the amounts are insignificant.
(2) Amortize them by equal monthly amounts over the remainder of the original life of the issue retired, or
(3) Amortize them by equal monthly amounts over the life of the new issue.
Once an election is made, it shall be applied on a consistent basis. The amounts in (1), (2), or (3) above shall be charged to account 428.1, Amortization of Loss on Reacquired Debt, or credited to account 429.1, Amortization of Gain on Reacquired Debt—Credit, as appropriate.
D. Under methods (2) and (3) above, the increase or reduction in current income taxes resulting from the reacquisition should be apportioned over the remainder of the original life of the issue retired or over the life of the new issue, as appropriate, as directed more specifically in paragraphs E and F below.
E. When the utility recognizes the loss in the year of reacquisition as a tax deduction, account 410.1, Provision for Deferred Income Taxes, Utility Operating Income, shall be debited and account 283, Accumulated Deferred Income Taxes—Other, shall be credited with the amount of the related tax effect, such amount to be allocated to the periods affected in accordance with the provisions of account 283.
F. When the utility chooses to recognize the gain in the year of reacquisition as a taxable gain, account 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, shall be credited and account 190, Accumulated Deferred Income Taxes, shall be debited with the amount of the related tax effect, such amount to be allocated to the periods affected in accordance with the provisions of account 190.
G. When the utility chooses to use the optional privilege of deferring the tax on the gain attributable to the reacquisition of debt by reducing the depreciable basis of utility property for tax purposes, pursuant to Section 108 of the Internal Revenue Code, the related tax effects shall be deferred as the income is recognized for accounting purposes, and the deferred amounts shall be amortized over the life of the associated property on a vintage year basis. Account 410.1, Provision for Deferred Income Taxes, Utility Operating Income, shall be debited, and account 282, Accumulated Deferred Income Taxes—Other Property, shall be credited with an amount equal to the estimated income tax effect applicable to the portion of the income, attributable to reacquired debt, recognized for accounting purposes during the period. Account 282 shall be debited and account 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, shall be credited with an amount equal to the estimated income tax effects, during the life of the property, attributable to the reduction in the depreciable basis for tax purposes.
H. The tax effects relating to gain or loss shall be allocated as above to utility operations except in cases where a portion of the debt reacquired is directly applicable to nonutility operations. In that event, the related portion of the tax effects shall be allocated to nonutility operations. Where it can be established that reacquired debt is generally applicable to both utility and nonutility operations, the tax effects shall be allocated between utility and nonutility operations based on the ratio of net investment in utility plant to net investment in non- utility plant.
I. Premium, discount, or expense on debt shall not be included as an element in the cost of construction or acquisition of property (tangible or intangible), except under the provisions of account 432, Allowance for Borrowed Funds Used During Construction—Credit.
J. Alternate method. Where a regulatory authority or a group of regulatory authorities having prime rate jurisdiction over the utility specifically disallows the rate principle of amortizing gains or losses on reacquisition of long-term debt without refunding, and does not apply the gain or loss to reduce interest charges in computing the allowed rate of return for rate purposes, then the following alternate method may be used to account for gains or losses relating to reacquisition of long-term debt, with or without refunding.
(1) The difference between the amount paid upon reacquisition of any long-term debt and the face value, adjusted for unamortized discount, expenses or premium, as the case may be, applicable to the debt redeemed shall be recognized currently in income and recorded in account 421, Miscellaneous Nonoperating Income, or account 426.5, Other Deductions.
(2) When this alternate method of accounting is used, the utility shall include a footnote to each financial statement, prepared for public use, explaining why this method is being used along with the treatment given for ratemaking purposes.
18. Comprehensive interperiod income tax allocation. A. Where there are timing differences between the periods in which transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income, the income tax effects of such transactions are to be recognized in the periods in which the differences between book accounting income and taxable income arise and in the periods in which the differences reverse using the deferred tax method. In general, comprehensive interperiod tax allocation should be followed whenever transactions enter into the determination of pretax accounting income for the period even though some transactions may affect the determination of taxes payable in a different period, as further qualified below.
B. Utilities are not required to utilize comprehensive interperiod income tax allocation until the deferred income taxes are included as an expense in the rate level by the regulatory authority having rate jurisdiction over the utility. Where comprehensive interperiod tax allocation accounting is not practiced the utility shall include as a note to each financial statement, prepared for public use, a footnote explanation setting forth the utility’s accounting policies with respect to interperiod tax allocation and describing the treatment for ratemaking purposes of the tax timing differences by regulatory authorities having rate jurisdiction.
C. Should the utility be subject to more than one agency having rate jurisdiction, its accounts shall appropriately reflect the ratemaking treatment (deferral or flow through) of each jurisdiction.
D. Once comprehensive interperiod tax allocation has been initiated either in whole or in part it shall be practiced on a consistent basis and shall not be changed or discontinued without prior Commission approval.
E. Tax effects deferred currently will be recorded as deferred debits or deferred credits in accounts 190, Accumulated Deferred Income Taxes, 281, Accumulated Deferred Income Taxes—Accelerated Amortization Property, 282, Accumulated Deferred Income Taxes—Other Property, and 283, Accumulated Deferred Income Taxes—Other, as appropriate. The resulting amounts recorded in these accounts shall be disposed of as prescribed in this system of accounts or as otherwise authorized by the Commission.
19. Criteria for classifying leases. A. If at its inception a lease meets one or more of the following criteria, the lease shall be classified as a capital lease. Otherwise, it shall be classified as an operating lease.
(1) The lease transfers ownership of the property to the leasee by the end of the lease term.
(2) The lease contains a bargain purchase option.
(3) The lease term is equal to 75 percent or more of the estimated economic life of the leased property. However, if the beginning of the lease term falls within the last 25 percent of the total estimated economic life of the lease property, including earlier years of use, this criterion shall not be used for purposes of classifying the lease.
(4) the present value at the beginning of the lease term of the minimum lease payments, excluding that portion of the payments representing executory costs such as insurance, maintenance, and taxes to be paid by the lessor, including any profit thereon, equals or exceeds 90 percent of the excess of the fair value of the leased property to the lessor at the inception of the lease over any related investment tax credit retained by the lessor and expected to be realized by the lessor. However, if the beginning of the lease term falls within the last 25 percent of the total estimated economic life of the lease property, including earlier years of use, this criterion shall not be used for purposes of classifying the lease. The lessee utility shall compute the present value of the minimum lease payments using his incremental borrowing rate, unless (a) it is practicable for the utility to learn the implicit rate computed by the lessor, and (b) the implicit rate computed by the lessor is less than the lessee’s incremental borrowing rate. If both of those conditions are met, the lessee shall use the implicit rate.
B. If at any time the lessee and lessor agree to change the provisions of the lease, other than by renewing the lease or extending its term, in a manner that would have resulted in a different classification of the lease under the criteria in paragraph A had the changed terms been in effect at the inception of the lease, the revised agreement shall be considered as a new agreement over its term, and the criteria in paragraph A shall be applied for purposes of classifying the lease. Likewise, any action that extends the lease beyond the expiration of the existing lease term, such as the exercise of a lease renewal option other than those already included in the lease term, shall be considered as a new agreement, and shall be classified according to the above provisions, Changes in estimates (for example, changes in estimates of the economic life or of the residual value of the leased property) or changes in circumstances (for example, default by the lessee), shall not give rise to a new classification of a lease for accounting purposes.
20. Accounting for leases. A. All leases shall be classified as either capital or operating leases. The accounting for capitalized leases is effective January 1, 1984, except for the retroactive classification of certain leases which, in accordance with FASB No. 71, will not be required to be capitalized until after a three year transition period. For the purpose of reporting to the FERC, the transition period shall be deemed to end December 31, 1986.
B. The utility shall record a capital lease as an asset in account 101.1, Property under Capital Leases (or account 121, Non-utility Property, if appropriate), and an obligation in account 227, Obligations under Capital Leases—Noncurrent, or account 243, Obligations under Capital Leases—Current, at an amount equal to the present value at the beginning of the lease term of minimum lease payments during the lease term, excluding that portion of the payments representing executory costs such as insurance, maintenance, and taxes to be paid by the lessor, together with any profit thereon. However, if the amount so determined exceeds the fair value of the leased property at the inception of the lease, the amount recorded as the asset and obligation shall be the fair value.
C. The utility, as a lessee, shall recognize an asset retirement obligation (See General Instruction 24) arising from the plant under a capital lease unless the obligation is recorded as an asset and liability under a capital lease. The utility shall record the asset retirement cost by debiting account 101.1, Property under capital leases, or account 121, Nonutility property, as appropriate, and crediting the liability for the asset retirement obligation in account 230, Asset retirement obligations. Asset retirement costs recorded in account 101.1 or account 121 shall be amortized by charging rent expense (See Operating Expense Instruction 3) or account 421, Miscellaneous nonoperating income, as appropriate, and crediting a separate subaccount of the account in which the asset retirement costs are recorded. Charges for the periodic accretion of the liability in account 230, Asset retirement obligations, shall be recorded by a charge to account 411.10, Accretion expense, for gas utility plant, and account 421, Miscellaneous nonoperating income, for nonutility plant and a credit to account 230, Asset retirement obligations.
D. Rental payments on all leases shall be charged to rent expense, fuel expense, construction work in progress, or other appropriate accounts as they become payable.
E. For a capital lease, for each period during the lease term, the amounts recorded for the asset and obligation shall be reduced by an amount equal to the portion of each lease payment which would have been allocated to the reduction of the obligation, if the payment had been treated as a payment on an installment obligation (liability) and allocated between interest expense and a reduction of the obligation so as to produce a constant periodic rate of interest on the remaining balance.
21. Gas well records. Each utility with natural gas operations shall maintain operating or accounting records for each well showing: (a) Acreage on which drilled, (b) dates of drilling period, (c) cost of drilling, (d) depth of well, (e) particulars and depth of each stratum drilled through, (f) geological formation from which gas is obtained, (g) initial rock pressure and open flow capacity, (h) sizes of casing used and lengths of each size, (i) total cost of well as recorded in gas plant accounts, (j) date well abandoned, for wells once productive, (k) date transferred to underground storage plant, for wells converted to storage use, and (l) date drilling discontinued, for wells determined to be nonproductive. The foregoing data, as appropriate, shall also be maintained for each subsequent change in the depth of each well.
22. Accounting for other comprehensive income.
A. Utilities shall record items of other comprehensive income in account 219, accumulated other comprehensive income. Amounts included in this account shall be maintained by each category of other comprehensive income. Examples of categories of other comprehensive income include, foreign currency items, minimum pension liability adjustments, unrealized gains and losses on available-for-sale type securities and cash flow hedge amounts. Supporting records shall be maintained for account 219 so that the company can readily identify the cumulative amount of other comprehensive income for each item included in this account.
B. When an item of other comprehensive income enters into the determination of net income in the current or subsequent periods, a reclassification adjustment shall be recorded in account 219 to avoid double counting of that amount.
C. When it is probable that an item of other comprehensive income will be included in the development of cost of service rates in subsequent periods, that amount of unrealized losses or gains shall be recorded in accounts 182.3 or 254 as appropriate.
23. Accounting for derivative instruments and hedging activities.
A. Utilities shall recognize derivative instruments as either assets or liabilities in the financial statements and measure those instruments at fair value, except those falling within recognized exceptions, the most common of which being the normal purchases and sales scope exception. Normal purchases or sales are contracts that provide for the purchase or sale of goods that will be delivered in quantities expected to be used or sold by the utility over a reasonable period in the normal course of business. A derivative instrument is a financial instrument or other contract with all three of the following characteristics:
(1) It has one or more underlyings and a notional amount or payment provision. Those terms determine the amount of the settlement or settlements, and, in some cases, whether or not a settlement is required.
(2) It requires no initial net investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have similar response to changes in market factors.
(3) Its terms require or permit net settlement, can readily be settled net by a means outside the contract, or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement.
B. The accounting for the changes in the fair value of derivative instruments depends upon its intended use and designation. Changes in the fair value of derivative instruments not designated as fair value or cash flow hedges will be recorded in account 175, derivative instrument assets, or account 244, derivative instrument liabilities, as appropriate, with the gains recorded in account 421, miscellaneous nonoperating income, and losses recorded in account 426.4, other deductions.
C. A derivative instrument may be specifically designated as a fair value or cash flow hedge. A hedge may be used to manage risk to price, interest rates, or foreign currency transactions. Utilities shall maintain documentation of the hedge relationship at the inception of the hedge that details the risk management objective and strategy for undertaking the hedge, the nature of the risk being hedged, and how hedge effectiveness will be determined.
D. If the utility designates the derivative instrument as a fair value hedge against exposure to changes in the fair value of a recognized asset, liability, or a firm commitment, it will record the change in fair value of the derivative instrument to account 176, derivative instrument assets—hedges, or account 245, derivative instrument liabilities—hedges, as appropriate, with a corresponding adjustment to the subaccount of the item being hedged. The ineffective portion of the hedge transaction shall be reflected in the same income or expense account that will be used when the hedged item enters into the determination of net income. In the case of a fair value hedge of a firm commitment a new asset or liability is created. As a result of the hedge relationship, the new asset or liability will become part of the carrying amount of the item being hedged.
E. If the utility designates the derivative instrument as a cash flow hedge against exposure to variable cash flows of a probable forecasted transaction, it shall record changes in the fair value of the derivative instrument in account 176, derivative instrument assets—hedges, or account 245, derivative instrument liabilities—hedges, as appropriate, with a corresponding amount in account 219, accumulated other comprehensive income, for the effective portion of the hedge. The ineffective portion of the hedge transaction shall be reflected in the same income or expense account that will be used when the hedged item enters into the determination of net income. Amounts recorded in other comprehensive income shall be reclassified into earnings in the same period or periods that the hedged forecasted item enters into the determination of net income.
24. Accounting for asset retirement obligations.
A. An asset retirement obligation represents a liability for the legal obligation associated with the retirement of a tangible long-lived asset that a utility is required to settle as a result of an existing or enacted law, statute, ordinance, or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel. An asset retirement cost represents the amount capitalized when the liability is recognized for the long-lived asset that gives rise to the legal obligation. The amount recognized for the liability and an associated asset retirement cost shall be stated at the fair value of the asset retirement obligation in the period in which the obligation is incurred.
B. The utility shall initially record a liability for an asset retirement obligation in account 230, Asset retirement obligations, and charge the associated asset retirement costs to gas utility plant and nonutility plant, as appropriate, related to the plant that gives rise to the legal obligation. The asset retirement cost shall be depreciated over the useful life of the related asset that gives rise to the obligations. For periods subsequent to the initial recording of the asset retirement obligation, a utility shall recognize the period to period changes of the asset retirement obligation that result from the passage of time due to the accretion of the liability and any subsequent measurement changes to the initial liability for the legal obligation recorded in account 230, Asset retirement obligations, as follows:
(1) The utility shall record the accretion of the liability by debiting account 411.10, Accretion expense, for gas utility plant, account 413, Expenses of gas plant leased to others, for gas plants leased to others, and account 421, Miscellaneous nonoperating income, for nonutility plant and crediting account 230, Asset retirement obligations; and
(2) The utility shall recognize any subsequent measurement changes of the liability initially recorded in account 230, Asset retirement obligations, for each specific asset retirement obligation as an adjustment of that liability in account 230 with the corresponding adjustment to gas utility plant, gas plant leased to others, and nonutility plant, as appropriate. The utility shall on a timely basis monitor any measurement changes of the asset retirement obligations.
C. Gains or losses resulting from the settlement of asset retirement obligations associated with utility plant resulting from the difference between the amount of the liability for the asset retirement obligation included in account 230, Asset retirement obligations, and the actual amount paid to settle the obligation shall be accounted for as follows:
(1) Gains shall be credited to account 411.6, Gains from disposition of utility plant, and;
(2) Losses shall be charged to account 411.7, Losses from disposition of utility plant.
D. Gains or losses on the settlement of the asset retirement obligations associated with nonutility plant resulting from the difference between the amount of the liability for the asset retirement obligation in account 230, Asset retirement obligations, and the amount paid to settle the obligation, shall be accounted for as follows:
(1) Gains shall be credited to account 421, Miscellaneous nonoperating income, and;
(2) Losses shall be charged to account 426.5, Other deductions.
E. Separate subsidiary records shall be maintained for each asset retirement obligation showing the initial liability and associated asset retirement cost, any incremental amounts of the liability incurred in subsequent reporting periods for additional layers of the original liability and related asset retirement cost, the accretion of the liability, the subsequent measurement changes to the asset retirement obligation, the depreciation and amortization of the asset retirement costs and related accumulated depreciation, and the settlement date and actual amount paid to settle the obligation. For purposes of analyses a utility shall maintain supporting documentation so as to be able to furnish accurately and expeditiously with respect to each asset retirement obligation the full details of the identity and nature of the legal obligation, the year incurred, the identity of the plant giving rise to the obligation, the full particulars relating to each component and supporting computations related to the measurement of the asset retirement obligation.
1. Classification of gas plant at the effective date of the system of accounts.
A. The gas plant accounts provided herein are generally the same as those contained in the prior system of accounts except for some changes in classification in the general equipment accounts. Except for these changes, the balances in the various plant accounts, as determined under the prior system of accounts, should be carried forward. Any remaining balance of plant which has not yet been classified pursuant to the requirements of the prior system, shall be classified in accordance with the following instructions.
B. The cost to the utility of its unclassified plant shall be ascertained by analysis of the utility’s records. Adjustments shall not be made to record in utility plant accounts amounts previously charged to operating expenses or to income deductions in accordance with the uniform system of accounts in effect at the time or in accordance with the discretion of management as exercised under a uniform system of accounts, or under accounting practices previously followed.
C. The detailed gas plant accounts (301 to 399, inclusive) shall be stated on the basis of cost to the utility of plant constructed by it and the original cost, estimated if not known, of plant acquired as an operating unit or system. The difference between the original cost as above, and the cost to the utility of gas plant after giving effect to any accumulated provision for depreciation, depletion, or amortization shall be recorded in account 114, Gas Plant Acquisition Adjustments. The original cost of gas plant shall be determined by analysis of the utility’s records or those of the predecessor or vendor companies with respect to gas plant previously acquired as operating units or systems and the differences between the original cost so determined, less accumulated provisions for depreciation, depletion and amortization, and the cost to the utility, with necessary adjustments for retirements from the date of acquisition, shall be entered in account 114, Gas Plant Acquisition Adjustments. Any difference between the cost of gas plant and its book cost, when not properly includable in other accounts, shall be recorded in account 116, Other Gas Plant Adjustments.
D. Plant acquired by lease which qualifies as capital lease property under General Instruction 19. Criteria for Classifying Leases, shall be recorded in Account 101.1, Property under Capital Leases.
2. Gas plant to be recorded at cost. A. All amounts included in the accounts for gas plant acquired as an operating unit or system, except as otherwise provided in the texts of the intangible plant accounts, shall be stated at the cost incurred by the person who first devoted the property to utility service. All other gas plant shall be included in the accounts at the cost incurred by the utility, except for property acquired by lease which qualifies as capital lease property under General Instruction 19. Criteria for Classifying Leases, and is recorded in Account 101.1, Property under Capital Leases. Where the term “cost” is used in the detailed plant accounts, it shall have the meaning stated in this paragraph.
B. When the consideration given for property is other than cash, the value of such consideration shall be determined on a cash basis. (See, however, definition 8.) In the entry recording such transaction, the actual consideration shall be described with sufficient particularity to identify it. The utility shall be prepared to furnish the Commission the particulars of its determination of the cash value of the consideration if other than cash.
C. When property is purchased under a plan involving deferred payments, no charge shall be made to the gas plant accounts for interest, insurance, or other expenditures occasioned solely by such form of payment.
D. The gas plant accounts shall not include the cost or other value of gas plant contributed to the company. Contributions in the form of money or its equivalent toward the construction of gas plant shall be credited to the accounts charged with the cost of such construction. Plant constructed from contributions of cash or its equivalent shall be shown as a reduction to gross plant constructed when assembling cost data in work orders for posting to plant ledger of accounts. The accumulated gross costs of plant accumulated in the work order shall be recorded as a debit in the plant ledger of accounts along with the related amount of contributions concurrently being recorded as a credit.
3. Components of construction cost. A. The cost of construction properly includable in the gas plant accounts shall include, where applicable, the direct and overhead costs as listed and defined hereunder:
(1) “Contract work” includes amounts paid for work performed under contract by other companies, firms, or individuals, costs incident to the award of such contracts, and the inspection of such work.
(2) “Labor” includes the pay and expenses of employees of the utility engaged on construction work, and related workmen’s compensation insurance, payroll taxes and similar items of expense. It does not include the pay and expenses of employees which are distributed to construction through clearing accounts nor the pay and expenses included in other items hereunder.
(3) “Materials and supplies” includes the purchase price at the point of free delivery plus customs duties, excise taxes, the cost of inspection, loading and transportation, the related stores expenses, and the cost of fabricated materials from the utility’s shop. In determining the cost of materials and supplies used for construction, proper allowance shall be made for unused materials and supplies, for materials recovered from temporary structures used in performing the work involved, and for discounts allowed and realized in the purchase of materials and supplies.
The cost of individual items of equipment of small value (for example, $500 or less) or of short life, including small portable tools and implements, shall not be charged to utility plant accounts unless the correctness of the accounting therefor is verified by current inventories. The cost shall be charged to the appropriate operating expense or clearing accounts, according to the use of such items, or, if such items are consumed directly in construction work, the cost shall be included as part of the cost of the construction.
(4) “Transportation” includes the cost of transporting employees, materials and supplies, tools, purchased equipment, and other work equipment (when not under own power) to and from points of construction. It includes amounts paid to others as well as the cost of operating the utility’s own transportation equipment. (See item 5 following.)
(5) “Special machine service” includes the cost of labor (optional), materials and supplies, depreciation, and other expenses incurred in the maintenance, operation and use of special machines, such as steam shovels, pile drivers, derricks, ditchers, scrapers, material unloaders, and other labor saving machines; also expenditures for rental maintenance and operation of machines of others. It does not include the cost of small tools and other individual items of small value or short life which are included in the cost of materials and supplies. (See item 3, above.) When a particular construction job requires the use for an extended period of time of special machines, transportation or other equipment, the net book cost thereof, less the appraised or salvage value at time of release from the job, shall be included in the cost of construction.
(6) “Shop service” includes the proportion of the expense of the utility’s shop department assignable to construction work except that the cost of fabricated materials from the utility’s shop shall be included in “materials and supplies.”
(7) “Protection” includes the cost of protecting the utility’s property from fire or other casualties and the cost of preventing damages to others, or to the property of others, including payments for discovery or extinguishment of fires, cost of apprehending and prosecuting incendiaries, witness fees in relation thereto, amounts paid to municipalities and others for fire protection, and other analogous items of expenditures in connection with construction work.
(8) “Injuries and damages” includes expenditures or losses in connection with the construction work on account of injuries to persons and damages to the property of others; also the cost of investigation of and defense against actions for such injuries and damages. Insurance recovered or recoverable on account of compensation paid for injuries to persons incident to construction shall be credited to the account or accounts to which such compensation is charged. Insurance recovered or recoverable on account of property damages incident to construction shall be credited to the account or accounts charged with the cost of the damages.
(9) “Privileges and permits” includes payments for and expenses incurred in securing temporary privileges, permits or rights in connection with construction work, such as for the use of private or public property, streets, or highways, but it does not include rents, or amounts chargeable as franchises and consents for which see account 302, Franchises and Consents.
(10) “Rents” includes amounts paid for the use of construction quarters and office space occupied by construction forces and amounts properly includible in construction costs for such facilities jointly used.
(11) “Engineering and supervision” includes the portion of the pay and expenses of engineers, surveyors, draftsmen, inspectors, superintendents and their assistants applicable to construction work.
(12) “General administration capitalized” includes the portion of the pay and expenses of the general officers and administrative and general expenses applicable to construction work.
(13) “Engineering services” includes amounts paid to other companies, firms, or individuals engaged by the utility to plan, design, prepare estimates, supervise, inspect, or give general advice and assistance in connection with construction work.
(14) “Insurance” includes premiums paid or amounts provided or reserved as self-insurance for the protection against loss and damages in connection with construction, by fire or other casualty, injury to or death of persons other than employees, damages to property of others, defalcation of employees and agents, and the nonperformance of contractual obligations of others. It does not include workmen’s compensation or similar insurance on employees included as “labor” in item 2, above.
(15) “Law expenditures” includes the general law expenditures incurred in connection with construction and the court and legal costs directly related thereto, other than law expenses included in protection, item 7, and in injuries and damages, item 8.
(16) “Taxes” includes taxes on physical property (including land) during the period of construction and other taxes properly includible in construction costs before the facilities become available for service.
(17) “Allowance for funds used during construction” includes the net cost for the period of construction of borrowed funds used for construction purposes and a reasonable rate on other funds when so used, not to exceed without prior approval of the Commission allowances computed in accordance with the formula prescribed in paragraph (a) below, except when such other funds are used for exploration and development or leases acquired after October 7, 1969, no allowance on such other funds shall be included in these accounts. No allowance for funds used during construction charges shall be included in these accounts upon expenditures for construction projects which have been abandoned.
(a) The formula and elements for the computation of the allowance for funds used during construction shall be:
(b) The rates shall be determined annually. The balances for long-term debt, preferred stock and common equity shall be the actual book balances as of the end of the prior year. The cost rates for long-term debt and preferred stock shall be the weighted average cost determined in the manner indicated in subpart D of part 154 of the Commission’s Regulations Under the Natural Gas Act. The cost rate for common equity shall be the rate granted common equity in the last rate proceeding before the ratemaking body having primary rate jurisdiction. If such cost rate is not available, the average rate actually earned during the preceding three years shall be used. The short-term debt balances and related cost and the average balance for construction work in progress shall be estimated for the current year with appropriate adjustments as actual data becomes available.
When a part only of a plant or project is placed in operation or is completed and ready for service but the construction work as a whole is incomplete, that part of the cost of the property placed in operation, or ready for service, shall be treated as “Gas Utility Plant” and allowance for funds used during construction thereon as a charge to construction shall cease. Allowance for funds used during construction on that part of the cost of the plant which is incomplete may be continued as a charge to construction until such time as it is placed in operation or is ready for service, except as limited in item 17, above.
(18) “Earnings and expenses during construction” includes (a) all revenues derived during the construction period from property which is included in the cost of a project under construction and (b) all expenses which are attributable to the revenues received.
(19) “Training costs”. When it is necessary that employees be trained to operate or maintain plant facilities that are being constructed and such facilities are not conventional in nature or are new to the company’s operations, these costs may be capitalized as a component of construction cost. Once plant is placed in service, the capitalization of training costs shall cease, and subsequent training costs shall be expensed. (See Operating Expense Instruction 4.)
(20) “Line pack gas.” Line pack includes the first cost of that quantity of gas introduced into the utility’s system necessary to bring the system up to its designed operating capacity or increases therein and which must be maintained in the system in order to sustain such design operating capacity.
(21) LNG “heel” is the first cost of that minimum quantity of liquefied natural gas necessary to be retained in holding tanks and other facilities for purposes of temperature and/or pressure maintenance.
(22) “Studies” includes the costs of studies such as operational, safety or environmental studies relative to plant under construction. Studies mandated by regulatory bodies relative to facilities in service, shall be charged to Account 183.2, Other Preliminary Survey and Investigation Charges.
(23) “Asset retirement costs.” The costs recognized as a result of asset retirement obligations incurred during the construction and testing of utility plant shall constitute a component of construction costs.
4. Overhead construction costs. A. All overhead construction costs, such as engineering, supervision, general office salaries and expenses, construction engineering and supervision by others than the accounting utility, law expenses, insurance, injuries and damages, relief and pensions, taxes and interest, shall be charged to particular jobs or units on the basis of the amounts of such overheads reasonably applicable thereto, to the end that each job or unit shall bear its equitable proportion of such costs and that the entire cost of the unit, both direct and overhead, shall be deducted from the plant accounts at the time the property is retired.
B. As far as practicable, the determination of pay roll charges includible in construction overheads shall be based on time card distributions thereof. Where this procedure is impractical, special studies shall be made periodically of the time of supervisory employees devoted to construction activities to the end that only such overhead costs as have a definite relation to construction shall be capitalized. The addition to direct construction costs of arbitrary percentages or amounts to cover assumed overhead costs is not permitted.
C. The record supporting the entries for overhead construction costs shall be so kept as to show the total amount of each overhead for each year, the nature and amount of each overhead expenditure charged to each construction work order and to each utility plant account, and the bases of distribution of such costs.
5. Gas plant purchased or sold. A. When gas plant constituting an operating unit or system is acquired by purchase, merger, consolidation, liquidation, or otherwise, after the effective date of this system of accounts, the costs of acquisition, including expenses incidental thereto properly includible in gas plant, shall be charged to account 102, Gas Plant Purchased or Sold.
B. The accounting for the acquisition shall then be completed as follows:
(1) The original cost of plant, estimated if not known, shall be credited to account 102, Gas Plant Purchased or Sold, and concurrently charged to the appropriate gas plant in service accounts and to account 104, Gas Plant Leased to Others, account 105, Gas Plant Held for Future Use, 105.1, Production Properties Held for Future Use, and account 107, Construction Work in Progress—Gas, as appropriate.
(2) The depreciation, depletion, and amortization applicable to the original cost of the properties purchased, shall be charged to account 102, Gas Plant Purchased or Sold, and concurrently credited to the appropriate account for accumulated provision for depreciation, depletion or amortization.
(3) The cost to the utility of any property includible in account 121, Nonutility Property, shall be transferred thereto.
(4) The amount remaining in account 102, Gas Plant Purchased or Sold, shall then be closed to account 114, Gas Plant Acquisition Adjustments.
C. If property acquired in the purchase of an operating unit or system is in such physical condition when acquired that it is necessary substantially to rehabilitate it in order to bring the property up to the standards of the utility, the cost of such work, except replacements, shall be accounted for as a part of the purchase price of the property.
D. When any property acquired as an operating unit or system includes duplicate or other plant which will be retired by the accounting utility in the reconstruction of the acquired property or its consolidation with previously owned property, the proposed accounting for such property shall be presented to the Commission.
E. In connection with the acquisition of gas plant constituting an operating unit or system, the utility shall procure, if possible, all existing records relating to the property acquired, or certified copies thereof, and shall preserve such records in conformity with regulations or practices governing the preservation of records of its own construction.
F. When gas plant constituting an operating unit or system is sold, conveyed, or transferred to another by sale, merger, consolidation, or otherwise, the book cost of the property sold or transferred to another shall be credited to the appropriate utility plant accounts, including amounts carried in account 114, Gas Plant Acquisition Adjustments. The amounts (estimated if not known) carried with respect thereto in the accounts for accumulated provision for depreciation, depletion, and amortization and in account 252, Customer Advances for Construction, shall be charged to such accounts and the contra entries made to account 102, Gas Plant Purchased or Sold. Unless otherwise ordered by the Commission, the difference, if any, between (a) the net amount of debits and credits and (b) the consideration received for the property (less commissions and other expenses of making the sale) shall be included in account 421.1, Gain on Disposition of Property, or account 421.2, Loss on Disposition of Property. (See account 102, Gas Plant Purchased or Sold.)
In cases where existing utilities merge or consolidate because of financial or operating reasons or statutory requirements rather than as a means of transferring title of purchased properties to a new owner, the accounts of the constituent utilities, with the approval of the Commission, may be combined. In the event original cost has not been determined, the resulting utility shall proceed to determine such cost as outlined herein.
6. Expenditures on leased property. A. The cost of substantial initial improvements (including repairs, rearrangements, additions, and betterments) made in the course of preparing for utility service property leased for a period of more than one year, and the cost of subsequent substantial additions, replacements, or betterments to such property, shall be charged to the gas plant account appropriate for the class of property leased. If the service life of the improvements is terminable by action of the lease, the cost, less net salvage, of the improvements shall be spread over the life of the lease by charges to account 404.3, Amortization of Other Limited-Term Gas Plant. However, if the service life is not terminated by action of the lease but by depreciation proper, the cost of the improvements, less net salvage, shall be accounted for as depreciable plant. The provisions of this paragraph are applicable to property leased under either capital leases or operating leases.
B. If improvements made to property leased for a period of more than one year are of relatively minor cost, or if the lease is for a period of not more than one year, the cost of the improvements shall be charged to the account in which the rent is included, either directly or by amortization thereof.
7. Land and land rights. A. The accounts for land and land rights shall include the cost of land owned in fee by the utility and rights, interests, and privileges held by the utility in land owned by others, such as leaseholds, easements, rights-of-way, natural gas rights, and other like interests in land. Do not include in the accounts for land and land rights and rights-of-way costs incurred in connection with first clearing and grading of land and rights-of-way and the damage costs associated with the construction and installation of plant. Such costs shall be included in the appropriate plant accounts directly benefited.
B. Where special assessments for public improvements provide for deferred payments, the full amount of the assessments shall be charged to the appropriate land account and the unpaid balance shall be carried in an appropriate liability account. Interest on unpaid balances shall be charged to the appropriate interest account. If any part of the cost of public improvement is included in the general tax levy, the amount thereof shall be charged to the appropriate tax account.
C. The net profit from the sale of timber, cord wood, sand, gravel, other resources or other property acquired with the rights-of-way or other lands shall be credited to the appropriate plant account to which related. Where land is held for a considerable period of time and timber and other natural resources on the land at the time of purchase increases in value, the net profit (after giving effect to the cost of the natural resources) from the sales of timber or its products or other natural resources shall be credited to the appropriate utility operating income account when such land has been recorded in account 105, Gas Plant Held for Future Use, account 105.1, Production Properties Held for Future Use, or classified as plant in service otherwise to account 421, Miscellaneous Nonoperating Income.
D. Separate entries shall be made for the acquisition, transfer, or retirement of each parcel of land, and each land right, or gas right (except rights-of-way for distribution mains), having a life of more than one year. A record shall be maintained showing the nature of ownership, full legal description, area, map reference, purpose for which used, city, county, and tax district in which situated, from whom purchased or to whom sold, payment given or received, other costs, contract date and number, date of recording of deed, and book and page of record. Entries transferring or retiring land or land rights shall refer to the original entry recording its acquisition. A parcel of land acquired and carried on the books as a unit is not required to be subdivided with transfers to other land accounts merely because of the erection thereon of an incidental structure to be used in gas operations but for a purpose differing from that for which the land is chiefly employed; for example, a small storehouse on production plant land.
E. Any difference between the amount received from the sale of land or land rights, less agents’ commissions and other costs incident to the sale, and the book cost of such land or rights shall be included in account 411.6, Gains from Disposition of Utility Plant or 411.7, Losses from Disposition of Utility Plant when such property has been recorded in account 105, Gas Plant Held for Future Use, 105.1, Production Properties Held for Future Use, otherwise to account 421.1, Gain on Disposition of Property or 421.2, Loss on Disposition of Property, as appropriate, unless a reserve therefor has been authorized and provided. Appropriate adjustments of the accounts shall be made with respect to any structures or improvements located on land sold.
F. The cost of buildings and other improvements (other than public improvements) shall not be included in the land accounts. If at the time of acquisition of an interest in land such interest extends to buildings or other improvements (other than public improvements), which are then devoted to utility operations, the land and improvements shall be separately appraised and the cost allocated to land and buildings or improvements on the basis of the appraisals. If the improvements are removed or wrecked without being used in operations, the cost of removing or wrecking shall be charged and the salvage credited to the account in which the cost of the land is recorded.
G. When the purchase of land for gas operations requires the purchase of more land than needed for such purposes, the charge to the specific land account shall be based upon the cost of the land purchased, less the fair market value of that portion of the land which is not to be used in utility operations. The portion of the cost measured by the fair market value of the land not to be used shall be included in account 105, Gas Plant Held for Future Use or, account 121, Nonutility Property, as appropriate. Regarding land and land rights held for the production of natural gas, account 101, Gas Plant in Service, shall include (1) the cost of lands owned in fee upon which producing natural gas wells are located on lands owned in fee which are being drained through the operation by the utility of wells on the other land, and (2) the first cost of lands held under lease upon which the utility pays royalties for the natural gas obtained therefrom. The cost of all other land and land rights held for the production of natural gas under a plant for such use shall be included in account 105, Gas Plant Held for Future Use, or 105.1, Production Properties Held for Future Use, as appropriate.
In addition to the accounting records prescribed herein, supplemental records of land and land rights held for future use shall be kept in such manner as to permit the segregation within a reasonable time of the land and land rights constituting (1) productive but nonproducing fields, (2) unproven or undeveloped fields, and (3) storage fields, and to show the following data with respect to each natural gas lease, regardless of the accounting treatment accorded the lease costs; (a) name of lessor, (b) location of leasehold and number or other identification assigned thereto, (c) date and period of lease agreement, (d) first cost of lease including details of the elements of such cost, (e) annual rental provisions, (f) date and cost of drilling, (g) date gas determined to exist, (h) date of completion of first well drilled by the utility in each pool of gas, (i) royalty provisions, (j) amortization and depletion provisions, and (k) date of abandonment of lease.
H. Provision shall be made for amortizing amounts carried in the accounts for limited-term interests in land, so as to apportion equitably the cost of each interest over the life thereof. For the purposes of amortization of natural gas rights, separate interests in land which comprise an interest in a production area may be grouped to form a depletion unit. (See account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant, account 404.1, Amortization and Depletion of Producing Natural Gas Land and Land Rights, account 404.3, Amortization of Other Limited-Term Gas Plant, and account 797, Abandonment, leases.)
I. The items of cost to be included in the accounts for land and land rights are as follows:
1. Bulkheads, buried, not requiring maintenance or replacement.
2. Cost, first, of acquisition including mortgages and other liens assumed (but not subsequent interest thereon).
3. [Reserved]
4. Condemnation proceedings, including court and counsel costs.
5. Consents and abutting damages, payment for.
6. Conveyancers’ and notaries’ fees.
7. Fees, commissions, and salaries to brokers, agents, and others in connection with the acquisition of the land or land rights.
8. [Reserved]
9. Leases, cost of voiding upon purchase to secure possession of land.
10. Removing, relocating, or reconstructing, property of others, such as buildings, highways, railroads, bridges, cemeteries, churches, telephone and power lines, etc., in order to acquire quiet possession.
11. Retaining walls unless identified with structures.
12. Special assessments levied by public authorities for public improvements on the basis of benefits for new roads, new bridges, new sewers, new curbing, new pavements, and other public improvements, but not taxes levied to provide for the maintenance of such improvements.
13. Surveys in connection with the acquisition, but not amounts paid for topographical surveys and maps where such costs are attributable to structures or plant equipment erected or to be erected or installed on such land.
14. Taxes assumed, accrued to date of transfer of title.
15. Title, examining, clearing, insuring, and registering in connection with the acquisition and defending against claims relating to the period prior to the acquisition.
16. Appraisals prior to closing title.
17. Cost of dealing with distributees or legatees residing outside of the state or county, such as recording power of attorney, recording will or exemplification of will, recording satisfaction of state tax.
18. Filing satisfaction of mortgage.
19. Documentary stamps.
20. Photographs of property at acquisition.
21. Fees and expenses incurred in the acquisition of water rights, and grants.
22. Cost of fill to extend bulkhead line over land under water, where riparian rights are held, which is not occasioned by the erection of a structure.
23. Sidewalks and curbs constructed by the utility on public property.
24. Labor and expenses in connection with securing rights of way, where performed by company employees and company agents.
8. Structures and improvements. A. The accounts for structures and improvements shall include the cost of all buildings and facilities to house, support, or safeguard property or persons, including all fixtures permanently attached to and made a part of buildings and which cannot be removed therefrom without cutting into the walls, ceilings, or floors, or without in some way impairing the buildings, and improvements of a permanent character on or to land. Also include those costs incurred in connection with the first clearing and grading of land and rights-of-way, and the damage costs associated with construction and installation of plant.
B. The cost of specially provided foundations not intended to outlast the machinery or apparatus for which provided, and the cost of angle irons, castings, etc., installed at the base of an item of equipment, shall be charged to the same account as the cost of the machinery, apparatus, or equipment.
C. Minor buildings and structures may be considered a part of the facility in connection with which constructed or operated and the cost thereof accounted for accordingly when the nature of the structure and facility indicates the correctness of such accounting.
D. Where furnaces and boilers are used primarily for furnishing steam for some particular department and only incidentally for furnishing steam for heating a building and operating the equipment therein, the entire cost of such furnaces and boilers shall be charged to the appropriate plant account, and no part to the building account.
E. The cost of disposing of materials excavated in connection with construction of structures shall be considered as a part of the cost of such work, except as follows: (a) When such material is used for filling, the cost of loading, hauling, and dumping shall be equitably apportioned between the work in connection with which the removal occurs and the work in connection with which the material is used; (b) when such material is sold, the net amount realized from such sales shall be credited to the work in connection with which the removal occurs. If the amount realized from the sale of excavated materials exceeds the removal costs and the costs in connection with the sale, the excess shall be credited to the land account in which the site is carried.
F. Lighting or other fixtures temporarily attached to buildings for purposes of display or demonstration shall not be included in the cost of the building but in the appropriate equipment account.
G. The items of cost to be included in the accounts for structures and improvements are as follows:
1. Architects’ plans and specifications including supervision.
2. Ash pits (when located within the building).
3. Athletic field structures and improvements.
4. Boilers, furnaces, piping, wiring, fixtures, and machinery for heating, lighting, signaling, ventilating, and air conditioning systems, plumbing, vacuum cleaning systems, incinerator and smoke pipe, flues, etc.
5. Bulkheads, including dredging, riprap fill, piling, decking, concrete, fenders, etc., when exposed and subject to maintenance and replacement.
6. Chimneys.
7. Coal bins and bunkers.
8. Commissions and fees to brokers, agents, architects and others.
9. Conduit (not to be removed) with its contents.
10. Damages to abutting property during construction.
11. Docks.
12. Door checks and door stops.
13. Drainage and sewerage systems.
14. Elevators, cranes, hoists, etc., and the machinery for operating them.
15. Excavation, including shoring, bracing, bridging, refill, and disposal of excess excavated material, cofferdams around foundation, pumping water from cofferdam during construction, and test borings.
16. Fences and fence curbs (not including protective fences insolating items of equipment, which shall be charged to the appropriate equipment account).
17. Fire protection systems when forming a part of a structure.
18. Flagpole.
19. Floor covering (permanently attached).
20. Foundations and piers for machinery, constructed as a permanent part of a building or other items listed herein.
21. Grading and clearing when directly occasioned by the building of a structure.
22. Holders—Relief.
23. Intrasite communication system, poles, pole fixtures, wires and cables.
24. Landscaping, lawns, shrubbery, etc.
25. Leases, voiding upon purchase to secure possession of structures.
26. Leased property, expenditures on.
27. Lighting fixtures and outside lighting system.
28. Mailchutes when part of a building.
29. Marquee, permanently attached to building.
30. Painting, first coat.
31. Permanent paving, concrete, brick, flagstone, asphalt, etc. within the property lines.
32. Partitions, including movable.
33. Permits and privileges.
34. Platforms, railings and gratings when constructed as a part of a structure.
35. Power boards for services to a building.
36. Refrigerating systems for general use.
37. Retaining walls except when identified with land.
38. Roadways, railroads, bridges, and trestles, intrasite, except railroads provided for in equipment accounts.
39. Roofs.
40. Scales, connected to and forming a part of a structure.
41. Screens.
42. Sewer systems, for general use.
43. Sidewalks, culverts, curbs and streets constructed by the utility on its property.
44. Sprinkling systems.
45. Sump pumps and pits.
46. Stacks—brick, steel, or concrete, when set on foundation forming part of general foundation and steelwork of a building.
47. Steel inspection during construction.
48. Storage facilities constituting a part of a building.
49. Storm doors and windows.
50. Subways, areaways, and tunnels, directly connected to and forming part of a structure.
51. Tanks, constructed as part of a building or as a distinct structural unit.
52. Temporary heating during construction (net cost).
53. Temporary water connection during construction (net cost).
54. Temporary shanties and other facilities used during construction (net cost).
55. Topographical maps.
56. Tunnels, intake and discharge, when constructed as part of a structure, including sluice gates, and those constructed to house mains.
57. Vaults constructed as part of a building.
58. Watchmen’s sheds and clock systems (net cost when used during construction only).
59. Water basins or reservoirs.
60. Water front improvements.
61. Water meters and supply system for a building or for general company purposes.
62. Water supply piping, hydrants and wells.
63. Wharves.
64. Window shades and ventilators.
65. Yard drainage system.
66. Yard lighting system.
67. Yard surfacing, gravel, concrete, or oil (First cost only).
Structures and Improvements accounts shall be credited with the cost of coal bunkers, stacks, foundations, subways, tunnels, etc., the use of which has terminated with the removal of the equipment with which they are associated even though they have not been physically removed.
9. Equipment. A. The cost of equipment chargeable to the gas plant accounts, unless otherwise indicated in the text of an equipment account, includes the net purchase price thereof, sales taxes, investigation and inspection expenses necessary to such purchase, expenses of transportation when borne by the utility, labor employed, materials and supplies consumed, and expenses incurred by the utility in unloading and placing the equipment in readiness to operate. Also include those costs incurred in connection with the first clearing and grading of land and rights-of-way and the damage costs associated with construction and installation of plant.
B. Exclude from equipment accounts hand and other portable tools which are likely to be lost or stolen or which have relatively small value (for example, $500 or less) or short life, unless the correctness of the accounting therefor as gas plant is verified by current inventories. Special tools acquired and included in the purchase price of equipment shall be included in the appropriate plant account. Portable drills and similar tool equipment when used in connection with the operation and maintenance of a particular plant or department, such as production, transmission, distribution, etc., or in “stores,” shall be charged to the plant account appropriate for their use.
C. The equipment accounts shall include angle irons and similar items which are installed at the base of an item of equipment, but piers and foundations which are designed to be as permanent as the buildings which house the equipment, or which are constructed as a part of the building and which cannot be removed without cutting into the walls, ceilings or floors or without in some way impairing the building, shall be included in the building accounts.
D. The equipment accounts shall include the necessary costs of testing or running a plant or part thereof during an experimental or test period prior to becoming available for service. The utility shall furnish the Commission with full particulars of and justification for any test or experimental run extending beyond a period of thirty days.
E. The cost of efficiency or other tests made subsequent to the date equipment becomes available for service shall be charged to the appropriate expense accounts, except that tests to determine whether equipment meets the specifications and requirements as to efficiency, performance, etc., guaranteed by manufacturers, made after operations have commenced and within the period specified in the agreement or contract of purchase, may be charged to the appropriate gas plant account.
10. Additions and retirements of gas plant.
A. For the purpose of avoiding undue refinement in accounting for additions to and retirements and replacements of gas plant, all property shall be considered as consisting of (1) retirement units and (2) minor items of property. Each utility shall maintain a written property units listing for use in accounting for additions and retirements of gas plant and apply the listing consistently.
B. The addition and retirement of retirement units shall be accounted for as follows:
(1) When a retirement unit is added to gas plant, the cost thereof shall be added to the appropriate gas plant account, except that when units are acquired in the acquisition of any gas plant constituting an operating system, they shall be accounted for as provided in gas plant instruction 5.
(2) When a retirement unit is retired from gas plant, with or without replacement, the book cost thereof shall be credited to the gas plant account in which it is included, determined in the manner set forth in paragraph D, below. If the retirement unit is of a depreciable class, the book cost of the unit retired and credited to gas plant shall be charged to the accumulated provision for depreciation applicable to such property. The cost of removal and the salvage shall be charged or credited, as appropriate, to such depreciation account.
C. The addition and retirement of minor items of property shall be accounted for as follows:
(1) When a minor item of property which did not previously exist is added to plant, the cost thereof shall be accounted for in the same manner as for the addition of a retirement unit, as set forth in paragraph B(1), above, if a substantial addition results, otherwise the charge shall be to the appropriate maintenance expense account.
(2) When a minor item of property is retired and not replaced, the book cost thereof shall be credited to the gas plant account in which it is included; and, in the event the minor item is a part of depreciable plant, the account for accumulated provision for depreciation shall be charged with the book cost and cost of removal and credited with the salvage. If, however, the book cost of the minor item retired and not replaced has been or will be accounted for by its inclusion in the retirement unit of which it is a part when such unit is retired, no separate credit to the property account is required when such minor item is retired.
(3) When a minor item of depreciable property is replaced independently of the retirement unit of which it is a part, the cost of replacement shall be charged to the maintenance account appropriate for the item, except that if the replacement effects a substantial betterment (the primary aim of which is to make the property affected more useful, more efficient, or of greater durability, or of greater capacity), the excess cost of the replacement over the estimated cost at current prices of replacing without betterment shall be charged to the appropriate gas plant account.
D. The book cost of gas plant retired shall be the amount at which such property is included in the gas plant accounts, including all components of construction costs. The book cost shall be determined from the utility’s records and if this cannot be done it shall be estimated. Utilities must furnish the particulars of such estimates to the Commission, if requested. When it is impracticable to determine the book cost of each unit, due to the relatively large number or small cost thereof, an appropriate average book cost of the units, with due allowance for any differences in size and character, shall be used as the book cost of the units retired.
E. The book cost of land retired shall be credited to the appropriate land account. If the land is sold, the difference between the book cost (less any accumulated provision for depreciation, depletion or amortization therefor which has been authorized and provided) and the sale price of the land (less commissions and other expenses of making the sale) shall be recorded in account 411.6, Gains from Disposition of Utility Plant or 411.7, Losses from Disposition of Utility Plant when the property has been recorded in account 105, Gas Plant Held for Future Use account 105.1, Production Properties Held for Future Use, otherwise to accounts 421.1, Gain on Disposition of Property or 421.2, Loss on Disposition of Property, as appropriate. If the land is not used in utility service but is retained by the utility, the book cost shall be charged to account 105, Gas Plant Held for Future Use, or account 121, Nonutility Property as appropriate.
F. The book cost less net salvage of depreciable gas plant retired shall be charged in its entirety to account 108. Accumulated Provision for Depreciation of Gas Plant in Service. Any amounts which, by approval or order of the Commission, are charged to account 182, Extraordinary Property Losses, shall be credited to account 108.
G. The accounting for the retirement of amounts included in account 302, Franchises and Consents, and account 303, Miscellaneous Intangible Plant, and the item of limited-term interest in land included in the accounts for land and land rights, shall be as provided for in the text of account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant, account 404.3, Amortization of Other Limited-Term Gas Plant, and account 405, Amortization of Other Gas Plant.
11. Work order and property record system required. A. Each utility shall record all construction and retirements of gas plant by means of work orders or job orders. Separate work orders may be opened for additions to and retirements of gas plant or the retirements may be included with the construction work order, provided, however, that all items relating to the retirements shall be kept separate from those relating to construction and provided, further, that any maintenance costs involved in the work shall likewise be segregated.
B. Each utility shall keep its work order system so as to show the nature of each addition to or retirement of gas plant, the total cost thereof, the source or sources of costs, and the gas plant account or accounts to which charged or credited. Work orders covering jobs of short duration may be cleared monthly.
C. Each utility shall maintain records in which, for each plant account, the amounts of the annual additions and retirements are classified so as to show the number and cost of the various record units or retirement units.
12. Transfers of property. When property is transferred from one gas plant account to another, from one utility department to another (such as from gas to electric), from one operating division or area to another, to or from account 101, Gas Plant in Service, 104, Gas Plant Leased to Others, 105, Gas Plant Held for Future Use, 105.1, Production Properties held for Future Use, and 121, Nonutility Property, the transfer shall be recorded by transferring the original cost thereof from the one account, department, or location to the other. Any related amounts carried in the accounts for accumulated provisions for depreciation, depletion, or amortization shall be transferred in accordance with the segregation of such accounts.
Amounts included in account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant, shall not be related to a particular natural gas lease, and therefore, shall not be transferred under the provisions of this instruction.
13. Common utility plant. A. If the utility is engaged in more than one utility service such as gas, electric, and water, and any of its utility plant is used in common for several utility services or for other purposes to such an extent and in such manner that it is impracticable to segregate it by utility services currently in the accounts, such property, with the approval of the Commission, may be designated and classified as “common utility plant.”
B. The book amount of utility plant designated as common plant shall be included in account 118, Other Utility Plant, and if applicable in part to gas department, shall be segregated and accounted for in subaccounts as gas plant is accounted for in accounts 101 to 107, inclusive, and gas plant adjustments in account 116; any amounts classifiable as common plant acquisition adjustments or common plant adjustments shall be subject to disposition as provided in paragraph C and B of accounts 114 and 116, respectively, for amounts classified in those accounts. The original cost of common utility plant in service shall be classified according to detailed utility plant accounts appropriate for the property.
C. The utility shall be prepared to show at any time and to report to the Commission annually, or more frequently, if required, and by utility plant accounts (301 to 399) the following: (1) The book cost of common utility plant, (2) the allocation of such cost to the respective departments using the common utility plant, and (3) the basis of the allocation.
D. The accumulated provision for depreciation and amortization of the utility shall be segregated so as to show the amount applicable to the property classified as common utility plant.
E. The expenses of operation maintenance, rents, depreciation and amortization of common utility plant shall be recorded in the accounts prescribed herein, but designated as common expenses, and the allocation of such expenses to the departments using the common utility plant shall be supported in such manner as to reflect readily the basis of allocation used.
14. Employee villages and living quarters. Where employee villages or living quarters are provided for operators and attendants of a functional installation such as a compressor station or gasoline plant, the structures and improvements shall be classified in the related functional structures and improvements account. The furnishings of such residential and recreational facilities shall be classified in the equipment account of the related function.
15. Fees for applications filed with the Commission. A. Fees for applications involving construction of property shall be accounted for as follows:
(1) All fees paid prior to the final disposition of the certificate application shall be charged to account 186, Miscellaneous Deferred Debits.
(2) If the certificate is granted and accepted, the amounts recorded in account 186 shall be cleared to account 107, Construction Work in Progress—Gas, and subsequently cleared to the appropriate plant accounts.
(3) If the certificate requested is not granted or is not accepted by the applicant, the fees recorded in account 186 shall be cleared to account 928, Regulatory Commission Expenses.
(4) All amounts paid after the Commission has granted the certificate shall be recorded in account 107, Construction Work in Progress—Gas, and subsequently cleared to the appropriate plant accounts.
B. All amounts paid related to certificate applications involving the acquisitions of facilities including those acquired by merger or pooling of interests shall be charged to account 928, Regulatory Commission Expenses.
C. All other fees for applications not involving construction or acquisition of facilities shall be charged to account 928, Regulatory Commission Expenses.
1. Supervision and engineering. The supervision and engineering includible in the operating expense accounts shall consist of the pay and expenses of superintendents, engineers, clerks, other employees and consultants engaged in supervising and directing the operation and maintenance of each utility function. Wherever allocations are necessary in order to arrive at the amount to be included in any account the method and basis of allocation shall be reflected by underlying records.
1. Special tests to determine efficiency of equipment operation.
2. Preparing or reviewing budgets, estimates, and drawings relating to operation or maintenance for departmental approval.
3. Preparing instructions for operations and maintenance activities.
4. Reviewing and analyzing operating results.
5. Establishing organizational setup of departments and executing changes therein.
6. Formulating and reviewing routines of departments and executing changes therein.
7. General training and instruction of employees by supervisors whose pay is charge- able hereto. Specific instruction and training in a particular type of work is chargeable to the appropriate functional account. (See Gas Plant Instruction 3(19).)
8. Secretarial work for supervisory personnel, but not general clerical and stenographic work chargeable to other accounts.
9. Consultants’ fees and expenses.
10. Meals, traveling and incidental expenses.
2. Maintenance. A. The cost of maintenance chargeable to the various operating expense and clearing accounts, includes labor, materials, overheads and other expenses incurred in maintenance work. A list of work operations applicable generally to utility plant is included hereunder. Other work operations applicable to specific classes of plant are listed in functional maintenance expense accounts.
B. Materials recovered in connection with the maintenance of property shall be credited to the same account to which the maintenance cost was charged.
C. If the book cost of any property is carried in account 102, Gas Plant Purchased or Sold, the cost of maintaining such property shall be charged to the accounts for maintenance of property of the same class and use, the book cost of which is carried in other gas plant in service accounts. Maintenance of property leased from others shall be treated as provided in operating expense instruction 3.
1. Direct field supervision of maintenance.
2. Inspecting, testing, and reporting on condition of plant specifically to determine the need for repairs, replacements, rearrangements and changes and inspecting and testing the adequacy of repairs which have been made.
3. Work performed specifically for the purpose of preventing failure, restoring serviceability or maintaining life of plant.
4. Rearranging and changing the location of plant not retired.
5. Repairing for reuse materials recovered from plant.
6. Testing for, locating and clearing trouble.
7. Net cost of installing, maintaining, and removing temporary facilities to prevent interruptions in service.
8. Replacing or adding minor items of plant which do not constitute a retirement unit. (See gas plant instruction 10.)
3. Rents. A. The rent expense accounts provided under the several functional groups of expense accounts shall include all rents, including taxes paid by the lessee on leased property, for property used in utility operations, except (1) minor amounts paid for occasional or infrequent use of any property or equipment and all amounts paid for use of equipment that, if owned, would be includible in plant accounts 391 to 398, inclusive, which shall be treated as an expense item and included in the appropriate functional account and (2) rents which are chargeable to clearing accounts, and distributed therefrom to the appropriate account. If rents cover property used for more than one function, such as production and transmission, or by more than one department, the rents shall be apportioned to the appropriate rent expense or clearing accounts of each department on an actual, or, if necessary, an estimated basis.
B. When a portion of property or equipment rented from others for use in connection with utility operations is subleased, the revenue derived from such subleasing shall be credited to the rent revenue account in operating revenues: Provided, however, That in case the rent was charged to a clearing account, amounts received from subleasing the property shall be credited to such clearing account.
C. The cost, when incurred by the lessee, of operating and maintaining leased property, shall be charged to the accounts appropriate for the expense if the property were owned.
D. The cost incurred by the lessee of additions and replacements to gas plant leased from other shall be accounted for as provided in gas plant instruction 6.
4. Training costs. When it is necessary that employees be trained to specifically operate or maintain plant facilities that are being constructed, the related costs shall be accounted for as a current operating and maintenance expense. These expenses shall be charged to the appropriate functional accounts currently as they are incurred. However, when the training costs involved relate to facilities which are not conventional in nature, or are new to the company’s operations, then see Gas Plant Instruction 3(19) for accounting.
A. This account shall include the original cost of gas plant, included in accounts 301 to 399 prescribed herein, owned and used by the utility in its gas operations, and having an expectation of life in service of more than one year from date of installation. Including such property owned by the utility but held by nominees. (See also account 106 for unclassified construction costs of completed plant actually in service.)
B. The cost of additions to and betterments of property leased from others, which are includible in this account, shall be recorded in subdivisions separate and distinct from those relating to owned property. (See gas plant instruction 6.)
A. This account shall include the amount recorded under capital leases for plant leased from others and used by the utility in its utility operations.
B. The gas property included in this account shall be classified separately according to the detailed accounts (301 to 399) prescribed for gas plant in service.
C. Records shall be maintained with respect to each capital lease reflecting: (1) Name of lessor, (2) basic details of lease, (3) terminal date, (4) original cost fair market value of property leased, (5) future minimum lease payments, (6) executory costs, (7) present value of minimum lease payments, (8) the amounts representing interest and the interest rate used, and (9) expenses paid. Records shall also be maintained for plant under a lease, to identify the asset retirement obligation and cost originally recognized for each lease and the periodic charges and credits made to the asset retirement obligations and asset retirement costs.
A. This account shall be charged with the cost of gas plant acquired as an operating unit or system by purchase, merger, consolidation, liquidation, or otherwise, and shall be credited with the selling price of like property transferred to others pending the distribution to appropriate accounts in accordance with gas plant instruction 5.
B. Within six months from the date of acquisition or sale of property recorded herein, the utility shall file with the Commission the proposed journal entries to clear from this account the amounts recorded herein.
A. This account shall include the cost of gas plant which was constructed as a research, development, and demonstration project under the provisions of paragraph C, Account 107, Construction Work in Progress—Gas, and due to the nature of the plant it is desirous to operate it for a period of time in an experimental status.
B. Amounts in this account shall be transferred to Account 101, Gas Plant in Service, or Account 121, Nonutility Property, as appropriate, when the project is no longer considered as experimental. Prior to transfer to account 101 the subject plant must be certified by the Commission for use as gas plant in service.
C. The depreciation on plant in this account shall be charged to account 403, Depreciation expense, and account 403.1, Depreciation expense for asset retirement costs, as appropriate, and credited to account 108, Accumulated provision for depreciation of gas utility plant. The amounts herein shall be depreciated over a period which corresponds to the estimated useful life of the relevant project considering the characteristics involved. However, when projects are transferred to account 101, Gas plant in service, a new depreciation rate based on the remaining service life and undepreciated amounts, will be established.
D. Records shall be maintained with respect to each unit of experiment so that full details may be obtained as to the cost, depreciation, and the experimental status.
E. Should it be determined that experimental plants recorded in this account will fail to satisfactorily perform its function, the costs thereof shall be accounted for as directed or authorized by the Commission.
A. This account shall include the original cost of gas plant owned by the utility but leased to others as operating units or systems, where the lessee has exclusive possession.
B. The property included in this account shall be classified according to the detailed accounts (301 to 399) prescribed for gas plant in service and this account shall be maintained in such detail as though the property were used by the owner in its utility operations.
A. This account shall include the original cost of gas plant (except land and land rights) owned and held for future use in gas service under a definite plan for such use, to include: (1) Property acquired (except land and land rights) but never used by the utility in gas service, but held for such service in the future under a definite plan, and (2) property (except land and land rights) previously used by the utility in gas service, but retired from such service and held pending its reuse in the future, under a definite plan, in gas service. This includes production properties relating to leases acquired on or before October 7, 1969.
B. This account shall also include the original cost of land and land rights owned and held for future use in gas service relating to leases acquired on or before October 7, 1969, under a plan for such use, to include land and land rights: (1) Acquired but never used by the utility in gas service, but held for such service in the future under a plan, and (2) previously held by the utility in gas service, but retired from such service and held pending its reuse in the future under a plan, in gas service. (See Gas Plant Instruction 7.)
C. In the event that property recorded in this account shall no longer be needed or appropriate for future utility operations, the company shall request Commission approval of journal entries to remove such property from this account when the gain realized from the sale or other disposition of the property is $100,000 or more, prior to their being recorded. Such filings shall include the description and original cost of individual properties removed from this account, the accounts charged upon removal, and any associated gains realized upon disposition of such property.
D. Gains or losses from the sale of land and land rights or other disposition of such property previously recorded in this account and not placed in utility service shall be recorded directly in accounts 411.6 or 411.7, as appropriate, except when determined to be significant by the Commission. Upon such a determination, the amounts shall be transferred to account 256, Deferred Gains from Disposition of Utility Plant, or account 187, Deferred Losses from Disposition of Utility Plant, and amortized to accounts 411.6, Gains from Disposition of Utility Plant, or 411.7, Losses from Disposition of Utility Plant, as appropriate.
E. The property included in this account shall be classified according to the detail accounts (301 to 399) prescribed for gas plant in service and the account shall be maintained in such detail as though the property were in service.
Materials and supplies, meters and house regulators held in reserve, and normal spare capacity of plant in service shall not be included in this account.
Include in this account natural gas wells shut in after construction which have not been connected with the line; also, natural gas wells which have been connected with the line but which are shut in for any reason except seasonal excess capacity or governmental proration requirements or for repairs, provided that the related production leases were acquired on or before October 7, 1969.
The loss on abandonment of natural gas leases acquired after October 7, 1969, shall be charged to Account 338, Unsuccessful Exploration and Development Costs.
A. This account shall include the cost of production properties (except land and land rights) relating to leases acquired on or after October 8, 1969, held under a definite plan for future use to insure a future supply of natural gas for use in pipeline operations, to include: (1) Production property (except land and land rights) acquired but never used by the utility in gas service, but held for such service in the future under a definite plan, and (2) production property (except land and land rights) previously used by the utility in gas service, but retired from such service and held pending its reuse in the future, under a definite plan, in gas service.
B. This account shall also include the original cost of land and land rights held under a plan for future use to insure a future supply of natural gas for use in pipeline operations, relating to leases acquired on or after October 8, 1969, to include land and land rights: (1) Acquired but never used by the utility in gas service, but held for service in the future under a plan, and (2) previously used by the utility in gas service, but retired from such service and held pending its reuse in the future under a plan, in gas service. (See Gas Plant Instruction 7.)
C. In the event that property recorded in this account shall no longer be needed or appropriate for future utility operations, the company shall request Commission approval of journal entries to remove such property from this account when the gain realized from the sale or other disposition of the property is $100,000 or more, prior to their being recorded. Such filings shall include the description and original cost of individual properties removed from this account, the accounts charged upon removal, and any associated gains realized upon disposition of such property.
D. Gains or losses from the sale of land and land rights or other disposition of such property previously recorded in this account and not placed in utility service shall be recorded directly in accounts 411.6 or 411.7, as appropriate, except when determined to be significant by the Commission. Upon such determination, the amounts shall be transferred to account 256, Deferred Gains from Sale of Utility Plant, or account 187, Deferred Losses from Sale of Utility Plant, and amortized to accounts 411.6, Gains from Disposition of Utility Plant or 411.7, Losses from Disposition of Utility Plant, as appropriate.
E. The property included in this account shall be classified according to the detailed accounts prescribed for natural gas production and gathering plant in service and such classification shall be maintained in the same detail as though the property were in service.
Unsuccessful exploration and development costs incurred on leases acquired after October 7, 1969, shall be charged to account 338, Unsuccessful Exploration and Development Costs.
At the end of the year or such other date as a balance sheet may be required by the Commission, this account shall include the total of the balances of work orders for gas plant which have been completed and placed in service but which work orders have not been classified for transfer to the detailed gas plant accounts.
For the purpose of reporting to the Commission the classification of gas plant in service by accounts is required, the utility shall also report the balance in this account tentatively classified as accurately as practicable according to prescribed account classifications. The purpose of this provision is to avoid any significant omissions in reported amounts of gas plant in service.
A. This account shall include the total of the balances of work orders for gas plant in process of construction.
B. Work orders shall be cleared from this account as soon as practicable after completion of the job. Further, if a project, such as a gas production plant, a compressor station, or a transmission line, is designed to consist of two or more units which may be placed in service at different dates, any expenditures which are common to and which will be used in the operation of the project as a whole shall be included in gas plant in service upon the completion and the readiness for service of the first unit. Any expenditures which are identified exclusively with units of property not yet in service shall be included in this account.
C. Expenditures on research, development, and demonstration projects for construction of utility facilities are to be included in a separate subdivision in this account. Records must be maintained to show separately each project along with complete detail of the nature and purpose of the research, development, and demonstration project together with the related costs.
This account shall include certificate application fees paid to the Federal Energy Regulatory Commission as provided for in gas plant instruction 15.
Unsuccessful exploration and development costs incurred on leases acquired after October 7, 1969, shall be transferred to account 338, Unsuccessful Exploration and Development Costs.
A. This account shall be credited with the following:
(1) Amounts charged to account 403, Depreciation Expense, or to clearing accounts for current depreciation expense for gas plant in service.
(2) Amounts charged to account 403.1, Depreciation expense for asset retirement costs, for current depreciation expense related to asset retirement costs in gas plant in service in a separate subaccount.
(3) Amounts charged to account 421, Miscellaneous Nonoperating Income, for depreciation expense on property included in account 105, Gas Plant Held for Future Use, or 105.1, Production Properties Held for Future Use. Include also, the balance of accumulated provision for depreciation on property when transferred to account 105 or 105.1, from other property accounts. Normally, account 108 will not be used for current depreciation provisions because, as provided herein, the service life during which depreciation is computed commences with the date property is includible in gas plant in service; however, if special circumstances indicate the propriety of current accruals for depreciation, such charges shall be made to account 421, Miscellaneous Nonoperating Income.
(4) Amounts charged to account 413, Expenses of Gas Plant Leased to Others, for gas plant included in account 104, Gas Plant Leased to Others.
(5) Amounts charged to account 416, Costs and Expenses of Merchandising, Jobbing and Contract Work, or to clearing accounts for current depreciation expense.
(6) Amounts of depreciation applicable to gas properties acquired as operating units or systems. (See gas plant instruction 5.)
(7) Amounts charged to account 182.1, Extraordinary Property Losses, when authorized by the Commission.
(8) Amounts of depreciation applicable to gas plant donated to the utility.
B. At the time of retirement of depreciable gas utility plant, this account shall be charged with the book cost of the property retired and the cost of removal and shall be credited with the salvage value and any other amounts recovered, such as insurance. When retirements, cost of removal and salvage are entered originally in retirement work orders, the net total of such work orders may be included in a separate subaccount hereunder. Upon completion of the work order, the proper distribution to subdivision of this account shall be made as provided in the following paragraph.
C. For general ledger and balance sheet purposes, this account shall be regarded and treated as a single composite provision for depreciation. For purposes of analysis, however, each utility shall maintain subsidiary records in which this account is segregating according to the following functional classification for gas plant:
(1) Production—manufactured gas, (2) production and gathering—natural gas, (3) products extraction—natural gas, (4) underground gas storage, (5) other storage, (6) base load LNG terminaling and processing plant, (7) transmission, (8) distribution, and (9) general. These subsidiary records shall reflect the current credits and debits to this account in sufficient detail to show separately for each such functional classification (a) the amount of provision for depreciation, (b) the book cost of property retired, (c) cost of removal, (d) salvage, and (e) other items, including recoveries from insurance. Separate subsidiary records shall be maintained for the amount of accrued cost of removal other than legal obligations for the retirement of plant recorded in account 108, Accumulated provision for depreciation of gas utility plant.
D. When transfers of plant are made from one gas plant account to another, or from or to another utility department, or from or to nonutility property accounts, the accounting for the related accumulated provision for depreciation shall be as provided in gas plant instruction 12.
E. The utility is restricted in its use of the provision for depreciation to the purposes set forth above. It shall not transfer any portion of this account to retained earnings or make any other use thereof without authorization by the Commission.
A. This account shall be credited with the following:
(1) Amounts charged to account 404.1, Amortization and Depletion of Producing Natural Gas Land and Land Rights, for current amortization and depletion of such land and land rights.
(2) Amounts charged to account 404.2, Amortization of Underground Storage Land and Land Rights, for current amortization.
(3) Amounts charged to account 404.3, Amortization of Other Limited-Term Gas Plant, for the current amortization of limited-term gas plant.
(4) Amounts charged to account 421, Miscellaneous Nonoperating Income, for amortization expense on property included in account 105, Gas Plant Held for Future Use, or 105.1, Production Properties Held for Future Use. Include also, the balance of accumulated provision for amortization on property when transferred to account 105 or 105.1 from other property accounts.
See also paragraph A(2), of account 108, Accumulated Provision for Depreciation of Gas Utility Plant.
(5) Amounts charged to account 405, Amortization of Other Gas Plant.
(6) Amounts charged to account 413, Expenses of Gas Plant Leased to Others, for current amortization thereof.
(7) Amounts charged to account 797, Abandoned Leases, to provide for the abandonment of nonproductive natural gas leases.
(8) Amounts charged to account 425, Miscellaneous Amortization, for the amortization of intangible or other gas plant which does not have a definite or terminable life and is not subject to charges for depreciation expense, with Commission approval.
B. When any property to which this account applies is sold, relinquished, or otherwise retired from service, this account shall be charged with the amount previously credited in respect to such property. The book cost of the property so retired less the amount chargeable to this account and less the net proceeds realized at retirement shall be included in account 421.1, Gain on Disposition of Property, or account 421.2, Loss on Disposition of Property, as appropriate.
C. For general ledger and balance sheet purposes, this account shall be regarded and treated as a single composite provision for amortization.
(1) Production—manufactured gas, (2) production and gathering—natural gas, (3) products extraction—natural gas, (4) underground gas storage, (5) other storage, (6) base load LNG terminaling and processing plant, (7) transmission, (8) distribution, and (9) general. These subsidiary records shall reflect the current credits and debits to this account in sufficient detail to show separately for each such functional classification (a) the amount of provision for amortization, (b) the book cost of property retired, (c) cost of removal, (d) salvage, and (e) other items, including recoveries from insurance. Records shall be maintained so as to show separately the balance applicable to each item of land and land rights which is being amortized or depleted except that natural gas land and land rights which comprise an interest in a production area may be grouped to form a unit for amortization and depletion and the accumulated provision applicable thereto need not be segregated to show the amount related to each gas right included therein. Records shall also be maintained so as to show separately the balance applicable to each underground gas storage project.
D. The utility is restricted in its use of the accumulated provision for amortization to the purposes set forth above. It shall not transfer any portion of this account to retained earnings or make any other use thereof without authorization by the Commission.
A. This account shall include the difference between (a) the cost to the accounting utility of gas plant acquired as an operating unit or system by purchase, merger, consolidation, liquidation, or otherwise, and (b) the original cost, estimated, if not known, of such property, less the amount or amounts credited by the accounting utility at the time of acquisition to accumulated provisions for depreciation, depletion, and amortization and contributions in aid of construction with respect to such property.
B. With respect to acquisitions after the effective date of this system of accounts, this account shall be subdivided so as to show the amounts included herein for each property acquisition and to gas plant in service, gas plant held for future use and gas plant leased to others. (See gas plant instruction 5.)
C. Debit amounts recorded in this account related to plant and land acquisition may be amortized to account 425, Miscellaneous Amortization, over a period not longer than the estimated remaining life of the properties to which such amounts relate. Amounts related to the acquisition of land only may be amortized to account 425 over a period of not more than 15 years. Should a utility wish to account for debit amounts in this account in any other manner, it shall petition the Commission for authority to do so. Credit amounts recorded in this account shall be accounted for as directed by the Commission.
This account shall be credited or debited with amounts which are includible in account 406, Amortization of Gas Plant Acquisition Adjustments or account 425, Miscellaneous Amortization, for the purpose of providing for the extinguishment of amounts in account 114, Gas Plant Acquisition Adjustments, in instances where the amortization of account 114 is not being made by direct write-off of the account.
A. This account shall include the difference between the original cost, estimated if not known, and the book cost of gas plant to the extent that such difference is not properly includible in account 114 Gas Plant Acquisition Adjustments. (See gas plant instruction 1C.)
B. Amounts included in this account shall be classified in such manner as to show the origin of each amount and shall be disposed of as the Commission may approve or direct.
The provisions of this account shall not be construed as approving or authorizing the recording of appreciation of gas plant.
The investment in and use of system gas included in Account 117.1, Gas Stored—Base Gas, and Account 117.2, System Balancing Gas, may be accounted for using either the “fixed asset” method or an “inventory” method as set forth below. The cost of stored gas included in Account 117.3 must be accounted for using an inventory method.
(a) Inventory Method—Gas stored during the year must be priced at cost according to generally accepted methods of cost determination consistently applied from year to year. Transmission expenses for facilities of the utility used in moving the gas to the storage area and expenses of storage facilities cannot be included in the inventory of gas except as may be authorized or directed by the Commission.
Withdrawals of gas must be priced using the first-in-first-out, last-in-first-out, or weighted average cost method, provided the method adopted by the utility is used consistently from year to year and appropriate inventory records are maintained. Approval of the Commission must be obtained for any other pricing method, or change in the pricing method adopted by the utility.
Adjustments for inventory losses related to gas held in underground reservoirs due to cumulative inaccuracies of gas measurements, or from other causes, must be charged to Account 823, Gas Losses. Losses of system gas not associated with underground reservoirs must be charged to Account 813, Other Gas Supply Expenses.
(b) Fixed Asset Method—When replacement of the gas is made, the amount carried in Account 117.4 for such volumes must be cleared with a contra entry to Account 808.2, Gas Delivered to Storage—Credit. Any difference between the utility’s cost of replacement gas volumes and the amount cleared from Account 117.4 must be recognized as a gain in Account 495, Other gas revenues, or as a loss in Account 813, Other gas supply expenses, with contra entries to Account 808.2.
Adjustments for inventory losses related to gas held in underground reservoirs due to cumulative inaccuracies of gas measurements, or from other causes, must be charged to Account 823, Gas Losses. Losses of system gas not associated with underground reservoirs must be charged to Account 813, Other Gas Supply Expenses. Gas losses must be priced at the market price of gas available to the utility in the month the loss is recognized.
Gas owned by the utility and injected into its system will be deemed to satisfy any encroachment on system gas first before any other use.
This account is to include the cost of recoverable gas volumes that are necessary, in addition to those volumes for which cost are properly includable in Account 101, Gas plant in service, to maintain pressure and deliverability requirements for each storage facility. Nonrecoverable gas volumes used for this purpose are to be recorded in Account 352.3, Nonrecoverable natural gas. For utilities using the fixed asset method of accounting, the cost of base gas applicable to each gas storage facility shall not be changed from the amount initially recorded except to reflect changes in volumes designated as base gas. If an inventory method is used to account for gas included herein, the utility may, at its election, price withdrawals in accordance with the instructions to Account 117.4.
This account is to be used to record the cost of system gas designated as available for transmission load balancing (including no-notice transportation) and other uses associated with maintaining efficient transmission operations other than gas properly recordable in Account 117.1 or the plant accounts. Detailed records must be kept separately identifying volumes and unit prices of system gas held in underground storage facilities and held in pipelines.
For utilities using fixed asset accounting, the cost initially recorded herein cannot be changed except for adjustments to volumes designated as system gas. Encroachments upon system gas must be accounted for in accordance with the instructions to Account 117.4, Gas owed to system gas.
This account is to include the cost of stored gas owned by the utility and available for sale or other purposes. Gas included in this account must be accounted for using an inventory method in accordance with the Special Instructions to Accounts 117.1, 117.2, and 117.3 above.
This account is to be used to record encroachments of system gas under the fixed asset method. This account may also be used to record encroachments of base gas for utilities electing to use an inventory method of accounting for system gas. Utilities may revalve cumulative net imbalances, net all transactions, and record one monthly entry with one month-end price for valuation purposes.
This account shall include the balance in accounts for utility plant, other than gas plant, such as electric, railway, etc.
This account shall include the accumulated provision for depreciation and amortization applicable to utility property other than gas plant.
A. This account shall include the book cost of land, structures, equipment or other tangible or intangible property owned by the utility, but not used in utility service and not properly includible in account 105, Gas Plant Held for Future Use. This account shall also include, where applicable, amounts recorded for asset retirement costs associated with nonutility plant.
B. This account shall also include the amount recorded under capital leases for property leased from others and used by the utility in its nonutility operations. Records shall be maintained with respect to each lease reflecting: (1) name of lessor, (2) basic details of lease, (3) terminal date, (4) original cost or fair market value of property leased, (5) future minimum lease payments, (6) executory costs, (7) present value of minimum lease payments, (8) the amount representing interest and the interest rate used, and (9) expenses paid.
C. This account shall be subdivided so as to show the amount of property used in operations which are nonutility in character but nevertheless constitute a distinct operating activity of the company (such as operation of an ice department where such activity is not classed as a utility) and the amount of miscellaneous property not used in operations. The records in support of each subaccount shall be maintained so as to show an appropriate classification of the property.
In the event of the subsequent sale or other disposition of property included in this account which had been previously recorded in account 105, Gas Plant Held for Future Use, or account 105.1, Production Properties Held for Future Use, such property costs shall be accounted for in accordance with paragraph C of accounts 105 and 105.1, respectively.
This account shall include the accumulated provision for depreciation and amortization applicable to nonutility property.
A. This account shall include the book cost of investments in securities issued or assumed by associated companies and investment advances to such companies, including interest accrued thereon when such interest is not subject to current settlement, provided that the investment does not relate to a subsidiary company. (If the investment relates to a subsidiary company it shall be included in account entry to the recording of amortization of discount or premium on interest bearing investments. Include herein the offsetting 123.1, Investment in Subsidiary Companies.) (See account 419, Interest and Dividend Income.)
B. This account shall be maintained in such manner as to show the investment in securities of, and advances to, each associated company together with full particulars regarding any of such investments that are pledged.
Securities and advances of associated companies owned and pledged shall be included in this account, but such securities, if held in special deposits or in special funds, shall be included in the appropriate deposit or fund account. A complete record of securities pledged shall be maintained.
Securities of associated companies held as temporary cash investments are includible in account 136, Temporary Cash Investments.
Balances in open accounts with associated companies, which are subject to current settlement, are includible in account 146, Accounts Receivable from Associated Companies.
The utility may write down the cost of any security in recognition of a decline in the value thereof. Securities shall be written off or written down to a nominal value if there be no reasonable prospect of substantial value. Fluctuations in market value shall not be recorded but a permanent impairment in the value of securities shall be recognized in the accounts. When securities are written off or written down, the amount of the adjustment shall be charged to account 426.5, Other Deductions, or to an appropriate account for accumulated provisions for loss in value established as a separate subdivision of this account.
A. This account shall include the cost of investments in securities issued or assumed by subsidiary companies and investment advances to such companies, including interest accrued thereon when such interest is not subject to current settlement plus the equity in undistributed earnings or losses of such subsidiary companies since acquisition. This account shall be credited with any dividends declared by such subsidiaries.
B. This account shall be maintained in such a manner as to show separately for each subsidiary: The cost of such investments in the securities of the subsidiary at the time of acquisition; the amount of equity in the subsidiary’s undistributed net earnings or net losses since acquisition; advances or loans to such subsidiary; and full particulars regarding any such investments that are pledged.
A. This account shall include the book cost of investments in securities issued or assumed by nonassociated companies, investment advances to such companies, and any investments not accounted for elsewhere. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments. Include also the offsetting entry to the recording of amortization of discount or premium on interest bearing investments. (See account 419, interest and dividend income.)
B. The cost of capital stock of the utility reacquired by it under a definite plan for resale pursuant to authorization by the Board of Directors may, if permitted by statutes, be included in a separate subdivision of this account. (See also account 210, Gain on Resale or Cancellation of Reacquired Capital Stock, and account 217, Reacquired Capital Stock.)
C. The records shall be maintained in such manner as to show the amount of each investment and the investment advances to each person.
Securities owned and pledged shall be included in this account, but securities held in special deposits or in special funds shall be included in appropriate deposit or fund accounts. A complete record of securities pledged shall be maintained.
Securities held as temporary cash investments shall not be included in this account.
See Note D of account 123.
This account shall include the amount of cash and book cost of investments held in sinking funds. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments. A separate account, with appropriate title, shall be kept for each sinking fund. Transfers from this account to special deposit accounts may be made as necessary for the purpose of paying matured sinking-fund obligations, or obligations called for redemption but not presented, or the interest thereon.
This account shall include the amount of cash and book cost of investments which have been segregated in a special fund for the purpose of identifying such assets with the accumulated provisions for depreciation. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments.
This account shall include the amount of cash and book cost of investments which have been segregated in special funds for insurance, employee pensions, savings, relief, hospital, and other purposes not provided for elsewhere. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments. A separate account with appropriate title, shall be kept for each fund.
Amounts deposited with a trustee under the terms of an irrevocable trust agreement for pensions or other employee benefits shall not be included in this account.
Current and accrued assets are cash, those assets which are readily convertible into cash or are held for current use in operations or construction, current claims against others, payment of which is reasonably assured, and amounts accruing to the utility which are subject to current settlement, except such items for which accounts other than those designated as current and accrued assets are provided. There shall not be included in the group of accounts designated as current and accrued assets any item, the amount or collectibility of which is not reasonably assured, unless an adequate provision for possible loss has been made therefor. Items of current character but of doubtful value may be written down and for record purposes carried in these accounts at nominal value.
This account shall include the amount of current cash funds except working funds.
This account shall include special deposits with fiscal agents or others for the payment of interest.
This account shall include special deposits with fiscal agents or others for the payment of dividends.
This account shall include deposits with fiscal agents or others for special purposes other than the payment of interest and dividends. Such special deposits may include cash deposited with federal, state, or municipal authorities as a guaranty for the fulfillment of obligations; cash deposited with trustees to be held until mortgaged property sold, destroyed, or otherwise disposed of is replaced; cash realized from the sale of the accounting utility’s securities and deposited with trustees to be held until invested in property of the utility, etc. Entries to this account shall specify the purpose for which the deposit is made.
Assets available for general corporate purposes shall not be included in this account. Further, deposits for more than one year, which are not offset by current liabilities, shall not be charged to this account but to account 128, Other Special Funds.
This account shall include cash advanced to officers, agents, employees, and others as petty cash or working funds.
A. This account shall include the book cost of investments, such as demand and time loans, bankers’ acceptances, United States Treasury certificates, marketable securities, and other similar investments, acquired for the purpose of temporarily investing cash.
B. This account shall be so maintained as to show separately temporary cash investments in securities of associated companies and of others. Records shall be kept of any pledged investments.
This account shall include the book cost, not includible elsewhere, of all collectible obligations in the form of notes receivable and similar evidences (except interest coupons) of money due on demand or within one year from the date of issue, except, however, notes receivable from associated companies. (See account 136, Temporary Cash Investments, and account 145, Notes Receivable from Associated Companies.)
The face amount of notes receivable discounted, sold, or transferred without releasing the utility from liability as endorser thereon, shall be credited to a separate subdivision of this account and appropriate disclosure shall be made in financial statements of any contingent liability arising from such transactions.
A. This account shall include amounts due from customers for utility service, and for merchandising, jobbing, and contract work. This account shall not include amounts due from associated companies.
B. This account shall be maintained so as to permit ready segregation of the amounts due for merchandising, jobbing, and contract work.
A. This account shall include amounts due the utility upon open accounts, other than amounts due from associated companies and from customers for utility services and merchandising, jobbing, and contract work.
B. This account shall be maintained so as to show separately amounts due on subscriptions to capital stock and from officers and employees, but the account shall not include amounts advanced to officers or others as working funds. (See account 135, Working Funds.)
A. This account shall be credited with amounts provided for losses on accounts receivable which may become uncollectible, and also with collections on accounts previously charged hereto. Concurrent charges shall be made to account 904, Uncollectible Accounts, for amounts applicable to utility operations, and to corresponding accounts for other operations. Records shall be maintained so as to show the write-offs of accounts receivable for each utility department.
B. This account shall be subdivided to show the provision applicable to the following classes of accounts receivable:
Accretions to this account shall not be made in excess of a reasonable provision against losses of the character provided for.
If provisions for uncollectible notes receivable or for uncollectible receivables from associated companies are necessary, separate subaccounts therefor shall be established under the account in which the receivable is carried.
A. These accounts shall include notes and drafts upon which associated companies are liable, and which mature and are expected to be paid in full not later than one year from date of issue, together with any interest thereon, and debit balances subject to current settlement in open accounts with associated companies. Items which do not bear a specified due date but which have been carried for more than twelve months and items which are not paid within twelve months from due date shall be transferred to account 123, Investment in Associated Companies.
B. A natural gas company participating in a cash management program must maintain supporting documentation for all deposits into, borrowings from, interest income from, and interest expense to such program. Cash management programs include all agreements in which funds in excess of the daily needs of the natural gas company along with the excess funds of the natural gas company’s parent, affiliated and subsidiary companies are concentrated, consolidated, or otherwise made available for use by other entities within the corporate group. The written documentation must include the following information:
(1) For deposits with and withdrawals from the cash management program: the date of the deposit or withdrawal, the amount of the deposit or withdrawal, and the maturity date, if any, of the deposit;
(2) For borrowings from a cash management program: the date of the borrowing, the amount of the borrowing, and the maturity date, if any, of the borrowing;
(3) The security, if any, provided by the cash management program for repayment of deposits into the cash management program and the security required, if any, by the cash management program in support of borrowings from the program; and
(4) The monthly balance of the cash management program.
C. The natural gas company must maintain current and up-to-date copies of the documents authorizing the establishment of the cash management program including the following:
(1) The duties and responsibilities of the administrator and the natural gas companies in the cash management program;
(2) The restrictions on deposits or borrowings by natural gas companies in the cash management program;
(3) The interest rate, including the method used to determine the interest earning rates and interest borrowing rates for deposits into and borrowings from the program; and
(4) The method used to allocate interest income and expenses among natural gas companies in the program.
On the balance sheet, accounts receivable from an associated company may be set off against accounts payable to the same company.
The face amount of notes receivable discounted, sold or transferred without releasing the utility from liability as endorser thereon, shall be credited to a separate subdivision of this account and appropriate disclosure shall be made in financial statements of any contingent liability arising from such transactions.
This account shall include the book cost of fuel on hand.
1. Invoice price of fuel less any cash or other discounts.
2. Freight, switching, demurrage and other transportation charges, not including, however, any charges for unloading from the shipping medium.
3. Excise taxes, purchasing agents’ commissions, insurance and other expenses directly assignable to cost of fuel.
A. This account may include the cost of labor and of supplies used and expenses incurred in unloading fuel from the shipping medium and in the handling thereof prior to its use, if such expenses are sufficiently significant in amount to warrant being treated as a part of the cost of fuel inventory rather than being charged direct to expense as incurred.
B. Amounts included herein shall be charged to expense as the fuel is used to the end that the balance herein, shall not exceed the expenses attributable to the inventory of fuel on hand.
1. Procuring and handling of fuel.
2. All routine fuel analyses.
3. Unloading from shipping facility and putting in storage.
4. Moving of fuel in storage and transferring from one station to another.
5. Handling from storage or shipping facility to first bunker, hopper, bucket, tank or holder of boiler house structure.
6. Operation of mechanical equipment, such as locomotives, trucks, cars, boats, barges, cranes, etc.
7. Tools, lubricants and other supplies.
8. Operating supplies for mechanical equipment.
9. Transportation and other expenses in moving fuel.
10. Stores expenses applicable to fuel.
This account shall include the book cost of residuals or extracted products produced in the manufacture of gas or in natural gas products extraction operations including like products purchased for resale.
A. This account shall include the cost of materials purchased primarily for use in the utility business for construction, operation and maintenance purposes. This account shall include also the book cost of materials recovered in connection with construction, maintenance or the retirement of property, such materials being credited to construction, maintenance or accumulated depreciation provision, respectively, and included herein as follows:
(1) Reusable materials consisting of large individual items shall be included in this account at original cost, estimated if not known. The cost of repairing such items shall be charged to the maintenance account appropriate for the previous use.
(2) Reusable materials consisting of relatively small items, the identity of which (from the date of original installation to the final abandonment or sale thereof) cannot be ascertained without undue refinement in accounting, shall be included in this account at current prices new for such items. The cost of repairing such items shall be charged to the appropriate expense account as indicated by previous use.
(3) Scrap and nonusable materials included in this account shall be carried at the estimated net amount realizable therefrom. The difference between the amounts realized for scrap and nonusable materials sold and the net amount at which the materials were carried in this account, as far as practicable, shall be adjusted to the accounts credited when the materials were charged to this account.
B. Materials and supplies issued shall be credited hereto and charged to the appropriate construction, operating expense, or other account on the basis of a unit price determined by the use of cumulative average, first-in-first out, or such other method of inventory accounting as conforms with accepted accounting standards consistently applied.
1. Invoice price of materials less cash or other discounts.
2. Freight, switching or other transportation charges when practicable to include as part of the cost of particular materials to which they relate.
3. Customs duties and excise taxes.
4. Costs of inspection and special tests prior to acceptance.
5. Insurance and other directly assignable charges.
Where expenses applicable to materials purchased cannot be directly assigned to particular purchases, they shall be charged to account 163, Stores expenses Undistributed.
This account shall include the book cost of materials and supplies, and appliances and equipment held primarily for merchandising, jobbing, and contract work. The principles prescribed in accounting for utility materials and supplies shall be observed in respect to items carried in this account.
This account shall include the book cost of materials and supplies held primarily for nonutility purposes. The principles prescribed in accounting for utility materials and supplies shall be observed in respect to items carried in this account.
A. This account shall include the cost of supervision, labor and expenses incurred in the operation of general storerooms, including purchasing, storage, handling and distribution of materials and supplies.
B. This account shall be cleared by adding to the cost of materials and supplies issued a suitable loading charge which will distribute the expense equitably over stores issues. The balance in the account at the close of the year shall not exceed the amount of stores expenses reasonably attributable to the inventory of materials and supplies exclusive of fuel, as any amount applicable to fuel cost should be included in account 152, Fuel Stock Expenses Undistributed.
1. Inspecting and testing materials and supplies when not assignable to specific items.
2. Unloading from shipping facility and putting in storage.
3. Supervision of purchasing and stores department to extent assignable to materials handled through stores.
4. Getting materials from stock and in readiness to go out.
5. Inventorying stock received or stock on hand by stores employees but not including inventories by general department employees as part of internal or general audits.
6. Purchasing department activities in checking material needs, investigating sources of supply, analyzing prices, preparing and placing orders, and related activities to extent applicable to materials handled through stores. (Optional. Purchasing department expenses may be included in administrative and general expenses.)
7. Maintaining stores equipment.
8. Cleaning and tidying storerooms and stores offices.
9. Keeping stock records, including recording and posting of material receipts and issues and maintaining inventory record of stock.
10. Collecting and handling scrap materials in stores.
11. Adjustments of inventories of materials and supplies but not including large differences which can readily be assigned to important classes of materials and equitably distributed among the accounts to which such classes of materials have been charged since the previous inventory.
12. Cash and other discounts not practically assignable to specific materials.
13. Freight, express, etc., when not assignable to specific items.
14. Heat, light and power for storerooms and store offices.
15. Brooms, brushes, sweeping compounds and other supplies used in cleaning and tidying storerooms and stores offices.
16. Injuries and damages.
17. Insurance on materials and supplies and on stores equipment.
18. Losses due to breakage, leakage, evaporation, fire or other causes, less credits for amounts received from insurance, transportation companies or others in compensation of such losses.
19. Postage, printing, stationery and office supplies.
20. Rent of storage space and facilities.
21. Communication service.
22. Excise and other similar taxes not assignable to specific materials.
23. Transportation expense on inward movement of stores and on transfer between storerooms but not including charges on materials recovered from retirements which shall be accounted for as part of cost of removal.
A physical inventory of each class of materials and supplies shall be made at least every two years.
This account shall be debited with such amounts as are credited to Account 117.2, System balancing gas, (for utilities using an inventory method of accounting for system gas) and Account 117.3, Gas Stored in Reservoirs and Pipelines-Noncurrent, to reflect classification for balance sheet purposes of such portion of the inventory of gas stored as represents a current asset according to conventional rules for classification of current assets.
It shall not be considered conformity to conventional rules of current asset classification if the amount included in this account exceeds an amount equal to the cost of estimated withdrawals of gas from storage within the 24-month period from date of the balance sheet, or if the amount represents a volume of gas which, in fact, could not be withdrawn from storage without impairing pressure levels needed for normal operating purposes.
A. This account shall include the cost of liquefied natural gas stored in above or below ground facilities.
B. Natural gas purchased in a liquefied form shall be priced at the cost of such gas to the utility. Natural gas liquefied by the utility shall be priced according to generally accepted methods of cost determination consistently applied from year to year. Transmission expenses for facilities to the utility used in moving the gas to the storage facilities shall not be included in the inventory of gas except as may be authorized by the Commission.
C. Amounts debited to this account for natural gas placed in stored shall be credited to account 808.2, Gas Delivered to Storage—Credit. Amounts credited to this account for gas withdrawn from storage shall be debited to account 808.1, Gas Withdrawn from Storage—Debit.
D. Withdrawals of gas may be priced according to the first-in-first-out, last-in-first-out, or weighted average cost method provided the method adopted by the utility is used consistently from year to year and inventory records are maintained in accordance therewith. Commission approval must be obtained for any other pricing method or for any change in the pricing method adopted by the utility. Separate records shall be maintained for each storage project of the Dth of gas delivered to storage and remaining in storage.
E. Adjustments for inventory losses shall be charged to account 842.3, Gas Losses.
A. This account shall include the cost of base load liquefied natural gas available for vaporization and injection into the utility’s natural gas system.
B. Natural gas purchased in a liquefied form shall be priced at the cost of such gas to the utility.
C. Amounts debited to this account for liquefied natural gas purchased for processing shall be credited to account 809.2, Deliveries of Natural Gas for Processing—Credit. Amounts credited for liquefied natural gas processed shall be debited to account 809.1, Withdrawals of Liquefied Natural Gas Held for Processing—Debit.
D. Withdrawals of gas held for vaporization may be priced according to the first-in-first-out, last-in-first-out or weighted average cost method provided the method adopted by the utility is used consistently from year to year and inventory records are maintained in accordance therewith. Commission approval must be obtained for any other pricing method or for any change from the pricing method adopted by the utility. Separate records shall be maintained for Dth of gas purchased for processing, processed, and remaining for processing.
E. Adjustments for inventory losses shall be charged to account 846.1, Gas Losses.
A. This account shall include payments for undelivered gas and other prepayments of rents, taxes, insurance, interest, and like disbursements made prior to the period to which they apply. Prepayments for gas are those amounts paid to a seller of gas under “take or pay” provisions of a gas purchase contract for a sale certificated by the Commission where future makeup of the gas not taken in the current period is provided for by the contract.
B. As the periods covered by such prepayments expire, credit this account and charge the proper operating expense or other appropriate account with the amount applicable to the period.
C. This account shall be kept or supported in such a manner as to disclose the amount of each class of prepayments.
A. This account shall include all advances made for gas (whether called “advances,” “contributions” or otherwise) to independent producers, affiliated or associated companies, or others operating within the lower 48 states and Alaska; for exploration, development or production (but not to include lease acquisition) of natural gas. Under each agreement with payee, such payments must be made prior to initial gas deliveries, or if the agreement provides for advances on a well by well basis, each incremental payment must be made prior to deliveries from an incremental well, or prior to Federal and/or State authorization, as appropriate. All agreements executed after June 17, 1975, (issuance date of Order No. 529) shall specify that (1) the pipeline shall have first call on any gas produced, attributable to the advance payment, under a long-term contract which is for a minimum initial term computed as the lesser of fifteen years or the life of the reserve in the field, and (2) the selling price of the gas committed by producers whose sales are subject to price regulation shall be governed by and limited to the area rate or national rate or, under appropriate showing of special circumstance, such other rate as may be authorized by the Commission under the provisions of optional pricing and special relief. As a determination of the initial rate, the time of first delivery in interstate commerce to the purchaser shall govern. Non-current advances not to be repaid within a two-year period shall be reclassified and transferred to account 124, Other Investments, for balance sheet purposes. This transfer is for reporting purposes only and has no effect on accounting and ratemaking.
B. When a pipeline obtains a working interest as a result of funds advanced to producers, such amounts shall be included in appropriate production accounts for formal contractual agreements executed prior to the date of issuance of Order No. 499. When an associated company obtains a working interest as a result of funds advanced from a pipeline company, the pipeline shall include such amounts in Account 123, Investment in Associated Companies, or Account 146, Accounts receivable from Associated Companies, as appropriate, for formal contractual commitments made during the period on or after November 10, 1971 (effective date of Order 441) but prior to December 29, 1972, the date of issuance of Order No. 465.
C. Outstanding advances shall be fully reduced within 5 years, or as otherwise authorized by the Commission, from the date gas deliveries commence or the date it is determined that recovery will be in other than gas. This account shall be credited with advances not fully recovered within the five-year period, and the unrecovered portion charged directly to Account 426.5, Other Deductions. A sufficient portion of all gas taken should be credited to the related outstanding advance so as to eliminate the advance within the 5-year period or as otherwise authorized by the Commission upon request by the pipeline company. The reduction of the outstanding advance should not be dependent on a buyer purchasing more than 100 percent of the minimum take or pay quantity provided in the contract. In those instances where the five-year recovery period has lapsed, but recovery of the advance continues beyond the five-year period, the unrecovered advances shall be removed from this account and transferred to Account 167, Other Advances for Gas.
D. Where recovery is by gas, the recovered advance shall be credited to this account and charged to the appropriate gas purchase account.
E. When an advance which is or has been included in this account and in rate base results in a source of proven reserves of natural gas, gas deliveries commence but no gas flows to the pipeline company making such advance, the amount of the advance shall be removed from this account (and from rate base) and recorded in account 167, Other Advances for Gas. Any revenues collected as a result of the advance being included in rate base shall be refunded by the pipeline company to its customers, together with interest, per annum, at the rate established by Order No. 513, issued October 10, 1974, or as subsequently revised by Commission Order, from the date of payment until refunded, within 12 months after the removal of the advance from this account, unless otherwise directed by the Commission. Where there is partial recovery of the advance by gas, in this situation, the amount of the advance transferred from this account to account 167 and the amount of revenues refunded, with interest, shall be appropriately apportioned.
F. However, if 5 years elapses from the time the advance has been included in this account and during such time no gas deliveries have commenced or no determination has been made that the recovery will be in economic consideration other than gas, the pipeline shall at the end of the 5–year period, transfer the advance from this account to Account 167, and cease rate base treatment thereof, unless otherwise directed by the Commission.
G. Whenever as a result of an advance included in this account, a pipeline receives any amount in excess of a full recovery of the advance, e.g. interest income, such amount must be credited to Account 813, Other Gas Supply Expenses, or as otherwise directed by the Commission. If the income or return is received in other than money, it shall be included at the market value of the assets received.
H. If the recipient of an advance is unable to repay it in full, through no fault of the pipeline or contractual provisions, in gas or other assets, the unpaid or nonrecoverable portion must be credited to this account at the time such amount is recognized as nonrecoverable. Nonrecoverable advances significant in amount must be eliminated within 5 years from the date of determination as nonrecoverable by either a charge to account 435, Extraordinary Deductions, or when authorized by the Commission, by a transfer to account 186, Miscellaneous Deferred Debits, and amortization to account 813, Other Gas Supply Expenses. Nonrecoverable advances insignificant in amount should be charged directly to account 813 in the year recognized as nonrecoverable, when authorized by the Commission.
I. No transfers shall be made to or from this account to any other accounts, unless otherwise provided herein, except as specifically authorized by the Commission upon request by the pipeline company.
J. Three copies of any agreement concerning advances will be filed with the Secretary within 30 days of the initial related entry in account 166.
This account may include advances for exploration (including lease acquisition costs) made according to the provisions of Order Nos. 410 and 410–A, for which a contractual commitment was made prior to November 10, 1971, (issue date of Order No. 441). All advances made pursuant to contractual commitments made prior to November 10, 1971, (issue date of Order No. 441) shall be subject to the provisions of Order Nos. 410 and 410–A.
This account shall not include advances for exploration (including lease acquisition costs) in accordance with Order No. 441, for which a contractual commitment was made on or after November 10, 1971 (issue date of Order No. 441), but prior to December 29, 1972 (issue date of Order No. 465). All advances made pursuant to contractual commitments made on or after November 10, 1971, but prior to December 29, 1972 (issue date of Order No. 465) shall be subject to the provisions of Order No. 441.
This account shall not include advances for lease acquisition costs but may include advances for exploration where such advances are pursuant to contractual commitments made on or after December 29, 1972 (issue date of Order No. 465).
All advances made pursuant to contractual commitments made on or after December 29, 1972 (issue date of Order No. 465) but prior to the date of issuance of Order No. 499, shall be subject to the provisions of Order No. 465.
All advances made pursuant to contractual commitments made on or after December 28, 1973 (issue date of Order No. 499), but prior to the date of issuance of Order No. 529, shall be subject to the provisions of Order No. 499.
This account shall not include advances expended for delay rentals, nonproductive well drilling or abandoned leases where such advances are related to lease acquisition, except in accordance with Note A and Note B to this account.
To keep the Commission informed when an advance is nonrecoverable by any means the company must submit the full details including copies of Federal and State plugging and abandonment reports involved as soon as such fact becomes known.
This account shall include all advances not properly includible in Account 166, exclusive of amounts advanced where a working interest is obtained.
This account shall include the amount of interest on bonds, mortgages, notes, commercial paper, loans, open accounts, deposits, etc., the payment of which is reasonably assured, and the amount of dividends declared or guaranteed on stocks owned.
Interest which is not subject to current settlement shall not be included herein but in the account in which is carried the principal on which the interest is accrued.
Interest and dividends receivable from associated companies shall be included in account 146. Accounts Receivable from Associated Companies.
This account shall include rents receivable or accrued on property rented or leased by the utility to others.
Rents receivable from associated companies shall be included in account 146. Accounts Receivable From Associated Companies.
At the option of the utility, the estimated amount accrued for service rendered, but not billed at the end of any accounting period, may be included herein. In case accruals are made for unbilled revenues, they shall be made likewise for unbilled expenses, such as for the purchase of gas.
A. This account shall include the book cost of all other current and accrued assets, appropriately designated and supported so as to show the nature of each asset included herein.
B. The utility is to include in a separate subaccount amounts receivable for gas in unbalanced transactions where gas is delivered to another party in exchange, load balancing, or no-notice transportation transactions. (See Account 806.) If the amount receivable is settled by other than gas, Account 495, Other Gas Revenues must be credited or Account 813, Other Gas Supply Expenses, charged for the difference between the amount of the consideration received and the recorded amount of the receivable settled. Records are to be maintained so that there is readily available for each party entering gas exchange, load balancing, or no-notice transportation transactions, the quantity and cost of gas delivered, and the amount and basis of consideration received, if other than gas.
This account shall include the amounts paid for derivative instruments, and the change in the fair value of all derivative instrument assets not designated as cash flow or fair value hedges. Account 421, miscellaneous nonoperating income, will be credited or debited as appropriate with the corresponding amount of the change in the fair value of the derivative instrument.
A. This account shall include the amounts paid for derivative instruments, and the change in the fair value of derivative instrument assets designated by the utility as cash flow or fair value hedges.
B. When a utility designates a derivative instrument asset as a cash flow hedge it will record the change in the fair value of the derivative instrument in this account with a concurrent charge to account 219, accumulated other comprehensive income, with the effective portion of the derivative gain or loss. The ineffective portion of the cash flow hedge shall be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
C. When a utility designates a derivative instrument asset as a fair value hedge it shall record the change in the fair value of the derivative instrument in this account with a concurrent charge to a subaccount of the asset or liability that carries the item being hedged. The ineffective portion of the fair value hedge shall be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
This account shall include expenses related to the issuance or assumption of debt securities. Amounts recorded in this account shall be amortized over the life of each respective issue under a plan which will distribute the amount equitably over the life of the security. The amortization shall be on a monthly basis, and the amounts thereof shall be charged to account 428, Amortization of Debt Discount and Expense. Any unamortized amounts outstanding at the time that the related debt is prematurely reacquired shall be accounted for as indicated in General Instruction 17.
A. When authorized or directed by the Commission, this account shall include extraordinary losses, which could not reasonably have been anticipated and which are not covered by insurance or other provisions, such as unforeseen damages to property.
B. Application to the Commission for permission to use this account shall be accompanied by a statement giving a complete explanation with respect to the items which it is proposed to include herein, the period over which, and the accounts to which it is proposed to write off the charges, and other pertinent information.
A. This account shall include: (1) Nonrecurring costs of studies and analyses mandated by regulatory bodies related to plants in service, transferred from account 183.2, Other Preliminary Survey and Investigation Charges, and not resulting in construction; and (2) when authorized by the Commission, significant unrecovered costs of plant facilities where construction has been cancelled or which have been prematurely retired.
B. This account shall be credited and account 407.1, Amortization of Property Losses, Unrecovered Plant and Regulatory Study Costs, shall be debited, over the period specified by the Commission.
C. Any additional costs incurred, relative to the cancellation or premature retirement, may be included in this account and amortized over the remaining period of the original amortization period. Should any gains of recoveries be realized relative to the cancelled or prematurely retired plant, such amounts shall be used to reduce the unamortized amount of the costs recorded herein.
D. In the event that the recovery of costs included herein is disallowed in rate proceedings, the disallowed costs shall be charged to account 426.5, Other Deductions, or account 435, Extraordinary deductions, in the year of such disallowance.
A. This account shall include the amounts of regulatory-created assets, not includible in other accounts, resulting from the ratemaking actions of regulatory agencies. (See Definition No. 31.)
B. The amounts included in this account are to be established by those charges which would have been included in net income, or accumulated other comprehensive income, determinations in the current period under the general requirements of the Uniform System of Accounts but for it being probable that such items will be included in a different period(s) for purposes of developing rates that the utility is authorized to charge for its utility services. When specific identification of the particular source of a regulatory asset cannot be made, such as in plant phase-ins, rate moderation plans, or rate levelization plans, account 407.4, regulatory credits, shall be credited. The amounts recorded in this account are generally to be charged, concurrently with the recovery of the amounts in rates, to the same account that would have been charged if included in income when incurred, except all regulatory assets established through the use of account 407.4 shall be charged to account 407.3, Regulatory debits, concurrent with the recovery in rates.
C. If rate recovery of all or part of an amount included in this account is disallowed, the disallowed amount shall be charged to Account 426.5, Other Deductions, or Account 435, Extraordinary Deductions, in the year of the disallowance.
D. The records supporting the entries to this account shall be kept so that the utility can furnish full information as to the nature and amount of each regulatory asset included in this account, including justification for inclusion of such amounts in this account.
A. This account shall be charged with all expenditures for preliminary surveys, plans, investigations, etc. made for the purpose of determining the feasibility of acquiring land and land rights to provide a future supply of natural gas. If such land or land rights are acquired, this account shall be credited and the appropriate gas plant account (see gas plant instruction 7–G) charged with the amount of the expenditures relating to such acquisition. If a project is abandoned involving a natural gas lease acquired before October 8, 1969, the expenditures related thereto shall be charged to account 798, Other Exploration. If a project is abandoned involving a lease acquired after October 7, 1969, the expenditures related thereto shall be charged to account 338, Unsuccessful Exploration and Development Costs.
B. The records supporting the entries to this account shall be so kept that the utility can furnish, for each investigation, complete information as to the identification and location of territory investigated, the number or other identification assigned to the land tract or leasehold acquired, and the nature and respective amounts of the charges.
The amount of preliminary survey and investigation charges transferred to gas plant shall not exceed the expenditures which may reasonably be determined to contribute directly and immediately and without duplication to gas plant.
A. This account shall be charged with all expenditures for preliminary surveys, plans, investigations, etc., made for the purpose of determining the feasibility of utility projects under contemplation, other than the acquisition of land and land rights to provide a future supply of natural gas. If construction results, this account shall be credited and the appropriate utility plant account charged. If the work is abandoned, the charge shall be made to account 426.5, Other Deductions, or the appropriate operating expense account.
B. This account shall also include costs of studies and analyses mandated by regulatory bodies related to plant in service. If construction results from such studies, this account shall be credited and the appropriate utility plant account charged with an equitable portion of such study costs directly attributable to new construction. The portion of such study costs not attributable to new construction or the entire cost if construction does not result shall be charged to account 182.2, Unrecovered Plant and Regulatory Study Costs, or the appropriate operating expense account. The costs of such studies relative to plant under construction shall be included directly in account 107, Construction Work in Progress—Gas.
C. The records supporting the entries to this account shall be so kept that the utility can furnish complete information as to the nature and the purpose of the survey, plans, or investigations and the nature and amounts of the several charges.
The amount of preliminary survey and investigation charges transferred to utility plant shall not exceed the expenditures which may reasonably be determined to contribute directly and immediately and without duplication to utility plant.
This caption shall include undistributed balances in clearing accounts at the date of the balance sheet. Balances in clearing accounts shall be substantially cleared not later than the end of the calendar year unless items held therein relate to a future period.
This account shall include amounts shown by work orders for plant installed for temporary use in utility service for periods of less than one year. Such work orders shall be charged with the cost of temporary facilities and credited with payments received from customers and net salvage realized on removal of the temporary facilities. Any net credit or debit resulting shall be cleared to account 488, Miscellaneous Service Revenues.
A. This account shall include all debits not elsewhere provided for, such as miscellaneous work in progress, construction certificate application fees paid prior to final disposition of the application as provided for in gas plant instruction 15A, and unusual or extraordinary expenses not included in other accounts which are in process of amortization, and items the final disposition of which is uncertain.
B. The records supporting the entries to this account shall be so kept that the utility can furnish full information as to each deferred debit included herein.
This account shall include losses from the sale or other disposition of property previously recorded in account 105, Gas Plant Held for Future Use and account 105.1, Production Properties Held for Future Use, under the provisions of paragraphs B, C, and D thereof, where such losses are significant and are to be amortized over a period of 5 years, unless otherwise authorized by the Commission. The amortization of the amounts in this account shall be made by debits to account 411.7, Losses from Disposition of Utility Plant. Subdivision of this account shall be maintained so that amounts relating to account 105, Gas Plant Held for Future Use and account 105.1, Production Properties Held for Future Use, can be readily identifiable. (See accounts 105, Gas Plant Held for Future Use and 105.1, Production Properties Held for Future Use.)
A. This account shall be charged with the cost of all expenditures coming within the meaning of Research, Development, and Demonstration (R.D. & D.) of this Uniform Systems of Accounts (see definition 28.B), except those expenditures properly chargeable to Account 107, Construction Work in Progress—Gas.
B. Costs that are minor or of a general or recurring nature shall be transferred from this account to the appropriate operating expense function or if such costs are common to the overall operations or cannot be feasibly allocated to the various operating accounts, then such costs shall be recorded in account 930.2, Miscellaneous General Expenses.
C. In certain instances a company may incur large and significant research, development, and demonstration expenditures which are nonrecurring and which would distort the annual research, development, and demonstration charges for the period. In such a case the portion of such amounts that cause the distortion may be amortized to the appropriate operating expense account over a period not to exceed five years unless otherwise authorized by the Commission.
D. The entries in this account must be so maintained as to show separately each project along with complete detail of the nature and purpose of the research, development, and demonstration project together with the related costs.
This account shall include the losses on long-term debt reacquired or redeemed. The amounts in this account shall be amortized in accordance with General Instruction 17.
A. This account shall be debited and account 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, or account 411.2, Provision for Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited with an amount equal to that by which income taxes payable for the year are higher because of the inclusion of certain items in income for tax purposes, which items for general accounting purposes will not be fully reflected in the utility’s determination of annual net income until subsequent years.
B. This account shall be credited and account 410.1, Provision for Deferred Income Taxes, Utility Operating Income, or account 410.2, Provision for Deferred Income Taxes, Other Income and Deductions, as appropriate, shall be debited with an amount equal to that by which income taxes payable for the year are lower because of prior payment of taxes as provided by paragraph A above, because of difference in timing for tax purposes of particular items of income or income deductions from that recognized by the utility for general accounting purposes. Such credit to this account and debit to account 410.1 or 410.2 shall, in general, represent the effect on taxes payable in the current year of the smaller amount of book income recognized, or the larger deduction permitted, for tax purposes as compared to the amount recognized in the utility’s current accounts with respect to the item or class of items for which deferred tax concept of accounting is affected.
C. Vintage year records with respect to entries to this account, as described above, and the account balance shall be so maintained as to show the factor of calculation with respect to each annual amount of the item or class of items for which deferred tax accounting by the utility is utilized.
D. The utility is restricted in its use of this account to the purpose set forth above. It shall not make use of the balance in this account or any portion thereof except as provided in the text of this account, without prior approval of the Commission. Any remaining deferred tax account balance with respect to an amount for any prior year’s tax deferral, the amortization of which or other recognition in the utility’s income accounts has been completed, or other disposition made, shall be debited to account 410.1, Provision for Deferred Income Taxes, Utility Operating Income, or account 410.2, Provision for Deferred Income Taxes, Other Income and Deductions, as appropriate, or otherwise disposed of as the Commission may authorize or direct. (See General Instruction 18.)
A. This account shall include purchase gas costs related to Commission approved purchased gas adjustment clauses when such costs are not included in the utility’s rate schedule on file with the Commission. This account shall also include such other costs as authorized by the Commission.
B. This account shall be debited or credited, as appropriate, each month for increases or decreases in purchased gas costs with contra entries to Account 805.1, Purchased Gas Cost Adjustments.
C. After a change in a rate schedule recognizing the increases or decreases in purchased gas costs recorded in this account is approved by the Commission, this account shall be debited or credited, as appropriate, with contra entries to expense Account 805.1, Purchased Gas Cost Adjustments, so that the balance accumulated in this account will be amortized on an appropriate basis over a succeeding 6–month period or over such other periods that the Commission may have authorized. Any over or under applied debits or credits to this account shall be carried forward to the succeeding period of amortization.
D. Separate subaccounts shall be maintained for the amounts relating to the period in which the increase or decrease is accumulated and for the amortization of purchase gas increases or decreases, as applicable, so as to keep each period separate.
A. These accounts shall include the par value or the stated value of stock without par value if such stock has a stated value, and, if not, the cash value of the consideration received for such nonpar stock, of each class of capital stock actually issued, including the par or stated value of such capital stock in account 124, Other Investments and account 217, Reacquired Capital Stock.
B. When the actual cash value of the consideration received is more or less than the par or stated value of any stock having a par or stated value, the difference shall be credited or debited, as the case may be, to the premium or discount account for the particular class and series.
C. When capital stock is retired, these accounts shall be charged with the amount at which such stock is carried herein.
D. A separate ledger account, with a descriptive title, shall be maintained for each class and series of stock. The supporting records shall show the shares nominally issued, actually issued, and nominally outstanding.
When a levy or assessment, except a call for payment on subscriptions, is made against holders of capital stock, the amount collected upon such levy or assessment shall be credited to account 207, Premium on Capital Stock; provided, however, that the credit shall be made to account 213, Discount on Capital Stock, to the extent of any remaining balance of discount on the issue of stock.
A. These accounts shall include the amount of legally enforceable subscriptions to capital stock of the utility. They shall be credited with the par or stated value of the stock subscribed, exclusive of accrued dividends, if any. Concurrently, a debit shall be made to subscriptions to capital stock, included as a Other Accounts Receivable, for the agreed price and any discount or premium shall be debited or credited to the appropriate discount or premium account. When properly executed stock certificates have been issued representing the shares subscribed, this account separate subdivision of account 143, shall be debited, and the appropriate capital stock account credited, with the par or stated value of such stock.
B. The records shall be kept in such manner as to show the amount of subscriptions to each class and series of stock.
A. These accounts shall include the par value or stated value, as appropriate, of capital stock which the utility has agreed to exchange for outstanding securities of other companies in connection with the acquisition of properties of such companies under terms which allow the holders of the securities of the other companies to surrender such securities and receive in return therefor capital stock of the accounting utility.
B. When the securities of the other companies have been surrendered and capital stock issued in accordance with the terms of the exchange, these accounts shall be charged and accounts 201, Common Stock Issued, or 204, Preferred Stock Issued, as the case may be, shall be credited.
C. The records shall be kept so as to show separately the stocks of each class and series for which a conversion liability exists.
A. This account shall include, in a separate subdivision for each class and series of stock, the excess of the actual cash value of the consideration received on original issues of capital stock over the par or stated value and accrued dividends of such stock, together with assessments against stockholders representing payments required in excess of par or stated values.
B. Premium on capital stock shall not be set off against expenses. Further, a premium received on an issue of a certain class or series of stock shall not be set off against expenses of another issue of the same class or series.
C. When capital stock which has been actually issued is retired, the amount in this account applicable to the shares retired shall be transferred to account 210, Gain on Resale or Cancellation of Reacquired Capital Stock.
This account shall include the balance of credits for donations received from stockholders consisting of capital stock of the utility, cancellation or reduction of debt of the utility, and the cash value of other assets received as a donation.
This account shall include the balance of credits arising from a reduction in the par or stated value of capital stock.
This account shall include the balance of credits arising from the resale or cancellation of reacquired capital stock. (See account 217, Reacquired Capital Stock.)
This account shall include the balance of all other credits for paid.in capital which are not properly includible in the foregoing accounts. This account may include all commissions and expenses incurred in connection with the issuance of capital stock.
Amounts included in capital surplus at the effective date of this system of accounts which cannot be classified as to the source thereof shall be included in this account.
A. This account shall include in a separate subdivision for each class and series of capital stock the amount of installments received on capital stock on a partial or installment payment plan from subscribers who are not bound by legally enforceable subscription contracts.
B. As subscriptions are paid in full and certificates issued, this account shall be charged and the appropriate capital stock account credited with the par or stated value of such stock. Any discount or premium on an original issue shall be included in the appropriate discount or premium account.
A. This account shall include in a separate subdivision for each class and series of capital stock all discount on the original issuance and sale of capital stock, including additional capital stock of a particular class or series as well as first issues.
B. When capital stock which has been actually issued is retired, the amount in this account applicable to the shares retired shall be written off to account 210, Gain on Resale or Cancellation of Reacquired Capital Stock, provided, however, that the amount shall be charged to account 439, Adjustments to Retained Earnings, to the extent that it exceeds the balance in account 210.
A. This account shall include in a separate subdivision for each class and series of stock all commissions and expenses incurred in connection with the original issuance and sale of capital stock, including additional capital stock of a particular class or series as well as first issues. Expenses applicable to capital stock shall not be deducted from premium on capital stock.
B. When capital stock which has been actually issued by the utility is retired, the amount in this account applicable to the shares retired shall be written off to account 210, Gain on Resale or Cancellation of Reacquired Capital Stock, provided, however, that the amount shall be charged to account 439, Adjustments to Retained Earnings, to the extent that it exceeds the balance in account 210.
Expenses in connection with the reacquisition or resale of the utility’s capital stock shall not be included herein.
The utility may write off capital stock expense in whole or in part by charges to account 211, Miscellaneous Paid-In Capital.
This account shall include the amount of earned surplus which has been appropriated or set aside for specific purposes. Separate subaccounts shall be maintained under such titles as will designate the purpose for which each appropriation was made.
This account shall include the balances, either debit or credit, of unappropriated retained earnings arising from earnings of the utility. This account shall not include any amounts representing the undistributed earnings of subsidiary companies.
This account shall include the balances, either debit or credit, of undistributed retained earnings of subsidiary companies since their acquisition. When dividends are received from subsidiary companies and the balances have been included in this account, this account shall be debited and account 216, Unappropriated Retained Earnings, credited.
A. This account shall include in a separate subdivision for each class and series of capital stock, the cost of capital stock actually issued by the utility and reacquired by it and not retired or canceled, except, however, stock which is held by trustees in sinking or other funds.
B. When reacquired capital stock is retired or canceled, the difference between its cost, including commissions and expenses paid in connection with the reacquisition, and its par or stated value plus any premium and less any discount and expenses applicable to the shares retired, shall be debited or credited, as appropriate, to account 210, Gain on Resale or Cancellation of Reacquired Capital Stock, provided, however, that debits shall be charged to account 439, Adjustments to Retained Earnings, to the extent that they exceed the balance in account 210.
C. When reacquired capital stock is resold by the utility, the difference between the amount received on the resale of the stock, less expenses incurred in the resale, and the cost of the stock included in this account shall be accounted for as outlined in paragraph B.
See account 124. Other Investments, for permissive accounting treatment of stock reacquired under a definite plan for resale.
The accounting for reacquired stock shall be as prescribed herein unless otherwise specifically required by statute.
A. This account shall include revenues, expenses, gains, and losses that are properly includable in other comprehensive income during the period. Examples of other comprehensive income include foreign currency items, minimum pension liability adjustments, unrealized gains and losses on certain investments in debt and equity securities, and cash flow hedges. Records supporting the entries to this account shall be maintained so that the utility can furnish the amount of other comprehensive income for each item included in this account.
B. This account shall also be debited or credited, as appropriate, with amounts of accumulated other comprehensive income that have been included in the determination of net income during the period and in accumulated other comprehensive income in prior periods. Separate records for each category of items will be maintained to identify the amount of the reclassification adjustments from accumulated other comprehensive income to earnings made during the period.
This account shall include in a separate subdivision for each class and series of bonds the face value of the actually issued and unmatured bonds which have not been retired or canceled; also the face value of such bonds issued by others the payment of which has been assumed by the utility.
A. This account shall include the face value of bonds actually issued or assumed by the utility and reacquired by it and not retired, or canceled. The account for reacquired debt shall not include securities which are held by trustee in sinking or other funds.
B. When bonds are reacquired, the difference between face value, adjusted for unamortized discount, expenses or premium, and the amount paid upon reacquisition, shall be included in account 189, Unamortized Loss on Reacquired Debt, or account 257, Unamortized Gain on Reacquired Debt, as appropriate. (See General Instruction 17.)
A. This account shall include the face value of notes payable to associated companies and the amount of open book accounts representing advances from associated companies. It does not include notes and open accounts representing indebtedness subject to current settlement which are includible in account 233, Notes Payable to Associated Companies, or account 234, Accounts Payable to Associated Companies.
B. The records supporting the entries to this account shall be so kept that the utility can furnish complete information concerning each note and open account.
A. This account shall include, until maturity, all long-term debt not otherwise provided for. This covers such items as receivers’ certificates, real estate mortgages executed or assumed, assessments for public improvements, notes and unsecured certificates of indebtedness not owned by associated companies, receipts outstanding for long-term debt, and other obligations maturing more than one year from date of issue or assumption.
B. Separate accounts shall be maintained for each class of obligation, and records shall be maintained to show for each class all details as to date of obligation, date of maturity, interest dates and rates, security for the obligation, etc.
Miscellaneous long-term debt reacquired shall be accounted for in accordance with the procedure set forth in account 222, Reacquired Bonds.
A. This account shall include the excess of the cash value of consideration received over the face value upon the issuance or assumption of long-term debt securities.
B. Amounts recorded in this account shall be amortized over the life of each respective issue under a plan which will distribute the amount equitably over the life of the security. The amortization shall be on a monthly basis, with the amounts thereof to be credited to account 429, Amortization of Premium on Debt—Credit. (See General Instruction 17.)
A. This account shall include the excess of the face value of long-term debt securities over the cash value of consideration received therefor, related to the issue or assumption of all types and classes of debt.
B. Amounts recorded in this account shall be amortized over the life of the respective issues under a plan which will distribute the amount equitably over the life of the securities. The amortization shall be on a monthly basis, with the amounts thereof charged to account 428, Amortization of Debt Discount and Expense. (See General Instruction 17.)
Current and accrued liabilities are those obligations which have either matured or which become due within one year from the date thereof; except, however, bonds, receivers’ certificates and similar obligations which shall be classified as long-term debt until date of maturity; accrued taxes, such as income taxes, which shall be classified as accrued liabilities even though payable more than one year from date; compensation awards, which shall be classified as current liabilities regardless of date due; and minor amounts payable in installments which may be classified as current liabilities. If a liability is due more than one year from date of issuance or assumption by the utility, it shall be credited to a long-term debt account appropriate for the transaction, except, however, the current liabilities previously mentioned.
This account shall include the portion not due within one year, of the obligations recorded for the amounts applicable to leased property recorded as assets in account 101.1, Property under Capital Leases, or account 121, Nonutility property.
No amounts shall be credited to these accounts unless authorized by a regulatory authority or authorities to be collected in a utility’s rate levels.
A. This account shall include amounts reserved by the utility for losses through accident, fire, flood, or other hazards to its own property or property leased from others, not covered by insurance. The amounts charged to account 924, Property Insurance, or other appropriate accounts to cover such risks shall be credited to this account. A schedule of risks covered shall be maintained, giving a description of the property involved, the character of the risks covered and the rates used.
B. Charges shall be made to this account for losses covered, not to exceed the account balance. Details of these charges shall be maintained according to the year the casualty occurred which gave rise to the loss.
A. This account shall be credited with amounts charged to account 925, Injuries and Damages, or other appropriate accounts, to meet the probable liability, not covered by insurance, for deaths or injuries to employees and others, and for damages to property neither owned nor held under lease by the utility.
B. When liability for any injury or damage is admitted by the utility either voluntarily or because of the decision of a court or other lawful authority, such as a workmens’ compensation board, the admitted liability shall be charged to this account and credited to the appropriate current liability account. Details of these charges shall be maintained according to the year the casualty occurred which gave rise to the loss.
Recoveries or reimbursements for losses charged to this account shall be credited hereto; the cost of repairs to property of others if provided for herein shall be charged to this account.
A. This account shall include provisions made by the utility and amounts contributed by employees for pensions, accident and death benefits, savings, relief, hospital and other provident purposes, where the funds are included in the assets of the utility either in general or in segregated fund accounts.
B. Amounts paid by the utility for the purposes for which this liability is established shall be charged hereto.
C. A separate account shall be kept for each kind of provision included herein.
If employee pension or benefit plan funds are not included among the assets of the utility but are held by outside trustees, payments into such funds, or accruals therefor, shall not be included in this account.
A. This account shall include all operating provisions which are not provided for elsewhere.
B. This account shall be maintained in such manner as to show the amount of each separate provision and the nature and amounts of the debits and credits thereto.
This account includes only provisions as may be created for operating purposes and does not include any reservations of income the credits for which should be carried in account 215, Appropriated Retained Earnings.
A. This account shall be credited with amounts charged to Account 496, Provision for Rate Refunds, to provide for estimated refunds where the utility is collecting amounts in rates subject to refund.
B. When a refund of any amount recorded in this account is ordered by a regulatory authority, such amount shall be charged hereto and credited to Account 242, Miscellaneous Current and Accrued Liabilities.
C. Records supporting the entries to this account shall be kept so as to identify each amount recorded by the respective rate filing docket number.
A. This account shall include the amount of liabilities for the recognition of asset retirement obligations related to gas utility plant and nonutility plant that gives rise to the obligations. This account shall be credited for the amount of the liabilities for asset retirement obligations with amounts charged to the appropriate gas utility plant accounts or nonutility plant accounts to record the related asset retirement costs.
B. This account shall also include the period to period changes for the accretion of the liabilities in account 230, Asset retirement obligations. The utility shall charge the accretion expense to account 411.10, Accretion expense, for gas utility plant, account 413, Expenses of gas plant leased to others, for gas plant leased to others, or account 421, Miscellaneous nonoperating income, for nonutility plant, as appropriate, and credit account 230, Asset retirement obligations.
C. This account shall be debited with amounts paid to settle the asset retirement obligations recorded herein.
D. The utility shall clear from this account any gains or losses resulting from the settlement of asset retirement obligations in accordance with the instructions prescribed in General Instruction 24.
This account shall include the face value of all notes, drafts, acceptances, or other similar evidences of indebtedness, payable on demand or within a time not exceeding one year from date of issue, to other than associated companies.
This account shall include all amounts payable by the utility within one year, which are not provided for in other accounts.
These accounts shall include amounts owing to associated companies on notes, drafts, acceptances, or other similar evidences of indebtedness, and open accounts payable on demand or not more than one year from date of issue or creation.
Exclude from these accounts notes and accounts which are includible in account 223, Advances from Associated Companies.
This account shall include all amounts deposited with the utility by customers as security for the payment of bills.
A. This account shall be credited with the amount of taxes accrued during the accounting period, corresponding debits being made to the appropriate accounts for tax charges. Such credits may be based upon estimates, but from time to time during the year as the facts become known, the amount of the periodic credits shall be adjusted so as to include as nearly as can be determined in each year the taxes applicable thereto. Any amount representing a prepayment of taxes applicable to the period subsequent to the date of the balance sheet, shall be shown under account 165, Prepayments.
B. If accruals for taxes are found to be insufficient or excessive, correction therefor shall be made through current tax accruals.
C. Accruals for taxes shall be based upon the net amounts payable after credit for any discounts, and shall not include any amounts for interest on tax deficiencies or refunds. Interest received on refunds shall be credited to account 419, Interest and Dividend Income, and interest paid on deficiencies shall be charged to account 431, Other Interest Expense.
D. The records supporting the entries to this account shall be kept so as to show for each class of taxes, the amount accrued, the basis for the accrual, the accounts to which charged, and the amount of tax paid.
This account shall include the amount of interest accrued but not matured on all liabilities of the utility not including, however, interest which is added to the principal of the debt on which incurred. Supporting records shall be maintained so as to show the amount of interest accrued on each obligation.
This account shall include the amount of dividends which have been declared but not paid. Dividends shall be credited to this account when they become a liability.
This account shall include the amount of long-term debt (including any obligation for premiums) matured and unpaid, without specific agreement for extension of the time of payment and bonds called for redemption but not presented.
This account shall include the amount of matured interest on long-term debt or other obligations of the utility at the date of the balance sheet unless such interest is added to the principal of the debt on which incurred.
This account shall include the amount of taxes collected by the utility through payroll deductions or otherwise pending transmittal of such taxes to the proper taxing authority.
Do not include liability for taxes assessed directly against the utility which are accounted for as part of the utility’s own tax expense.
A. This account shall include the amount of all other current and accrued liabilities not provided for elsewhere appropriately designated and supported as to show the nature of each liability.
B. The utility is to include in a separate subaccount amounts payable for gas in unbalanced transactions where gas is received from another party in exchange, load balancing, or no-notice transportation transactions. (See Account 806.) If the amount payable is settled by other than gas, Account 495, Other Gas Revenues, must be credited or Account 813, Other gas supply expenses, charged for the difference between the amount of the consideration paid and the recorded amount of the payable settled. Records are to be maintained so that there is readily available for each party entering gas exchange, load balancing, or no-notice transportation transactions, the quantity and cost of gas received and the amount and basis of consideration paid if other than gas.
This account shall include the portion due within one year, of the obligations recorded for the amounts applicable to leased property recorded as assets in account 101.1, Property under Capital Leases, or account 121, Non-Utility Property.
This account shall include the change in the fair value of all derivative instrument liabilities not designated as cash flow or fair value hedges. Account 426.5, other deductions, shall be debited or credited as appropriate with the corresponding amount of the change in the fair value of the derivative instrument.
A. This account shall include the change in the fair value of derivative instrument liabilities designated by the utility as cash flow or fair value hedges.
B. A utility shall record the change in the fair value of a derivative liability related to a cash flow hedge in this account, with a concurrent charge to account 219, accumulated other comprehensive income, with the effective portion of the derivative gain or loss. The ineffective portion of the cash flow hedge shall be charged to the same income or expense account that will be charged when the hedged item enters into the determination of net income.
C. A utility shall record the change in the fair value of a derivative instrument liability related to a fair value hedge in this account, with a concurrent charge to a subaccount of the asset or liability that carries the item being hedged. The ineffective portion of the fair value hedge shall be charged to the same income or expense account that will be charged when the hedged item enters into the determination of net income.
This account shall include advances by customers for construction which are to be refunded either wholly or in part. When a customer is refunded the entire amount to which he is entitled, according to the agreement or rule under which the advance was made, the balance, if any, remaining in this account shall be credited to the respective plant account.
This account shall include advance billings and receipts and other deferred credit items, not provided for elsewhere, including amounts which cannot be entirely cleared or disposed of until additional information has been received.
A. This account shall include the amounts of regulatory liabilities, not includible in other accounts, imposed on the utility by the ratemaking actions of regulatory agencies. (See Definition No. 30.)
B. The amounts included in this account are to be established by those credits which would have been included in net income, or accumulated other comprehensive income, determinations in the current period under the general requirements of the Uniform System of Accounts but for it being probable that: Such items will be included in a different period(s) for purposes of developing the rates that the utility is authorized to charge for its utility services; or refunds to customers, not provided for in other accounts, will be required. When specific identification of the particular source of the regulatory liability cannot be made or when the liability arises from revenues collected pursuant to tariffs on file at a regulatory agency, account 407.3, regulatory debits, shall be debited. The amounts recorded in this account generally are to be credited to the same account that would have been credited if included in income when earned except: All regulatory liabilities established through the use of account 407.3 shall be credited to account 407.4, regulatory credits; and in the case of refunds, a cash account or other appropriate account should be credited when the obligation is satisfied.
C. If it is later determined that the amounts recorded in this account will not be returned to customers through rates or refunds, such amounts shall be credited to Account 421, Miscellaneous Nonoperating Income, or Account 434, Extraordinary Income, as appropriate, in the year such determination is made.
D. The records supporting the entries to this account shall be so kept that the utility can furnish full information as to the nature and amount of each regulatory liability included in this account, including justification for inclusion of such amounts in this account.
A. This account shall be credited with all investment tax credits deferred by companies which have elected to follow deferral accounting, partial or full, rather than recognizing in the income statement the total benefits of the tax credit as realized. After such election, a company may not transfer amounts from this account, except as authorized herein and in accounts 411.4, Investment Tax Credit Adjustments, Utility Operations, 411.5, Investment Tax Credit Adjustments, Nonutility Operations, and 420, Investment Tax Credits, or with approval of the Commission.
B. Where the company’s accounting provides that investment tax credits are to be passed on to customers, this account shall be debited and account 411.4 credited with a proportionate amount determined in relation to the average useful life of gas utility plant to which the tax credits relate to such lesser period of time as allowed by a regulatory agency having rate jurisdiction. If, however, the deferral procedure provides that investment tax credits are not to be passed on to customers the proportionate restorations to income shall be credited to account 420.
C. If any of the investment tax credits to be deferred are related to utility operations other than gas or to non- utility operations, appropriate subdivisions of this account shall be maintained. Contra entries affecting such subdivisions shall be appropriately recorded in accounts 413, Expenses of Gas Plant Leased to Others; or 414, Other Utility Operating Income.
D. Records shall be maintained identifying the properties related to the investment tax credits for each year, the weighted average service life of such properties, and any unused balance of such credits. Such records are not necessary unless the credits are deferred.
This account shall include gains from the sale or other disposition of property previously recorded in account 105, Gas Plant Held for Future Use and account 105.1, Production Properties Held for Future Use, under the provisions of paragraphs B, C, and D thereof, where such gains are significant and are to be amortized over a period of 5 years, unless otherwise authorized by the Commission. The amortization of the amounts in this account shall be made by credits to account 411.6, Gains from Disposition of Utility Plant. Subdivision of this account shall be maintained so that amounts relating to account 105, Gas Plant Held for Future Use and account 105.1, Production Properties Held for Future Use, can be readily identifiable. (See accounts 105, Gas Plant Held for Future Use and account 105.1, Production Properties Held for Future Use.)
This account shall include the amounts of discount realized upon reacquisition or redemption of long-term debt. The amounts in this account shall be amortized in accordance with General Instruction 17.
A. Before using the deferred tax accounts provided below refer to General Instruction 18. Comprehensive Interperiod Income Tax Allocation.
B. The text of these accounts are designed primarily to cover deferrals of Federal income taxes. However, they are also to be used when making deferrals of State and local income taxes. Natural gas companies which, in addition to a gas utility department, have another utility department, electric, water, etc., and nonutility property which have deferred taxes on income with respect thereto shall separately classify such deferrals in the accounts provided below so as to allow ready identification of items relating to each utility department and to Other Income and Deductions.
A. This account shall include tax deferrals resulting from adoption of the principles of comprehensive interperiod tax allocation described in General Instruction 18 of this system of accounts that relate to property for which the utility has availed itself of the use of accelerated (5-year) amortization of (1) certified defense facilities as permitted by Section 168 of the Internal Revenue Code and (2) certified pollution control facilities as permitted by Section 169 of the Internal Revenue Code.
B. This account shall be credited and accounts 410.1, Provision for Deferred Income Taxes, Utility Operating Income, or 410.2, Provision for Deferred Income Taxes, Other Income and Deductions, as appropriate, shall be debited with tax effects related to property described in paragraph A above where taxable income is lower than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
C. This account shall be debited and accounts 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, or 411.2, Provision for Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited with tax effects related to property described in paragraph A above where taxable income is higher than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
D. The utility is restricted in its use of this account to the purposes set forth above. It shall not transfer the balance in this account or any portion thereof to retained earnings or make any use thereof except as provided in the text of this account without prior approval of the Commission. Upon the disposition by sale, exchange, transfer, abandonment or premature retirement of plant on which there is a related balance herein, this account shall be charged with an amount equal to the related income tax expense, if any, arising from such disposition and account 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, or 411.2, Provision for Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited. When the remaining balance, after consideration of any related income tax expense, is less than $25,000, this account shall be charged and account 411.1 or 411.2, as appropriate, credited with such balance. If after consideration of any related income tax expense, there is a remaining amount of $25,000 or more, the Commission shall authorize or direct how such amount shall be accounted for at the time approval for the disposition of accounting is granted. When plant is disposed of by transfer to a wholly owned subsidiary the related balance in this account shall also be transferred. When the disposition relates to retirement of an item or items under a group method of depreciation where there is no tax effect in the year of retirement, no entries are required in this account if it can be determined that the related balances would be necessary to be retained to offset future group item tax deficiencies.
A. This account shall include the tax deferrals resulting from adoption of the principle of comprehensive interperiod income tax allocation described in General Instruction 18 of this system of accounts which are related to all property other than accelerated amortization property.
B. This account shall be credited and accounts 410.1, Provision for Deferred Income Taxes, Utility Operating Income, or 410.2, Provision for Deferred Income Taxes, Other Income and Deductions, as appropriate, shall be debited with tax effects related to property described in paragraph A above where taxable income is lower than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
C. This account shall be debited and accounts 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, or 411.2, Provision for Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited with tax effects related to property described in paragraph A above where taxable income is higher than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
D. The utility is restricted in its use of this account to the purposes set forth above. It shall not transfer the balance in this account or any portion thereof to retained earnings or make any use thereof except as provided in the text of this account without prior approval of the Commission. Upon the disposition by sale, exchange, transfer, abandonment or premature retirement of plant on which there is a related balance herein, this account shall be charged with an amount equal to the related income tax expense, if any, arising from such disposition and account 411.1, Income Taxes Deferred in Prior Years—Credit, Utility Operating Income, or 411.2, Income Taxes Deferred in Prior Years—Credit, Other Income and Deductions, shall be credited. When the remaining balance, after consideration of any related tax expenses, is less than $25,000, this account shall be charged and account 411.1 or 411.2, as appropriate, credited with such balance. If after consideration of any related income tax expense, there is a remaining amount of $25,000 or more, the Commission shall authorize or direct how such amount shall be accounted for at the time approval for the disposition of accounting is granted. When plant disposed of by transfer to a wholly owned subsidiary, the related balance in this account shall also be transferred. When the disposition relates to retirement of an item or items under a group method of depreciation where there is no tax effect in the year of retirement, no entries are required in this account if it can be determined that the related balance would be necessary to be retained to offset future group item tax deficiencies.
A. This account shall include all credit tax deferrals resulting from the adoption of the principles of comprehensive interperiod income tax allocation described in General Instruction 18 of this system of accounts other than those deferrals which are includible in Accounts 281, Accumulated Deferred Income Taxes—Accelerated Amortization Property and 282, Accumulated Deferred Income Taxes—Other Property.
B. This account shall be credited and accounts 410.1 Provision for Deferred Income Taxes, Utility Operating Income, or 410.2, Provision for Deferred Income Taxes, Other Income and Deductions, as appropriate, shall be debited with tax effects related to items described in paragraph A above where taxable income is lower than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
C. This account shall be debited and accounts 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income or 411.2, Provision for Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate shall be credited with tax effects related to items described in paragraph A above where taxable income is higher than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
D. Records with respect to entries to this account, as described above, and the account balance, shall be so maintained as to show the factors of calculation with respect to each annual amount of the item or class of items.
E. The utility is restricted in its use of this account to the purposes set forth above. It shall not transfer the balance in the account or any portion thereof to retained earnings or to any other account or make any use thereof except as provided in the text of this account, without prior approval of the Commission. Upon the disposition by sale, exchange, transfer, abandonment or premature retirement of items on which there is a related balance herein, this account shall be charged with an amount equal to the related income tax effect, if any, arising from such disposition and account 411.1, Provision For Deferred Income Taxes—Credit, Utility Operating Income, or 411.2, Provision For Deferred Income Taxes—Credit, Other Income and Deductions, as appropriate, shall be credited. When the remaining balance, after consideration of any related tax expenses, is less than $25,000, this account shall be charged and account 411.1 or 411.2, as appropriate, credited with such balance. If after consideration of any related income tax expense, there is a remaining amount of $25,000 or more, the Commission shall authorize or direct how such amount shall be accounted for at the time approval for the disposition of accounting is granted.
This account shall include all fees paid to Federal or State governments for the privilege of incorporation and expenditures incident to organizing the corporation, partnership, or other enterprises and putting it into readiness to do business.
1. Cost of obtaining certificates authorizing an enterprise to engage in the public utility business.
2. Fees and expenses for incorporation.
3. Fees and expenses for mergers or consolidations.
4. Office expenses incident to organizing the utility.
5. Stock and minute books and corporate seal.
This account shall not include any discounts upon securities issued or assumed; nor shall it include any costs incident to negotiating loans, selling bonds or other evidences of debt, or expenses in connection with the authorization, issuance, or sale of capital stock.
Exclude from this account and include in the appropriate expense account the cost of preparing and filing papers in connection with the extension of the term of incorporation unless the first organization costs have been written off. When charges are made to this account for expenses incurred in mergers, consolidations, or reorganizations, amounts previously included herein or in similar accounts in the books of the companies concerned shall be excluded from this account.
A. This account shall include amounts paid to the Federal Government, to a State or to a political subdivision thereof in consideration for franchises, consents, or certificates, running in perpetuity or for a specified term of more than 1 year, together with necessary and reasonable expenses incident to procuring such franchises, consents, or certificates of permission and approval, including expenses of organizing and merging separate corporations, where statutes require, solely for the purpose of acquiring franchises.
B. If a franchise, consent, or certificate is acquired by assignment, the charge to this account in respect thereof shall not exceed the amount paid therefor by the utility to the assignor, nor shall it exceed the amount paid by the original grantee, plus the expense of acquisition to such grantee. Any excess of the amount actually paid by the utility over the amount above specified shall be charged to account 426.5, Other Deductions.
C. When any franchise has expired, the book cost thereof shall be credited hereto and charged to account 426.5, Other Deductions, or to account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant, as appropriate.
D. Records supporting this account shall be kept so as to show separately the book cost of each franchise or consent.
Annual or other periodic payments under franchises shall not be included herein but in the appropriate operating expense account.
A. This account shall include the cost of patent rights, licenses, privileges, and other intangible property necessary or valuable in the conduct of the utility’s gas operations and not specifically chargeable to any other account.
B. When any item included in this account is retired or expires, the book cost thereof shall be credited hereto and charged to account 426.5, Other Deductions, or account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant, as appropriate.
C. This account shall be maintained in such a manner that the utility can furnish full information with respect to the amounts included herein.
This account shall include the cost of land and land rights used in connection with manufactured gas production. (See gas plant instruction 7.)
This account shall include the cost of structures and improvements used in connection with manufactured gas production. (See gas plant instruction 8.)
Include relief holders in this account.
This account shall include the cost installed of furnaces, boilers, steam and feed water piping, boiler apparatus, and accessories used in the production of steam at gas production plants.
1. Accumulators.
2. Air preheaters, including fans and drives, and ducts not part of building.
3. Ash disposal equipment, including sluiceways not part of a building, pumps and piping, crane, ash bucket conveyor and drives, ash cars, etc.
4. Belt conveyors, including drives.
5. Blast gate valves.
6. Blow-down tanks and piping.
7. Boilers, including valves attached thereto, casings, safety valves, soot blowers, soot hoppers, superheaters, and feed water regulators.
8. Cinder and dust catcher system, including mechanical and electric types.
9. Coal and coke handling equipment, including hoppers, lorries, etc., used wholly for boilers.
10. Combustion control system, including all apparatus installed for the regulation and control of the supply of fuel or air to boilers.
11. Control apparatus.
12. Cranes, hoists, etc., wholly identified with apparatus listed herein.
13. Desuperheaters and reducing valves.
14. Draft apparatus, including forced, induced, and other draft systems, with blowers, fans, and ducts not part of building.
15. Economizers.
16. Emergency lighting systems, not part of building, keep-a-lite systems, etc.
17. Emergency signal systems, in connection with boiler operation.
18. Feed water heaters, including primary and stage.
19. Flues, uptakes, and breeching, whether or not stacks are included in this account.
20. Foundations and settings, specially constructed for and not intended to outlast the apparatus for which provided.
21. Furnaces.
22. Gas firing system, including gas lines, burners, etc., for gas fired boilers.
23. Injectors.
24. Mechanical stoker and feeding systems, clinker grinders, including drives.
25. Meters, gauges, recording instruments, etc.
26. Oil burning equipment, including tanks, heaters, pumps with drives, burner equipment, piping, and conditioning apparatus.
27. Painting, first cost.
28. Panels, control (for operating apparatus listed herein).
29. Piping system, steam header and exhaust header, including accessory pipe hangers, steam traps, etc., make-up water, feed water, drip, blow-off, water pipe lines used for steam plant, and valve control system.
30. Platforms, railings, steps, gratings, etc., appurtenant to apparatus listed herein.
31. Pulverizing equipment.
32. Pumps and driving units, for feed water, heater condensate, condenser water, and drip.
33. Stacks—brick, steel, and concrete, when set on separate foundations independent of substructure or superstructure of building.
34. Steam reheaters.
35. Steelwork, especially constructed for apparatus listed herein.
36. Tanks, including surge, weighing, return, blow-off, feed water storage.
37. Tar burning equipment for utilization of tar as boiler fuel, including tanks, pumps, burner equipment, piping, etc.
38. Waste heat boilers and accessories—stack valve and stack irrespective of location.
39. Water treatment system, including purifiers, settling tanks, filters, chemical mixing and dosing apparatus, etc.
This account shall not include boilers or steam pipes whose primary purpose is the heating of buildings.
When the system for supplying boiler or condenser water is elaborate, as when it includes a dam, reservoir, canal, or pipe line, the cost shall not be charged to this account but to a special subdivision of account 305, Structures and Improvements—Manufactured Gas.
A. This account shall include the cost installed of electric generating and accessory equipment used for supplying electricity in gas production plants.
B. This account shall also include the cost installed of miscellaneous power equipment at gas production plants which is not included in any other account.
1. Acid proofing of battery rooms.
2. Air duct runs in battery rooms.
3. Air pump, streamjet.
4. Batteries for control and general station use.
5. Belts, pulleys, hangers, shafts, and countershafts.
6. Cables between generators and switchboards.
7. Cabinets, control.
8. Compartments, including buses, connections, and items permanently attached.
9. Enclosure equipment not an integral part of building.
10. Engines, including steam rotary or reciprocating, steam turbines, and internal combustion engines.
11. Foundations and settings, specially constructed for and not intended to outlast the apparatus for which provided.
12. Generators, a.c. or d.c., including excitation system.
13. Ground connections, for main station ground.
14. Lightning arresters.
15. Motor generators, frequency changers and converters.
16. Overhead power lines, including poles, crossarms, insulators, conductors, etc.
17. Panels, control, including supports and instruments.
18. Piping applicable to apparatus listed herein.
19. Reactors.
20. Rectifiers.
21. Safety equipment, including rubber mats, remote closing devices, glove cabinets.
22. Switchboards, including frames, panels, meters, and instruments.
23. Switching equipment, including oil circuit breakers, disconnecting switches, and connections.
24. Synchronous converters.
25. Transformers, including transformer platforms.
26. Underground conduit system, including manholes and conductors.
When any unit of equipment listed herein is wholly used to furnish power to equipment included in another single account, its cost shall be included in such account.
This account shall include the cost installed of coke ovens used for the production of gas.
1. Apparatus for placing coal in ovens.
2. Bins, if not part of a building.
3. Cabinets, control.
4. Calorimeters.
5. Cars, quenching.
6. Charging lorry.
7. Clay mixers.
8. Coke guide.
9. Coke and pusher benches.
10. Collecting mains.
11. Control apparatus.
12. Conveyor, flight.
13. Cover lifting machinery.
14. Door handling machine.
15. Door luting machine.
16. Driving units for coke oven machinery.
17. Enclosures for machinery.
18. Engines, when not an integral part of the driven equipment.
19. Firing equipment.
20. Flues, uptakes, and breeching.
21. Foundations.
22. Fuel handling equipment used exclusively for coal to be carbonized in ovens.
23. Fuel systems under ovens.
24. Hot coke wharves.
25. Hot coke cars.
26. Instruments or meters, electrical.
27. Locomotives.
28. Mud mill.
29. Motor control equipment.
30. Ovens.
31. Panel, control.
32. Piping, including ascension pipes, hydraulic main, liquor flushing decanter tank, liquor pump, and return line to hydraulic main.
33. Pushers, including tracks and driving equipment.
34. Quenching station including structure, tank, well, piping, etc.
35. Quenching towers, piping, etc.
36. Regenerator, from bottom of oven floor tile to battery foundation.
37. Reversing machine, with enclosure.
38. Scale, platform.
39. Signal system.
40. Skip hoist.
41. Stacks.
42. Steel and iron work supports, platforms, stairways, etc.
43. Switches and switchboards.
This account shall include the cost installed of equipment used for the production of producer gas.
1. Ash handling equipment, used exclusively for producers.
2. Blast apparatus, including blowers, driving units, and blast mains.
3. Control apparatus.
4. Coolers and scrubbers.
5. Driving apparatus for producers.
6. Foundations and settings, specially constructed for and not intended to outlast the apparatus for which provided.
7. Fuel handling equipment, used exclusively for producers.
8. Humidifiers.
9. Piping—air, steam (commencing at steam header), water (inside of building), and producer gas (up to outlet of final piece of apparatus in building).
10. Producer boosters, including driving units.
11. Producers.
12. Water separators.
This account shall include the cost installed of equipment used in the generation of water gas.
1. Automatic operation equipment.
2. Back-run installations.
3. Blast equipment, including blowers and driving units, piping and supports.
4. Bridge, coal shed to generator house.
5. Carburetors.
6. Charging equipment, fuel.
7. Circulating water pumps.
8. Concrete or brick pits, including cover, not part of building.
9. Control apparatus.
10. Conveyors.
11. Dust collectors.
12. Enclosures for equipment (barriers, fire walls, guards, housings, screens, etc.).
13. Flow meters.
14. Foundations and settings, specially constructed for and not intended to outlast the apparatus for which provided.
15. Fuel handling equipment used exclusively for fuel for this account.
16. Gauges, indicating and recording.
17. Generators.
18. Hot valves.
19. Hydraulic operation equipment.
20. Instruments and meters, electrical.
21. Oil handling and storage apparatus used solely for water gas apparatus (tanks, pumps and oil lines, oil heaters, manholes, valve pits, regulators, strainers, etc.).
22. Oil spray.
23. Operating floors and supports, stairways, etc.
24. Piling under foundations.
25. Piping and valves—steam (commencing at steam header) tar (to decanter) water (inside of building), and gas up to outlet of final pieces of apparatus in building).
26. Pressure regulators.
27. Scales, when used in connection with items in this account.
28. Seal pots.
29. Superheaters and superheater stacks.
30. Tanks, hydraulic pressure.
31. Valve operating mechanisms.
32. Wash boxes.
A. This account shall include the cost installed of equipment used for the production of gas from petroleum derivatives, such as propane, butane, or gasoline.
B. Subdivisions of this account shall be maintained for each producing process for which this account is provided. A separate subaccount shall be maintained also for bottling equipment included herein.
1. Blowers.
2. Boilers.
3. Calorimixer.
4. Carbureting equipment.
5. Compression equipment.
6. Controller.
7. Control apparatus.
8. Enclosures and protective fences.
9. Foundations and settings, specially constructed for and not intended to outlast the apparatus for which provided.
10. Heat exchanger.
11. Gauges and instruments.
12. Mixing or proportioning equipment.
13. Motors, not an integral part of driven equipment.
14. Odorizing equipment.
15. Oil separator.
16. Piping—steam (commencing at steam header), water (inside of building), oil (from supply tank), and gas (up to outlet of final piece of apparatus in building).
17. Pits.
18. Prime movers.
19. Pumps, including driving units.
20. Regulator.
21. Stairs, platforms, and ladders.
22. Storage equipment, tanks, etc.
23. Superheater.
24. Traps.
25. Valves—regulating and check.
26. Vaporizing equipment.
This account shall include the cost installed of equipment used for generating oil gas.
1. Air blast equipment, including blowers and driving units, piping and supports.
2. Air inlet louvres and filters.
3. Foundations and settings, specially constructed for and not intended to outlast the apparatus for which provided.
4. Generating equipment, including automatic cycle controls, generators, operating floor, superheaters and wash boxes.
5. Instruments and instrument boards, complete with signal lights and thermocouples and including gauge board, pressure gauges, and pyrometers.
6. Meters and regulators, such as, air flow meter, generator oil meter, steam flow meter, and steam regulator.
7. Piping and valves, air, steam (commencing at steam header), water (inside building), and oil gas (up to outlet of final piece of apparatus in building).
8. Pumps, hydraulic and oil.
9. Tanks, hydraulic accumulator, hydraulic return, oil and steam accumulator.
This account shall include, with subdivisions for each type of gas produced, the cost installed of generating equipment which is not included in any of the foregoing accounts, such as benches and retorts for the production of coal gas, equipment used for generating acetylene gas, etc.
As to coal gas production equipment:
1. Benches.
2. Charging and drawing machines.
3. Control apparatus.
4. Equipment for steaming retorts.
5. Flues, uptakes and breeching, whether or not stacks are included in this account.
6. Foundations.
7. Fuel handling equipment used exclusively for retorts, including weight lorries, tracks, etc., and grinders, breakers, and screens located in retort house.
8. Fuel system under retorts, including built-in producers.
9. Piping, including ascension pipes, hydraulic main, liquor flushing decanter tank. liquor pump, and return line to hydraulic main.
10. Primary atmospheric condensers.
11. Retorts.
12. Stacks—brick, steel, and concrete when set on separate foundations independent of substructure or superstructure of buildings, including lightning arresters.
This account shall include the cost installed of structures or equipment used for the transportation, storage, washing, and treatment of coal, coke, and ashes, when used for general gas plant operations.
1. Bins—mixing, refuse, storage, etc.
2. Boom operating mechanism.
3. Breaker equipment.
4. Bridges, bridge track, and machinery.
5. Bucket conveyors and supports.
6. Capstan.
7. Cars.
8. Chutes.
9. Circuit breakers.
10. Coal loaders.
11. Coal preparation machinery, including washing and drying equipment.
12. Conduit, electrical.
13. Conveyors and supports.
14. Crane, caterpillar.
15. Driving apparatus for equipment listed herein.
16. Elevators.
17. Enclosure equipment.
18. Engines, not an integral part of driven equipment.
19. Foundations and settings, specially constructed for and not intended to outlast the apparatus for which provided.
20. Gravity swing unloader.
21. Hoppers.
22. Instruments or meters, electrical.
23. Ladders, fixed.
24. Loading towers and equipment.
25. Locomotives.
26. Motor generators used only for equipment in this account.
27. Panel, control.
28. Pitts.
29. Pulverizing equipment.
30. Railroad sidings and yard tracks.
31. Sampling equipment.
32. Scales.
33. Screens.
34. Sheds and fencing.
35. Shuttle boom.
36. Signal system equipment.
37. Silo.
38. Skip hoist.
39. Stairs, railings, etc.
40. Transfer cars and trucks.
41. Trestles.
42. Turntable.
43. Unloaders.
44. Weightometer.
This account shall include the cost installed of equipment used for producing gas by the catalytic cracking process.
1. Caloric meters.
2. Catalytic furnace, including catalyst and foundation.
3. Combustion air blowers.
4. Compressors, air.
5. Control equipment.
6. Cooling coils, including foundations.
7. Cooling towers, including foundations.
8. Enclosures.
9. Fractionalizing units.
10. Piping and valves.
11. Preheaters.
12. Pressure regulators.
13. Proportioning controls.
14. Tanks.
15. Vaporizers.
This account shall include the cost installed of equipment, other than catalytic cracking equipment, used primarily for reforming gas with resultant changes in its chemical composition and calorific value.
1. Blast equipment, including blowers and driving units, piping, and supports.
2. Control apparatus.
3. Foundations and settings, specially constructed for and not intended to outlast the apparatus for which provided.
4. Fuel and ash handling equipment, used wholly in reforming gas.
5. Oil gas apparatus, used for reforming gas.
6. Piping—steam (commencing at steam header), water (inside of building), and gas (up to outlet of final piece of apparatus in building).
7. Pumps and driving units.
8. Purifiers for gas to be reformed.
9. Regulators.
10. Water gas generators, used primarily for reforming gas.
This account shall include the cost installed of apparatus used for the removal of impurities from gas and apparatus for conditioning gas, including pumps, wells, and other accessory apparatus.
1. Blowers for revivifying.
2. Blowers for activators.
3. Condensers and washer coolers.
4. Control apparatus—conduit, cable, cabinets, switchboards, etc.
5. Crane or cover lifting equipment, not part of the structure.
6. Dehydrators.
7. Engines, not an integral part of driven equipment.
8. Foundations and settings, specially constructed for and not intended to outlast the equipment for which provided.
9. Instruments and meters, electric.
10. Lubricators.
11. Naphthalene and light oil scrubbers.
12. Other accessory equipment such as coolers, spray ponds, pumps, platforms, railings, stairs.
13. Oxide elevators and pits, platforms, tables, and trenches.
14. Piping—air, steam, water, gas, condensate, liquor, tar, etc., from inlet valve of first piece of apparatus to outlet valve of final piece of apparatus (or, in building, from entrance to building to exit from building).
15. Precipitators.
16. Purifiers—iron oxide or liquid, including first filling.
17. Recording gauges and thermometers.
18. Revivifying air ducts.
19. Saturator with auxiliary equipment.
20. Scrubbers.
21. Seal and drip pots.
22. Signal system identified with equipment herein.
23. Sulphur removal apparatus.
24. Tar extractors and Cottrell precipitators.
25. Tar pumps and tanks.
26. Track runs for cranes and hoists.
27. Wash boxes.
28. Water meters, for cooling water.
This account shall include the cost installed of apparatus used in refining and handling of residuals except where the apparatus is necessary for the operation of property included in account 317, Purification Equipment.
1. Ammonia stills, condensers, saturators, etc.
2. Apparatus for removal of residuals from purifier liquids.
3. Coke filter.
4. Coke handling and storage facilities used solely for coke held for sale.
5. Condensers.
6. Control apparatus.
7. Coolers.
8. Decanters.
9. Foundations specially constructed for and not intended to outlast the apparatus for which provided.
10. Gauges.
11. Heating equipment for apparatus included in this account.
12. Instruments.
13. Light oil stills, washers, etc.
14. Piping and pumps.
15. Platforms, stairs, and ladders.
16. Separators.
17. Storage tanks.
18. Supports.
19. Tar dehydrators, stills, etc.
This account shall include the cost installed of equipment used for mixing manufactured and natural gas, or the mixing of other gases incident to delivery of such mixed gases to the distribution system.
1. Alcohol units.
2. Automatic mixing controls.
3. Btu adjustor.
4. Calorimeter.
5. Calorimixer.
6. Compressor.
7. Gas heater.
8. Gas scrubber (air filter, dust cleaner).
9. Gauges and instruments.
10. Meters.
11. Mixing chambers.
12. Odorizing equipment.
13. Oil pump units.
14. Panel and control equipment.
15. Piping and valves.
16. Regulators, pressure and ratio.
17. Safety alarm equipment.
This account shall include the cost installed of equipment used in the production of gas, when not assignable to any of the foregoing accounts.
1. Cabinet, control.
2. Compressed air system.
3. Fire hose carts.
4. First aid room equipment.
5. Foamite system.
6. Foundations and settings specially constructed for and not intended to outlast the apparatus for which provided.
7. Gasoline pumps.
8. Hand pumps.
9. Machine shop equipment, such as lathes, pipe cutting and threading machines, vise grinders, power saw, shop motors, shafting and belting, drill press, shapers, milling machines, planes, etc.
10. Odorizing equipment.
11. Office furniture and equipment.
12. Oil foggers.
13. Panel, control.
14. Piping—yard, when not includible in other accounts.
15. Pits.
16. Platforms.
17. Portable scaffolds, ladders, etc.
18. Power shovels.
19. Production laboratory equipment.
20. Scales, not associated with other equipment.
21. Special signal equipment.
22. Tractors for general plant use.
23. Works exhauster including driving unit and governor.
24. Works station meters, including gauges, piping and accessories.
The net book value of amounts recorded in the natural gas production accounts incurred on or related to leases acquired after October 7, 1969, shall, in general, not exceed the net realizable value (estimated selling price less estimated costs of extraction, completion, and disposal) of recoverable hydrocarbon reserves discovered on such leases. After initiation of exploration and development on leases acquired after October 7, 1969, the utility must determine after a reasonable period of time, and annually thereafter, whether the net realizable value of such recoverable reserves will be sufficient to absorb the net book value of amounts recorded in the accounts. The recoverable reserves shall be determined and attested to by independent appraisers no less frequently than every 3 years. If the net realizable value of recoverable reserves is not sufficient to absorb the net book value of amounts in the production accounts, the utility shall reduce the net book value of the amounts in the accounts to net realizable value of recoverable reserves. The reduction shall be done by first reducing the unamortized amounts recorded in Account 338, Unsuccessful Exploration and Development Costs, by debiting Account 404.1, Amortization and Depletion of Producing Natural Gas Land and Land Rights (for Nonmajor companies, 403.1, Depreciation and Depletion Expense). Next, if the net book value related to successful costs exceeds the net realizable value of the recoverable reserves, the production plant accounts shall be written down to such net realizable value by appropriate charges and credits to the expense and valuation accounts.
This account shall include asset retirement costs on plant included in the manufactured gas production plant function.
This account shall include the cost of lands held in fee on which producing natural gas wells are located, and lands held in fee which are being drained of natural gas through the operation by the utility of wells on other land. (See gas plant instruction 7–G.)
A. This account shall include the cost of acquiring leaseholds on which the utility pays royalties for natural gas obtained therefrom. (See gas plant instruction 7–G.)
B. Exclude from this account rents paid periodically for rights obtained under leases. Exclude also from this account the cost of leaseholds which terminate in one year or less after they become effective.
This account shall include the cost of natural gas rights used in producing natural gas, whereby the utility obtains ownership in gas underlying land not owned or leased by the utility. It does not provide for gas rights which are leased and which are properly chargeable to account 325.2, Producing Leaseholds.
This account shall include the cost of all interests in land which terminate more than 1 year after they become effective and on which are located gathering pipelines, telephone pole lines, and like property used in connection with the production of natural gas. (See gas plant instruction 7.)
This account shall include the cost of land and land rights used in connection with the production of natural gas, when not properly assignable to any of the foregoing accounts. (See gas plant instruction 7.)
This account shall include the cost of well structures and improvements used in connection with the housing of permanent bailers and other equipment necessary to keep the wells in operation. (See gas plant instruction 8.)
This account shall include the cost of structures and improvements used in connection with the housing of compressor station equipment used to raise the pressure of natural gas before it is conveyed to the terminus of the field lines. (See gas plant instruction 8.)
This account shall include the cost of structures and improvements used in connection with the housing of meters, regulators, and appurtenant appliances for measuring and regulating natural gas before the point where it enters the transmission or distribution system. (See gas plant instruction 8.)
This account shall include the cost of structures and improvements used in connection with natural gas production and gathering not provided for elsewhere. (See gas plant instruction 8.)
This account shall include the cost of drilling producing gas wells.
1. Clearing well site.
2. Hauling, erecting, dismantling, and removing boilers, portable engines, derricks, rigs, and other equipment and tools used in drilling.
3. Drilling contractors’ charges.
4. Drive pipe.
5. Fuel or power.
6. Labor.
7. Rent of drilling equipment.
8. Water used in drilling, obtained either by driving wells, piping from springs or streams, or by purchase.
9. Hauling well equipment.
10. Shooting, fracturing, acidizing.
This account shall include the cost of equipment in producing gas wells.
1. Bailing equipment.
2. Boilers and drives permanently connected.
3. Casing.
4. Derrick.
5. Fence, when solely an enclosure for equipment.
6. Fittings, including shut-in valves, bradenheads and casing heads.
7. Packing.
8. Tank, oil or water, etc.
9. Tubing.
This account shall include the cost installed of field lines used in conveying natural gas from the wells to the point where it enters the transmission or distribution system.
1. Gathering lines, including pipe, valves, fittings, and supports.
2. Cathodic protection equipment.
3. Creek crossings, suspension bridges and other special construction.
4. Line drips and separators.
5. Line pack gas.
This account shall include the cost installed of compressor station equipment and associated appliances used to raise the pressure of natural gas before it is conveyed to the terminus of the field lines.
1. Boiler plant, coal handling and ash handling equipment for steam powered compressor station.
2. Compressed air system equipment.
3. Compressor equipment and driving units, including auxiliaries, foundations, guard rails and enclosures, etc.
4. Electric system equipment, including generating equipment and driving units, power wiring, transformers, regulators, battery equipment, switchboard, etc.
5. Fire fighting equipment.
6. Gas lines and equipment, including fuel supply lines, cooling tower and pond and associated equipment, dehydrators, fuel gas mixers, special pipe bends and connections, and associated scrubbers, separators, tanks, gauges and instruments.
7. Laboratory and testing equipment.
8. Lubricating oil system, including centrifuge, filter, tanks, purifier, and lubricating oil piping, etc.
9. Office furniture and fixtures and general equipment such as heating boilers, steel lockers, first-aid equipment, gasoline dispensing equipment, lawn mowers, incinerators, etc.
10. Shop tools and equipment.
11. Water supply and circulation system, including water well, tank, water piping, cooling tower, spray fence, and water treatment equipment, etc., but not including water system equipment solely for domestic and general use.
This account shall include the cost installed of meters, gauges, and other equipment used in measuring and regulating natural gas collected in field lines before the point where it enters the transmission or distribution system.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundations, pits, etc.
4. Gas cleaners, scrubbers, separators, dehydrators, etc.
5. Gauges and instruments, including piping, fittings, wiring, etc., and panel boards.
6. Headers.
7. Meters, orifice or positive, including piping and connections.
8. Oil fogging equipment.
9. Odorizing equipment.
10. Regulators or governors, including controls and instruments.
11. Structures of a minor nature or portable type.
This account shall include the cost of implements and equipment used in drilling and cleaning natural gas wells.
1. Bailers.
2. Bits and other drilling tools.
3. Boilers.
4. Derricks.
5. Drilling cables.
6. Drilling machines.
7. Engines.
8. Motors.
9. Pulling machines.
10. Pumps.
11. Rigs.
12. Tanks.
This account shall include the cost installed of apparatus used for the removal of impurities from gas and apparatus for conditioning gas.
1. Condensers and washer coolers.
2. Dehydrators.
3. Foundations and settings, specially constructed for and not intended to outlast the equipment for which provided.
4. Other accessory equipment, such as coolers, spray ponds, pumps, platforms, railings, stairs.
5. Piping, from inlet valve of first piece of apparatus to outlet valve of final piece of apparatus (or, in building, from entrance to building to exit from building).
6. Scrubbers.
7. Sulphur removal apparatus.
8. Water supply system.
In general this account shall include all dehydrators located in or adjacent to production areas which are used to remove water and other stray liquids from gas produced by the utility or purchased in or adjacent to production areas. In some instances such dehydrators may be located some distance from the production sources of the gas. Where, however, the utility has no production and gathering facilities with respect to any of the gas passing through the dehydrators, such as at the purchase point at the head of a transmission pipe line company, the dehydrators may be included in account 368, Compressor Station Equipment, or account 367, Mains, whichever is the most practicable and reasonable under the circumstances. Dehydrators which are an adjunct to products extraction operations shall be included in account 342, Extraction and Refining Equipment. Dehydrators used in connection with underground gas storage operations shall be included in account 356, Purification Equipment.
This account shall include the cost installed of equipment used in the production and gathering of natural gas, when not assignable to any of the foregoing accounts.
1. Calorimeter.
2. Control installation.
3. Crane.
4. Laboratory equipment.
5. Odorizing unit.
6. Office furniture and equipment.
7. Oil fogger.
A. This account shall include unsuccessful exploration and development costs incurred on or related to hydrocarbon leases, on properties in the contiguous 48 States and the State of Alaska, acquired after October 7, 1969. It shall also include costs of a preliminary nature incurred in the search for natural gas in such areas after October 7, 1969.
B. The costs recorded in this account shall be amortized by debiting account 404.1, Amortization and Depletion of Producing Natural Gas Land and Land Rights, and crediting this account using the unit-of-production or other acceptable method of amortization as hydrocarbons are extracted from producing wells.
C. In general, the unamortized costs recorded in this account shall not exceed the net realizable value (estimated selling price less estimated costs of extraction, completion and disposal) of proven hydrocarbon reserves on leases acquired after October 7, 1969. (See “Special Instructions—Costs Related to Leases Acquired After October 7, 1969,” above.)
This account shall include asset retirement costs on plant included in the natural gas production and gathering plant function.
This account shall include the cost of land and land rights used in connection with the processing of natural gas for removal of gasoline, butane, propane, or other salable products. (See gas plant instruction 7.)
This account shall include the cost of structures and improvements used in connection with the processing of natural gas for removal of gasoline, butane, propane, or other salable products. (See gas plant instruction 8.)
This account shall include the cost installed of equipment used for the extraction from natural gas of gasoline, butane, propane, or other salable products and for the refining of such products.
1. Boiler plant equipment, including boiler, boiler setting, heat exchangers, etc.
2. Compressed air system, including air compressor, air storage tank, etc.
3. Cooling equipment such as coolers, cooling tower and accessories for gas, extracted products, etc.
4. Cranes, trolleys, and hoists.
5. Electrical system, including generator and driving unit, power lines, transformers, switchboard, yard lighting system, etc.
6. Extraction and refining equipment, such as absorbers, reabsorbers, stills, dephlegmators, fractionating towers, stabilizing columns, control apparatus.
7. Foundations and structural supports for equipment items not intended to outlast the equipment for which provided.
8. Fuel regulating and measuring equipment.
9. Gasoline blending equipment including dye pot, educator pumps, lead storage tanks, weighing device, etc.
10. Gauges and instruments.
11. Loading racks and associated other equipment.
12. Lubricating oil system.
13. Pumps of various types, such as boiler feed water pumps, loading and transfer pumps, drip still pumps, oil pumps, skimmer basin pumps, etc.
14. Tanks of various types such as accumulator and dewatering tanks, separator tanks, gasoline feed tanks, compressed air tanks, oil surge tanks, etc., except tanks classifiable as storage equipment, account 344.
15. Water supply system including water well, water tank and supports, water softener or purification apparatus, traveling water screen and drive.
16. Yard piping, gas, water, steam, compressed air, fuel, vapor, extracted products, including headers, valves, etc., but not including off-site lines includible in account 343, Pipe Lines.
This account shall include the cost installed of gas and liquids pipe lines used in connection with the processing of natural gas for the removal of gasoline, butane, propane, or other salable products, exclusive of runs of pipe appropriately includible in other equipment accounts, embracing principally off-site gas, gasoline gathering, and loading lines not includible as yard piping in account 342, Extraction and Refining Equipment.
1. Gas lines, off-site, relating solely to extraction operations.
2. Gasoline gathering lines connecting with off-site sources.
3. Gathering line drips.
4. Instruments, indicating and recording.
5. Loading lines connecting with remote off-site loading racks or storage facilities.
6. Pumps and driving units.
This account shall include the cost installed of storage tanks and associated equipment used in the storing, prior to sale, of gasoline, butane, propane, and other salable products extracted from natural gas.
1. Foundations.
2. Instruments.
3. Regulators.
4. Storage tanks for partially or fully processed products.
5. Valves.
This account shall include the cost installed of compressor equipment and associated appliances used in connection with the receipt, processing, and return of natural gas processed for removal of gasoline, butane, propane, or other salable products.
(See account 333 for items.)
This account shall include the cost installed of meters, gauges, and other equipment used in measuring or regulating natural gas received and/or returned from processing for removal of gasoline, butane, propane, or other salable products.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundations, pits, etc.
4. Gas cleaners, scrubbers, separators, dehydrators, etc.
5. Gauges and instruments, including piping, fittings, wiring, etc., and panel boards.
6. Headers.
7. Meters, orifice or positive, including piping and connections.
8. Oil fogging equipment.
9. Odorizing equipment.
10. Regulators or governors, including controls and instruments.
11. Structures of a minor nature or portable type.
This account shall include the cost installed of equipment used in processing natural gas and refining gasoline, butane, propane, and other salable products extracted from natural gas, when not assignable to any of the foregoing accounts.
1. Fire fighting equipment.
2. Laboratory and testing equipment.
3. Miscellaneous equipment, such as first-aid cabinet, gasoline dispensing pump, heating boiler, incinerator, lawn mower, warehouse truck.
4. Office furniture and equipment.
5. Shop tools and equipment.
The above accounts are to be used by the transmission and distribution companies for the classification of storage facilities used for peak shaving operations. The accounts shall be subdivided to classify the peak shaving storage facilities according to the transmission or distribution function, if the utility operates both transmission and distribution systems. Only base load liquefied natural gas terminaling and processing facilities are to be classified in accounts 364.1 through 364.8.
This account shall include asset retirement costs on plant included in the products extraction plant function.
This account shall include the cost of lands held in fee on which underground storage wells are located, and other lands held in fee within an area utilized for the underground storage of gas. (See gas plant instruction 7–G.)
This account shall include the cost of all interests in land which do not terminate until more than 1 year after they become effective and on which are located underground storage lines, telephone poles lines, and like property used in connection with underground gas storage operations. (See gas plant instruction 7.)
A. This account shall include the cost in place of structures and improvements used wholly or predominantly in connection with underground storage of natural gas. (See gas plant instruction 8.)
B. This account shall be subdivided as follows:
This account shall include the drilling cost of wells used for injection and withdrawal of gas from underground storage projects, including wells kept open and used for observation.
1. Clearing well site.
2. Hauling, erecting, dismantling, and removing boilers, portable engines, derricks, rigs, and other equipment and tools used in drilling.
3. Drilling contractors’ charges.
4. Drive pipe.
5. Fuel or power.
6. Labor.
7. Rent of drilling equipment.
8. Water used in drilling, obtained either by driving wells, piping from springs or streams, or by purchase.
9. Hauling well equipment.
10. Shooting, fracturing, acidizing.
11. Bailing equipment.
12. Boilers and drives permanently connected.
13. Casing.
14. Derrick.
15. Fence, when solely an enclosure for equipment.
16. Fittings, including shut-in valves, bradenheads and casing heads.
17. Packing.
18. Tank, oil or water, etc.
19. Tubing.
A. This account shall include the cost of leaseholds, storage rights, mineral deeds, etc. on lands for the purpose of utilizing subsurface reservoirs for underground gas storage operations. (See gas plant instruction 7–G.)
B. Exclude from this account rents or other charges paid periodically for use of subsurface reservoirs for underground gas storage purposes.
Items such as buildings, wells, lines, equipment and recoverable gas used in storage operations acquired with land or storage leaseholds and rights are to be classified in the appropriate accounts.
This account shall include costs to prepare underground reservoirs for the storage of natural gas.
1. Geological, geophysical and seismic costs.
2. Plugging abandoned wells.
3. Fuel and power.
4. Drilling and equipping fresh water wells, disposal wells, and solution wells.
5. Leaching of salt dome caverns.
6. Rentals on storage rights and leases incurred during construction and development period.
7. Gas used during the development period.
8. Costs incident to maintaining covenants of production leaseholds during the period required to convert them to storage leaseholds.
9. Other rehabilitation work.
A. This account shall include the cost of gas in underground reservoirs, including depleted gas or oil fields and other underground caverns or reservoirs used for the storage of gas which will not be recoverable.
B. Such nonrecoverable gas shall be priced at cost according to generally accepted methods of cost determination consistently applied. (See the Special Instructions to Accounts 117.1, 117.2, and 117.3.
This account shall include the cost installed of gas pipe lines used wholly or predominantly for conveying gas from point of connection with transmission or field lines to underground storage wells and from underground storage wells to the point where the gas enters the transmission or distribution system.
1. Cathodic protection equipment.
2. Creek crossings, suspension bridges and other special construction.
3. Lines, including pipe, valves, fittings, and supports.
4. Line drips and separators.
5. Line pack gas.
This account shall include the cost installed of compressor station equipment used wholly or predominantly for the purpose of raising the pressure of gas for delivery to underground storage or to raise the pressure of gas withdrawn from underground storage for delivery to the transmission or distribution system.
1. Boiler plant, coal handling and ash handling equipment for steam powered compressor station.
2. Compressed air system equipment.
3. Compressor equipment and driving units, including auxiliaries, foundations, guard rails and enclosures, etc.
4. Electric system equipment, including generating equipment and driving units, power wiring, transformers, regulators, battery equipment, switchboard, etc.
5. Fire fighting equipment.
6. Gas lines and equipment, including fuel supply lines, cooling tower and pond and associated equipment, dehydrators, fuel gas mixers, special pipe bends and connections, and associated scrubbers, separators, tanks, gauges and instruments.
7. Laboratory and testing equipment.
8. Lubricating oil system, including centrifuge, filter, tanks, purifier, and lubricating oil piping, etc.
9. Office furniture and fixtures and general equipment such as steel lockers, first-aid equipment, gasoline dispensing equipment, lawn mowers, incinerators, etc.
10. Shop tools and equipment.
11. Water supply and circulation system, including water well, tank, water piping, cooling tower, spray fence, and water treatment equipment, etc., but not including water system equipment solely for domestic and general use.
This account shall include the cost installed if equipment used wholly or predominantly for the purpose of measuring and regulating deliveries of gas to underground storage and withdrawals of gas from underground storage.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundations, pits, etc.
4. Gas cleaners, scrubbers, separators, dehydrators, etc.
5. Gauges and instruments, including piping, fittings, wiring, etc., and panel boards.
6. Headers.
7. Meters, orifice or positive, including piping and connections.
8. Oil fogging equipment.
9. Odorizing equipment.
10. Regulators or governors, including controls and instruments.
11. Structures of a minor nature or portable type.
This account shall include the cost installed of apparatus used wholly or predominantly for the removal of impurities from and the conditioning of, gas delivered to or removed from underground storage fields.
1. Condensers and washer coolers.
2. Dehydrators.
3. Foundations and settings, specially constructed for and not intended to outlast the equipment for which provided.
4. Other accessory equipment, such as coolers, spray ponds, pumps, platforms, railings, stairs.
5. Piping, from inlet valve of first piece of apparatus to outlet valve of final piece of apparatus (or, in building, from entrance to building to exit from building).
6. Scrubbers.
7. Sulphur removal apparatus.
8. Water supply system.
This account shall include the cost installed of equipment used wholly or predominantly in connection with underground storage of gas, when not assignable to any of the foregoing accounts.
1. Calorimeter.
2. Control installation.
3. Crane.
4. Odorizing unit.
5. Office furniture and equipment.
6. Oil foggers.
This account shall include asset retirement costs on plant included in the underground storage plant function.
This account shall include the cost of land and land rights used in connection with the storage of gas in holders. (See gas plant instruction 7.)
This account shall include the cost in place of structures and improvements used in connection with the storage of gas in holders. (See gas plant instruction 8.)
This account shall include the cost installed of holders and associated appliances used in the storage of gas above ground, or in underground receptacles.
1. Alarm systems.
2. Buried piping, tanks or other underground construction for gas storage.
3. Flood and fire control equipment.
4. Foundations.
5. Holder pistons.
6. Holders-waterless, including elevators, tar apparatus, and inlet and outlet connections.
7. Holders-waterseal, including oil skimmer, heating equipment, drips, and inlet and outlet connections.
8. Hortonspheres and high pressure tanks, including inlet and outlet connections, access equipment, etc.
9. Lighting.
10. Pumps.
11. Ventilating equipment.
12. Walkways.
If the utility stores gas by the liquefaction process the holders for such liquids, whether above or below ground, shall be included in a separate subaccount hereunder.
Relief holders used in connection with manufactured gas operations shall be included in account 305, Structures and Improvements.
This account shall include the cost installed of apparatus used for the removal of impurities from gas and apparatus for conditioning gas.
1. Condensers and washer coolers.
2. Dehydrators.
3. Foundations and settings, specially constructed for and not intended to outlast the equipment for which provided.
4. Other accessory equipment, such as coolers, spray ponds, pumps, platforms, railings, stairs.
5. Piping from inlet valve of first piece of apparatus to outlet valve of final piece of apparatus (or, in building from entrance to building to exit from building).
6. Scrubbers.
7. Sulphur removal apparatus.
8. Water supply system.
This account shall include the cost installed of equipment used in liquefaction of natural gas.
1. Cold box.
2. Heat exchanger.
3. Condensers.
4. Pumps.
5. Tanks.
This account shall include the cost installed of vaporizing equipment used in connection with liquefied natural gas storage.
This account shall include the cost installed of compressor equipment and associated appliances used in connection with other storage plant.
This account shall include the cost installed of equipment used to measure deliveries of gas to other storage and withdrawals of gas from other storage.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundations, pits, etc.
4. Gas cleaners, scrubbers, separators, dehydrators, etc.
5. Gauges and instruments, including piping, fittings, wiring, etc., and panel boards.
6. Headers.
7. Meters, orifice or positive, including piping and connections.
8. Oil fogging equipment.
9. Odorizing equipment.
10. Regulators or governors, including controls and instruments.
11. Structures of a minor nature or portable type.
This account shall include the cost installed of other equipment used in connection with the storage of gas in holders.
1. Complete inlet and outlet connections.
2. Compressor.
3. Foundation.
4. Gauges and instruments.
5. Regulating apparatus.
6. Line pack gas.
This account shall include asset retirement costs on plant included in the other storage plant function.
A. This account shall include the cost of land and land rights used in connection with liquefied natural gas terminaling and processing operations. (See gas plant instruction 7.)
A. This account shall include the cost in place of structures and improvements used in connection with liquefied natural gas terminaling and processing operations. (See gas plant instruction 8.)
B. This account shall be subdivided as follows:
1. Docking and harbor facilities.
2. LNG processing terminal structures.
3. Measuring and regulating structures.
4. Compressor station structures.
5. Other structures.
This account shall include the cost installed of equipment used to receive, hold, and regasify liquefied natural gas for delivery into the utility’s transmission or distribution system.
1. Aftercoolers.
2. Air compressors.
3. Air coolers.
4. Alarm systems.
5. Blowers.
6. Cold box, condensers.
7. Controls and control apparatus.
8. Dikes.
9. Drums.
10. Electrical power and ignition circuits including wiring and conduits.
11. Emission control equipment.
12. Fire control devices and equipment.
13. Foundations.
14. Generators.
15. Heat exchangers.
16. Heaters and reheaters.
17. Instrumentation.
18. Intercoolers.
19. Liquefaction compressors.
20. Liquefied gas holders and storage tanks.
21. Nitrogen system equipment.
22. Plant piping including pipe supports.
23. Pollution control facilities.
24. Pumps and driving units.
25. Stacks.
26. Tanks, other than LNG storage tanks (including ladders, stairs, walkways, and lighting).
27. Unloading and loading arms, and appurtenant equipment.
28. Valves.
29. Vaporizers.
30. Waste heat recovery units.
31. Water craft not to include LNG tankers and barges.
32. Miscellaneous other equipment.
33. Line pack gas.
This account shall include the cost of vehicles used for the transportation of liquefied natural gas.
1. LNG barges.
2. LNG maritime tankers.
3. LNG tank trucks.
4. Other LNG transportation equipment.
This account shall include the cost installed of meters, gauges and other equipment used in base load LNG operations for measuring or regulating natural gas prior to its entrance into the utility’s transmission or distribution system.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundation, pits, etc.
4. Gas analyzer equipment.
5. Gas cleaners, scrubbers, separators, dehydrators, etc.
6. Gauges and instruments, including piping, fittings, wiring, etc., and panel boards.
7. Headers.
8. Meters, orifice or positive, including piping and connections.
9. Oil fogging equipment.
10. Odorizing equipment.
11. Regulators or governors, including controls and instruments.
12. Stabilization equipment.
13. Structures of a minor or portable type.
14. Other equipment.
This account shall include the cost installed of compressor station equipment and associated appliances used in connection with liquefied natural gas operations prior to entrance of vaporized gas into the utility’s transmission or distribution system.
1. Boiler plant, coal handling, and ash handling equipment for steam powered compressor station.
2. Compressed air system equipment.
3. Compressor equipment and driving units, including auxiliaries, foundations, guard rails, and enclosures, etc.
4. Electric system equipment, including generating equipment and driving units, power wiring, transformers, regulators, battery equipment, switchboard, etc.
5. Fire fighting equipment.
6. Gas lines and equipment, including fuel supply lines, cooling tower and pond and associated equipment, dehydrators, fuel gas mixers, special pipebends and connections, and associated scrubbers, separators, tanks, gauges, and instruments.
7. Laboratory and testing equipment.
8. Lubricating oil system, including centrifuge, filter, tanks, purifier, and lubricating oil piping, etc.
9. Office furniture and fixtures and general equipment such as steel lockers, first-aid equipment, gasoline dispensing equipment, lawn mowers, incinerators, etc.
10. Shop tools and equipment.
11. Water supply and circulation system, including water well, tank, water pipeline, cooling tower, spray fence, and water treatment equipment, etc., but not including water system equipment used solely for domestic and general use.
12. Other equipment.
This account shall include the cost installed of radio, telephone, microwave, and other equipment used wholly or predominantly in connection with the operation and maintenance of the liquefied natural gas system. (See also accounts 370 and 397, Communication Equipment.)
1. Carrier terminal equipment including repeaters, power supply equipment, transmitting and receiving sets.
2. Microwave equipment, including power supply equipment, transmitters, amplifiers, paraboloids, towers, reflectors, receiving equipment, etc.
3. Radio equipment, fixed and mobile, including antenna, power equipment, transmitter units.
4. Telephone equipment including switchboards, power and testing equipment, conductors, pole lines, etc.
5. Other equipment.
This account shall include the cost installed of equipment used in liquefied natural gas operations, when not assignable to any of the foregoing accounts.
1. Garage and service equipment.
2. General tools, including power operated equipment.
3. Laboratory equipment.
4. Materials handling equipment.
5. Office furniture and equipment.
6. Power generation equipment.
7. Shop equipment.
8. Tools, other than small hand tools.
9. Other equipment.
This account shall include asset retirement costs on plant included in the base load liquefied natural gas terminaling and processing plant function.
This account shall include the cost of land and land rights except rights-of-way used in connection with transmission operations. (See gas plant instruction 7.)
This account shall include the cost of rights-of-way used in connection with transmission operations. (See gas plant instruction 7.)
A. This account shall include the cost in place of structures and improvements used in connection with transmission operations. (See gas plant instruction 8.)
B. This account shall be subdivided as follows:
A. This account shall include the cost installed of transmission system mains.
B. The records supporting this account shall be so kept as to show separately the cost of mains of different sizes and types and of each tunnel, bridge, or river crossing.
1. Anti-freeze lubricating equipment.
2. Automatic valve operating mechanisms, including pressure tanks, etc.
3. By-pass assembly.
4. Caissons, tunnels, trestles, etc., for submarine mains.
5. Cathodic protection equipment.
6. Drip lines and pots.
7. Excavation, including shoring, bracing, bridging, pumping, backfill, and disposal of excess excavated material.
8. Foundations.
9. Gas cleaners, scrubbers, etc. when not part of compressor station or measuring and regulating equipment.
10. Leak clamps. (See gas plant instruction 10–C (1).)
11. Line pack gas.
12. Linewalkers’ bridges.
13. Manholes.
14. Municipal inspection.
15. Pavement disturbed, including cutting and replacing pavement, pavement base, and sidewalks.
16. Permits.
17. Pipe coating.
18. Pipe and fittings.
19. Pipe laying.
20. Pipe supports.
21. Protection of street openings.
22. River, highway, and railroad crossings, including revetments, pipe anchors, etc.
23. Valves.
24. Welding.
This account shall include the cost installed of compressor station equipment and associated appliances used in connection with transmission system operations.
1. Boiler plant, coal handling and ash handling equipment for steam powered compressor station.
2. Compressed air system equipment.
3. Compressor equipment and driving units, including auxiliaries, foundations, guard rails and enclosures, etc.
4. Electric system equipment, including generating equipment and driving units, power wiring, transformers, regulators, battery equipment, switchboard, etc.
5. Fire fighting equipment.
6. Gas lines and equipment, including fuel supply lines, cooling tower and pond and associated equipment, dehydrators, fuel gas mixers, special pipe bends and connections, and associated scrubbers, separators, tanks, gauges and instruments.
7. Laboratory and testing equipment.
8. Lubricating oil system, including centrifuge, filter, tanks, purifier, and lubricating oil piping, etc.
9. Office furniture and fixtures and general equipment such as steel lockers, first-aid equipment, gasoline dispensing equipment, lawn mowers, incinerators, etc.
10. Shop tools and equipment.
11. Water supply and circulation system, including water well, tank, water piping, cooling tower, spray fence, and water treatment equipment, etc., but not including water system equipment solely for domestic and general use.
This account shall include the cost installed of meters, gauges, and other equipment used in measuring or regulating gas in connection with transmission system operations.
1. Automatic control equipment.
2. Boilers, heaters, etc.
3. Foundations, pits, etc.
4. Gas cleaners, scrubbers, separators, dehydrators, etc.
5. Gauges and instruments, including piping, fittings, wiring, etc., and panel boards.
6. Headers.
7. Meters, orifice or positive, including piping and connections.
8. Oil fogging equipment.
9. Odorizing equipment.
10. Regulators or governors, including controls and instruments.
11. Structures of a minor nature or portable type.
Pipeline companies, including companies who measure deliveries of gas to their own distribution system, shall include in the transmission function classification city gate and main line industrial measuring and regulating stations.
This account shall include the cost installed of radio, telephone, microwave, and other equipment used wholly or predominantly in connection with the operation and maintenance of the gas transmission system. (See also account 397, Communication Equipment.)
1. Carrier terminal equipment including repeaters, power supply equipment, transmitting and receiving sets.
2. Microwave equipment, including power supply equipment, transmitters, amplifiers, paraboloids, towers, reflectors, receiving equipment, etc.
3. Radio equipment, fixed and mobile, including antenna, power equipment, transmitters and receivers, and portable receiver-transmitter units.
4. Telephone equipment including switchboards, power and testing equipment, conductors, pole lines, etc.
This account shall include the cost installed of equipment used in transmission system operations, when not assignable to any of the foregoing accounts.
This account shall include asset retirement costs on plant included in the transmission plant function.
This account shall include the cost of land and land rights used in connection with distribution operations. (See gas plant instruction 7.)
This account shall include the cost in place of structures and improvements used in connection with distribution operations. (See gas plant instruction 8.)
A. This account shall include the cost installed of distribution system mains.
B. The records supporting this account shall be so kept as to show separately the cost of mains of different sizes and types and of each tunnel, bridge, or river crossing.
1. Caissons, tunnels, trestles, etc. for submarine mains.
2. Clamps, leak (bell and spigot) when installed at time of construction; when clamps are installed subsequent to construction, the accounting shall be in accordance with gas plant instruction 10, paragraph (C) 1.
3. Drip lines and pots.
4. Electrolysis tests, in connection with new construction.
5. Excavation, including shoring, bracing, bridging, pumping, backfill, and disposal of excess excavated material.
6. Hauling, unloading, and stringing pipe.
7. Lamping and watching new construction.
8. Line pack gas.
9. Municipal inspection.
10. Pavement disturbed, including cutting and replacing pavement, pavement base, and sidewalks.
11. Permits.
12. Pipe coating.
13. Pipe and fittings.
14. Pipe laying.
15. Pipe supports.
16. Protection of street openings.
17. Relocating city storm and sanitary sewers, catch basins, etc., or protecting same in connection with new construction.
18. Replacement of municipal drains and culverts in connection with new construction.
19. Roadway boxes.
20. Shifting excavated material due to traffic conditions in connection with new construction.
21. Sleeves and couplings.
22. Special crossovers, bridges and foundations for special construction.
23. Surveying and staking lines.
24. Valves not associated with pumping or regulating equipment.
25. Welding.
26. Wood blocking.
This account shall include the cost installed of compressor station equipment and associated appliances used in connection with distribution system operations.
1. Boiler plant, coal handling and ash handling equipment for steam powered compressor station.
2. Compressed air system equipment.
3. Compressor equipment and driving units, including auxiliaries, foundations, guard rails and enclosures, etc.
4. Electric system equipment, including generating equipment and driving units power wiring, transformers, regulators, battery equipment, switchboard, etc.
5. Fire fighting equipment.
6. Gas lines and equipment, including fuel supply lines, cooling tower and pond and associated equipment, dehydrators, fuel gas mixers, special pipe bends and connections, and associated scrubbers, separators, tanks, gauges and instruments.
7. Laboratory and testing equipment.
8. Lubricating oil system, including centrifuge, filter, tanks, purifier, and lubricating oil piping, etc.
9. Office furniture and fixtures and general equipment such as steel lockers, first-aid equipment, gasoline dispensing equipment, lawn mowers, incinerators, etc.
10. Shop tools and equipment.
11. Water supply and circulation system, including water well, tank water piping, cooling tower, spray fence and water treatment equipment, etc., but not including water system equipment solely for domestic and general use.
This account shall include the cost installed of meters, gauges and other equipment used in measuring and regulating gas in connection with distribution system operations other than the measurement of gas deliveries to customers.
1. Automatic control equipment.
2. Foundations.
3. Gauges and instruments.
4. Governors or regulators.
5. Meters.
6. Odorizing equipment.
7. Oil fogging equipment.
8. Piping.
9. Pressure relief equipment.
10. Vaults or pits, including valves contained therein.
By-passes outside governor pits are includible in account 376, Mains.
This account shall include the cost installed of meters, gauges, and other equipment used in measuring and regulating the receipt of gas at entry points to distribution systems.
Pipeline companies, including companies who measure deliveries of gas to their own distribution system, shall include in the transmission function classification city gate and main line industrial measuring and regulating stations.
(See account 378 for items.)
A. This account shall include the cost installed of service pipes and accessories leading to the customers’ premises.
B. A complete service begins with the connection on the main and extends to but does not include the connection with the customer’s meter. A stub service extends from the main to the property line, or the curb stop.
C. Services which have been used but have become inactive shall be retired from utility plant in service immediately if there is no prospect for reuse, and, in any event, shall be retired by the end of the second year following that during which the service became inactive unless reused in the interim.
1. Curb valves and curb boxes.
2. Excavation, including shoring, bracing, bridging, pumping, backfill, and disposal of excess excavated material.
3. Landscaping, including lawns, and shrubbery.
4. Municipal inspection.
5. Pavement disturbed, including cutting and replacing pavement, pavement base, and sidewalks.
6. Permits.
7. Pipe and fittings, including saddle, T, or other fitting on street main.
8. Pipe coating.
9. Pipe laying.
10. Protection of street openings.
11. Service drips.
12. Service valves, at head of service, when installed or furnished by the utility.
A. This account shall include the cost installed of meters or devices and appurtenances thereto, for use in measuring gas delivered to users, whether actually in service or held in reserve.
B. When a meter is permanently retired from service, the installed cost included herein shall be credited to this account.
C. The records of meters shall be so kept that the utility can furnish information as to the number of meters of each type and capacity in service and in reserve as well as the location of each meter.
1. Meters, including badging and initial testing.
2. Cocks.
3. Labor.
4. Locks.
5. Meter bars.
6. Pipe and fittings.
7. Seals.
8. Shelves.
9. Swivels and bushings.
10. Transportation.
At the option of the utility, costs of meter installations may be accounted for separately from the cost of meters in accordance with the provisions of account 382, Meter Installations. The practice of the utility, however, shall be consistent from year to year and throughout the utility’s system.
The cost of removing and resetting meters shall be charged to account 878, Meter and House Regulator Expenses.
A. This account shall include the cost of labor and materials used, and expenses incurred in connection with the original installation of customer meters.
B. When a meter installation is permanently retired from service, the cost thereof shall be credited to this account.
1. Cocks.
2. Locks.
3. Labor.
4. Meter bars.
5. Pipe and fittings.
6. Seals.
7. Shelves.
8. Swivels and bushings.
9. Transportation.
At the option of the utility, meter installations may be accounted for as part of the cost installed of meters, in accordance with the provisions of account 381, Meters. The practice of the utility, however, shall be consistent from year to year and throughout the utility’s system.
A. This account shall include the cost installed of house regulators whether actually in service or held in reserve.
B. When a house regulator is permanently retired from service, the installed cost thereof shall be credited to this account.
1. House regulator.
2. Cocks.
3. Labor.
4. Locks.
5. Pipe and fittings.
6. Regulator vents.
7. Swivels and bushings.
8. Transportation.
At the option of the utility, costs of house regulator installations may be accounted for separately from the cost of house regulators in accordance with the provisions of account 384, House Regulator Installations. The practice of the utility, however, shall be consistent from year to year and throughout the utility’s system.
A. This account shall include the cost of labor and materials used and expenses incurred in connection with the original installation of house regulators.
B. When a house regulator installation is permanently retired from service, the cost thereof shall be credited to this account.
1. Cocks.
2. Labor.
3. Locks.
4. Pipe and fittings.
5. Regulator vents.
6. Swivels and bushings.
7. Transportation.
At the option of the utility, house regulator installations may be accounted for as part of the cost installed of house regulators in accordance with the provisions of account 383. House Regulators. The practice, however, shall be consistent from year to year and throughout the utility’s system.
This account shall include the cost of special and expensive installations of measuring and regulating station equipment, located on the distribution system, serving large industrial customers.
(See account 378 for items.)
Do not include in this account measuring and regulating station equipment serving main line industrial customers. (See account 369.
By-passes outside of governor pits are includible in account 376, Mains.
This account shall include the cost, including first setting and connecting, of equipment owned by the utility installed on customer premises which is not includible in other accounts.
This account shall include the cost installed of all other distribution system equipment not provided for in the foregoing accounts, including street lighting equipment.
1. Carbon monoxide tester and indicators.
2. Explosimeters.
3. Fire extinguisher.
4. Gas masks.
5. Lockers.
6. Portable pump.
7. Recording gauges.
8. Street lighting equipment.
9. Test meters.
10. Watchmen’s clocks.
This account shall include asset retirement costs on plant included in the distribution plant function.
This account shall include the cost of land and land rights used for utility purposes, the cost of which is not properly includible in other land and land rights accounts. (See gas plant instruction 7.)
This account shall include the cost in place of structures and improvements used for utility purposes, the cost of which is not properly includible in other structures and improvements accounts. (See gas plant instruction 8.)
This account shall include the cost of office furniture and equipment owned by the utility and devoted to utility service, and not permanently attached to buildings, except the cost of such furniture and equipment which the utility elects to assign to other plant accounts on a functional basis.
1. Book cases and shelves.
2. Desks, chairs, and desk equipment.
3. Drafting-room equipment.
4. Filing, storage and other cabinets.
5. Floor covering.
6. Library and library equipment.
7. Mechanical office equipment such as accounting machines, typewriters, etc.
8. Safes.
9. Tables.
This account shall include the cost of transportation vehicles used for utility purposes.
1. Airplanes.
2. Automobiles.
3. Bicycles.
4. Electrical vehicles.
5. Motor trucks.
6. Motorcycles.
7. Repair cars or trucks.
8. Tractors and trailers.
9. Other transportation vehicles.
This account shall include the cost of equipment used for the receiving, shipping, handling and storage of materials and supplies.
1. Chain falls.
2. Counters.
3. Cranes (portable).
4. Elevating and stacking equipment (portable).
5. Hoists.
6. Lockers.
7. Scales.
8. Shelving.
9. Storage bins.
10. Trucks, hand and power driven.
11. Wheelbarrows.
This account shall include the cost of tools, implements, and equipment used in construction, repair work, general shops and garages and not specifically provided for or includible in other accounts.
1. Air compressors.
2. Anvils.
3. Automobile repair shop equipment.
4. Battery charging equipment.
5. Belts, shafts and countershafts.
6. Boilers.
7. Cable pulling equipment.
8. Concrete mixers.
9. Derricks.
10. Drill presses.
11. Electric equipment.
12. Engines.
13. Forges.
14. Foundations and settings specially constructed for equipment in this account and not expected to outlast the equipment for which provided.
15. Furnaces.
16. Gas producers.
17. Gasoline pumps, oil pumps, and storage tanks.
18. Greasing tools and equipment.
19. Hoists.
20. Ladders.
21. Lathes.
22. Machine tools.
23. Motor driven tools.
24. Motors.
25. Pipe threading and cutting tools.
26. Pneumatic tools.
27. Pumps.
28. Riveters.
29. Smithing equipment.
30. Tool racks.
31. Vises.
32. Welding apparatus.
33. Work benches.
This account shall include the cost installed of laboratory equipment used for general laboratory purposes and not specially provided for or includible in other departmental or functional plant accounts.
1. Balances and scales.
2. Barometers.
3. Calorimeters-bomb, flow, recording types, etc.
4. Electric furnaces.
5. Gas burning equipment.
6. Gauges.
7. Glassware, beakers, burettes, etc.
8. Humidity testing apparatus.
9. Laboratory hoods.
10. Laboratory tables and cabinets.
11. Muffles.
12. Oil analysis apparatus.
13. Piping.
14. Specific gravity apparatus.
15. Standard bottles for meter prover testing.
16. Stills.
17. Sulphur and ammonia apparatus.
18. Tar analysis apparatus.
19. Thermometers—indicating and recording.
20. Any other item of equipment for testing gas, fuel, flue gas, water, residuals, etc.
This account shall include the cost of power operated equipment used in construction or repair work exclusive of equipment includible in other accounts. Include, also, the tools and accessories acquired for use with such equipment and the vehicle on which such equipment is mounted.
1. Air compressors, including driving unit and vehicle.
2. Back filling machines.
3. Boring machines.
4. Bulldozers.
5. Cranes and hoists.
6. Diggers.
7. Engines.
8. Pile drivers.
9. Pipe cleaning machines.
10. Pipe coating or wrapping machines.
11. Tractors—Crawler type.
12. Trenchers.
13. Other power operated equipment.
It is intended that this account include only such large units as are generally self-propelled or mounted on movable equipment.
This account shall include the cost installed of telephone, telegraph and wireless equipment for general use in connection with the utility’s gas operations. (See account 370 for communication equipment used wholly or predominantly in connection with operation and maintenance of the transmission system.)
1. Carrier terminal equipment including repeaters, power supply equipment, transmitting and receiving sets.
2. Microwave equipment, including power supply equipment, transmitters, amplifiers, paraboloids, towers, reflectors, receiving equipment, etc.
3. Radio equipment, fixed and mobile, including antenna, power equipment, transmitters and receivers, and portable receiver-transmitter units.
4. Telephone equipment including switchboards, power and testing equipment, conductors, pole lines, etc.
This account shall include the cost of equipment, apparatus, etc., used and useful in gas operations, which is not includible in any other account.
1. Hospital and infirmary equipment.
2. Kitchen equipment.
3. Operator’s cottage furnishings.
4. Radios.
5. Recreation equipment.
6. Restaurant equipment.
7. Soda fountains.
8. Other miscellaneous equipment.
Miscellaneous equipment of the nature indicated above wherever practicable shall be assigned to the utility plant accounts on a functional basis.
This account shall include the cost of tangible utility plant not provided for elsewhere.
This account shall include asset retirement costs on plant included in the general plant function.
There shall be shown under this caption the total amount included in the gas operating revenue accounts provided herein.
There shall be shown under this caption the total amount included in the gas operation expense accounts provided herein. (See note to operating expense instruction 3.)
There shall be shown under this caption the total amount included in the gas maintenance expense accounts provided herein.
A. This account shall include the amount of depreciation expense for all classes of depreciable gas plant in service except such depreciation expense as is chargeable to clearing accounts or to account 416, Costs and Expenses of Merchandising, Jobbing and Contract Work.
B. The utility shall keep such records of property and property retirements as will reflect the service life of property which has been retired and aid in estimating probable service life by mortality, turnover, or other appropriate methods; and also such records as will reflect the percentage of salvage and cost of removal for property retired from each account, or subdivision thereof, for depreciable gas plant.
Depreciation expense applicable to property included in account 104, Gas Plant Leased to Others, shall be charged to account 413, Expenses of Gas Plant Leased to Others.
Depreciation expense applicable to transportation equipment, shop equipment, tools, work equipment, power operated equipment and other general equipment may be charged to clearing accounts as necessary in order to obtain a proper distribution of expenses between construction and operation.
This account shall include the depreciation expense for asset retirement costs included in gas utility plant in service.
A. This account shall include charges for amortization and depletion of producing natural gas land and land rights. (See account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant).
B. The charges to this account shall be made in such manner as to distribute the cost of producing natural gas land and land rights over the period of their benefit to the utility, based upon the exhaustion of the natural gas deposits recoverable from such land and land rights.
A. This account shall include charges for amortization of land and land rights of underground storage projects for natural gas. (See account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant.)
B. The charges to this account shall be made in such manner as to distribute the cost of amortizable land and land rights over the period of their benefit to the utility, and with respect to any land or land rights which include native gas in the storage reservoir, such amounts shall be amortized or depleted on the basis of production of such native gas after the volume of stored gas has been withdrawn from the reservoir.
This account shall include amortization charges applicable to amounts included in the gas plant accounts for limited-term franchises, licenses, patent rights limited-term interests in land, and expenditures on leased property where the service life of the improvements is terminable by action of the lease. The charges to this account shall be such as to distribute the book cost of each investment as evenly as may be over the period of its benefit to the utility. (See account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant.)
A. When authorized by the Commission, this account shall include charges for amortization of intangible or other gas utility plant, which does not have a definite or terminable life and which is not subject to charges for depreciation expense.
B. This account shall be supported in such detail as to show the amortization applicable to each investment being amortized, together with the book cost of the investment and the period over which it is being written off.
This account shall be debited or credited, as the case may be, with amounts includible in operating expenses, pursuant to approval or order of the Commission, for the purpose of providing for the extinguishment of the amount in account 114, Gas Plant Acquisition Adjustments.
This account shall be charged with amounts credited to Account 182.1, Extraordinary Property Losses, and Account 182.2 Unrecovered Plant and Regulatory Study Costs, when the Commission has authorized the amount in the latter account to be amortized by charges to gas operating expenses.
This account shall be charged with amortization of amounts authorized by the Commission to be included in Account 186, Miscellaneous Deferred Debits, for expenses incurred in the conversion of distribution plant from manufactured gas service to natural gas service.
This account shall be debited, when appropriate, with the amounts credited to Account 254, Other Regulatory Liabilities, to record regulatory liabilities imposed on the utility by the ratemaking actions of regulatory agencies. This account shall also be debited, when appropriate, with the amounts credited to Account 182.3, Other Regulatory Assets, concurrent with the recovery of such amounts in rates.
This account shall be credited, when appropriate, with the amounts debited to Account 182.3, Other Regulatory Assets, to establish regulatory assets. This account shall also be credited, when appropriate, with the amounts debited to Account 254, Other Regulatory Liabilities, concurrent with the return of such amounts to customers through rates.
A. These accounts shall include the amounts of ad valorem, gross revenue or gross receipts, taxes, state unemployment insurance, franchise taxes, federal excise taxes, social security taxes, and all other taxes assessed by federal, state, county, municipal, or other local governmental authorities, except income taxes.
B. These accounts shall be charged in each accounting period with the amounts of taxes which are applicable thereto, with concurrent credits to account 236, Taxes Accrued, or account 165, Prepayments, as appropriate. When it is not possible to determine the exact amounts of taxes, the amounts shall be estimated and adjustments made in current accruals as the actual tax levies become known.
C. The charges to these accounts shall be made or supported so as to show the amount of each tax and the basis upon which each charge is made. In the case of a utility rendering more than one utility service, taxes of the kind includible in these accounts shall be assigned directly to the utility department the operation of which gave rise to the tax in so far as a specific utility department, it shall be distributed among the utility departments or nonutility operations on an equitable basis after appropriate study to determine such basis.
Special assessments for street and similar improvements shall be included in the appropriate utility plant or nonutility property account.
Taxes specifically applicable to construction shall be included in the cost of construction.
Gasoline and other sales taxes shall be charged as far as practicable to the same amount as the materials on which the tax is levied.
Social security and other forms of so-called payroll taxes shall be distributed to utility departments and to nonutility functions on a basis related to payroll. Amounts applicable to construction shall be charged to the appropriate plant accounts.
Interest on tax refunds or deficiencies shall not be included in these accounts but in account 419, Interest and Dividend Income, or 431, Other Interest Expense, as appropriate.
This account shall include those taxes other than income taxes which relate to utility operating income This account shall be maintained so as to allow ready identification of the various classes of taxes relating to Utility Operating Income (by department), Utility Plant Leased to Others and Other Utility Operating Income.
This account shall include those taxes other than income taxes which relate to Other Income and Deductions.
A. These accounts shall include the amounts of local, state and federal income taxes on income properly accruable during the period covered by the income statement to meet the actual liability for such taxes. Concurrent credits for the tax accruals shall be made to account 236, Taxes Accrued, and as the exact amounts of taxes become known, the current tax accruals shall be adjusted by charges or credits to these accounts so that these accounts as nearly as can be ascertained shall include the actual taxes payable by the utility.
B. The accruals for income taxes shall be apportioned among utility departments and to Other Income and Deductions so that, as nearly as practicable, each tax shall be included in the expenses of the utility department or Other Income and Deductions, the income from which gave rise to the tax. The tax effects relating to Interest Charges shall be allocated between utility and nonutility operations. The basis for this allocation shall be the ratio of net investment in utility plant to net investment in nonutility plant.
Taxes assumed by the utility on interest shall be charged to account 431, Other Interest Expense.
Interest on tax refunds or deficiencies shall not be included in these accounts but in account 419, Interest and Dividend Income, or account 431, Other Interest Expense, as appropriate.
This account shall include the amount of those local, state and federal income taxes which relate to utility operating income. This account shall be maintained so as to allow ready identification of tax effects (both positive and negative) relating to Utility Operating Income (by department), Utility Plant Leased to Others and Other Utility Operating Income.
This account shall include the amount of those local, state and federal income taxes (both positive and negative), which relate to Other Income and Deductions.
This account shall include the amount of those local, state and federal income taxes (both positive and negative), which relate to Extraordinary Items.
A. Accounts 410.1 and 410.2 shall be debited, and Accumulated Deferred Income Taxes shall be credited with amounts equal to any current deferrals of taxes on income or any allocations of deferred taxes originating in prior periods, as provided by the texts of accounts 190, 281, 282 and 283. There shall not be netted against entries required to be made to these accounts any credit amounts appropriately includible in accounts 411.1 or 411.2.
B. Accounts 411.1 and 411.2 shall be credited, and Accumulated Deferred Income Taxes shall be debited with amounts equal to any allocations of deferred taxes originating in prior periods or any current deferrals of taxes on income, as provided by the texts of accounts 190, 281, 282, and 283. There shall not be netted against entries required to be made to these accounts any debit amounts appropriately includible in accounts 410.1 or 410.2.
This account shall include the amounts of those deferrals of taxes and allocations of deferred taxes which relate to Utility Operating Income (by department).
This account shall include the amounts of those deferrals of taxes and allocations of deferred taxes which relate to other income and deductions.
This account shall include the amounts of those allocations of deferred taxes and deferrals of taxes, credit, which relate to Utility Operating Income (by department).
This account shall include the amounts of those allocations of deferred taxes and deferrals of taxes, credit, which relate to Other Income and Deductions.
A. Account 411.4 shall be debited with the amounts of investment tax credits related to gas utility property that are credited to account 255, Accumulated Deferred Investment Tax Credits, by companies which do not apply the entire amount of the benefits of the investment credit as a reduction of the overall income tax expense in the year in which such credit is realized (see account 255).
B. Account 411.4 shall be credited with the amounts debited to account 255 for proportionate amounts of tax credit deferrals allocated over the average useful life of gas utility property to which the tax credits relate or such lesser period of time as may be adopted and consistently followed by the company.
C. Account 411.5 shall also be debited and credited as directed in paragraphs A and B, for investment tax credits related to non- utility property.
This account shall include the amount of those investment tax credit adjustments related to property used in Utility Operations (by department).
This account shall include the amount of those investment tax credit adjustments related to property used in Nonutility Operations.
A. This account shall include, as approved by the Commission, amounts relating to gains from the disposition of future use utility plant including amounts which were previously recorded in and transferred from account 105, Gas Plant Held for Future Use and account 105.1, Production Properties Held for Future Use, under the provisions of paragraphs B, C, and D thereof. Income taxes relating to gains recorded in this account shall be recorded in account 409.1, Income Taxes, Utility Operating Income.
B. The utility shall record in this account gains resulting from the settlement of asset retirement obligations related to utility plant in accordance with the accounting prescribed in General Instruction 24.
A. This account shall include, as approved by the Commission, amounts relating to losses from the disposition of future use utility plant including amounts which were previously recorded in and transferred from account 105, Gas Plant Held for Future Use and account 105.1, Production Properties Held for Future Use, under the provisions of paragraphs B, C, and D thereof. Income taxes relating to losses recorded in this account shall be recorded in account 409.1, Income Taxes, Utility Operating Income.
B. The utility shall record in this account losses resulting from the settlement of asset retirement obligations related to utility plant in accordance with the accounting prescribed in General Instruction 24.
This account shall be charged for accretion expense on the liabilities associated with asset retirement obligations included in account 230, Asset retirement obligations, related to gas utility plant.
A. These accounts shall include, respectively, revenues from gas property constituting a distinct operating unit or system leased by the utility to others, and which property is properly includible in account 104, Gas Plant Leased to Others, and the expenses attributable to such property.
B. The detail of expenses shall be kept or supported so as to show separately the following:
Operation.
Maintenance.
Depreciation.
Amortization.
Related taxes shall be recorded in account 408.1, Taxes Other Than Income Taxes, Utility Operating Income, or account 409.1, Income Taxes, Utility Operating Income, as appropriate.
A. This account shall include the revenues received and expenses incurred in connection with the operations of utility plant, the book cost of which is included in account 118, Other Utility Plant.
B. The expenses shall include every element of cost incurred in such operations, including depreciation, rents, and insurance.
Related taxes shall be recorded in account 408.1, Taxes Other Than Income Taxes, Utility Operating Income, or account 409.1, Income Taxes, Utility Operating Income, as appropriate.
A. These accounts shall include, respectively, all revenues derived from the sale of merchandise and jobbing or contract work, including any profit or commission accruing to the utility on jobbing work performed by it as agent under contracts whereby it does jobbing work for another for a stipulated profit or commission, and all expenses incurred in such activities. Interest related income from installment sales shall be recorded in Account 419, Interest and Dividend Income.
B. Records in support of these accounts shall be so kept as to permit ready summarization of revenues, costs and expenses by such major items as are feasible.
The classification of revenues, costs and expenses of merchandising, jobbing and contract work as nonoperating, and thus inclusion in this account, is for accounting purposes. It does not preclude consideration for justification to the contrary for ratemaking or other purpose.
Related taxes shall be recorded in account 408.2, Taxes Other Than Income Taxes, Other Income and Deductions, or account 409.2, Income Taxes, Other Income and Deductions, as appropriate.
1. Revenues from sale of merchandise and from jobbing and contract work.
2. Discounts and allowances made in settlement of bills for merchandise and jobbing work.
1. Canvassing and demonstrating appliances in homes and other places for the purpose of selling appliances.
2. Demonstrating and selling activities in sales rooms.
3. Installing appliances on customer premises where such work is done only for purchasers of appliances from the utility.
4. Installing piping or other property work on a jobbing or contract basis.
5. Preparing advertising materials for appliance sales purposes.
6. Receiving and handling customer orders for merchandise or for jobbing services.
7. Cleaning and tidying sales rooms.
8. Maintaining display counters and other equipment used in merchandising.
9. Arranging merchandise in sales rooms and decorating display windows.
10. Reconditioning repossessed appliances.
11. Bookkeeping and other clerical work in connection with merchandise and jobbing activities.
12. Supervising merchandise and jobbing operations.
13. Advertising in newspapers, periodicals, radio, television, etc.
14. Cost of merchandise sold and of materials used in jobbing work.
15. Stores expenses on merchandise and jobbing stocks.
16. Fees and expenses of advertising and commercial artists’ agencies.
17. Printing booklets, dodgers, and other advertising data.
18. Premiums given as inducement to buy appliances.
19. Light, heat, and power.
20. Depreciation on equipment used primarily for merchandise and jobbing operations.
21. Rent of sales rooms or of equipment.
22. Transportation expense in delivery and pick-up of appliances by utility’s facilities or by others.
23. Stationery and office supplies and expenses.
24. Losses from uncollectible merchandise and jobbing accounts.
A. These accounts shall include revenues and expenses applicable to operations which are nonutility in character but nevertheless constitute a distinct operating activity of the enterprise as a whole, such as the operation of an ice department where applicable statutes do not define such operation as a utility, or the operation of a servicing organization for furnishing supervision, management, engineering, and similar services to others.
B. The expenses shall include all elements of costs incurred in such operations, and the accounts shall be maintained so as to permit ready summarization as follows:
Operation.
Maintenance.
Rents.
Depreciation.
Amortization.
Related taxes shall be recorded in account 408.2, Taxes Other Than Income Taxes, Other Income and Deductions, or account 409.2, Income Taxes, Other Income and Deductions, as appropriate.
A. This account shall include all rent revenues and related expenses of land, buildings, or other property included in account 121, Nonutility Property, which is not used in operations covered by accounts 417 or 417.1.
B. The expenses shall include all elements of costs incurred in the ownership and rental of property and the accounts shall be maintained so as to permit ready summarization as follows:
Operation.
Maintenance.
Rents.
Depreciation.
Amortization.
Related taxes shall be recorded in account 408.2, Taxes Other Than Income Taxes, Other Income and Deductions, or account 409.2, Income Taxes, Other Income and Deductions, as appropriate.
This account shall include the utility’s equity in the earnings or losses of subsidiary companies for the year.
A. This account shall include interest revenues on securities, loans, notes, advances, special deposits, tax refunds and all other interest-bearing assets, and dividends on stocks of other companies, whether the securities on which the interest and dividends are received are carried as investments or included in sinking or other special fund accounts.
B. This account may include the pro rata amount necessary to extinguish (during the interval between the date of acquisition and the date of maturity) the difference between the cost to the utility and the face value of interest-bearing securities. Amounts thus credited or charged shall be concurrently included in the accounts in which the securities are carried.
C. Where significant in amount expenses, excluding operating taxes and income taxes, applicable to security investments and to interest and dividend revenues thereon shall be charged hereto.
Related taxes shall be recorded in account 408.2, Taxes Other Than Income Taxes, Other Income and Deductions, or account 409.2, Income Taxes, Other Income and Deductions, as appropriate.
Interest accrued, the payment of which is not reasonably assured, dividends receivable which have not been declared or guaranteed, and interest or dividends upon reacquired securities issued or assumed by the utility shall not be credited to this account.
This account shall include concurrent credits for allowance for other funds used during construction, not to exceed amounts computed in accordance with the formula prescribed in Gas Plant Instruction 3(17).
This account shall be credited as follows with investment tax credit amounts not passed on to customers:
(a) By amounts equal to debits to accounts 411.4, Investment Tax Credit Adjustments, Utility Operations, and 411.5, Investment Tax Credit Adjustments, Nonutility Operations, for investment tax credits used in calculating income taxes for the year when the company’s accounting provides for nondeferral of all or a portion of such credits; and,
(b) By amounts equal to debits to account 255, Accumulated Deferred Investment Tax Credits, for proportionate amounts of tax credit deferrals allocated over the average useful life of the property to which the tax credits relate, or such lesser period of time as may be adopted and consistently used by the company.
This account shall include all revenue and expense items except taxes properly includible in the income account and not provided for elsewhere. Related taxes shall be recorded in account 408.2, Taxes Other Than Income Taxes, Other Income and Deductions, or account 409.2, Income Taxes, Other Income and Deductions, as appropriate.
1. Profit on sale of timber. (See gas plant instruction 7C.)
2. Profits from operations of others realized by the utility under contracts.
3. Gains on disposition of investments. Also gains on reacquisition and resale or retirement of utilities debt securities when the gain is not amortized and used by a jurisdictional regulatory agency to reduce embedded debt cost in establishing rates. See General Instruction 17.
4. This account shall include the accretion expense on the liability for an asset retirement obligation included in account 230, Asset retirement obligations, related to nonutility plant.
5. This account shall include the depreciation expense for asset retirement costs related to nonutility plant.
6. The utility shall record in this account gains resulting from the settlement of asset retirement obligations related to nonutility plant in accordance with the accounting prescribed in General Instruction 24.
This account shall be credited with the gain on the sale, conveyance, exchange or transfer of utility or other property to another. Amounts relating to gains on land and land rights held for future use recorded in accounts 105, Gas Plant Held for Future Use and 105.1, Production Properties Held for Future Use, will be accounted for as prescribed in paragraphs B, C, and D thereof. (See gas plant instructions 5F, 7E, and 10E.) Income taxes on gains recorded in this account shall be recorded in account 409.2, Income Taxes, Other Income and Deductions.
This account shall be charged with the loss on the sale, conveyance, exchange or transfer of utility or other property to another. Amounts relating to losses on land and land rights held for future use recorded in accounts 105, Gas Plant Held for Future Use and 105.1, Production Properties Held for Future Use, will be accounted for as prescribed in paragraphs B, C, and D thereof. (See gas plant instructions 5F, 7E, and 10E.) The reduction in income taxes relating to losses recorded in this account shall be recorded in account 409.2, Income Taxes, Other Income and Deductions.
This account shall include amortization charges not includible in other accounts which are properly deductible in determining the income of the utility before interest charges. Charges includible herein, if significant in amount, must be in accordance with an orderly and systematic amortization program.
1. Amortization of utility plant acquisition adjustments, or of intangibles included in utility plant in service when not authorized to be included in utility operating expenses by the Commission.
2. Other miscellaneous amortization charges allowed to be included in this account by the Commission.
These accounts shall include miscellaneous expense items which are nonoperating in nature but which are properly deductible before determining total income before interest charges.
The classification of expenses as nonoperating and their inclusion in these accounts is for accounting purposes. It does not preclude Commission consideration of proof to the contrary for ratemaking or other purposes.
This account shall include all payments or donations for charitable, social or community welfare purposes.
This account shall include all payments for life insurance of officers and employees where company is beneficiary (net premiums less increase in cash surrender value of policies).
This account shall include payments by the company for penalties or fines for violation of any regulatory statutes by the company or its officials.
This account shall include expenditures for the purpose of influencing public opinion with respect to the election or appointment of public officials, referenda, legislation, or ordinances (either with respect to the possible adoption of new referenda, legislation or ordinances or repeal or modification of existing referenda, legislation or ordinances) or approval, modification, or revocation of franchises; or for the purpose of influencing the decisions of public officials, but shall not include such expenditures which are directly related to appearances before regulatory or other governmental bodies in connection with the reporting utility’s existing or proposed operations.
This account shall include other miscellaneous expenses which are nonoperating in nature, but which are properly deductible before determining total income before interest charges.
1. Loss relating to investments in securities written-off or written-down.
2. Loss on sale of investments.
3. Loss on reacquisition, resale or retirement of utility’s debt securities, when the loss is not amortized and used by a jurisdictional regulatory agency to increase embedded debt cost in establishing rates. See General Instruction 17.
4. Preliminary survey and investigation expenses related to abandoned projects, when not written-off to the appropriate operating expense account.
5. Costs of preliminary abandonment costs recorded in accounts 182.1, Extraordinary Property Losses, and 182.2, Unrecovered Plant and Regulatory Study Costs, not allowed to be amortized to account 407.1, Amortization of Property Losses, Unrecovered Plant and Regulatory Study Costs.
6. The utility shall record in this account losses resulting from the settlement of asset retirement obligations related to nonutility plant in accordance with the accounting prescribed in General Instruction 24.
A. This account shall include the amount of interest on outstanding long-term debt issued or assumed by the utility, the liability for which is included in account 221, Bonds, or account 224, Other Long-Term Debt.
B. This account shall be so kept or supported as to show the interest accruals on each class and series of long-term debt.
This account shall not include interest on nominally issued or nominally outstanding long-term debt, including securities assumed.
A. This account shall include the amortization of unamortized debt discount and expense on outstanding long-term debt. Amounts charged to this account shall be credited concurrently to accounts 181, Unamortized Debt Expense, and 226, Unamortized Discount on Long-Term Debt—Debit.
B. This account shall be so kept or supported as to show the debt discount and expense on each class and series of long-term debt.
A. This account shall include the amortization of the losses on reacquisition of debt. Amounts charged to this account shall be credited concurrently to account 189, Unamortized Loss on Reacquired Debt.
B. This account shall be maintained so as to allow ready identification of the loss amortized applicable to each class and series of long-term debt reacquired. See General Instruction 17.
A. This account shall include the amortization of unamortized net premium on outstanding long-term debt. Amounts credited to this account shall be charged concurrently to account 225, Unamortized Premium on Long-Term Debt.
B. This account shall be so kept or supported as to show the premium on each class and series of long-term debt.
A. This account shall include the amortization of the gains realized from reacquisition of debt. Amounts credited to this account shall be charged concurrently to account 257, Unamortized Gain on Reacquired Debt.
B. This account shall be maintained so as to allow ready identification of the gains amortized applicable to each class and series of long-term debt reacquired. See General Instruction 17.
A. This account shall include interest accrued on amounts included in account 223, Advances from Associated Companies, and on all other obligations to associated companies.
B. The records supporting the entries to this account shall be so kept as to show to whom the interest is to be paid, the period covered by the accrual, the rate of interest and the principal amount of the advances or other obligations on which the interest is accrued.
This account shall include all interest charges not provided for elsewhere.
1. Interest on notes payable on demand or maturing one year or less from date and on open accounts, except notes and accounts with associated companies.
2. Interest on customers’ deposits.
3. Interest on claims and judgments, tax assessments, and assessments for public improvements past due.
4. Income and other taxes levied upon bondholders of utility and assumed by it.
This account shall include concurrent credits for allowance for borrowed funds used during construction, not to exceed amounts computed in accordance with the formula prescribed in Gas Plant Instruction 3(17).
This account shall be credited with gains of unusual nature and infrequent occurrence, which would significantly distort the current year’s income computed before Extraordinary Items, if reported other than as extraordinary items. Income tax relating to the amounts recorded in this account shall be recorded in account 409.3, Income Taxes, Extraordinary Items. (See General Instruction 7.)
This account shall be debited with losses of unusual nature and infrequent occurrence, which would significantly distort the current year’s income computed before Extraordinary Items, if reported other than as extraordinary items. Income tax relating to the amounts recorded in this account shall be recorded in account 409.3, Income Taxes, Extraordinary Items. (See General Instruction 7.)
This account shall include the net credit or debit transferred from income for the year.
This account shall include appropriations of retained earnings.
1. Appropriations required under terms of mortgages, orders of courts, contracts, or other agreements.
2. Appropriations required by action of regulatory authorities.
3. Other appropriations made at option of utility for specific purposes.
A. This account shall include amounts declared payable out of retained earnings as dividends on actually outstanding preferred or prior lien capital stock issued by the utility.
B. Dividends shall be segregated for each class and series of preferred stock as to those payable in cash, stock and other forms. If not payable in cash, the medium of payment shall be described with sufficient detail to identify it.
A. This account shall include amounts declared payable out of retained earnings as dividends on actually outstanding common capital stock issued by the utility.
B. Dividends shall be segregated for each class of common stock as to those payable in cash, stock and other forms. If not payable in cash, the medium of payment shall be described with sufficient detail to identify it.
A. This account shall, with prior Commission approval, include significant nonrecurring transactions accounted for as prior period adjustments, as follows:
(1) Correction of an error in the financial statements of a prior year.
(2) Adjustments that result from realization of income tax benefits of pre-acquisition operating loss carryforwards of purchased subsidiaries.
B. Adjustments, charges, or credits due to losses on reacquisition, resale or retirement of the company’s own capital stock shall be included in this account. (See account 210, Gain on Resale or Cancellation of Reacquired Capital Stock, for the treatment of gains.)
A. This account shall include the net billing for gas supplied for residential or domestic purposes.
B. Records shall be maintained so that the quantity of gas sold and the revenues received under each rate schedule shall be readily available.
When gas supplied through a single meter is used for both residential and commercial purposes, the total revenue shall be included in this account or account 481, Commercial and Industrial Sales, according to the rate schedule which is applied. If the same rate schedules are applicable to both residential and commercial service, classification shall be according to principal use.
A. This account shall include the net billing for gas supplied to commercial and industrial customers.
B. Records shall be maintained so that the quantity of gas sold and revenue received under each rate schedule shall be readily available.
C. Records shall be maintained so as to show separately the revenues from commercial and industrial customers, as follows:
When gas supplied through a single meter is used for both commercial and residential purposes, the total revenue shall be included in this account or in account 480, Residential Sales, according to the rate schedule which is applied. If the same rate schedules are applicable to both residential and commercial service, classification shall be according to principal use.
A. This account shall include the net billing for gas supplied to municipalities or divisions or agencies of Federal or State Governments, under special contracts or agreements or service classifications, applicable only to public authorities, for general governmental and institutional purposes, except any revenues under rate schedules the revenues from which are includible in account 481 or 483, and except any revenues from gas used for purposes such as powerplant fuel for publicly owned electric systems, manufacturing processes of arsenals, etc., and other major uses of gas which appropriately may be classified in account 481, Commercial and Industrial Sales.
B. Records shall be maintained so that the quantity of gas sold and the revenue received from each customer and from each major special contract shall be readily available.
A. This account shall include the net billing for gas supplied to other gas utilities or to public authorities for resale purposes.
B. Records shall be maintained so that there shall be readily available the revenues for each customer under each revenue schedule and the billing determinants, as applicable, i.e., volume of gas (actual and billing), contract demand, maximum actual demand, billing demand, and Btu adjustment factor.
Revenues from gas supplied to other public utilities for use by them and not for distribution, shall be included in account 481, Commercial and Industrial Sales, unless supplied under the same contract as and not readily separable from revenues includible in this account.
A. This account shall include amounts charged by the gas department at tariff or other specified rates for gas supplied by it to other utility departments.
B. Records shall be maintained so that the quantity of gas supplied each other department and the charge made therefor shall be readily available.
A. This account shall include, for informational purposes only, the amount recorded for gas supplied by the production division when the price is not determined by a cost-of-service rate proceeding.
B. Records shall be maintained so that the quality of gas transferred shall be readily available.
This account shall include the amount of discounts forfeited or additional charges imposed because of the failure of customers to pay gas bills on or before a specified date.
This account shall include revenues from all miscellaneous services and charges billed to customers which are not specifically provided for in other accounts.
1. Fees for changing, connecting, or disconnecting service.
2. Profit on maintenance of appliances, piping, gas firing, and other utilization facilities, or other installations on customers’ premises.
3. Net credit or debit (cost less net salvage and less payment from customers) on closing work orders for plant installed for temporary service of less than 1 year. (See account 185, Temporary Facilities.)
4. Recovery of expenses in connection with gas diversion cases. (Billing for the gas consumed shall be included in the appropriate gas revenue account.)
5. Services performed for other gas companies for testing and adjusting meters, changing charts, etc.
This account includes revenues from transporting gas for other companies through the gathering facilities of the utility.
This account includes revenues from transporting gas for other companies through the transmission facilities of the utility.
This account includes revenues from transporting gas for other companies through the distribution facilities of the utility.
This account includes revenues from storing gas for other companies.
A. This account shall include revenues from sales of gasoline, butane, propane, and other products extracted from natural gas, net of allowances, adjustments, and discounts, including sales of similar products purchased for resale.
B. Records shall be maintained so that the quantity, sales price, and revenues for each type of product sold to each purchaser shall be readily available.
A. This account shall include revenues from royalties and permits, or other bases of settlement, for permission granted others to remove products from natural gas of the utility.
B. The records supporting this account must be maintained so that full information concerning determination of the revenues will be readily available concerning each processor of gas of the utility, including as applicable (a) The Dth of gas delivered to such other party for processing, (b) the Dth of gas received back from the processor, (c) the field, general production area , or other source of the gas processed, (d) Dth of gas used for processing fuel, etc., which is chargeable to the utility, (e) total gallons of each product recovered by the processor and the utility’s share thereof, (f) the revenues accruing to the utility, and (g) the basis of determination of the revenues accruing to the utility. Such records shall be maintained even though no revenues are derived from the processor.
This account shall include revenues from natural gas gasoline produced direct from gas wells or recovered from drips or obtained in connection with purification or dehydration processes, and revenues from oil obtained from wells which produce oil and gas, the investment in which is carried in accounts 330, Producing Gas Wells—Well Construction, and 331, Producing Gas Wells—Well Equipment.
A. This account shall include rents received for the use by others of land, buildings, and other property devoted to gas operations by the utility.
B. When property owned by the utility is operated jointly with others under a definite arrangement for sharing the actual expenses among the parties to the arrangement, any amount received by the utility for interest or return or in reimbursement of taxes or depreciation on the property shall be credited to this account.
Do not include rent from property constituting an operating unit or system in this account. (See account 412, Revenues From Gas Plant Leased to Others.)
This account shall include credits for rental charges made against other departments of the utility. In the case of property operated under a definite arrangement to allocate actual costs among the departments using the property, any allowance to the gas department for interest or return and depreciation and taxes shall be credited to this account.
This account includes revenues derived from gas operations not includible in any of the foregoing accounts.
1. Commission on sale or distribution of gas of others when sold under rates filed by such others.
2. Compensation for minor or incidental services provided for others such as customer billing, engineering, etc.
3. Profit or loss on sale of material and supplies not ordinarily purchased for resale and not handled through merchandising and jobbing accounts.
4. Sales of steam, water, or electricity, including sales or transfers to other departments of the utility.
5. Miscellaneous royalties received.
6. Revenues from dehydration and other processing of gas of others, except products extraction where products are received as compensation and sales of such are includible in account 490, Sales of Products Extracted From Natural Gas, and except compression of gas of others, revenues from which are includible in accounts 489.1, 489.2, or 489.3, Revenues from Transportation of Gas of Others.
7. Include in a separate subaccount, revenues in payment for rights and/or benefits received from others which are realized through research, development, and demonstration ventures.
8. Include in a separate subaccount, gains on settlements of imbalance receivables and payables (See Accounts 174 and 242) and gains on replacement of encroachment volumes (See Account 117.4). Records must be maintained and readily available to support the gains included in this account.
9. Include in a separate subaccount revenues from penalties earned pursuant to tariff provisions, including penalties associated with cash-out settlements.
A. This account shall be charged with provisions for the estimated pretax effects on net income of the portions of amounts being collected subject to refund which are estimated to be required to be refunded. Such provisions shall be credited to Account 229, Accumulated Provision for Rate Refunds.
B. This account shall also be charged with amounts refunded when such amounts had not been previously accrued.
C. Income tax effects relating to the amounts recorded in this account shall be recorded in account 410.1, Provision for Deferred Income Taxes, Utility Operating Income, or account 411.1, Provision for Deferred Income Taxes—Credit, Utility Operating Income, as appropriate.
This account shall include the cost of labor and expenses incurred in the general supervision and direction of the operation of steam production. (See operating expense instruction 1.)
This account shall include the cost of labor used in boiler rooms and elsewhere about the premises engaged in the production of steam or assignable to the production of steam.
1. Blowing flues.
2. Cleaning boilers.
3. Handling coal, coke, and breeze from place of storage to boilers.
4. Janitorial, messenger, watchmen, and similar services.
5. Operating boilers.
6. Operating elevators.
7. Pulverizing coal.
8. Pumping tar from storage tank to boilers.
9. Removing ashes.
10. Testing steam meters, gauges, and other instruments.
A. This account shall include the cost of coal, oil, gas, or other fuel used in the production of steam, including applicable amounts of fuel stock expenses. It shall also include the net cost of, or the net amount realized from, the disposal of ashes.
B. Records shall be maintained to show the quantity and cost of each type of fuel used. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of fuel, except gas, and related fuel stock expenses, shall be charged initially to appropriate fuel accounts carried under accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of fuel used. See accounts 151 and 152 for basis of fuel costs and includible items of fuel stock expenses.
This account shall include the cost of materials used and expenses incurred in the production of steam, not includible in the foregoing accounts.
1. Boiler compounds.
2. Building service expenses.
3. Chemicals.
4. Communication service.
5. Lubricants.
6. Miscellaneous supplies.
7. Pumping supplies and expenses.
8. Purification supplies and expenses.
9. Tools, hand.
10. Waste.
11. Water purchased.
12. Research, development, and demonstration expenses.
A. This account shall include such portion of the cost of producing steam as is charged to other gas operating expense accounts, or to others or to a coordinate department under a joint facility arrangement.
B. The records supporting the entries to this account shall be so kept that the utility can furnish readily an explanation of the bases of the credits to this account and the amounts charged to (1) other gas accounts, (2) other utility departments, and (3) outside parties under a joint facility arrangement. The records shall show, likewise, the amounts of steam production operation and steam production maintenance expenses, respectively, chargeable to each of the foregoing.
If the utility produces gas by a single process at only one plant, credits need not be made to this account for the cost of steam used in such gas production facility.
Where steam is produced by producer gas equipment or waste heat boilers, and such steam becomes part of the general plant supply, this account should be charged and the steam expense account in the appropriate functional group of accounts (coal gas production, water gas production, etc.) credited with the value of such steam. However, if the steam so produced is used in the same functional operation as that through which derived, such entries need not be made.
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of steam production facilities. Direct field supervision of specific jobs shall be charged to the appropriate maintenance accounts. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures and improvements used in steam production operations, the book cost of which is includible in account 305, Structures and Improvements. (See operating expense instruction 2.)
This account shall indicate the cost of labor, materials used and expenses incurred in the maintenance of equipment used in steam production the book cost of which is includible in account 306, Boiler Plant Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment used in steam production operations, the book cost of which is includible in account 314, Coal, Coke, and Ash Handling Equipment, or account 320, Other Equipment. (See operating expense instruction 2.)
A. This account shall include the cost of labor and expenses occurred in the general supervision and direction of the operation of manufactured gas stations. Direct supervision of specific activities such as steam production and power operations, coke oven operations, water gas generation, etc., shall be charged to the appropriate account. (See operating expense instruction 1.)
A. This account shall include the cost of steam used in manufactured gas production. This includes the cost of steam transferred from the gas department’s own supply and charges for steam transferred from others or from coordinate departments under joint facility arrangements. (See account 704, Steam Transferred—Credit.)
B. This account shall be so kept as to show separately for each source of steam the point of delivery, the quantity, the charges therefor, and the bases of such charges.
This account shall include the cost of electricity or other power, except steam, used in manufactured gas operation. This includes the cost of power purchased, the operation cost of electricity or other power such as compressed air produced by the gas department and charges from others or from coordinate departments for power produced under joint facility arrangements.
This account shall include the cost of labor used and expenses incurred in the operation of coke ovens for the production of coal gas, exclusive of the cost of fuel for the coke ovens and coal carbonized.
1. Supervising.
2. Work of the following character in operation of coke ovens:
a. Charging and leveling coal.
b. Heating ovens to produce coke.
c. Pushing, transporting, quenching, and dumping coke on wharf.
d. Reclaiming coke spillage, removing, replacing, and luting oven doors and lids.
e. Handling and mixing luting mud.
f. Controlling oven heats and gas heating value with dilution gas.
g. Controlling flue temperature, stack drafts, collecting main pressure and the flow of flushing liquor and drains.
h. Operating, cleaning, and lubricating equipment not incidental to maintenance work, such as: charger, pusher, door operating and luting, mud mixing, gas reversal, transportation machinery and equipment, quenching pumps and tower, together with valves, instruments, meters, controls, gauges, and records connected with their operation.
i. Tar chasing (spooning tar in hot drains.)
j. Cleaning doors, jambs, and stand pipes.
3. Handling and transporting coal from storage or boats to battery bins.
4. Operating, cleaning and lubricating mechanical equipment, such as: hoist machines, conveyors and their housing, hammermills and breakers, mixing and battery bins, together with their control valves, instruments, etc.
5. Wetting and handling coke to the coke wharf or storage including cleaning and lubricating of equipment not incident to maintenance.
6. Pumping gas from ovens and maintaining the proper pressures on the collecting main and throughout the apparatus train, including cleaning and lubricating the oven gas exhausters and revivifying blowers, not incident to maintenance.
7. Removing and disposing of carbon, fines, sediment, and waste material.
8. Cleaning ovens and exhauster house, including janitor service in the employees’ locker and wash room within this operating area.
9. Packing, waste, lubricants, etc.
10. Small hand tools.
11. Building service, communication service, transportation.
This account shall include the cost of labor used and expenses incurred in making producer gas exclusive of the cost of fuel for producer gas.
1. Supervising.
2. Work of the following character in connection with operation of producer gas sets (excepting the waste heat boiler and auxiliaries):
a. Inspecting, testing, clinkering, lighting and starting set.
b. Controlling fire and heats with fuel charges.
c. Barring, measuring, and rodding fires.
d. Observing pyrometers, pressures and CO
e. Regulating input materials, such as coke, steam and air and making required flow rate and operating cycle changes.
f. Cleaning and removal of ash, dust, sediment and materials from the set and connections, seal pots, duct pockets, bootlegs, collectors and pumps.
g. Cleaning and reluting producer set doors.
h. Operating, cleaning and lubricating fuel charging lorries, grates, jackets and auxiliaries, ash removal apparatus, and associated instruments, meters, gauges, controls, etc.
3. Handling fuel from storage into bins with conveyors.
4. Operating, cleaning and lubricating auxiliary equipment, not incident to maintenance work, such as coolers, pumps, blowers, exhausters or boosters, fuel handling equipment, etc.
5. Removing and disposing of ashes, sediment and other waste material.
6. Cleaning the producer and booster houses including janitorial and similar services.
7. Packing, waste, lubricants, etc.
8. Small hand tools.
9. Building service, communication service, transportation.
This account shall include the cost of labor used and expenses incurred in the operation of water gas sets exclusive of the cost of fuel and oil for water gas production.
1. Supervising.
2. Work of the following character in connection with the operation of water gas sets (excepting the waste heat boiler and auxiliaries):
a. Inspecting, testing, clinkering, lighting and starting up.
b. Controlling fire and heats with fuel charges, barring and rodding fires, operating grates and jackets, taking stains, observing pyrometers, pressures, seal pot water flow and stack gases, regulating input materials such as coke, oil, natural gas, steam and air.
c. Making required flow rate and operating cycle changes.
d. Cleaning and removing ashes, carbon, and sediment from the set and connections, the wash box, seal pot, oil spray, duct pockets, bootlegs, and collectors, and cleaning and reluting producer set doors.
e. Operating, cleaning and lubricating fuel charging lorries, blowers, valves, automatic operators, and grates, together with their instruments, gauges, and controls, also the ash belts.
3. Operating, cleaning and lubricating auxiliary equipment, such as hydraulic pumps, circulating water pumps, oil pumps from storage to sets, steam accumulators and regulators and reducers on natural gas for reforming, exhausters, revivifying air blowers, and purifier exhausters.
4. Handling fuel from storage into bins with conveyors.
5. Removing and disposing of ashes, carbon, sediment, and other waste material.
6. Cleaning of generator and exhauster houses, including janitorial and similar services.
7. Packing, waste, lubricants, etc.
8. Small hand tools.
9. Building service, communication service, transportation.
This account shall include the cost of labor used and expenses incurred in the operation of equipment for the production of oil gas exclusive of cost of the oil.
1. Supervising.
2. Cleaning, firing and operating oil gas machines.
3. Handling oil from place of storage to oil gas sets.
4. Measuring oil.
5. Removing and disposing of carbon deposits, and other cleaning and incidental labor.
6. Packing, waste, lubricants, etc.
7. Small hand tools.
8. Building service, communication service, transportation.
This account shall include the cost of labor used and expenses incurred in the operation of equipment used for vaporizing petroleum derivatives such as propane, butane or gasoline exclusive of cost of the materials vaporized or used for fuel in the vaporizing process.
1. Supervising.
2. Operating, cleaning and lubricating liquid petroleum vaporizers and injectors.
3. Taking pressures and temperatures, and reading gauges on storage tanks.
4. Inspecting and testing equipment and setting and adjusting controls and regulators.
5. Watching pressure gauges, maintaining pressures and relieving excess pressures through lines.
6. Repressuring storage tanks.
7. Packing, waste, lubricants, etc.
8. Small hand tools.
9. Building service, communication service, transportation.
This account shall include the cost of labor used and expenses incurred in operating equipment used for the production of gas by processes not provided for in the foregoing accounts.
A. This account shall include the cost of gas, other than coke oven gas or producer gas, or other fuel used under coke ovens for making coal gas. Concurrent credits shall be made to account 734, Duplicate Charges—Credit, for gas made by the utility and so used, or account 812, Gas Used for Other Utility Operations—Credit, for other gas used under coke ovens.
B. Records shall be kept to show the quantity and cost of each type of fuel used and fuel handling expenses.
1. Gas made by the utility and used under coke ovens.
2. Natural and other purchased gas used under coke ovens.
A. This account shall include the cost of fuel used in making producer gas including applicable amounts of fuel stock expenses. It shall also include the net cost of, or the net amount realized from, the disposal of ashes.
B. Records shall be kept to show the quantity and the cost of each type of fuel used. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of fuel and related fuel stock expenses shall be charged initially to the appropriate fuel account carried under accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of fuel used. See accounts 151 and 152 for basis of fuel costs and includible items of fuel stock expenses.
A. This account shall include the cost of fuel used in making water gas, including applicable amounts of fuel stock expenses. It shall also include the net cost of, or net proceeds from, the disposal of ashes.
B. Records shall be kept to show the quantity and cost of each type of fuel used. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of fuel and related fuel stock expenses shall be charged initially to the appropriate fuel account carried under accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of fuel used. See accounts 151 and 152 for basis of fuel costs and includible items of fuel stock expenses.
This account shall include the cost of fuel for the manufacture of gas by the oil gas process.
This account shall include the cost of fuel for vaporization of liquefied petroleum gas and for the compression of air in liquefied petroleum gas process.
This account shall include the cost of fuel for the manufacture of gas by processes not provided for in the above fuel accounts.
A. This account shall include the cost of coal used in coke ovens for making coal gas, including applicable amounts of fuel stock expenses.
B. Records shall be kept to show the type, quantity, and cost of coal used. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of coal carbonized and related fuel stock expenses shall be charged initially to the appropriate account carried under accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of coal used. See accounts 151 and 152 for basis of costs and includible items of fuel stock expenses.
A. This account shall include the cost of oil used in carbureting water gas, including applicable amounts of fuel stock expenses.
B. Records shall be kept to show the type, quantity, and cost of oil used. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of oil and related fuel stock expenses shall be charged initially to the appropriate accounts carried under accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of oil used. See accounts 151 and 152 for basis of costs and includible items of fuel stock expenses.
A. This account shall include the cost of oil used in making oil gas, including applicable amounts of fuel stock expenses.
B. Records shall be kept to show the type, quantity, and cost of oil used. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of oil and related fuel stock expenses shall be charged initially to the appropriate raw materials account carried under accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of oil used. See accounts 151 and 152 for basis of costs and includible items of fuel stock expenses.
A. This account shall include the cost of liquefied petroleum gas, such as propane, butane, or gasoline, vaporized for mixing with other gases or for sale unmixed, including applicable amounts of fuel stock expenses.
B. Records shall be kept to show the type, quantity, and cost of liquefied petroleum gas. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of liquefied petroleum gas and related fuel stock expenses shall be charged initially to the appropriate accounts under accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of liquefied petroleum gas used. See accounts 151 and 152 for basis of costs and includible items of fuel stock expenses.
A. This account shall include the cost of raw materials used in the production of manufactured gas by any process not provided for by the foregoing accounts including the production of coal gas by use of retorts, including applicable amounts of fuel stock expenses.
B. Records shall be kept to show the type, quantity, and cost of each raw material used, comparable to the accounting specified in the foregoing accounts for specified types of gas processes. Respective amount of fuel stock and fuel stock expenses shall be readily available.
The cost of raw materials and fuel stock expenses shall be charged initially to the appropriate accounts carried under accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of raw materials used. See accounts 151 and 152 for basis of raw materials costs and includible items of raw materials stock expenses.
A. This account shall include the cost of labor, materials used and expenses incurred including uncollectible accounts in obtaining, handling, preparing, refining, and marketing residuals produced in manufactured gas production processes.
B. Divisions of this account shall be maintained for each of the principal types of expenses chargeable hereto and for each residual or by-product carried in account 731, Residuals Produced—Credit.
A. This account shall be credited and the appropriate subdivision of account 153, Residuals and Extracted Products, debited monthly with the estimated value of residuals and other by-products obtained in connection with the production of manufactured gas, whether intended for sale or for use in operations.
B. If the net amount realized from the sale of residuals is greater or less than the amount at which they were originally credited hereto, an adjusting entry shall be made crediting or debiting this account and charging or crediting the appropriate subdivision of account 153, Residuals and Extracted Products, with the difference.
This account shall include the cost of labor, materials used and expenses incurred in operating purification equipment and apparatus used for conditioning manufactured gas.
1. Supervising.
2. Operating conveyors, condensers, coolers, tar extractors and precipitators, shaving scrubbers and naphthalene and light oil scrubbers.
3. Emptying, rearranging, shifting, cleaning, purging, and refilling purifier boxes.
4. Removing spent oxide to refuse pile.
5. Revivifying oxide.
6. Oiling dip sheets of purifier boxes.
7. Inspecting, testing, controlling adjustments, and taking stains.
8. Cleaning and lubricating purification equipment.
9. Iron oxide.
10. Unslacked lime.
11. Shavings.
12. Soda ash for liquid purifiers.
13. Wash oil for naphthalene scrubber.
14. Sulphuric acid.
This account shall include the cost of labor, materials used and expenses incurred in operating equipment for mixing natural and manufactured gas, or vaporized liquefied petroleum gases for delivery to the distribution system.
1. Supervising.
2. Mixing enrichment gas and other gases or air, including mixing of liquid petroleum gas with air in a liquid petroleum air gas plant, and operation of air jetting equipment and controls.
3. Operating, cleaning and lubricating of cleaners, reducers, calorimeters, calorimixers, appliances and mixing apparatus with their related recorders, gauges, valves and controls, and gravitometers.
4. Inspecting, testing and adjusting mixing equipment.
5. Reading instruments and gauges, changing charts, and recording instrument and gauge readings.
6. Packing, waste, lubricants, etc.
7. Small hand tools.
8. Building service, communication service, transportation.
This account shall include concurrent credits for charges which are made to manufactured gas production operating expenses for manufactured gas not entering common system supply, steam or electricity used for which there is no direct money outlay.
For manufactured gas used from the common system supply, concurrent credits shall be made to account 812, Gas Used for Other Utility Operations—Credit.
This account shall include the cost of labor, materials used and expenses incurred in manufacturing gas production operations not includible in any of the foregoing accounts.
1. Supervising.
2. Cleaning gas works yard of coke dust and other waste materials.
3. Humidifying gas or oil fogging gas at the production plant.
4. Cutting grass and care of the grounds around the gas works.
5. Clearing gas works yard of snow.
6. Janitor service and messenger service.
7. Operating elevators and other conveyances for general use at the gas works.
8. General clerical and stenographic work at gas works.
9. Guarding and patrolling plant and yard.
10. Testing plant instruments not elsewhere provided for.
11. Laboratory labor, except that chargeable to other accounts.
12. Reading manufactured gas meters, and calculating and recording hourly volumes produced.
13. Pumping drips (water) at plant (not provided for elsewhere).
14. Odorizing manufactured gas.
15. Operating, cleaning, and lubricating of air compressors with their tanks, instruments, meters, gauges, and controls when used to supply compressed air into the plant’s air system.
16. Operating effluent water treatment systems, including chemical treatment ozonation, filter, and related equipment, including treatment of carbon and residual sludge, and removing spent oxide, and spent filtering materials.
17. Pumping water for cooling and condensing.
18. Cleaning filters and other operating duties of water system.
19. Producer gas transferred from coke oven plant to water gas plant for dilution purposes.
20. Building service, communication service, transportation.
21. First aid supplies and safety equipment.
22. Office supplies, printing and station- ery.
23. Meals, travelling and incidental expenses.
24. Fuel for heating plant, water for fire protection or general use, and similar items.
25. Lubricants, packing, waste, etc.
26. Odorizing chemicals.
27. Hand tools, drills, saw blades, files, etc.
28. Fire protection supplies.
29. Fogging oils, alcohol, etc.
30. Chemicals, filter materials, etc., and payments to others for disposal of plant effluents and waste.
31. Chemicals for water treatment.
32. Research, development, and demonstration expenses.
This account shall include rents for property of others used, occupied or operated in connection with manufactured gas production operations. (See operating expense instruction 3.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of manufactured gas production facilities. Direct field supervision of specific jobs shall be charged to the appropriate maintenance accounts. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures, the book cost of which is includible in account 305, Structures and Improvements. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment for the production of manufactured gas, the book cost of which is included in accounts 306 to 320, inclusive, except such equipment as is used for the production of steam the maintenance of which is includible in accounts 707, Maintenance of Boiler Plant Equipment, and 708, Maintenance of Other Steam Production Plant. (See operating expense instruction 2.)
A. This account shall include the cost of labor and expenses incurred in the general supervision and direction of the operation of production and gathering systems. Direct supervision of specific activities such as turning on and shutting off wells, operating measuring and regulating stations, etc., shall be charged to the appropriate account. (See operating expense instruction 1.)
B. For Nonmajor companies, this account shall include the cost of supervision and labor in the operation of gas wells, lines, compressors and other equipment of the natural gas production and gathering system including miscellaneous labor such as care of grounds, building service, and general clerical and stenographic work at field offices.
1. Supervision. (See operating expense instruction 1.)
2. Gas depletion and gas reserve activities.
3. Geological activities in connection with gas production.
4. Rights-of-way office activities and supervision, not in connection with construction or retirement work, or storage.
This account shall include the cost of labor, materials used and expenses incurred in the preparation and maintenance of production maps and records.
1. Supervising.
2. Preparing farm maps, field inventory maps, well location plats, and other maps used in connection with natural gas production and gathering operations.
3. Posting changes and making corrections of maps.
4. Maintaining files of maps and tracings.
5. Surveying deeds, leases, rights-of-way, well locations, etc., for map revisions.
6. Reproducing maps (blueprints, photostats, etc.).
7. Supervising.
8. Abstracting titles to date for extension and renewal of leases.
9. Adjusting land and well rentals.
10. Checking free gas rights.
11. Maintaining land and lease records.
12. Delivering rental and royalty checks.
13. Assigning, pooling, merging, renewing, and extending leases.
14. Patrolling land.
15. Preparing expiration calendars.
16. Replacing leases (not involving additional consideration).
17. Transferring payees.
18. Blueprints, photostats, etc.
19. Drafting materials and supplies.
20. Surveying materials and supplies.
21. Employee transportation and travel expenses.
22. Freight, express, parcel post, trucking, and other transportation.
23. Janitor and washroom supplies, etc.
24. Office supplies, stationery and printed forms.
25. Utility services: light, water, and telephone.
This account shall include the cost of labor, materials used and expenses incurred in operating producing gas wells.
1. Supervising.
2. Testing, bailing, swabbing, blowing and gauging producing gas wells.
3. Cleaning off old well locations.
4. Painting signs, etc.
5. Minor upkeep of well roads and fences, etc.
6. Turning wells off and on.
7. Pumping wells.
8. Gas, gasoline, and oil used in pumping, bailing, heating, and swabbing.
9. Lumber, nails, and other materials used for upkeep of fences, making signs, etc.
10. Materials for upkeep of well roads, etc.
11. Well swabs.
12. Employees’ transportation and travel expenses.
13. Freight, express, parcel post, trucking and other transportation.
14. Transportation: company and rented vehicles.
This account shall include the cost of labor, materials used and expenses incurred in operating field lines.
1. Supervising.
2. Walking or patrolling lines.
3. Attending valves, lubricating valves and other equipment, blowing and cleaning lines and drips, draining water from lines, operating and cleaning scrubbers, thawing freezes.
4. Taking line pressures, changing pressure charts, operating alarm gauges.
5. Building and repairing gate boxes, foot bridges, stiles, tool boxes, etc., used in line operations, erecting line markers and warning signs, repairing old line roads.
6. Cleaning debris, cutting grass and weeds on rights-of-way.
7. Inspecting and testing not specifically to determine necessity for repairs.
8. Protecting utility property during work by others.
9. Standby time of emergency crews, responding to fire calls, etc.
10. Locating valve boxes or drip riser boxes.
11. Cleaning and repairing tools used in mains operations, making tool boxes, etc.
12. Cleaning structures and equipment.
13. Driving trucks.
14. Line markers and warning signs.
15. Lumber, nails, etc., used in building and repairing gate boxes, foot bridges, stiles, tool boxes, etc.
16. Charts.
17. Scrubber oil.
18. Hand tools.
19. Lubricants, wiping rags, waste, etc.
20. Freight, express, parcel post, trucking and other transportation charges.
21. Employees’ transportation and travel expenses.
22. Janitor and washroom supplies.
23. Utility services: light, water, telephone.
24. Gas used in field line operations.
This account shall include the cost of labor, materials used, except fuel, and expenses incurred in operating field compressor stations.
1. Supervising.
2. Operating and checking engines, equipment valves, machinery, gauges, and other instruments, including cleaning, wiping, polishing, and lubricating.
3. Operating boilers and boiler accessory equipment, including fuel handling and ash disposal, recording fuel used, and unloading and storing coal and oil.
4. Repacking valves and replacing gauge glasses, etc.
5. Recording pressures, replacing charts, keeping logs, and preparing reports of station operations.
6. Inspecting and testing equipment when not specifically to determine necessity for repairs or replacement of parts.
7. Pumping drips at the station.
8. Taking dew point readings.
9. Testing water.
10. Cleaning structures, cutting grass and weeds, and minor grading around station.
11. Cleaning and repairing hand tools used in operations.
12. Driving trucks.
13. Watching during shut downs.
14. Clerical work at station.
15. Scrubber oil.
16. Lubricants, wiping rags, and waste.
17. Charts and printed forms, etc.
18. Gauge glasses.
19. Chemicals to test waters.
20. Water tests and treatment by other than employees.
21. Janitor and washroom supplies, first aid supplies, landscaping supplies, etc.
22. Employees’ transportation and travel expenses.
23. Freight, express, parcel post, trucking, and other transportation.
24. Utility services: light, water, telephone.
A. This account shall include the cost of gas, coal, oil, or other fuel, or electricity, used for the operation of field compressor stations, including applicable amounts of fuel stock expenses.
B. Records shall be maintained to show the quantity of each type of fuel consumed or electricity used at each compressor station, and the cost of such fuel or power. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of fuel, except gas, and related fuel stock expenses shall be charged initially to appropriate fuel accounts carried in accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of fuel used. See accounts 151 and 152 for the basis of fuel costs and includible fuel stock expenses.
This account shall include the cost of labor, materials used and expenses incurred in operating field measuring and regulating stations.
1. Supervising.
2. Recording pressures and changing charts, reading meters, etc.
3. Estimating lost meter registrations, etc., except gas purchases and sales.
4. Calculating gas volumes from meter charts, except for gas purchases and sales.
5. Adjusting and calibrating measuring equipment, changing meters, orifice plates, gauges, clocks, etc., not in connection with maintenance or construction.
6. Testing gas samples, inspecting and testing gas sample tanks and other meter engineer’s equipment, determining specific gravity and Btu content of gas.
7. Inspecting and testing equipment not specifically to determine necessity for repairs including pulsation tests.
8. Cleaning and lubricating equipment.
9. Keeping log and other operating records, preparing reports of operations, etc.
10. Attending boilers and operating other accessory equipment.
11. Installing and removing district gauges for pressure survey.
12. Thawing freeze in gauge pipes.
13. Inspecting and pumping drips, dewatering manholes and pits, inspecting sumps, cleaning pits, etc., blowing meter drips.
14. Moving equipment, minor structures, etc., not in connection with construction, retirement, or maintenance work.
15. Charts and printed forms, stationery and office supplies, etc.
16. Lubricants, wiping rags, waste.
17. Employees’ transportation and travel expense.
18. Freight, express, parcel post, trucking and other transportation.
19. Utility services: light, water, telephone.
This account shall include the cost of labor, materials used and expenses incurred in operating equipment used for purifying, dehydrating, and conditioning of natural gas.
1. Supervising.
2. Changing charts on fuel meters.
3. Emptying, cleaning and refilling purifier boxes.
4. Oiling dip sheets of purifier covers.
5. Removing spent oxide to refuse piles.
6. Revivifying oxide.
7. Taking readings of inlet and outlet pressures and temperature.
8. Unloading and storing glycol.
9. Watching station and equipment.
10. Cutting grass and weeds, and minor grading around equipment and stations.
11. Hauling operating employees, materials, supplies and tools, etc.
12. Inspecting and testing equipment, not specifically to determine necessity for repairs or replacement of parts.
13. Lubricating equipment, valves, etc.
14. Operating and checking equipment, valves, instruments, etc.
15. Liquid purifying supplies.
16. Iron oxide.
17. Odorizing materials.
18. Charts, printed forms, etc.
19. Employees’ transportation and travel expenses.
20. Freight, express, parcel post, trucking, and other transportation.
21. Gas used in operations.
22. Janitor, washroom, and landscaping supplies.
23. Lubricants, wiping rags, waste, etc.
24. Utility services: light, water, telephone.
Inclusion of dehydration expenses in this account shall be consistent with the functional classification of dehydration plant as to which, see the note to account 336, Purification Plant, relating to cases where dehydrators may be located some distance from the production sources of gas.
A. This account shall include royalties paid for natural gas produced by the utility from wells on land owned by others.
B. Records supporting the entries to this account shall be so kept that the utility can furnish the name of the parties to each contract involving royalties, the terms of each contract, the location of the property involved, the method of determining the royalties, and the amounts payable.
This account shall include the cost of labor, materials used and expenses incurred in producing and gathering natural gas and not includible in any of the foregoing accounts.
1. Moving cleaning tools between locations.
2. Operating communications system.
3. Reading limited and unlimited free gas meters.
4. Miscellaneous small tools, etc.
5. Research, development, and demonstration expenses.
This account shall include rents for property of others used, occupied or operated in connection with the production and gathering of natural gas, other than rentals on land and land rights held for the supply of natural gas. (See operating expense instruction 3.)
See account 795, Delay Rentals, for rentals paid on lands held for the purpose of obtaining a supply of gas in the future.
This account shall include the cost of labor, materials used and expenses incurred in the general supervision and direction of maintenance of the production and gathering facilities as a whole. Direct field supervision of specific jobs shall be charged to the appropriate maintenance account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures and improvements, the book cost of which is includible in accounts 326, Gas Well Structures, 327, Field Compressor Station Structures, 328, Field Measuring and Regulating Station Structures, and 329, Other Structures. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of gas wells and equipment includible in accounts 330. Producing Gas Wells—Well Construction, and 331, Producing Gas Wells—Well Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of field lines the book cost of which is includible in account 332, Field Lines. (See operating expense instruction 2.)
1. Electrolysis and leak inspections (not routine).
2. Installing and removing temporary lines, when necessitated by maintenance.
3. Lamping and watching while making repairs.
4. Lowering and changing location of portion of lines, when the same pipe is used.
5. Protecting lines from fires, floods, land slides, etc.
6. Rocking creek crossings.
This account shall include the cost of labor and expenses incurred in the maintenance of field compressor station equipment includible in account 333, Field Compressor Station Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of field measuring and regulating station equipment includible in account 334, Field Measuring and Regulating Station Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of purification equipment includible in account 336, Purification Equipment. (See operating expense instruction 2.)
Inclusion of dehydration maintenance expenses in this account shall be consistent with the functional classification of dehydration plant as to which see the note to account 336, Purification Equipment, relating to cases where dehydrators may be located some distance from the production sources of gas.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of drilling and cleaning equipment includible in account 335, Drilling and Cleaning Equipment, except such costs of maintaining drilling tools or other equipment which are assignable to the cost of drilling wells. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in maintenance of other production and gathering equipment includible in account 337, Other Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of products extraction and refining operations, except supervision of marketing and selling operations which shall be charged to account 779, Marketing Expenses. Direct supervision of specific extraction and refining activities shall be charged to the appropriate account. (See operating expense instruction 1.)
This account shall include the cost of labor used in the operation of facilities for the extraction of gasoline, butane, propane, or other salable products from natural gas and for refining such products.
1. Supervising.
2. Operating, checking, lubricating, wiping, polishing, and cleaning engines, equipment, valves, machinery, gauges, and other instruments, etc.
3. Inspecting and testing equipment and instruments, not specifically to determine necessity for repairs or replacement of parts.
4. Reading meters, gauges, and other instruments, changing charts, preparing operating reports, etc.
5. Testing gasoline samples, water, etc.
6. Cleaning structures housing equipment, cutting grass and weeds and doing minor grading work around equipment and structures, etc.
7. Driving trucks used in products extraction operations.
8. Cleaning and repairing hand tools used in operations, etc.
9. Watching plant during shut-down periods.
10. Making electricity or steam.
A. This account shall include the cost of gas lost or absorbed in the process of extraction of salable products from natural gas, exclusive of gas used as fuel, the cost of which shall be included in account 773, Fuel.
B. Concurrent credits offsetting charges to this account shall be made to account 811, Gas Used for Products Extraction—Credit.
A. This account shall include the cost of natural gas or other fuel used in extracting gasoline, butane, propane and other salable products from natural gas, including fuel used for generation of electricity or making steam.
B. Concurrent Credits offsetting charges to this account shall be made to account 811, Gas Used for Products Extraction—Credit.
This account shall include the cost of electricity purchased for operation of facilities used in the extraction of gasoline, butane, propane, or other salable products from natural gas.
This account shall include the cost of materials used in extracting salable products from natural gas and blending and refining such products.
1. Absorption oil.
2. Charcoal.
3. Water (payments to others for water).
4. Steam (payments to others for steam).
5. Blending agents.
6. Natural gasoline removed from inventory for blending and refining purposes.
7. Tetraethyl lead.
This account shall include supplies used and expenses incurred in the operation of facilities for recovering salable products from natural gas and blending and refining such products, not provided for elsewhere.
1. Employee transportation and travel expenses.
2. Freight, express, parcel post, trucking and other transportation.
3. Utility services: light, water, telephone.
4. Charts, gas measurement, etc.
5. Janitor, washroom and landscaping supplies.
6. Lubricants: oil and grease, wiping rags and waste, etc.
7. Testing equipment, hand tools, etc., of a portable nature and relatively minor cost or of short life.
8. Research, development, and demonstration expenses.
A. This account shall include the cost of gas shrinkage, gas consumed for fuel, royalties, and other expenses in connection with the processing of gas of the utility by others for extraction of salable products, for which the related revenues are includible in account 491, Revenues from Natural Gas Processed by Others.
B. Concurrent credits offsetting charges to this account for the difference between gas delivered to others for processing and gas returned after processing, such as shrinkage in the processing operations and gas of the utility used for fuel, shall be made to account 811, Gas Used for Products Extraction of Credit.
C. Records supporting this account shall be so maintained that full information will be readily available concerning gas shrinkage, gas used for fuel, royalties, and other expenses assumed or paid by the utility with regard to each processor of gas of the utility. (See paragraph B of account 491, Revenues from Natural Gas Processed by Others.)
1. Gas shrinkage, being cost of the reduction in gas from products extraction operations of gas of the utility processed by others.
2. Gas for fuel, being cost of gas of the utility used for fuel in connection with the products extraction processing of the utility’s gas by others.
3. Royalties, being payments of fractional interests of royalty holders in products extracted by others from gas of the utility.
This account shall include royalties paid by the utility to others for the right to extract salable products from natural gas.
A. This account shall include the cost of labor, materials used and expenses incurred in the marketing of products extracted from natural gas and of similar products purchased for resale.
B. The records supporting this account shall be so maintained that summaries of the various types of expenses shall be readily available.
1. Salaries of persons directly engaged in marketing operations.
2. Employee transportation and travel expenses.
3. Tank car rentals.
4. Freight and hauling charges for products shipped.
5. Miscellaneous marketing expenses.
6. Building service charges for space occupied by marketing personnel.
7. Uncollectible accounts for extracted products sold.
A. This account shall include the cost of gasoline, butane, propane, or other salable products purchased from others for resale.
B. The records supporting this account shall be so maintained that the kind, quantity, and cost of products purchased from each vendor are readily available.
This account shall include credits for increases, and debits for decreases in the inventories of salable products extracted from natural gas or purchased for resale. The net debit or credit in this account shall equal the difference between the inventory at the beginning of the accounting year and the end of the accounting month.
This account shall include concurrent credits for charges which are made of operating expenses or other accounts of the gas department for gasoline or other extracted products which are used from stocks recovered in the natural gas extraction process or purchased for resale, and for such products used for blending and refining processes, the contra debit for which is account 775, Materials.
This account shall include all rents for the property of others used, occupied, or operated in connection with the extraction of salable products from natural gas, exclusive of tank car rentals and other similar rentals includible in account 779, Marketing Expenses. (See operating expense instruction 3.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of facilities used in the extraction and refining of salable products from natural gas. Direct field supervision of specific jobs shall be charged to the appropriate maintenance account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures, the book cost of which is includible in account 341, Structures and Improvements. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 342, Extraction and Refining Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 343, Pipe Lines. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 344, Extracted Products Storage Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 345, Compressor Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 346, Gas Measuring and Regulating Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 347, Other Equipment. (See operating expense instruction 2.)
A. This account shall be charged with the amount of rents paid periodically on natural gas lands acquired by lease before October 8, 1969, in order to hold natural gas land and land rights for the purpose of obtaining a supply of gas in the future.
B. Include also in this account, the cost of obtaining natural gas leases for a period of 1 year or less when such leases were acquired before October 8, 1969.
C. Records supporting this account shall be so kept that the utility can furnish complete details of the charges made for each natural gas leasehold. (See note to gas plant instruction 7G.)
Rents paid periodically on natural gas lands acquired by lease after October 7, 1969, shall be charged to account 105.1, Production Properties Held for Future Use.
This account shall include the net cost of drilling wells on natural gas leases acquired before October 8, 1969, which prove to be nonproductive.
Records in support of the charges to this account shall conform, as appropriate, to Note B of General Instruction 12, Records for Each Plant.
The net cost of drilling wells on natural gas leases acquired after October 7, 1969, which prove to be nonproductive, shall be charged to account 338, Unsuccessful Exploration and Development Costs.
A. This account shall be charged with amounts credited to account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant, to cover the probable loss on abandonment of natural gas leases acquired before October 8, 1969, included in account 105, Gas Plant Held for Future Use, which has never been productive. (See account 182.1.)
B. When natural gas leaseholds which were acquired before October 8, 1969, and which have never been productive are abandoned, and the amounts provided in account 111, Accumulated Provision for Amortization and Depletion of Gas Utility Plant, are not sufficient to cover the cost thereof, the deficiency shall be charged to this account unless otherwise authorized or directed by the Commission. (See account 182.1.)
Losses on abandonment of natural gas leases acquired after October 7, 1969, shall be charged to account 338, Unsuccessful Exploration and Development Costs.
This account shall be charged with the cost of abandoned projects involving natural gas leases acquired before October 8, 1969, on which preliminary expenditures were made for the purpose of determining the feasibility of acquiring acreage to provide a future supply of natural gas (see account 183.1, Preliminary Natural Gas Survey and Investigation Charges).
Preliminary expenditures on abandoned projects involving natural gas leases acquired after October 7, 1969, shall be charged to account 338, Unsuccessful Exploration and Development Costs.
A. This account shall include the cost at well head of natural gas purchased from producers in gas fields or production areas where only the utility’s facilities are used in bringing the gas from the well head into the utility’s natural gas system.
B. The records supporting this account shall be so maintained that there shall be readily available for each vendor and well head the quantity of gas, basis of charges, and amount paid for the gas.
If gas purchases are made under one contract covering both well head and field line purchases and such amounts are not readily separable, the utility may classify such purchases according to predominant source or according to a reasonable estimate.
A. This account shall include, for informational purposes only, the amount recorded for gas supplied by the production division when the price is not determined by a cost-of-service rate proceeding.
B. The records supporting this account shall be so maintained that there will be readily available for each well-head, the quantity of gas, the basis of intracompany charges, and the amount of intracompany charges for gas.
A. This account shall include the cost, at point of receipt by the utility, of natural gas purchased in gas fields or production areas at points along gathering lines, and at points along the utility’s transmission lines within field or production areas, exclusive of purchases at outlets of gasoline plants includible in account 802, where facilities of the vendor or others are used in bringing the gas from the well head to the point of entry into the utility’s natural gas system.
B. The records supporting this account shall be so maintained that there shall be readily available for each vendor and each point of receipt, the quantity of gas, basis of charges, and amount paid for the gas.
If gas purchases are made under one contract covering both well head and field line purchases and such amounts are not readily separable, the utility may classify such purchases according to predominant source or according to a reasonable estimate.
A. This account shall include the cost, at point of receipt by the utility, of natural gas purchased at the outlet side of vendor’s natural gas products extraction plants.
B. The records supporting this account shall be so maintained that there shall be readily available for each vendor and for each products extraction plant, the quantity of gas, basis of the charges, and the amount paid for the gas.
A. This account shall include the cost, at point of receipt by the utility, of natural gas purchased at points along the utility’s transmission lines not within gas fields or production areas, excluding purchases at the outlets of products extraction plants includible in account 802.
B. The records supporting this account shall be so maintained that there shall be readily available for each vendor and each point of receipt, the quantity of gas, basis of charges, and the amount paid for the gas.
A. This account shall include the cost, at point of receipt by the utility, of natural gas purchased which is received at the entrance to the distribution system of the utility.
B. The records supporting this account shall be so maintained that there shall be readily available for each vendor and each point of receipt, the quantity of gas, basis of the charges, and the amount paid for the gas.
Do not credit this account for gas used in reforming for which the cost is charged to manufactured gas production expenses. Credits for such gas should be made to account 812, Gas Used for Other Utility Operations—Credit.
A. This account shall include the cost, including transportation, at point of receipt by the utility, of liquefied natural gas purchased for the purpose of vaporization and injection into the utility’s transmission or distribution system for resale.
B. The records supporting this account shall be so maintained that there shall be readily available for each vendor and point of receipt, the quantity of liquefied natural gas purchased, basis of charges, the amount paid for the liquefied gas, and transportation charges incurred up to the point of receipt of the liquefied gas.
A. This account shall include the cost, at point of receipt by the utility, of manufactured gas, refinery gas, or any gas other than natural gas, or other than any mixed gas in which the natural gas is an important proportion of the mixture.
B. The records supporting this account shall be so maintained that there shall be readily available for each vendor and each point of receipt, the kind and quantity of gas, Btu content, basis of the charges, and the amount paid for the gas.
C. Utilities recognizing revenue for shipper-supplied gas must include the current market price of such gas in this account. Current market price is the delivered spot price of gas in the utility’s supply area, as published in a recognized industry journal. The publication used must be the same one identified in the pipeline’s tariff for use in its cash-out provision, if it has one. If it has no cash-out provision, the utility must use one publication consistently. Contra entries to those recorded herein must be made to the appropriate transportation revenue account (Account 489.1 through Account 489.4). Records are to be maintained and readily available that include the name of shipper, quantity of gas, and the publication and price used to value shipper-supplied gas.
D. The value of gas received from shippers under tariff allowances that is not consumed in operations nor returnable to customers through rate tracking mechanisms must be credited to Account 495, Other Gas Revenues and charged to this account. Utilities must simultaneously charge Accounts 117.3 or 117.4 as appropriate, with contra credits to Account 808.2, Gas Delivered to Storage—Credit. Records are to be maintained and readily available that include the name of shipper, quantity of gas, and the publication and price used to value shipper-supplied gas.
A. This account shall be debited or credited with decreases or increases in purchased gas costs related to Commission approved purchased gas adjustment clauses when such costs are not included in the utility’s rate schedules on file with the Commission.
B. This account shall be debited or credited with amounts amortized from Account 191, Unrecovered Purchased Gas Costs.
This account includes debits or credits for the cost of gas in unbalanced transactions where gas is received from or delivered to another party in exchange, load balancing, or no-notice transportation transactions. The costs are to be determined consistent with the accounting method adopted by the utility for its system gas. If the utility has adopted the inventory method of accounting, the amounts to be recorded in Account 806 must be based on the historical cost of the gas. If the utility has adopted the fixed asset method of accounting, the amounts to be recorded in Account 806 must be based on the current market price of gas at the time gas is tendered for transportation. (See the Special Instructions to Accounts 117.1, 117.2, and 117.3 for a description of the inventory and fixed asset methods and the definition of the current market price of gas.) Contra entries to those in this account are to be made to account 174, Miscellaneous Current and Accrued Assets, for gas receivable and to account 242, Miscellaneous Current and Accrued Liabilities, for gas deliverable under such transactions. Such entries must be reversed and appropriate contra entries made to this account when gas is received or delivered in satisfaction of the amounts receivable or deliverable.
A. This account shall include expenses incurred directly in connection with the purchase of gas for resale.
B. The utility shall not include as purchased gas expense, segregated or apportioned expenses of operating and maintaining gathering system plant whether such plant is devoted solely or partially to purchases of gas, except that the utility shall include the cost of turning on and off purchase gas wells and operating measuring stations devoted exclusively to measuring purchased gas.
C. In general, it is intended that this account include only the expenses directly related to purchased gas, including the expenses of computing volumes of gas purchased, and special items directly related to gas purchases which are not includible in other accounts.
D. This account shall be subdivided as follows:
A. This account shall include debits for the cost of gas withdrawn from storage during the year. Contra credits for entries to this account shall be made to accounts 117.1 through 117.4, or account 164.2, Liquefied Natural Gas Stored, as appropriate. (See the Special Instructions to accounts 117.1, 117.2, and 117.3).
B. Withdrawal of gas from storage shall not be netted against deliveries to storage. (See account 808.2.)
Adjustments for gas inventory losses due to cumulative inaccuracies in gas measurement, or from other causes, shall be entered in account 823, Gas Losses. If, however, any adjustment is substantial, the utility may, with approval of the Commission, amortize the amount of the adjustment to account 823 over future operating periods.
A. This account shall include credits for the cost of gas delivered to storage during the year. Contra debits for entries to this account shall be made to accounts 117.1 through 117.4, or account 164.2, Liquefied Natural Gas Stored, as appropriate. (See the Special Instructions to accounts 117.1, 117.2, and 117.3).
A. This account shall include debits for the cost of liquefied gas withdrawn during the year. Contra credits for entries to this account shall be made to account 164.3, Liquefied Natural Gas Held for Processing.
B. Withdrawals of liquefied natural gas held for processing shall not be netted against deliveries. (See account 809.2).
Adjustments for gas inventory losses due to cumulative inaccuracies in gas measurement, or from other causes, shall be entered in account 846.1, Gas Losses, in the month determined, if, however, any adjustment is substantial, the utility may, with approval of the Commission, amortize the amount of the adjustment to account 846.1 over future operating periods.
A. This account shall include credits for the cost of gas delivered for processing during the year. Contra debits for entries to this account shall be made to account 164.3, Liquefied Natural Gas Held for Processing.
B. Deliveries of natural gas for processing shall not be netted against withdrawals from processing. (See account 809.1).
This account shall include concurrent credits for charges which are made to operating expenses for gas consumed for compressor station fuel from the common system gas supply.
This account shall include concurrent credits for charges which are made to products extraction expenses for gas shrinkage and gas used for fuel in products extraction operations of the utility and for similar uses of gas of the utility by others processing gas of the utility for extraction of salable products.
This account shall include concurrent credits for charges which are made to operating expenses or other accounts of the gas department for gas consumed from the common system supply for operating and utility purposes other than uses for which credits are includible in any of the foregoing accounts. (See account 484, Interdepartmental Sales, for gas supplied to departments other than the gas utility department.)
A. This account shall include the cost of labor, materials used and expenses incurred in connection with gas supply functions not provided for in any of the above accounts, including, research and development expenses.
B. Include in separate subaccounts: (1) losses on settlements of imbalance receivables and payables (See Account 174 and 242) and losses on replacement of encroachment volumes (See the Special Instructions to Accounts 117.1, 117.2 and 117.3); (2) revaluations of storage encroachments; and (3) system gas losses not associated with storage. Appropriate records must be maintained and readily available that include the amount of losses and associated volumes in Dth.
This account shall include the cost of labor and expenses incurred in the general supervision and direction of underground storage operations. Direct supervision of specific activities such as turning on and shutting off storage wells, compressor station operations, etc., shall be charged to the appropriate account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the preparation and maintenance of storage maps and land records.
With respect to land records:
1. Supervising.
2. Abstracting titles to date for extension and renewal of leases.
3. Adjusting land and well rentals.
4. Renewing and extending leases or replacing leases not involving additional consideration.
5. Transferring, assigning, pooling, and merging leases.
6. Delivering rental checks.
7. Clerical work in maintaining storage land and lease records.
8. Preparing and maintaining lease expiration calendars.
With respect to maps:
9. Supervising.
10. Preparing maps, well location plats, etc.
11. Reproducing maps (blueprints or photostats).
12. Posting and revising maps.
13. Surveying deeds, leases, rights-of-way, well locations, etc., for map revisions.
14. Maintaining files of maps and tracings.
15. Field checking boundaries, markers, etc. in connection with preparation of maps.
16. Reproduction of land and lease records and maps (blueprints, photostats, etc.).
17. Drafting materials and supplies.
18. Surveying materials and supplies.
19. Employees’ transportation and travel expenses.
This account shall include the cost of labor, materials used and expenses incurred in operating storage gas wells.
1. Supervising.
2. Testing, bailing, swabbing, blowing, and gauging storage wells.
3. Painting signs, etc.
4. Minor upkeep of well roads, fences, etc.
5. Turning storage wells on and off.
6. Moving cleaning out tools between locations.
7. Driving trucks.
8. Gas, gasoline, and oil used in pumping, bailing, heating, and swabbing.
9. Lumber, nails, and other materials used for repairing old well roads and fences.
10. Well swabs.
11. Employees’ transportation and travel expenses.
12. Freight, express, parcel post, trucking, and other transportation.
This account shall include the cost of labor, materials used and expenses incurred in operating underground storage lines.
1. Supervising.
2. Walking or patrolling lines.
3. Attending valves, lubricating valves and other equipment, blowing and cleaning lines and drips, draining water from lines, operating and cleaning scrubbers, thawing freezes.
4. Taking line pressures, changing pressure charts, operating alarm gauges.
5. Building and repairing gate boxes, foot bridges, stiles, tool boxes, etc., used in line operations, erecting line markers and warning signs, repairing old line roads.
6. Cleaning debris, cutting grass and weeds on rights-of-way.
7. Inspecting and testing not specifically to determine necessity for repairs.
8. Protecting utility property during work by others.
9. Standby time of emergency crews, responding to fire calls, etc.
10. Locating valve boxes or drip riser boxes.
11. Cleaning and repairing tools used in storage lines operations.
12. Cleaning structures and equipment.
13. Driving trucks.
14. Line markers and warning signs.
15. Lumber, nails, etc., used in building and repairing gate boxes, foot bridges, stiles, etc.
16. Charts.
17. Scrubber oil.
18. Hand tools.
19. Lubricants, wiping rags, waste, etc.
20. Freight, express, parcel post, trucking and other transportation.
21. Employees’ transportation and travel expenses.
22. Janitor and washroom supplies.
23. Utility services: light, water, telephone.
24. Gas used in operations.
This account shall include the cost of labor, materials used and expenses incurred in operating underground storage compressor stations.
1. Supervising.
2. Operating and checking engines, equipment, valves, machinery, gauges, and other instruments, including cleaning, wiping, polishing, and lubricating.
3. Operating boilers and boiler accessory equipment, including fuel handling and ash disposal, recording fuel used, and unloading and storing coal and oil.
4. Repacking valves and replacing gauge glasses, etc.
5. Recording pressures, replacing charts, keeping logs, and preparing reports of station operations.
6. Inspecting and testing equipment when not specifically to determine necessity for repairs or replacement of parts.
7. Pumping drips at the station.
8. Taking dew point readings.
9. Testing water.
10. Cleaning structures housing equipment, cutting grass and weeds, and minor grading around station.
11. Cleaning and repairing hand tools used in operations.
12. Driving trucks
13. Watching during shut downs.
14. Clerical work at station.
15. Scrubber oil.
16. Lubricants, wiping rags, and waste.
17. Charts and printed forms, etc.
18. Gauge glasses.
19. Chemicals to test water.
20. Water tests and treatment by other than employees.
21. Janitor and washroom supplies, first aid supplies, landscaping supplies, etc.
22. Employees’ transportation and travel expenses.
23. Freight, express, parcel post, trucking, and other transportation.
24. Utility services: light, water, telephone.
A. This account shall include the cost of gas, coal, oil, or other fuel, or electricity, used for the operation of underground storage compressor stations, including applicable amounts of fuel stock expenses.
B. Records shall be maintained to show the quantity of each type of fuel consumed or electricity used at each compressor station, and the cost of such fuel or power. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of fuel, except gas, and related fuel stock expenses shall be charged initially to appropriate fuel accounts carried in accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of fuel used. See accounts 151 and 152 for the basis of fuel costs and includible fuel stock expenses.
This account shall include the cost of labor, materials used and expenses incurred in operating underground storage measuring and regulating stations.
1. Supervising.
2. Recording pressures and changing charts, reading meters, etc.
3. Estimating lost meter registrations, etc. except gas purchases and sales.
4. Calculating gas volumes from meter charts except gas purchases and sales.
5. Adjusting and calibrating measuring equipment, changing meters, orifice plates, gauges, clocks, etc., not in connection with construction or maintenance.
6. Testing gas samples, inspecting and testing gas sample tanks and other meter engineers equipment, determining specific gravity and Btu content of gas.
7. Inspecting and testing equipment not specifically to determine necessity for repairs, including pulsation tests.
8. Cleaning and lubricating equipment.
9. Keeping log and other operating records, preparing reports of operation, etc.
10. Attending boilers and operating other accessory equipment.
11. Installing and removing district gauges for pressure survey.
12. Thawing freeze in gauge pipe.
13. Inspecting and pumping drips, dewatering manholes and pits, inspecting sumps, cleaning pits, etc., blowing meter drips.
14. Moving equipment, minor structures, etc., not in connection with maintenance or construction.
15. Charts and printed forms, stationery and office supplies, etc.
16. Lubricants, wiping rags, waste.
17. Employees’ transportation and travel expense.
18. Freight, express, parcel post, trucking and other transportation.
19. Utility services: light, water, telephone.
This account shall include the cost of labor, materials used and expenses incurred in operating equipment used for purifying, dehydrating, and conditioning of natural gas in connection with underground storage operations.
1. Supervising.
2. Changing charts on fuel meters.
3. Emptying, cleaning and refilling purifier boxes.
4. Oiling dip sheets of purifier covers.
5. Removing spent oxide to refuse piles.
6. Revivifying oxide.
7. Taking readings of inlet and outlet pressures and temperature.
8. Unloading and storing glycol.
9. Watching station and equipment.
10. Cutting grass and weeds, and minor grading around equipment and stations.
11. Hauling operating employees, materials, supplies and tools, etc.
12. Inspecting and testing equipment, not specifically to determine necessity for repairs or replacement of parts.
13. Lubricating equipment, valves, etc.
14. Operating and checking equipment, valves, instruments, etc.
15. Liquid purifying supplies.
16. Iron oxide.
17. Odorizing materials.
18. Charts, printed forms, etc.
19. Employees’ transportation and travel expenses in connection with purification and dehydration operations.
20. Freight, express, parcel post, trucking and other transportation.
21. Gas used in operations.
22. Janitor, washroom and landscaping supplies.
23. Lubricants, wiping rags, waste, etc.
24. Utility services: light, water, telephone.
This account shall include expenses of investigation, exploration, and development of underground storage projects under consideration which prove not feasible. There also shall be included in this account the net cost of drilling nonoperative wells within an existing storage project. (For Major companies see account 183.2, Other Preliminary Survey and Investigation Charges.)
Include in account 352, Wells, the cost of wells which may be drilled within a storage project for purposes of pressure observation rather than for injection or withdrawal of gas.
This account shall include the amounts of inventory adjustments representing the cost of gas lost or unaccounted for in underground storage operations due to cumulative inaccuracies of gas measurements or other causes. (See the Special Instructions to Accounts 117.1, 117.2 and 117.3). If however, any adjustment is substantial, the utility may, with approval of the Commission, amortize the amount of the adjustment to this account over future operating periods.
This account shall include the cost of labor, material used and expenses incurred in operating underground storage plant, and other underground storage operating expenses, not includible in any of the foregoing accounts, including research, development, and demonstration expenses.
A. This account shall include royalties, rents, and other payments includible in operating expenses for gas wells and gas land acreage located within and comprising underground storage projects of the utility. (See operating expense instruction 3.)
B. The records supporting this account shall be so maintained that information will be readily available for each storage project, of the parties to each contract, basis of the charges, and location of wells to which the royalties or rents of each contract relate.
This account shall include rents for property of others used in connection with the storage of gas underground, other than rents and royalties paid with respect to storage wells and gas lands utilized for the holding of gas in underground storage. (See operating expense instruction 3.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of underground storage facilities. Direct field supervision of specific jobs shall be charged to the appropriate maintenance account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures, the book cost of which is includible in account 351, Structures and Improvements. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of storage wells, the book cost of which is included in account 352, Wells, and the maintenance of reservoirs, the book cost of which is included in account 352.2, Reservoirs. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of underground storage lines, the book cost of which is includible in account 353, Lines. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 354, Compressor Station Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 355, Measuring and Regulating Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of purification equipment, the book cost of which is includible in account 356, Purification Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 357, Other Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of the operation of other storage facilities. Direct supervision of specific activities such as operation of gas holders shall be charged to the appropriate account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in operating storage holders and other storage equipment.
1. Supervising.
2. Operating, checking, lubricating, cleaning, and polishing equipment, machinery, valves, instruments, and other local storage equipment.
3. Reading meters, gauges and other instruments, changing charts, preparing operating reports, etc.
4. Pumping inlet and outlet holder drips.
5. Inspecting and testing equipment when not specifically for repairs or replacement of parts.
6. Cleaning structures and housing equipment, cutting grass and weeds, and doing minor grading work around structures and equipment.
7. Cleaning and repairing hand tools used for operations, etc.
8. Operating steam lines for heating storage facilities.
9. Charts for pressure gauges and meters, printed forms, etc.
10. Lubricants, wiping rags, waste, etc.
11. Janitor and washroom supplies, landscaping supplies, etc.
12. Employee travel and transportation expenses.
13. Freight, express, parcel post, trucking, and other transportation.
14. Utility services: light, water, and telephone.
15. Chemicals.
16. Refrigerants.
17. Research, development, and demonstration expenses.
This account shall include rents for property of others used or operated in connection with other storage operations. (See operating expense instruction 3.)
A. This account shall include the cost of natural gas or other fuel used in the operation of other storage plant.
B. Concurrent credits offsetting charges to this account for natural gas used for fuel shall be made to account 812, Gas Used for Other Utility Operations—Credit.
This account shall include the cost of electricity consumed for operation of facilities used in the operation of other storage plant.
This account shall include the amounts of inventory adjustments representing the cost of gas lost or unaccounted for in other storage operations due to shrinkage or other causes.
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of other storage facilities. Direct field supervision of specific jobs shall be charged to the appropriate maintenance account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures, the book cost of which is includible in account 361, Structures and Improvements. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of gas holders, the book cost of which is includible in account 362, Gas Holders. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of purification equipment, the book cost of which is includible in account 363, Purification Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of liquefaction equipment, the book cost of which is includible in account 363.1, Liquefaction Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of vaporizing equipment, the book cost of which is includible in account 363.2, Vaporizing Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of compressor equipment, the book cost of which is includible in account 363.3, Compressor Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of measuring and regulating equipment, the book cost of which is includible in account 363.4, Measuring and Regulating Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment the book cost of which is includible in account 363.5, Other Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of operations of liquefied natural gas facilities. Direct supervision of specific activities shall be charged to the appropriate operations accounts.
This account shall include the cost of labor, materials used and expenses incurred in operating liquefied natural gas processing equipment.
1. Supervising.
2. Operating, checking, lubricating, cleaning, and polishing equipment, machinery, valves, instruments, and other processing equipment.
3. Reading meters, gauges and other instruments, changing charts, preparing operating reports, etc.
4. Inspecting and testing equipment when not specifically for repairs or replacement of parts.
5. Cleaning structures housing equipment, cutting grass and weeds, and doing minor grading work around structures and equipment.
6. Cleaning and repairing hand tools used for operations, etc.
7. Operating offshore facilities such as piers, docks, loading and unloading arms, water craft, etc.
8. Charts for pressure gauges and meters, printed forms, office supplies, etc.
9. Lubricants, wiping rags, cleaning materials, etc.
10. Janitor and washroom supplies, landscaping supplies, etc.
11. Employee travel and transportation expenses.
12. Freight, express, parcel post, trucking, and other transportation.
13. Utility services: light, water, and telephone.
14. Chemicals.
15. Refrigerants.
16. Small hand tools.
This account shall include the cost of labor, materials used and expenses incurred in operating natural gas liquefaction equipment.
1. Supervising.
2. Operating, checking, lubricating, cleaning, and polishing equipment, machinery, valves, instruments, and other processing equipment.
3. Reading meters, gauges and other instruments, changing charts, preparing operating reports, etc.
4. Inspecting and testing equipment when not specifically for repairs or replacement of parts.
5. Cleaning structures housing equipment, cutting grass and weeds, and doing minor grading work around structures and equipment.
6. Cleaning and repairing hand tools used for operations, etc.
7. Operating offshore facilities such as piers, docks, loading and unloading arms, water craft, etc.
8. Charts for pressure gauges and meters, printed forms, office supplies, etc.
9. Lubricants, wiping rags, cleaning materials, etc.
10. Janitor and washroom supplies, landscaping supplies, etc.
11. Employee travel and transportation expenses.
12. Freight, express, parcel post, trucking, and other transportation.
13. Utility services: light, water, and telephone.
14. Chemicals.
15. Refrigerants.
16. Small hand tools.
This account shall include the cost of labor, materials used and expenses incurred in operating LNG transportation equipment.
1. Supervision.
2. Operating LNG maritime tankers, LNG barges, LNG tank trucks and other LNG transportation equipment.
3. Cleaning and lubricating equipment.
4. Inspecting and testing equipment.
5. Charts, printed forms, office supplies, etc.
6. Dry dock charges.
7. Lubricants, wiping rags, cleaning materials, etc.
8. Employee’s transportation travel and temporary housing expenses.
This account shall include the cost of labor, materials used and expenses incurred in operating, measuring and regulating stations in connection with liquefied natural gas operations.
1. Supervising.
2. Recording pressures and changing charts, reading meters, etc.
3. Estimating lost meter registrations, etc., except gas purchases and sales.
4. Calculating gas volumes from meter charts, except gas purchases and sales.
5. Adjusting and calibrating measuring equipment, changing meters, orifice plates, gauges, clocks, etc., not in connection with construction or maintenance.
6. Testing gas samples, determining specific gravity and Btu content of gas.
7. Inspecting and testing equipment not specifically to determine necessity for repairs including pulsation tests.
8. Cleaning and lubricating equipment.
9. Keeping log and other operating records, preparing records of operations, etc.
10. Attending boilers and operating other accessory equipment.
11. Installing and removing district gauges for pressure survey.
12. Thawing freeze in gauge pipe.
13. Inspecting and pumping drips, dewatering manholes and pits, inspecting sumps, cleaning pits, blowing meter drips, etc.
14. Moving equipment, minor structures, etc., not in connection with maintenance or construction.
15. Charts and printed forms.
16. Lubricants, wiping rags, waste.
17. Employees’ transportation and travel expense.
18. Freight, express, parcel post, trucking and other transportation.
19. Utility services: light, water, telephone.
This account shall include the cost of labor, materials used and expenses incurred, including fuel and power, in operating compressor stations in connection with liquefied natural gas operations.
1. Supervising.
2. Operating and checking engines, equipment valves, machinery, gauges, and other instruments, including cleaning, wiping, polishing, and lubricating.
3. Operating boilers and boiler accessory equipment, including fuel handling, recording fuel used, etc.
4. Repacking valves and replacing gauge glasses, etc.
5. Recording pressures, replacing charts, keeping logs, and preparing reports of station operations.
6. Pumping drips at the station.
7. Taking dew point readings.
8. Testing water.
9. Cleaning structures housing equipment, cutting grass and weeds, and minor grading around station.
10. Cleaning and repairing hand tools used in operations.
11. Driving trucks.
12. Watching during shutdowns.
13. Clerical work at station.
14. Scrubber oil.
15. Lubricants, wiping rags, waste.
16. Charts and printed forms, etc.
17. Gauge glasses.
18. Chemicals to treat water.
19. Water tests and treatment by other than employees.
20. Janitor and washroom supplies, first aid supplies, landscaping supplies, etc.
21. Employees’ transportation and travel expenses.
22. Freight, express, parcel post, trucking, and other transportation.
23. Utility services: light, water, telephone.
This account shall include the cost of labor, materials used and expenses incurred in connection with the operation of liquefied natural gas communications facilities, such as radio, telephone, microwave and other communication systems, including payments to others for communications services.
1. Supervising.
2. Operating switchboards, radio equipment, power generators, microwave equipment, etc. (except general office switchboards).
3. Tagging telephone poles.
4. Testing and replacing telephone batteries, radio tubes, etc.
5. Cutting weeds and grass along telephone rights-of-way and around structures and equipment.
6. Changing radio frequencies.
7. Securing FCC authorization to change frequencies.
8. Taking FCC radio operator tests.
9. Transferring mobile radios between vehicles and/or vessels.
10. Changing locations of telephones and other communications equipment not in connection with maintenance or construction.
11. Inspecting and testing not specifically to determine necessity for repairs.
12. Cleaning and lubricating equipment.
13. Cleaning structures housing equipment.
14. Payments to others for communications services.
15. Telephone batteries, radio tubes and other electronic components.
16. Radio crystals and other materials used in changing radio frequencies.
17. Lubricants, wiping rags, and waste.
18. Employees’ transportation and travel expenses.
19. Freight, express, parcel post, trucking and other transportation.
This account shall include the cost of labor and expenses incurred in dispatching and controlling the supply and flow of liquefied gas and vaporized gas prior to introduction of such vaporized gas into the utility’s transmission or distribution system.
1. Supervising.
2. Analysis of pressures for irregularities, as received.
3. Collecting pressures by telephone and radio.
4. Controlling mixture of various gases to maintain proper Btu content.
5. Correspondence and records, typing and maintaining files.
6. Controlling inputs and withdrawals of liquefied gas for processing.
7. Instructing field men to increase or decrease pressures at regulators.
8. Maintaining pressures at compressor stations, key line junctions and regulating stations to divide the available gas during heavy demand periods.
9. Maintaining pressure log sheets.
10. Maintaining proper compression ratios at compressor stations, consistent with economical operations.
11. Maintaining lowest necessary line pressures consistent with satisfactory service.
12. Requesting pressure changes at compressor stations, regulating stations, and key line junctions.
13. Rerouting gas during emergencies and planned shutdowns.
14. Consultants’ fees and expenses.
15. Meals, traveling and incidental expenses in connection with system load dispatching.
16. Office supplies, stationery and printed forms.
17. Transportation: company and rental vehicles.
18. Utility services: light, water, telephone.
A. This account shall include the cost of gas or other fuel used for the operation of liquefied natural gas terminaling and processing facilities, except compressor station fuel.
B. Concurrent credits offsetting charges to this account for natural gas used for fuel shall be made to account 812, Gas Used for Other Utility Operations—Credit.
This account shall include the cost of purchased power used in operation of liquefied natural gas processing facilities, except compressor station power.
This account shall include rents for property of others used, occupied or operated in connection with liquefied natural gas processing operations. (See operating expense instruction 3.)
This account shall include demurrage charges incurred by the utility relative to LNG shipments received or processed by the utility.
This account shall include wharfage receipts received or receivable from LNG shippers or other parties relative to LNG shipments received or processed by the utility.
A. This account shall include amounts paid to others for the processing of liquefied or vaporized gas of the utility.
B. Records supporting this account shall be so maintained that there shall be readily available for each agreement, the name of the other party, Dth of gas delivered to the other party for processing and the Dth, of gas received back by the utility after processing, points of delivery to and receipt of gas from the other party, amount and basis of charges for the processing service.
If in connection with any gas delivered to another for processing such other party also processes the gas for extraction of gasoline or other salable products, credits attributable to the products so extracted shall be made to account 491, Revenues from Natural Gas Processed by Others, to the end that amounts recorded in this account shall only be charges for processing other than for extraction of salable products.
This account shall include the amounts of inventory adjustments representing the cost of gas lost or unaccounted for in liquefied natural gas operations due to cumulative inaccuracies of gas measurements or other causes. (See paragraph E of account 164.3, Liquefied Natural Gas Held for Processing.) If, however, any adjustment is substantial, the utility may, with approval of the Commission, amortize the amount of the adjustment to this account over future operating periods.
This account shall include the cost of labor, materials used, and expenses incurred in operating liquefied natural gas plant not includible elsewhere.
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of liquefied natural gas terminaling and processing facilities. Direct field supervision of specific jobs shall be charged to the appropriate maintenance accounts. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures and improvements, the book cost of which is included in account 364.2, Structures and Improvements. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of LNG terminal processing equipment, the book cost of which is included in account 364.3, LNG Processing Terminal Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of transportation equipment, the book cost of which is included in account 364.4, LNG Transportation Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of measuring and regulating equipment, the book cost of which is included in account 364.5, Measuring and Regulating Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of compressor station equipment, the book cost of which is included in account 364.6, Compressor Station Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of communication equipment, the book cost of which is included in account 364.7, Communication Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is included in account 364.8, Other Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of the operation of transmission facilities. Direct supervision of specific activities such as operation of transmission lines, compressor stations, etc. shall be charged to the appropriate account. (See operating expense instruction 1.)
This account shall include the cost of labor and expenses incurred in dispatching and controlling the supply and flow of gas through the system.
1. Supervising.
2. Analyses of pressures for irregularities, as received.
3. Collecting pressures by telephone and radio.
4. Controlling mixture of various gases to maintain proper Btu content.
5. Correspondence and records, typing and maintaining files.
6. Controlling production and storage inputs and withdrawals.
7. Instructing field men to increase or decrease pressures at regulators.
8. Maintaining pressures at compressor stations, key line junctions and regulating stations to divide the available gas during heavy demand periods.
9. Maintaining pressure log sheets.
10. Maintaining proper compression ratios at compressor stations, consistent with economical operations.
11. Maintaining lowest necessary line pressures consistent with satisfactory service.
12. Maintaining well operation record by well classification.
13. Requesting pressure changes at compressor stations, regulating stations, and key line junctions.
14. Rerouting gas during emergencies and planned shut downs.
15. Consultants’ fees and expenses.
16. Meals, traveling, and incidental expenses in connection with system load dispatching.
17. Office supplies, stationery and printed forms.
18. Transportation: company and rental vehicles.
19. Utility services: light, water, telephone.
A. This account shall include the cost of labor, materials used and expenses incurred in connection with the operation of transmission communications facilities, such as radio and telephone communications systems, including payments to others for communications services for transmission and load dispatching operations.
B. Credits shall be made to this account and charges made to production, distribution and other gas utility functions and to other utility departments for equitable portions of transmission communications expenses attributable to use of transmission communications facilities other than in connection with gas transmission and load dispatching operation.
1. Supervising.
2. Operating switchboards, radio equipment, power generators, microwave equipment, etc. (except general office switchboards.)
3. Tagging telephone poles.
4. Testing and replacing telephone batteries, radio tubes, etc.
5. Cutting weeds and grass along telephone rights-of-way and around structures and equipment.
6. Changing radio frequencies.
7. Securing FCC authorization to change frequencies.
8. Taking FCC radio operator tests.
9. Transferring mobile radios between vehicles.
10. Changing locations of telephones and other communications equipment not in connection with maintenance or construction.
11. Inspecting and testing not specifically to determine necessity for repairs.
12. Cleaning and lubricating equipment.
13. Cleaning structures housing equipment.
14. Payments to others for communications services.
15. Telephone batteries, radio tubes, etc.
16. Radio crystals and other materials used in changing radio frequencies.
17. Lubricants, wiping rags, and waste.
18. Employees’ transportation and travel expenses.
19. Freight, express, parcel post, trucking, and other transportation.
This account shall include the cost of labor, materials used and expenses incurred (other than fuel and power) in operating transmission compressor stations.
1. Supervising.
2. Operating and checking engines, equipment valves, machinery, gauges, and other instruments, including cleaning, wiping, polishing, and lubricating.
3. Operating boilers and boiler accessory equipment, including fuel handling and ash disposal, recording fuel used, and unloading and storing coal and oil.
4. Repacking valves and replacing gauge glasses, etc.
5. Recording pressures, replacing charts, keeping logs, and preparing reports of station operations.
6. Inspecting and testing equipment not specifically to determine necessity for repairs.
7. Pumping drips at the station.
8. Taking dew point readings.
9. Testing water.
10. Cleaning structures housing equipment, cutting grass and weeds, and minor grading around station.
11. Cleaning and repairing hand tools used in operations.
12. Driving trucks.
13. Watching during shut downs.
14. Clerical work at station.
15. Scrubber oil.
16. Lubricants, wiping rags, and waste.
17. Charts and printed forms, etc.
18. Gauge glasses.
19. Chemicals to treat water.
20. Water tests and treatment by other than employees.
21. Janitor and washroom supplies, first aid supplies, landscaping supplies, etc.
22. Employees’ transportation and travel expenses.
23. Freight, express, parcel post, trucking, and other transportation.
24. Utility services: light, water, telephone.
A. This account shall include the cost of gas used for the operation of transmission compressor stations.
B. Records shall be maintained to show the Dth of gas consumed at each compressor station, and the cost of such gas.
A. This account shall include the cost of coal, oil, and other fuel, or electricity, used for the operation of transmission compressor stations, including applicable amounts of fuel stock expenses.
B. Records shall be maintained to show the quantity of each type of fuel consumed or electricity used at each compressor station, and the cost of such fuel or power. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of fuel, includible in this account, and related fuel stock expenses shall be charged initially to appropriate fuel accounts carried in accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of fuel used. See accounts 151 and 152 for the basis of fuel costs and includible fuel stock expenses.
This account shall include the cost of labor, materials used and expenses incurred in operating transmission mains.
1. Supervising.
2. Walking or patrolling lines.
3. Attending valves, lubricating valves and other equipment, blowing and cleaning lines and drips, draining water from lines, operating and cleaning scrubbers, thawing freezes.
4. Taking line pressures, changing pressure charts, operating alarm gauges.
5. Building and repairing gate boxes, foot bridges, stiles, etc., used in line operations, erecting line markers and warning signs, repairing old line roads.
6. Cleaning debris, cutting grass and weeds on rights-of-way.
7. Inspecting and testing not specifically to determine necessity for repairs.
8. Protecting utility property during work by others.
9. Standby time of emergency crews, responding to fire calls, etc.
10. Locating valve boxes or drip riser boxes.
11. Cleaning and repairing tools used in mains operations, making tool chests, etc.
12. Cleaning structures and equipment.
13. Driving trucks.
14. Line markers and warning signs.
15. Lumber, nails, etc., used in building and repairing gate boxes, foot bridges, stiles, etc.
16. Charts.
17. Scrubber oil.
18. Hand tools.
19. Lubricants, wiping rags, waste, etc.
20. Freight, express, parcel post, trucking and other transportation.
21. Employees’ transportation and travel expenses.
22. Janitor and washroom supplies.
23. Utility services: light, water, telephone.
24. Gas used in mains operations.
This account shall include the cost of labor, materials used and expenses incurred in operating transmission measuring and regulating stations.
1. Supervising.
2. Recording pressures and changing charts, reading meters, etc.
3. Estimating lost meter registrations, etc., except gas purchases and sales.
4. Calculating gas volumes from meter charts, except gas purchases and sales.
5. Adjusting and calibrating measuring equipment, changing meters, orifice plates, gauges, clocks, etc. not in connection with construction or maintenance.
6. Testing gas samples, inspecting and testing gas sample tanks and other meter engineers’ equipment, determining specific gravity and Btu content of gas.
7. Inspecting and testing equipment not specifically to determine necessity for repairs including pulsation tests.
8. Cleaning and lubricating equipment.
9. Keeping log and other operating records, preparing reports of operations, etc.
10. Attending boilers and operating other accessory equipment.
11. Installing and removing district gauges for pressure survey.
12. Thawing freeze in gauge pipe.
13. Inspecting and pumping drips, dewatering manholes and pits, inspecting sumps, cleaning pits, etc., blowing meter drips.
14. Moving equipment, minor structures, etc., not in connection with maintenance or construction.
15. Charts and printed forms.
16. Lubricants, wiping rags, waste.
17. Employees’ transportation and travel expense.
18. Freight, express, parcel post, trucking and other transportation.
19. Utility services: light, water, telephone.
A. This account shall include amounts paid to others for the transmission and compression of gas of the utility.
B. Records supporting this account shall be so maintained that there shall be readily available for each agreement, name of other party, Dth of gas delivered to the other party for transmission or compression and the Dth of gas received back by the utility after transmission or compression, points of delivery to and receipt of gas from other party, amount and basis of charges for the transmission or compression service.
If in connection with any gas delivered to another for transmission or compression such other party also processes the gas for extraction of gasoline or other salable products, credits attributable to the products so extracted shall be made to account 491, Revenues from Natural Gas Processed by Others, to the end that amounts recorded in this account shall only be charges for transportation or compression service.
This account shall include the cost of labor, material used and expenses incurred in operating transmission system equipment and other transmission system expenses not includible in any of the foregoing accounts, including research, development, and demonstration expenses.
This account shall include rents for property of others used, occupied or operated in connection with the operation of the transmission system. Include herein rentals paid for regulator sites, railroad crossings, rights-of-way, annual payments to governmental bodies and others for use of public or private lands, and reservations for rights-of-way. (See operating expense instruction 3.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of transmission system facilities. Direct field supervision of specific jobs shall be charged to the appropriate maintenance accounts. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures, the book cost of which is includible in account 366, Structures and Improvements. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of mains, the book cost of which is includible in account 367, Mains. (See operating expense instruction 2.)
1. Supervising.
2. Electrolysis and leak inspection.
3. Installing and removing temporary lines, when necessitated by maintenance.
4. Lamping and watching while making repairs.
5. Lowering and changing location of lines, when the same pipe is used.
6. Protecting lines from fires, floods, landslides, etc.
7. Rocking creek crossings.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 368, Compressor Station Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 369, Measuring and Regulating Station Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 370, Communication Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 371, Other Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of distribution system operations. Direct supervision of specific activities such as load dispatching, mains operation, removing and resetting meters, etc., shall be charged to the appropriate account. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in dispatching and controlling the supply and flow of gas through the distribution system.
1. Supervising.
2. Analyzing pressures for irregularities.
3. Collecting pressures by telephone and radio.
4. Controlling mixture of various gases to maintain proper Btu content.
5. Correspondence and records, typing and maintaining files.
6. Controlling gas-make and inputs to distribution system.
7. Maintaining pressures at key points to divide the available gas during heavy demand periods.
8. Maintaining pressure log sheets.
9. Maintaining lowest necessary line pressures consistent with satisfactory service.
10. Rerouting gas during emergencies and planned shut downs.
11. Consultants’ fees and expenses.
12. Meals, traveling, and incidental expenses.
13. Office supplies, stationery and printed forms.
14. Transportation: company and rented vehicles.
15. Utility services: light, water, telephone.
This account shall include the cost of labor, materials used and expenses incurred in operating distribution compressor stations.
1. Supervising.
2. Operating and checking engines, equipment valves, machinery, gauges, and other instruments, including cleaning, wiping, polishing, and lubricating.
3. Operating boilers and boiler accessory equipment, including fuel handling and ash disposal, recording fuel used, and unloading and storing coal and oil.
4. Repacking valves and replacing gauge glasses, etc.
5. Recording pressures, replacing charts, keeping logs, and preparing reports of station operations.
6. Inspecting and testing equipment and instruments when not specifically to determine necessity for repairs or replacement of parts.
7. Pumping drips at the station.
8. Taking dew point readings.
9. Testing water.
10. Cleaning structures housing equipment, cutting grass and weeds, and doing minor grading around station.
11. Cleaning and repairing hand tools used in operations.
12. Driving trucks.
13. Watching during shut downs.
14. Clerical work at station.
15. Scrubber oil.
16. Lubricants, wiping rags, and waste.
17. Charts and printed forms, etc.
18. Gauge glasses.
19. Chemicals to test water.
20. Water tests and treatment by other than employees.
21. Janitor and washroom supplies, first aid supplies, landscaping supplies, etc.
22. Employees’ transportation and travel expenses.
23. Freight, express, parcel post, trucking, and other transportation.
24. Utility services: light, water, telephone.
A. This account shall include the cost of gas, coal, oil, or other fuel, or electricity, used for the operation of distribution compressor stations, including applicable amounts of fuel stock expenses.
B. Records shall be maintained to show the quantity of each type of fuel consumed or electricity used at each compressor station, and the cost of such fuel or power. Respective amounts of fuel stock and fuel stock expenses shall be readily available.
The cost of fuel, except gas, and related fuel stock expenses shall be charged initially to appropriate fuel accounts carried in accounts 151, Fuel Stock, and 152, Fuel Stock Expenses Undistributed, and cleared to this account on the basis of fuel used. See accounts 151 and 152 for the basis of fuel costs and includible fuel stock expenses.
This account shall include the cost of labor, materials used and expenses incurred in operating distribution system mains and services.
1. Supervising.
2. Walking or patrolling lines.
3. Attending valves, lubricating valves and other equipment, blowing and cleaning lines and drips, draining water from lines, thawing freezes.
4. Taking line pressures, changing pressure charts, operating alarm gauges.
5. Building and repairing gate boxes, foot bridges, stiles, etc. used in distribution mains operations, erecting line markers and warning signs, etc.
6. Cleaning debris, cutting grass and weeds on rights-of-way.
7. Inspecting and testing equipment not specifically to determine necessity for repairs.
8. Protecting utility property during work by others.
9. Standby time of emergency crews, responding to fire calls, etc.
10. Locating and inspecting valve boxes or drip riser boxes, service lines, mains, etc.
11. Cleaning and repairing tools used in mains operations, making tool boxes, etc.
12. Cleaning structures and equipment.
13. Driving trucks used in mains and service operations.
14. Making routine leak survey.
15. Oil fogging.
1. Line markers and warning signs.
2. Lumber, nails, etc., used in building and repairing gate boxes (foot bridges, stiles, tool boxes, etc.).
3. Charts and printed forms.
4. Scrubber oils.
5. Hand tools.
6. Lubricants, wiping rags, waste, etc.
7. Freight, express, parcel post, trucking and other transportation.
8. Uniforms.
9. Employee transportation and travel expenses.
10. Janitor and washroom supplies.
11. Utility services: light, water, telephone.
12. Gas used in mains operation.
13. Oil for fogging.
This account shall include the cost of labor, materials used and expenses incurred in operating general distribution measuring and regulating stations.
1. Supervising.
2. Recording pressures and changing charts, reading meters, etc.
3. Estimating lost meter registrations, etc. except purchases and sales.
4. Calculating gas volumes from meter charts, except gas purchases and sales.
5. Adjusting and calibrating measuring equipment, changing meters, orifice plates, gauges, clocks, etc.
6. Taking and testing gas samples, inspecting and testing valves, regulators, gas sample tanks and other meter engineers’ equipment, determining specific gravity and Btu content of gas.
7. Inspecting and testing equipment and instruments not specially to determine necessity for repairs, including pulsation tests.
8. Cleaning and lubricating equipment.
9. Keeping log and other operating records.
10. Attending boilers and operating other accessory equipment.
11. Installing and removing district gauges for pressure survey.
12. Thawing freeze in gauge pipe.
13. Inspecting and pumping drips, dewatering manholes and pits, inspecting sumps, cleaning pits, blowing meter drips, etc.
14. Moving equipment, minor structures, etc., not in connection with maintenance or construction.
15. Charts and printed forms, stationery and office supplies, etc.
16. Lubricants, wiping rags, waste.
17. Uniforms.
18. Employee transportation and travel expenses.
19. Freight, express, parcel post, trucking and other transportation.
20. Utility services: light, water, telephone.
This account shall include the cost of labor, materials used and expenses incurred in operating large measuring and regulating stations located on local distribution systems to serve specific commercial and industrial customers.
(See account 875 for items.)
This account shall include the cost of labor, materials used and expenses incurred in operating measuring and regulating stations used to measure and regulate the receipt of gas at entry points to distribution systems.
Pipe line companies shall include in the transmission functional classification city gate and main line industrial measuring and regulating stations, except that where pipe line companies measure deliveries of gas at entry points to their own distribution systems, they shall have the option, if consistently observed, of including such stations either in the transmission or distribution function for accounting purposes.
(See account 875 for items.)
This account shall include the cost of labor, materials used and expenses incurred in connection with removing, resetting, changing, testing, and servicing customer meters and house regulators.
(a) Removing, reinstalling, and changing or exchanging customer meters and house regulators:
1. Initiating or terminating service, including incidental meter reading.
2. Periodic replacement of meters and house regulators because of age.
3. Changing or exchanging meters and house regulators because of complaints or removal for inspection.
4. Resetting meters on existing connections.
5. Handling meters and house regulators to and from customer premises and meter shop.
6. Listing, tagging, and placing meter labels, etc., for removed and reset meters.
7. Changing position of meters or house regulators on the same premises.
8. Installing or removing blank linings.
9. Unproductive calls, etc.
(b) Turning on and turning off meters, except for failures of customers to pay bills:
10. Turning on meters, including necessary time to insure that gas lines are proper to use and that appliances are in usable condition.
11. Turning off meters including time to make safety precautions.
(c) Other:
12. Supervising.
13. Clerical work on meter history and associated equipment record cards, test cards, and reports.
14. Handling and recording meters for stock.
15. Inspecting and testing meters and house regulators.
16. Inspecting and adjusting meter testing equipment.
17. Driving trucks used in meter operations.
18. Meter locks and seals.
19. Lubricants, wiping rags, waste, etc.
20. Uniforms.
21. Freight, express, parcel post, trucking, and other transportation.
22. Utility services: light, water, telephone, heating.
23. Office supplies, stationery and printing.
24. Employees’ transportation expenses.
25. Janitor, washroom, first aid supplies, etc.
The cost of the first setting of a meter or house regulator shall be charged to account 382, Meter Installations, or account 384, House Regulator Installations, as appropriate.
A. This account shall include the cost of labor, materials used and expenses incurred in work on customer premises other than expenses includible in account 878, Meter and House Regulator Expenses, including the cost of servicing customer-owned appliances when the cost of such work is borne by the utility.
B. Damage to customer equipment by employees of the utility whether incidental to the work or the result of negligence, shall be charged to the job on which the employee was engaged at the time of damage.
1. Supervising.
2. Altering customer-owned service extensions or meter connections.
3. Investigating and correcting pressure difficulties or stoppages in customer-owned piping.
4. Adjusting and repairing burner pilots because of impurities in the gas or failure of the distribution system.
5. Oiling or spraying noisy customer meters.
6. Investigating and stopping gas leaks on customers’ premises caused by defective meter, customer-owned piping, or customer appliances.
7. Inspecting new installations to determine that the customers’ equipment and piping are properly installed and connected.
8. Consolidating meter installations, without change of size, due to elimination of separate meters for different service classifications.
9. Investigating and adjusting complaints of service on customers’ premises.
10. Gas load surveys including the incidental preparations and replacement of meters.
11. Unproductive calls.
12. Stenographic and clerical work.
13. Janitorial services, etc.
14. Installing demand or test meters.
15. Inspecting, cleaning, repairing and adjusting customer-owned appliances for domestic, industrial, or commercial use, including house heating furnaces and other space heating appliances, hotel and restaurant appliances.
16. Replacing defective parts in customer-owned appliances and salvaging reusable appliance parts.
17. Lubricants, wiping rags, waste, etc.
18. Uniforms.
19. Replacement parts for appliances.
20. Office supplies, printing and station- ery.
21. Janitor, washroom, first aid supplies, etc.
22. Employees’ transportation and travel expenses.
23. Utility services: light, water, telephone.
Amounts billed customers for any work, the cost of which is charged to this account, shall be credited to this account. Any excess over costs resulting therefrom shall be transferred to account 488, Miscellaneous Service Revenues.
This account shall include the cost of distribution maps and records, distribution office expenses, and the cost of labor and materials used and expenses incurred in distribution systems operations not provided for elsewhere, including the expenses of operating street lighting systems and research, development, and demonstration expenses.
This account shall include rents for property of others used, occupied or operated in connection with the operation of the distribution system. Include herein rentals paid for regulator sites, railroad crossings, rights-of-way, annual payments to governmental bodies and others for use of public or private lands, and reservations for rights-of-way. (See operating expense instruction 3.)
This account shall include the cost of labor and expenses incurred in the general supervision and direction of maintenance of distribution system facilities. Direct field supervision of specific jobs shall be charged to the appropriate maintenance accounts. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of structures, the book cost of which is includible in account 375, Structures and Improvements. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of distribution mains, the book cost of which is includible in account 376, Mains. (See operating expense instruction 2.)
1. Supervising.
2. Trenching, backfilling, and breaking and restoring pavement in connection with the installation of leak or reinforcing clamps.
3. Work performed as the result of municipal improvements, such as street widening, sewers, etc., where the gas mains are not retired.
4. Municipal inspections relating to maintenance work.
5. Other work of the following character:
a. Locating leaks incident to maintenance.
b. Cutting off mains without replacement. (Minor cuts not retired.)
c. Repairing leaking joints.
d. Repairing broken mains.
e. Repairing leaks on main drip riser or valve test pipe.
f. Bringing main valve box, main drip riser box, valve test pipe box, or pressure pipe roadway box up to grade.
g. Cleaning, repainting, coating, and wrapping exposed mains.
h. Repacking main valves.
i. Locating and clearing gas main faults.
j. Lowering and changing location of mains.
k. Trenching, backfilling, cutting-in or removal of pipe not retired in connection with the installation of leak clamps, valves, or drips.
l. Watching and lamping open cuts associated with maintenance.
m. Restoration of permanent pavement in connection with work chargeable to maintenance.
n. Emergency stand-by time associated with maintenance.
o. Repairing sewers, drains, walls, etc., when damaged by maintenance work.
p. Making electrolysis tests to maintain life of plant.
q. Repairing property of others damaged by maintenance work.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 377, Compressor Station Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 378, Measuring and Regulating Station Equipment—General. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 385, Industrial Measuring and Regulating Station Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of equipment, the book cost of which is includible in account 379, Measuring and Regulating Station Equipment—City Gate Check Stations. (See operating expense instruction 2.)
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of services, the book cost of which is includible in account 380, Services. (See operating expense instruction 2.)
1. Supervising.
2. Testing pipe for leaks and condition of wrapping.
3. Testing for, locating, and clearing trouble on company maintained services.
4. Inspecting and testing after repairs have been made.
5. Reporting on the condition of gas services to determine the need for repairs.
6. Making minor repairs and changes.
7. Rearranging and changing the location of services not retired.
8. Repairing service valves for reuse.
9. Stopping leaks on service pipes and drip risers.
10. Lowering and raising curb boxes to grade.
11. Replacing less than a complete service when not retired.
12. Installing fittings, valves, drips, frost protection devices, or replacing similar items on existing services.
13. Cutting and replacing pavement, pavement base and sidewalks in connection with maintenance work.
14. Restoring condition of services damaged by fire, storm, leakage, flood, accident or other casualties.
15. Repairing property of others damaged by maintenance work.
16. Transferring services in connection with the installation of new mains.
17. Installing, maintaining, and removing temporary facilities to prevent the interruption of service.
18. Converting low pressure gas distribution service to medium or high pressure service.
19. Relocating and rerouting gas service temporarily during alterations of buildings.
20. Performing work resulting from municipal improvements, such as street widening, sewers, etc.
21. Replacing service valve box or drip riser box.
22. Installing, removing or replacing service valve, drip pot, or drip riser.
23. Repacking service valve.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of meters and house regulators, the book cost of which is includible in accounts 381, Meters, and 383, House Regulators. (See operating expense instruction 2.)
1. Inspecting and testing meters and house regulators on customers’ premises or in shops in connection with repairs.
2. Cleaning, repairing, and painting meters, house regulators, and accessories and equipment.
3. Repairing testing equipment.
4. Rebuilding and overhauling meters without changing their rated capacities.
5. Resealing house regulators with mercury, replacing diaphragms, springs and other defective or worn parts.
6. Replacing or adding any item not constituting a retirement unit.
This account shall include the cost of labor, materials used and expenses incurred in the maintenance of street lighting equipment and all other distribution system equipment not provided for elsewhere, the book cost of which is includible in accounts 386, Other Property on Customers’ Premises, and 387, Other Equipment. (See operating expense instruction 2.)
This account shall include the cost of labor and expenses incurred in the general direction and supervision of customer accounting and collecting activities. Direct supervision of a specific activity shall be charged to account 902, Meter Reading Expenses, or account 903, Customer Records and Collection Expenses, as appropriate. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in reading customer meters, and determining consumption when performed by employees engaged in reading meters.
1. Addressing forms for obtaining meter readings by mail.
2. Changing and collecting meter charts used for billing purposes.
3. Inspecting time clocks, checking seals, etc., when performed by meter readers and the work represents a minor activity incidental to regular meter reading routine.
4. Meter reading—small consumption, and obtaining load information for billing purposes. (Exclude and charge to account 878, Meter and House Regulator Expenses, or to account 903, Customer Records and Collection Expenses, as applicable, the cost of obtaining meter readings, first and final, if incidental to the operation of removing or resetting, sealing or locking, and disconnecting, or reconnecting meters.)
5. Measuring gas—large consumption, including reading meters, changing charts, calculating charts, estimating lost meter registrations, determining specific gravity, etc., for billing purposes.
6. Computing consumption from meter reader’s book or from reports by mail when done by employees engaged in reading meters.
7. Collecting from prepayment meters when incidental to meter reading.
8. Maintaining record of customers’ keys.
9. Computing estimated or average consumption when performed by employees engaged in reading meters.
10. Badges, lamps, and uniforms.
11. Demand charts, meter books and binders and forms for recording readings, but not the cost of preparation.
12. Postage and supplies used in obtaining meter readings by mail.
13. Transportation, meals and incidental expenses.
This account shall include the cost of labor, materials used and expenses incurred in work on customer applications, contracts, orders, credit investigations, billing and accounting, collections and complaints.
1. Receiving, preparing, recording and handling routine orders for service, disconnections, transfers or meter tests initiated by the customer, excluding the cost of carrying out such orders, which is chargeable to the account appropriate for the work called for by such orders.
2. Investigations of customers’ credit and keeping of records pertaining thereto, including records of uncollectible accounts written off.
3. Receiving, refunding or applying customer deposits and maintaining customer deposit, line extension, and other miscellaneous records.
4. Checking consumption shown by meter readers’ reports where incidental to preparation of billing data.
5. Preparing address plates and addressing bills and delinquent notices.
6. Preparing billing data.
7. Operating billing and bookkeeping machines.
8. Verifying billing records with contracts or rate schedules.
9. Preparing bills for delivery, and mailing or delivering bills.
10. Collecting revenues, including collection from prepayment meters unless incidental to meter reading operations.
11. Balancing collections, preparing collections for deposit, and preparing cash reports.
12. Posting collections and other credits or charges to customer accounts and extending unpaid balances.
13. Balancing customer accounts and controls.
14. Preparing, mailing, or delivering delinquent notices and preparing reports of delinquent accounts.
15. Final meter reading of delinquent accounts when done by collectors incidental to regular activities.
16. Disconnecting and reconnecting services because of nonpayment of bills.
17. Receiving, recording, and handling of inquiries, complaints, and requests for investigations from customers, including preparation of necessary orders, but excluding the cost of carrying out such orders, which is chargeable to the account appropriate for the work called for by such orders.
18. Statistical and tabulating work on customer accounts and revenues, but not including special analyses for sales department, rate department, or other general purposes, unless incidental to regular customer accounting routines.
19. Preparing and periodically rewriting meter reading sheets.
20. Determining consumption and computing estimated or average consumption when performed by employees other than those engaged in reading meters.
21. Address plates and supplies.
22. Cash overages and shortages.
23. Commissions or fees to others for collecting.
24. Payments to credit organizations for investigations and reports.
25. Postage.
26. Transportation expenses, including transportation of customer bills and meter books under centralized billing procedure.
27. Transportation, meals, and incidental expenses.
28. Bank charges, exchange, and other fees for cashing and depositing customers’ checks.
29. Forms for recording orders for services, removals, etc.
30. Rent of mechanical equipment.
The cost of work on meter history and meter location records is chargeable to account 878, Meter and House Regulator Expenses.
This account shall be charged with amounts sufficient to provide for losses from uncollectible utility revenues. Concurrent credits shall be made to account 144, Accumulated Provision for Uncollectible Accounts—Credit. Losses from uncollectible accounts shall be charged to account 144.
This account shall include the cost of labor, materials used and expenses incurred not provided for in other accounts.
1. General clerical and stenographic work.
2. Miscellaneous labor.
3. Communication service.
4. Miscellaneous office supplies and expenses and stationery and printing other than those specifically provided for in accounts 902 and 903.
This account shall include the cost of labor and expenses incurred in the general direction and supervision of customer service activities, the object of which is to encourage safe, efficient and economical use of the utility’s service. Direct supervision of a specific activity within customer service and informational expense classification shall be charged to the account wherein the costs of such activity are included. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used, and expenses incurred in providing instructions or assistance to customers, the object of which is to promote safe, efficient and economical use of the utility’s service.
1. Direct supervision of department.
2. Processing customer inquiries relating to the proper use of gas equipment, the replacement of such equipment and information related to such equipment.
3. Advice directed to customers as to how they may achieve the most efficient and safest use of gas equipment.
4. Demonstrations, exhibits, lectures, and other programs designed to instruct customers in the safe, economical or efficient use of gas service, and/or oriented toward conservation of energy.
5. Engineering and technical advice to customers, the object of which is to promote safe, efficient and economical use of the utility’s service.
6. Supplies and expenses pertaining to demonstrations, exhibits, lectures, and other programs.
7. Loss in value on equipment and appliances used for customer assistance programs.
8. Office supplies and expenses.
9. Transportation, meals, and incidental expenses.
Do not include in this account expenses that are provided for elsewhere, such as accounts 416, Costs and Expenses of Merchandising, Jobbing and Contract Work, 879, Customer Installations Expenses, and 912, Demonstrating and Selling Expenses.
This account shall include the cost of labor, materials used and expenses incurred in activities which primarily convey information as to what the utility urges or suggests customers should do in utilizing gas service to protect health and safety, to encourage environmental protection, to utilize their gas equipment safely and economically, or to conserve natural gas.
1. Direct supervision of informational activities.
2. Preparing informational materials for newspapers, periodicals, billboards, etc., and preparing and conducting informational motion pictures, radio and television programs.
3. Preparing informational booklets, bulletins, etc., used in direct mailings.
4. Preparing informational window and other displays.
5. Employing agencies, selecting media and conducting negotiations in connection with the placement and subject matter of information programs.
6. Use of newspapers, periodicals, billboards, radio, etc., for informational purposes.
7. Postage on direct mailings to customers exclusive of postage related to billings.
8. Printing of informational booklets, dodgers, bulletins, etc.
9. Supplies and expenses in preparing informational materials by the utility.
10. Office supplies and expenses.
Exclude from this account and charge to account 930.2, Miscellaneous General Expenses, the cost of publication of stockholder reports, dividend notices, bond redemption notices, financial statements, and other notices of a general corporate character. Exclude also all expenses of a promotional, institutional, goodwill or political nature, which are includible in such accounts as 913, Advertising Expenses, 930.1, General Advertising Expenses, and 426.4, Expenditures for Certain Civic, Political and Related Activities.
Entries relating to informational advertising included in this account shall contain or refer to supporting documents which identify the specific advertising message. If references are used, copies of the advertising message shall be readily available.
This account shall include the cost of labor, materials used and expenses incurred in connection with customer service and informational activities which are not includible in other customer information expense accounts.
1. General clerical and stenographic work not assigned to specific customer service and information programs.
2. Miscellaneous labor.
3. Communication service.
4. Printing, postage and office supplies expenses.
This account shall include the cost of labor and expenses incurred in the general direction and supervision of sales activities, except merchandising. Direct supervision of a specific activity, such as demonstrating, selling, or advertising shall be charged to the account wherein the costs of such activity are included. (See operating expense instruction 1.)
This account shall include the cost of labor, materials used and expenses incurred in promotional, demonstrating, and selling activities, except by merchandising, the object of which is to promote or retain the use of utility services by present and prospective customers.
1. Demonstrating uses of utility services.
2. Conducting cooking schools, preparing recipes, and related home service activities.
3. Exhibitions, displays, lectures, and other programs designed to promote use of utility services.
4. Experimental and development work in connection with new and improved appliances and equipment, prior to general public acceptance.
5. Solicitation of new customers or of additional business from old customers, including commissions paid employees.
6. Engineering and technical advice to present or prospective customers in connection with promoting or retaining the use of utility services.
7. Special customer canvasses when their primary purpose is the retention of business or the promotion of new business.
8. Supplies and expenses pertaining to demonstration, and experimental and development activities.
9. Booth and temporary space rental.
10. Loss in value on equipment and appliances used for demonstration purposes.
11. Transportation, meals, and incidental expenses.
This account shall include the cost of labor, materials used and expenses incurred in advertising designed to promote or retain the use of utility service, except advertising the sale of merchandise by the utility.
1. Direct supervision of department.
2. Preparing advertising material for newspapers, periodicals, billboards, etc., and preparing and conducting motion pictures, radio and television programs.
3. Preparing booklets, bulletins, etc., used in direct mail advertising.
4. Preparing window and other displays.
5. Clerical and stenographic work.
6. Investigating advertising agencies and media and conducting negotiations in connection with the placement and subject matter of sales advertising.
7. Advertising in newspapers, periodicals, billboards, radio, etc., for sales promotion purposes, but not including institutional or goodwill advertising includible in account 930.1, General Advertising Expenses.
8. Materials and services given as prizes or otherwise in connection with canning, or cooking contests, bazaars, etc., in order to publicize and promote the use of utility services.
9. Fees and expenses of advertising agencies and commercial artists.
10. Novelties for general distribution.
11. Postage on direct mail advertising.
12. Premiums distributed generally, such as recipe books, etc., when not offered as inducement to purchase appliances.
13. Printing booklets, dodgers, bulletins, etc.
14. Supplies and expenses in preparing advertising material.
15. Office supplies and expenses.
The cost of advertisements which set forth the value or advantages of utility service without reference to specific appliances, or, if reference is made to appliances, invites the reader to purchase appliances from his dealer, or refer to appliances not carried for sale by the utility, shall be considered sales promotion advertising and charged to this account. However, advertisements which are limited to specific makes of appliances sold by the utility and prices, terms, etc., thereof, without referring to the value or advantages of utility service, shall be considered as merchandise advertising and the cost shall be charged to Costs and Expenses of Merchandising, Jobbing and Contract Work, accounts 416.
Advertisements which substantially mention or refer to the value or advantages of utility service, together with specific reference to makes of appliances sold by the utility and the price, terms, etc., thereof, and designed for the joint purpose of increasing the use of utility service and the sales of appliances, shall be considered as a combination advertisement and the costs shall be distributed between this account and account 416 on the basis of space, time, or other proportional factors.
Exclude from this account and charge to account 930.2, Miscellaneous General Expenses, the cost of publication of stockholder reports, dividend notices, bond redemption notices, financial statements, and other notices of a general corporate character. Exclude also all institutional or goodwill advertising. (See account 930.1, General Advertising Expenses.)
This account shall include the cost of labor, materials used and expenses incurred in connection with sales activities, except merchandising, which are not includible in other sales expense accounts.
1. General clerical and stenographic work not assigned to specific functions.
2. Special analysis of customer accounts and other statistical work for sales purposes not a part of the regular customer accounting and billing routine.
3. Miscellaneous labor.
4. Communication service.
5. Printing, postage, and office supplies and expenses applicable to sales activities, except those chargeable to account 913, Advertising Expenses.
A. This account shall include the compensation (salaries, bonuses, and other consideration for services, but not including directors’ fees) of officers, executives, and other employees of the utility properly chargeable to utility operations and not chargeable directly to a particular operating function.
B. This account may be subdivided in accordance with a classification appropriate to the departmental or other functional organization of the utility.
A. This account shall include office supplies and expenses incurred in connection with the general administration of the utility’s operations which are assignable to specific administrative or general departments and are not specifically provided for in other accounts. This includes the expenses of the various administrative and general departments, the salaries and wages of which are includible in account 920.
B. This account may be subdivided in accordance with a classification appropriate to the departmental or other functional organization of the utility.
Office expenses which are clearly applicable to any group of operating expenses other than the administrative and general group shall be included in the appropriate account in such group. Further, general expenses which apply to the utility as a whole rather than to a particular administrative function shall be included in account 930.2, Miscellaneous General Expenses.
1. Automobile service, including charges through clearing account.
2. Bank messenger and service charges.
3. Books, periodicals, bulletins and subscriptions to newspapers, newsletters, tax services, etc.
4. Building service expenses for customer accounts, sales, and administrative and general purposes.
5. Communication service expenses.
6. Cost of individual items of office equipment used by general departments which are of small value or short life.
7. Membership fees and dues in trade, technical, and professional associations paid by a utility for employees. (Company memberships are includible in account 930.2.)
8. Office supplies and expenses.
9. Payment of court costs, witness fees, and other expenses of legal department.
10. Postage, printing and stationery.
11. Meals, traveling and incidental expenses.
This account shall be credited with administrative expenses recorded in accounts 920 and 921 which are transferred to construction costs or to nonutility accounts. (See gas plant instruction 4.)
A. This account shall include the fees and expenses of professional consultants and others for general services which are not applicable to a particular operating function or to other accounts. It shall include also the pay and expenses of persons engaged for a special or temporary administrative or general purpose in circumstances where the person so engaged is not considered as an employee of the utility.
B. This account shall be so maintained as to permit ready summarization according to the nature of service and the person furnishing the same.
1. Fees, pay and expenses of accountants and auditors, actuaries, appraisers, attorneys, engineering consultants, management consultants, negotiators, public relations counsel, tax consultants, etc.
2. Supervision fees and expenses paid under contracts for general management services.
Do not include inspection and brokerage fees and commissions chargeable to other accounts or fees and expenses in connection with security issues which are includible in the expenses of issuing securities.
A. This account shall include the cost of insurance or reserve accruals to protect the utility against losses and damages to owned or leased property used in its utility operations. It shall include also the cost of labor and related supplies and expenses incurred in property insurance activities.
B. Recoveries from insurance companies or others for property damages shall be credited to the account charged with the cost of the damage. If the damaged property has been retired, the credit shall be to the appropriate account for accumulated provision for depreciation.
C. Records shall be kept so as to show the amount of coverage for each class of insurance carried, the property covered, and the applicable premiums. Any dividends distributed by mutual insurance companies shall be credited to the accounts to which the insurance premiums were charged.
1. Premiums payable to insurance companies for fire, storm, burglary, boiler explosion, lightning, fidelity, riot, and similar insurance.
2. Amounts credited to account 228.1, Accumulated Provision for Property Insurance; for similar protection.
3. Special costs incurred in procuring insurance.
4. Insurance inspection service.
5. Insurance counsel, brokerage fees, and expenses.
The cost of insurance or reserve accruals capitalized shall be charged to construction either directly or by transfer to construction work orders from this account.
The cost of insurance or reserve accruals for the following classes of property shall be charged as indicated.
(1) Materials and supplies and stores equipment, to account 163, Stores Expense Undistributed or appropriate materials account.
(2) Transportation and other general equipment to appropriate clearing accounts that may be maintained.
(3) Gas plant leased to others, to account 413, Expenses of Gas Plant Leased to Others.
(4) Nonutility property, to the appropriate nonutility income account.
(5) Merchandise and jobbing property, to account 416, Costs and Expenses of Merchandising, Jobbing and Contract Work.
The cost of labor and related supplies and expenses of administrative and general employees, who are only incidentally engaged in property insurance work, may be included in accounts 920 and 921, as appropriate.
A. This account shall include the cost of insurance or reserve accruals to protect the utility against injuries and damages claims of employees or others, losses of such character not covered by insurance, and expenses incurred in settlement of injuries and damages claims. It shall also include the cost of labor and related supplies and expenses incurred in injuries and damages activities.
B. Reimbursements from insurance companies or others for expenses charged hereto on account of injuries and damages and insurance dividends or refunds shall be credited to this account.
1. Premiums payable to insurance companies for protection against claims from injuries and damages by employees or others, such as public liability, property damages, casualty, employee liability, etc., and amounts credited to account 228.2, Accumulated Provision for Injuries and Damages; for similar protection.
2. Losses not covered by insurance or reserve accruals on account of injuries or deaths to employees or others and damages to the property of others.
3. Fees and expenses of claim investigators.
4. Payment of awards to claimants for court costs and attorneys’ services.
5. Medical and hospital service and expenses for employees as the result of occupational injuries, or resulting from claims of others.
6. Compensation payments under workmen’s compensation laws.
7. Compensation paid while incapacitated as the result of occupational injuries. (See Note A.)
8. Cost of safety, accident prevention and similar educational activities.
Payments to or in behalf of employees for accident or death benefits, hospital expenses, medical supplies or for salaries while incapacitated for service or on leave of absence beyond periods normally allowed, when not the result of occupational injuries, shall be charged to account 926, Employee Pensions and Benefits. (See also Note B of account 926.)
The cost of injuries and damages or reserve accruals capitalized shall be charged to construction directly or by transfer to construction work orders from this account.
Exclude herefrom the time and expenses of employees (except those engaged in injuries and damages activities) spent in attendance at safety and accident prevention educational meetings, if occurring during the regular work period.
The cost of labor and related supplies and expenses of administrative and general employees, who are only incidentally engaged in injuries and damages activities, may be included in accounts 920 and 921, as appropriate.
A. This account shall include pensions paid to or on behalf of retired employees, or accruals to provide for pensions, or payments for the purchase of annuities for this purpose, when the utility has definitely, by contract, committed itself to a pension plan under which the pension funds are irrevocably devoted to pension purposes, and payments for employee accident, sickness, hospital, and death benefits, or insurance therefor. Include, also, expenses incurred in medical, educational or recreational activities for the benefit of employees, and administrative expenses in connection with employee pensions and benefits.
B. The utility shall maintain a complete record of accruals or payments for pensions and be prepared to furnish full information to the Commission of the plan under which it has created or proposes to create a pension fund and a copy of the declaration of trust or resolution under which the pension plan is established.
C. There shall be credited to this account the portion of pensions and benefits expenses which is applicable to nonutility operations or which is charged to construction unless such amounts are distributed directly to the accounts involved and are not included herein in the first instance.
D. Records in support of this account shall be so kept that the total pensions expense, the total benefits expense, the administrative expenses included herein, and the amounts of pensions and benefits expenses transferred to construction or other accounts will be readily available.
1. Payment of pensions under a nonaccrual or nonfunded basis.
2. Accruals for or payments to pension funds or to insurance companies for pension purposes.
3. Group and life insurance premiums (credit dividends received).
4. Payments for medical and hospital services and expenses of employees when not the result of occupational injuries.
5. Payments for accident, sickness, hospital, and death benefits or insurance.
6. Payments to employees incapacitated for service or on leave of absence beyond periods normally allowed, when not the result of occupational injuries, or in excess of statutory awards.
7. Expenses in connection with educational and recreational activities for the benefit of employees.
The cost of labor and related supplies and expenses of administrative and general employees who are only incidentally engaged in employee pension and benefit activities, may be included in accounts 920 and 921, as appropriate.
Salaries paid to employees during periods of nonoccupational sickness may be charged to the appropriate labor account rather than to employee benefits.
A. This account shall include payments to municipal or other governmental authorities, and the cost of materials, supplies and services furnished such authorities without reimbursement in compliance with franchise, ordinance, or similar requirements; provided, however, that the utility may charge to this account at regular tariff rates, instead of cost, utility service furnished without charge under provisions of franchises.
B. When no direct outlay is involved, concurrent credit for such charges shall be made to account 929, Duplicate Charges—Cr.
C. The account shall be maintained so as to readily reflect the amounts of cash outlays, utility service supplied without charge, and other items furnished without charge.
Franchise taxes shall not be charged to this account but to account 408.1, Taxes Other Than Income Taxes, Utility Operating Income.
Any amount paid as initial consideration for a franchise running for more than one year shall be charged to account 302, Franchises and Consents.
A. This account shall include all expenses (except pay of regular employees only incidentally engaged in such work) properly includible in utility operating expenses, incurred by the utility in connection with formal cases before regulatory commissions, or other regulatory bodies, or cases in which such a body is a party, including payments made to a regulatory commission for fees assessed against the utility for pay and expenses of such commission, its officers, agents, and employees.
B. Amounts of regulatory commission expenses which by approval or direction of the Commission are to be spread over future periods shall be charged to account 186, Miscellaneous Deferred Debits, and amortized by charges to this account.
C. The utility shall be prepared to show the cost of each formal case.
1. Salaries, fees, retainers, and expenses of counsel, solicitors, attorneys, accountants, engineers, clerks, attendants, witnesses, and others engaged in the prosecution of, or defense against petitions or complaints presented to regulatory bodies, or in the valuation of property owned or used by the utility in connection with such cases.
2. Office supplies and expenses, payments to public service or other regulatory commissions, stationery and printing, traveling expenses, and other expenses incurred directly in connection with formal cases before regulatory commissions.
3. All application fees except those involving construction certificate applications which have been approved. (See Gas Plant Instruction 16.)
Exclude from this account and include in other appropriate operating expense accounts, expenses incurred in the improvement of service, additional inspection, or rendering reports, which are made necessary by the rules and regulations, or orders, of regulatory bodies.
Do not include in this account amounts includible in account 302, Franchises and Consents, account 181, Unamortized Debt Expense, or account 214, Capital Stock Expense.
This account shall include concurrent credits for charges which may be made to operating expenses or to other accounts for the use of utility service from its own supply. Include, also, offsetting credits for any other charges made to operating expenses for which there is no direct money outlay.
This account shall include the cost of labor, materials used, and expenses incurred in advertising and related activities, the cost of which by their content and purpose are not provided for elsewhere.
1. Supervision.
2. Preparing advertising material for newspapers, periodicals, billboards, etc., and preparing or conducting motion pictures, radio and television programs.
3. Preparing booklets, bulletins, etc., used in direct mail advertising.
4. Preparing window and other displays.
5. Clerical and stenographic work.
6. Investigating and employing advertising agencies, selecting media and conducting negotiations in connection with the placement and subject matter of advertising.
7. Advertising in newspapers, periodicals, billboards, radio, etc.
8. Advertising matter such as posters, bulletins, booklets and related items.
9. Fees and expenses of advertising agencies and commercial artists.
10. Postage and direct mail advertising.
11. Printing of booklets, dodgers, bulletins, etc.
12. Supplies and expenses in preparing advertising materials.
13. Office supplies and expenses.
Properly includible in this account is the cost of advertising activities on a local or national basis of a goodwill or institutional nature, which is primarily designed to improve the image of the utility or the industry, including advertisements which inform the public concerning matters affecting the company’s operations, such as, the cost of providing service, the company’s efforts to improve the quality of service, the company’s efforts to improve and protect the environment, etc. Entries relating to advertising included in this account shall contain or refer to supporting documents which identify the specific advertising message. If references are used, copies of the advertising message shall be readily available.
Exclude from this account and include in account 426.4. Expenditures for Certain Civic, Political and Related Activities, expenses for advertising activities, which are designed to solicit public support or the support of public officials in matters of a political nature.
This account shall include the cost of labor and expenses incurred in connection with the general management of the utility not provided for elsewhere.
1. Miscellaneous labor not elsewhere provided for:
2. Industry Association dues for company memberships.
3. Contributions for conventions and meetings of the industry.
4. Research, development, and demonstration expenses not charged to other operation and maintenance expense accounts on a functional basis.
5. Communication service not chargeable to other accounts.
6. Trustee, registrar, and transfer agent fees and expenses.
7. Stockholders meeting expenses.
8. Dividend and other financial notices.
9. Printing and mailing dividend checks.
10. Directors’ fees and expenses.
11. Publishing and distributing annual reports to stockholders.
12. Public notices of financial, operating, and other data required by regulatory statutes, not including, however, notices required in connection with security issues or acquisitions of property.
This account shall include rents properly includible in utility operating expenses for the property of others used, occupied, or operated in connection with the customer accounts, customer service and informational, sales, and general and administrative functions of the utility. (See operating expense instruction 3.)
A. This account shall include the cost assignable to customer accounts, sales and administrative and general functions of labor, materials used and expenses incurred in the maintenance of property, the book cost of which is includible in account 390, Structures and Improvements, account 391, Office Furniture and Equipment, account 397, Communication Equipment, and account 398, Miscellaneous Equipment. (See operating expense instruction 2.)
B. Maintenance expenses on office furniture and equipment used elsewhere than in general, commercial and sales offices shall be charged to the following accounts:
Maintenance of plant included in other general plant equipment accounts shall be included herein unless charged to clearing accounts or to a particular functional maintenance expense indicated by the use of the equipment.
PART 204—RESERVED [NOTE]
For the Uniform System of Accounts for Natural Gas Companies subject to the Natural Gas Act, see part 201 of this subchapter. (Order 390, 49 FR 32526, Aug. 14, 1984; 50 FR 5745, Feb. 12, 1985)
PART 225—PRESERVATION OF RECORDS OF NATURAL GAS COMPANIES
§ 225.1 Promulgation.
This part is prescribed and promulgated as the regulations governing the preservation of records by natural gas companies subject to the jurisdiction of the Commission, to the extent and in the manner set forth therein.
§ 225.2 General instructions.
(a) Scope of this part. (1) The regulations in this part must apply to all books of account and other records prepared by or on behalf of the natural gas company. See item 40 of the schedule for those records that come into possession of the natural gas company in connection with the acquisition of property, such as purchases, consolidation, merger, etc.
(2) The regulations in this part should not be construed as excusing compliance with other lawful requirements of any other governmental body, Federal or State, prescribing other record keeping requirements, or for preservation of records for periods longer than those prescribed in this part.
(3) To the extent that any Commission regulations may provide for a different retention period, the records should be retained for the longer of the retention periods.
(4) Records other than those listed in the schedule may be destroyed at the option of the natural gas company: Provided, however, That records which are used in lieu of those listed shall be preserved for the periods prescribed for the records used for substantially similar purposes. And, provided further, That retention of records pertaining to added services, functions, plant, etc., the establishment of which cannot be presently foreseen, shall conform to the principles embodied herein.
(5) Notwithstanding the provisions of the Records Retention Schedule, the Commission may, upon the request of the company, authorize a shorter period of retention for any record listed therein upon a showing by the company that preservation of such record for a longer period is not necessary or appropriate in the public interest or for the protection of investors or consumers.
(b) Designation of supervisory official. Each natural gas company subject to the regulations in this part shall designate one or more persons with official responsibility to supervise the natural gas company’s program for preservation and the authorized destruction of its records.
(c) Protection and storage of records. The natural gas company shall provide reasonable protection for records subject to the regulations in this part from damage by fires, floods, and other hazards and, in the selection of storage spaces, safeguard the records from unnecessary exposure to deterioration from excessive humidity, dryness, or lack of proper ventilation.
(d) Record storage media. Each natural gas company has the flexibility to select its own storage media subject to the following conditions.
(1) The storage media must have a life expectancy at least equal to the applicable record retention period provided in § 225.3 unless there is a quality transfer from one media to another with no loss of data.
(2) Each natural gas company is required to implement internal control procedures that assure the reliability of and ready access to data stored on machine readable media. Internal control procedures must be documented by a responsible supervisory official.
(3) Each transfer of data from one media to another must be verified for accuracy and documented. Software and hardware required to produce readable records must be retained for the same period the media format is used.
(e) Destruction of records. At the expiration of the records retention period, natural gas companies may use any appropriate method to destroy records.
(f) Premature destruction or loss of records. When records are destroyed or lost before the expiration of the prescribed period of retention, a certified statement listing, as far as may be determined, the records destroyed and describing the circumstances of accidental or other premature destruction or loss must be filed with the Commission within ninety (90) days from the date of discovery of the destruction.
(g) Schedule of records and periods of retention. (1) Records related to plant in service must be retained until the facilities are permanently removed from service, all removal and restoration activities are completed, and all costs are retired from the accounting records unless accounting adjustments resulting from reclassification and original costs studies have been approved by the regulatory commission having jurisdiction. If the plant is sold, the associated records or copies thereof, must be transferred to the new owners.
(2) Records related to additions, retirements, and betterments thereto must be retained until the Commission has determined the actual legitimate original cost of the facilities.
(h) Retention periods designated “Destroy at option”. “Destroy at option” constitutes authorization for destruction of records at managements’ discretion if it does not conflict with other legal retention requirements or usefulness of such records in satisfying pending regulatory actions or directives.
(i) Records of services performed by associated companies. The natural gas companies must assure the availability of records of services performed by associated or affiliated companies with supporting cost information for the periods indicated in § 225.3 as necessary to be able to readily furnish detailed information as to the nature of the transaction, the amounts involved, and the accounts used to record the transactions.
(j) Index of records. Natural gas companies must arrange, file, and index records so they may be readily identified and made available to Commission representatives.
(k) Rate case. Notwithstanding the minimum retention periods provided in these regulations, if a natural gas company intends to reflect costs in a current, pending, or future rate case, or if a natural gas company has abandoned or retired a plant subsequent to the test period of its last rate case, it must retain all relevant records.
(l) Pending complaint litigation or governmental proceeding. Notwithstanding the minimum requirements, if a natural gas company is involved in pending litigation, complaint procedures, proceedings remanded by the court, or governmental proceedings, it must retain all relevant records.
(m) Life or mortality study data. Life or mortality study data for depreciation purposes must be retained for 25 years or for 10 years after plant is retired whichever is longer.
§ 225.3 Schedule of records and periods of retention.
Schedule of Records and Periods of Retention
| Item No. and description | Retention period |
|---|---|
| 1. Reports to stockholders: Annual reports or statements to stockholders | 5 years. |
| 2. Organizational documents: | |
| (a) Minute books of stockholders’, directors’, and directors’ committee meetings | 5 years or termination of the corporation’s existence, whichever occurs first. |
| (b) Titles, franchises, and licenses: Copies of formal orders of regulatory commissions served upon the natural gas company | 6 years after final non-appealable order. |
| 3. Contracts including amendments and agreements (except contracts provided for elsewhere): | |
| (a) Service contracts, such as for management, accounting, and financial services | All contracts, related memoranda, and revisions should be retained for 4 years after expiration or until the conclusion of any contract disputes pertaining to such contracts, whichever is later. |
| (b) Contracts with others for transportation or for the purchase, sale or interchange of product | All contracts, related memoranda, and revisions should be retained for 4 years after expiration or until the conclusion of any contract disputes or governmental proceedings pertaining to such contracts, whichever is later. |
| (c) Memoranda essential to clarifying or explaining provisions of contracts listed above, including requests for discounts | For the same periods as contracts to which they relate. |
| (d) Card or book records of contracts, leases, and agreements made that show dates of expirations, renewals, memoranda of receipts, and payments under such contracts | For the same periods as contracts to which they relate. |
| 4. Accountants’ and auditors’ reports: | |
| (a) Reports of examinations and audits by accountants and auditors not in the regular employ of the natural gas company (such as reports of public accounting firms and Commission accountants) | 5 years after the date of the report. |
| (b) Internal audit reports and working papers | 5 years after the date of the report. |
| 5. Automatic data processing records (retain original source data used as input for data processing and data processing report printouts for the applicable periods prescribed elsewhere in the schedule): Software program documentation and revisions thereto. | Retain as long as it represents an active viable program or for periods prescribed for related output data, whichever is shorter. |
| 6. General and subsidiary ledgers: | |
| (a) Ledgers: | |
| (1) General ledgers | 10 years. |
| (2) Ledgers subsidiary or auxiliary to general ledgers except ledgers provided for elsewhere | 10 years. |
| (b) Indexes: | |
| (1) Indexes to general ledgers | 10 years. |
| (2) Indexes to subsidiary ledgers except ledgers provided for elsewhere | 10 years. |
| (c) Trial balance sheets of general and subsidiary ledgers | 2 years. |
| 7. Journals: General and subsidiary | 10 years. |
| 8. Journal vouchers and journal entries including supporting detail: | |
| (a) Journal vouchers and journal entries | 10 years. |
| (b) Analyses, summarizations, distributions, and other computations which support journal vouchers and journal entries: | |
| (1) Charging plant accounts | 25 years. See § 225.2(g). |
| (2) Charging all other accounts | 6 years. |
| 9. Cash books: General and subsidiary or auxiliary books | 5 years after close of fiscal year. |
| 10. Voucher registers: Voucher registers or similar records when used as a source document | 5 years. See § 225.2(g). |
| 11. Vouchers: | |
| (a) Paid and canceled vouchers (1 copy-analysis sheets showing detailed distribution of charges on individual vouchers and other supporting papers) | 5 years. See § 225.2(g). |
| (b) Original bills and invoices for materials, services, etc., paid by vouchers | 5 years. See § 225.2(g). |
| (c) Paid checks and receipts for payments of specific vouchers | 5 years. |
| (d) Authorization for the payment of specific vouchers | 5 years. See § 225.2(g). |
| (e) Lists of unaudited bills (accounts payable), list of vouchers transmitted, and memoranda regarding changes in audited bills | Destroy at option. |
| (f) Voucher indexes | Destroy at option. |
| 12. Insurance records: | |
| (a) Records of insurance policies in force, showing coverage, premiums paid, and expiration dates | Destroy at option after expiration. |
| (b) Records of amounts recovered from insurance companies in connection with losses and of claims against insurance companies, including reports of losses, and supporting papers | 6 years. See § 225.2(g). |
| 13. Production—Gas: | |
| (a) Recording instrument charts such as pressure (static and/or differential), temperature, specific gravity, heating value, etc | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| (b) Test of heating value at stations and outlying points | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| (c) Records of gas produced, out, and holder stock | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| (d) Analysis of (gas produced) B.T.U. and sulphur content | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| (e) Well records, including clearing, bailing, shooting etc., records; rock pressure; open flow; production, gas analysts’ reports etc | 1 year after field or relevant production area abandoned |
| (f) Gas measuring records | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| 14. Transmission and distribution—Gas: | |
| (a) Substation and transmission line log | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| (b) System operator’s daily logs and reports of operation | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| (c) Gas measuring records | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| (d) Transmission line operating reports | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| (e) Compression operation and reports | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| (f) Recording instrument charts such as pressure (static and/or differential), temperature, specific heating value, etc | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| 14.1 Underground storage of natural gas: | |
| (a) Well records, reports, and logs which include data relating to pressures, injected volumes, withdrawn volumes, core analysis, daily volumes of gas injected into and withdrawn from reservoir, cushion, and working gas volumes for each reservoir | 1 year after reservoir, field, or relevant storage area is abandoned. |
| (b) Records containing information relating to reservoir gas leakage, showing the total gas leakage, and recycled gas | 1 year after reservoir, field, or relevant storage area is abandoned. |
| (c) Records on back pressure tests field data | 1 year or until superseded. |
| (d) Records on back pressure test results, gas analysis | 1 year or until superseded. |
| 15. Maintenance work orders and job orders: | |
| (a) Authorizations for expenditures for maintenance work to be covered by work orders, including memoranda showing the estimates of costs to be incurred | 5 years. |
| (b) Work order sheets to which are posted in detail the entries for labor, material, and other charges in connection with maintenance, and other work pertaining to natural gas company operations | 5 years. |
| (c) Summaries of expenditures on maintenance and job orders and clearances to operating other accounts (exclusive of plant accounts) | 5 years. |
| 16. Plant ledgers: | |
| (a) Ledgers of natural gas company’s plant accounts including land and other detailed ledgers showing the cost of plant by class | 25 years. See § 225.2(g). |
| (b) Continuing plant inventory ledger, book or card records showing description, location, quantities, cost, etc., of physical units (or items) of natural gas plant owned | 25 years. See § 225.2(g). |
| 17. Construction work in progress ledgers: | |
| (a) Construction work in progress ledgers | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired. |
| (b) Work order sheets to which are posted in summary form or in detail the entries for labor, materials, and other charges for natural gas company’s plant additions and the entries closing the work orders to plant in service at completion | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired. |
| (c) Authorizations for expenditures for additions to natural gas company plant, including memoranda showing the detailed estimates of cost, and the bases therefor (including original and revised or subsequent authorizations) | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired. |
| (d) Requisitions and registers of authorizations for natural gas company plant expenditures | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired. |
| (e) Completion or performance reports showing comparison between authorized estimates and actual expenditures for natural gas company plant additions | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired. |
| (f) Analysis or cost reports showing quantities of materials used, unit costs, number of man-hours etc., in connection with completed construction project | 5 years after clearance to the plant account, provided continuing plant inventory records are maintained; otherwise 5 years after plant is retired. |
| (g) Records and reports pertaining to progress of construction work, the order in which jobs are to be completed, and similar records which do not form a basis of entries to the accounts | Destroy at option. |
| (h) Well-drilling logs and well construction records | 1 year after field or well is abandoned. |
| 18. Retirement work in progress ledgers, work orders, and supplemental records: | |
| (a) Work order sheets to which are posted the entries for removal costs, materials recovered, and credits to natural gas company plant accounts for cost of plant retirement | 5 years after plant is retired. |
| (b) Authorizations for retirement of natural gas company plant, including memoranda showing the basis for determination of cost of plant to be retired, and estimates of salvage and removal costs | 5 years after plant is retired. |
| (c) Registers of retirement work | 5 years. |
| 19. Summary sheets, distribution sheets, reports, statements, and papers directly supporting debits and credits to natural gas company plant accounts not covered by construction or retirement work orders and their supporting records | 5 years. |
| 20. Appraisals and valuations: | |
| (a) Appraisals and valuations made by the company of its properties or investments or of the properties or investments of any associated companies. Includes all records essential thereto | 3 years after appraisal. |
| (b) Determinations of amounts by which properties or investments of the company or any of its associated companies will be either written up or written down as a result of: | |
| (1) Mergers or acquisitions | 10 years after completion of transaction or as ordered by the Commission. |
| (2) Asset impairments | 10 years after recognition of asset impairment. |
| (3) Other bases | 10 years after the asset was written up or down. |
| 21. The original or reproduction of engineering records, drawings, and other supporting data for proposed or as-constructed gas facilities: Maps, diagrams, profiles, photographs, field survey notes, plot plan, detail drawings, records of engineering studies, and similar records showing the location of proposed or as-constructed facilities | Retained until retired or abandoned. |
| 22. Contracts relating to natural gas plant: | |
| (a) Contracts relating to acquisition or sale of plant | 6 years after plant is retired or sold. |
| (b) The primary records of gas acreage owned, leased or optioned excluding deeds and leases but including such records as lease sheets, leasehold cards, and option agreements | 6 years after plant is retired or sold. |
| 23. Records pertaining to reclassification of natural gas plant accounts to conform to prescribed systems of accounts including supporting papers showing the bases for such reclassifications | 6 years. |
| 24. Records of accumulated provisions for depreciation and depletion of gas plant and supporting computation of expense: | |
| (a) Detailed records or analysis sheets segregating the accumulated depreciation according to functional classification of plant | 25 years. |
| (b) Records reflecting the service life of property and the percentage of salvage and cost of removal for property retired from each account for depreciable natural gas plant | 25 years. |
| 25. Procurement: | |
| (a) Agreements entered into for the acquisition of goods or the performance of services. Includes all forms of agreements not specifically set forth in Subsection 7 such as but not limited to: Letters of intent, exchange of correspondence, master agreements, term contracts, rental agreements, and the various types of purchase orders: | |
| (1) For goods or services relating to plant construction | 6 years. See § 225.2(g). |
| (2) For other goods or services | 6 years. |
| (b) Supporting documents including accepted and unaccepted bids or proposals (summaries of unaccepted bids or proposals may be kept in lieu of originals) evidencing all relevant elements of the procurement | 6 years. See § 225.2(g). |
| 26. Material ledgers: Ledger sheets of materials and supplies received, issued, and on hand | 6 years after the date records/ledgers were created. |
| 27. Materials and supplies received and issued: Records showing the detailed distribution of materials and supplies issued during accounting periods | 6 years. See § 225.2(g). |
| 28. Records of sales of scrap and materials and supplies: | |
| (a) Authorization for sale of scrap and materials and supplies | 3 years. |
| (b) Contracts for sale of scrap and materials and supplies | 3 years. |
| 29. Customers’ service applications and contracts: Contracts, including amendments for extensions of service, for which contributions are made by customers and others | 4 years after expiration. |
| 30. Rate schedules: General files of published rate sheets and schedules of natural gas company service (including schedules suspended or superseded) | 6 years after published rate sheets and schedules are superseded or no longer used to charge for services. |
| 31. Maximum demand, pressure, temperature, and specific gravity charts and demand meter record card | If the measurement data have not been disputed or adjusted, destroy after 1 year. |
| 32. Miscellaneous billing data: Billing department’s copies of contracts with customers (other than contracts in general files) | Destroy at option. |
| 33. Revenue summaries: Summaries of monthly operating revenues according to classes of service. Including summaries of forfeited discounts and penalties | 5 years. |
| 34. Tax records: | |
| (a) Copies of tax returns and supporting schedules filed with taxing authorities, supporting working papers, records of appeals of tax bills, and receipts for payment. See Subsection 11(b) for vouchers evidencing disbursements: | |
| (1) Income tax returns | 2 years after final tax liability is determined. |
| (2) Property tax returns | 2 years after final tax liability is determined. |
| (3) Sales and other use taxes | 2 years. |
| (4) Other taxes | 2 years after final tax liability is determined. |
| (5) Agreements between associate companies as to allocation of consolidated income taxes | 2 years after final tax liability is determined. |
| (6) Schedule of allocation of consolidated Federal income taxes among associate companies | 2 years after final tax liability is determined. |
| (b) Filings with taxing authorities to qualify employee benefit plans | 5 years after discontinuance of plan. |
| (c) Information returns and reports to taxing authorities | 3 years after final tax liability is determined. |
| 35. Statements of funds and deposits: | |
| (a) Statements of periodic deposits with fund administrators or trustees | Retain records for the most recent 3 years. |
| (b) Statements of periodic withdrawals from fund | Retain records for the most recent 3 years. |
| (c) Statements prepared by fund administrator or trustees of fund activity including: | Retain records until the fund is dissolved or terminated. |
| (1) Beginning of the year fund balance | |
| (2) Deposits with the fund; | |
| (3) Acquisition of investments held by the fund; | |
| (4) Disposition of investments held by the fund; | |
| (5) Disbursements from the fund, including party to whom disbursement was made; and, | |
| (6) End of year fund balance. | |
| 36. Records of deposits with banks and others: | |
| (a) Statements from depositories showing the details of funds received, disbursed, transferred, and balances on deposit | Destroy at option after completion of audit by independent accountants. |
| (b) Check stubs, registers, or other records of checks issued | 3 years. |
| 37. Records of receipts and disbursements: | |
| (a) Daily or other periodic statements of fund receipts or disbursements | Destroy at option after completion of annual audit by independent accountants. |
| (b) Records or periodic statements of outstanding vouchers, checks, drafts, etc., issued and not presented | Destroy at option after completion of annual audit by independent accountants. |
| (c) Reports of associates showing working fund transactions and summaries thereof | Destroy at option after completion of annual audit by independent accountants. |
| (d) Reports of revenue collections by field cashiers, pay stations, etc | Destroy at option after completion of annual audit by independent accountants. |
| 38. Statistics: Financial, operating, and statistical reports used for internal administrative or operating purposes | 5 years. |
| 39. Budgets and other forecasts (prepared for internal administrative or operating purposes) of estimated future income, receipts, and expenditures in connection with financing, construction and operations, including acquisitions and disposals of properties or investments | 3 years. |
| 40. Records of predecessor companies | Retain consistent with the requirements for the same types of records of the natural gas company. |
| 41. Reports to Federal and State regulatory commissions including annual financial, operating, and statistical reports | 5 years. |
| 42. Advertising: Copies of advertisements by or for the company on behalf of itself or any associate company in newspapers, magazines, and other publications, including costs and other records relevant thereto (excluding advertising of appliances, employment opportunities, routine notices, and invitations for bids all of which may be destroyed at option) | 2 years. |
SUBCHAPTER G—APPROVED FORMS, NATURAL GAS ACT
PART 250—FORMS
§§ 250.1-250.5 [Reserved]
§ 250.6 Form of application to be filed by distributor under section 7(a), seeking gas service of not more than 2,000 Mcf per day (3d year of operation) for a single community (see § 156.3(d) of this chapter).
1. Name of applicant (indicate whether individual, corporation or municipality). 2. Address. 3. Name, title, mailing address, and telephone number of person to be contacted concerning the application. 4. Name of natural gas company from whom service is desired. 5. Are you now rendering gas service? If so, briefly describe operations. 6. Nature of service sought, giving a brief description of proposal, including location of community, population, number of residences and kind of service sought and to be rendered, showing: (a) Is this an initial connection with the pipe line, or is it an extension or improvement of existing facilities? (b) Estimate of maximum day requirements for residential, commercial and industrial customers for each of the first three years of proposed operations (Mcf at 14.73 psia), and how the estimates were derived; (c) Estimate of annual requirements for residential, commercial and industrial customers for each of the first three years of proposed operations (Mcf at 14.73 psia), and how the estimates were derived. 7. Do you have or do you need a franchise to render the proposed service? If you have filed an application for such a franchise, with whom was it filed and what action has been taken on it? 8. Do you have or do you need a state certificate approving the proposed distribution system project? If you have filed an application for such a certificate, with whom was it filed and what action has been taken on it? 9. When do you propose to start construction and when do you estimate it will be completed? When do you propose to start selling gas? 10. How much are the facilities expected to cost? Show separately the estimated cost of the distribution system, the connecting supply lines, legal fees, financing fees and engineering fees, and briefly state how the estimates were derived. 11. Have you used the services of an engineering consultant? If so, the consultant should state his experience in the design of distribution systems, cost data of systems now in service compared with his initial estimates, and the actual rate at which new customers were attached in the new distribution systems. 12. How do you propose to finance the proposed facilities? Submit evidence that the money will be available. (This evidence need not be submitted if you have a state certificate for your project.) 13. For each of the first three years of operation of the proposed facilities, show (a) the estimated gross annual revenues for the natural gas estimated to be sold to residential, commercial and industrial customers as shown in item 6(c) and the rates you propose to charge, and (b) the cost of gas purchased by you (state the rate to be paid to the pipeline supplier and the pipeline’s rate schedule under which you will purchase said gas), other operating and maintenance expenses and operating revenue deductions, and (c) the net operating revenues. If you have received a certificate of public convenience and necessity issued by a local regulatory commission, it may be submitted in lieu of this requirement. 14. Municipalities should submit a bond amortization and interest schedule for the life of the bond issue related to the project and computation of the average debt service coverage ratio over the life of the issue. State briefly how all estimates were derived. Exhibits to be furnished: Exhibit A. A geographical map showing clearly all of the transmission facilities proposed to be installed and operated by you between your distribution system and the transmission pipeline system of the proposed supplier, including: (a) Location, length and size of your transmission lines; (b) Location and size (related horsepower) of your transmission compressor stations (if any); (c) Location and designation of each point of connection of your proposed transmission facilities with proposed pipeline supplier; (d) And if known, location, length and size of facilities to be installed by the proposed supplier. Exhibit B. A flow diagram showing the maximum daily capacity of the proposed connecting pipeline to carry gas from the supplier to the community to be served. The diagram should show expected operating pressures on the connecting pipeline at the point of connection with the supplier and at the other terminal of the connecting pipeline flow of gas through the connecting pipeline in Mcf per day; length of the connecting pipeline and its inside and outside diameter.
§§ 250.7-250.15 [Reserved]
§ 250.16 Format of compliance plan for transportation services and affiliate transactions.
(a) Who must comply. An interstate natural gas pipeline that transports natural gas for others pursuant to Subparts B or G of Part 284 of this chapter and is affiliated, as that term is defined in § 358.3 of this chapter, in any way with a natural gas marketing or brokering entity and conducts transportation transactions with its marketing or brokering affiliate must comply with the requirements of this section. The requirements of this section also apply to pipeline sales operating units to the extent provided in § 284.286 of this chapter.
(b) Tariff requirements. An interstate pipeline must maintain tariff provisions containing the following:
(1) The procedures used to address and resolve complaints by shippers and potential shippers including a provision that the pipeline will respond within 48 hours and in writing within 30 days to such complaints.
(2) [Reserved]
(c) Log of data used to allocate capacity. (1) An interstate pipeline that relies upon contract information or other data to allocate capacity must maintain a log showing, for each transportation contract (both for marketing affiliates and non-affiliates) on its system: the shipper’s name (including a designation whether the shipper is a local distribution company, an interstate pipeline, an intrastate pipeline, an end-user, a producer, a marketer, or a pipeline sales operating unit); the shipper’s affiliation with the pipeline; the contract number; and the applicable dates or other information used to allocate capacity under its tariff. The log data relating to each contract must be maintained as long as the contract is used to allocate capacity and for three years after the contract data is no longer used for capacity allocation.
(2) The current log of allocation data for marketing affiliates must be posted on the pipeline’s Internet Web site, operated pursuant to § 284.12 of this chapter. The posting must conform with the requirements of § 284.12 of this chapter and the pipeline’s tariff requirements relating to Internet Web sites. Access to the information must be provided using the same protocols and procedures used for the pipeline’s Internet Web site.
(3) The log of affiliate and non-affiliate information must be provided to the Commission upon request and must be made available to the public under 18 CFR part 385, subpart D. When requested by the Commission, the information must be provided, within a reasonable time, according to the specifications and format contained in Form No. 592, which can be obtained on the Commission’s website, https://www.ferc.gov.
(d) Transportation Discount Information. (1) A pipeline that provides transportation service at a discounted rate must maintain, for each billing period, the following information: the name of the shipper being provided the discount; the affiliate’s role in the transportation transaction (i.e., shipper, marketer, supplier, seller); the duration of the discount; the maximum rate or fee; the rate or fee actually charged during the billing period; and the quantity of gas scheduled at the discounted rate during the billing period for each delivery point. The discount information with respect to each transaction must be maintained for three years from the date the transaction commences.
(2) The discount information must be made available to the Commission upon request and to the public under 18 CFR part 385, subpart D. When requested by the Commission, the information must be provided, within a reasonable time, according to the specifications and format contained in Form No. 592, which can be obtained on the Commission’s website, https://www.ferc.gov.
(e) Penalty for failure to comply. (1) Any person who transports gas for others pursuant to subpart B or G of part 284 of this chapter and who knowingly violates the requirements of §§ 358.4 and 358.5 of this chapter, this section, or § 284.13 of this chapter will be subject, pursuant to sections 311(c), 501, and 504(b)(6) of the Natural Gas Policy Act of 1978, to a civil penalty, which the Commission may assess, of not more than $1,544,521 for any one violation.
(2) For purposes of this paragraph, in the case of a continuing violation, each day of the violation will constitute a separate violation.
PART 260—STATEMENTS AND REPORTS (SCHEDULES)
§ 260.1 FERC Form No. 2, Annual report for Major natural gas companies.
(a) Prescription. The form of Annual Report of Natural Gas Companies (Class A and Class B), designated herein as FERC Form No. 2, is prescribed.
(b) Filing requirements. Each natural gas company, as defined by the Natural Gas Act (15 U.S.C. 717, et seq.) which is a major company (a natural gas company whose combined gas transported or stored for a fee exceed 50 million Dth in each of the three previous calendar years) must prepare and file with the Commission, as follows:
(1) The annual report for the year ending December 2004 must be filed on April 25, 2005.
(2) The annual report for each year thereafter must be filed on April 18 of the subsequent year.
(3) Newly established entities must use projected data to determine whether FERC Form No. 2 must be filed.
(4) The form must be filed in electronic format only, as indicated in the general instructions set out in that form. The format for the electronic filing is available through the Commission’s website, https://www.ferc.gov. One copy of the report must be retained by the respondent in its files.
§ 260.2 FERC Form No. 2–A, Annual report for Nonmajor natural gas companies.
(a) Prescription. The form of Annual Report for Nonmajor Natural Gas Companies, designated herein as FERC Form No. 2—A, is prescribed.
(b) Filing requirements. Each natural gas company, as defined by the Natural Gas Act, not meeting the filing threshold for FERC Form No. 2, but having total gas sales or volume transactions exceeding 200,000 Dth in each of the three previous calendar years, must prepare and file with the Commission, as follows:
(1) The annual report for the year ending December 2004 must be filed on April 25, 2005.
(2) The annual report for each year thereafter must be filed on April 18 of the subsequent year.
(3) Newly established entities must use projected data to determine whether FERC Form No. 2–A must be filed.
(4) The form must be filed in electronic format only, as indicated in the General Instructions set out in that form. The format for the electronic filing is available through the Commission’s website, https://www.ferc.gov. One copy of the report must be retained by the respondent in its files.
§§ 260.4-260.7 [Reserved]
§ 260.8 System flow diagrams: Format No. FERC 567.
(a) Each Major natural gas pipeline company, having a system delivery capacity in excess of 100,000 Mcf per day (measured at 14.73 p.s.i.a. and 60 °F), shall file with the Commission by June 1 of each year five (5) copies of a diagram or diagrams reflecting operating conditions on its main transmission system during the previous twelve months ended December 31. For purposes of system peak deliveries, the heating season overlapping the year’s end shall be used. Facilities shall be those installed and in operation on December 31 of the reporting year. All volumes shall be reported on a uniform stated pressure and temperature base. Receipt and delivery point information required in various exhibits must be labeled with a location point name and code in accordance with the location name and code adopted by the pipeline in accordance with § 284.13(f) of this chapter.
(b) The diagram or diagrams shall include the following items of information:
(1) Nominal diameter (inches) of each pipeline.
(2) Miles of pipeline (to nearest 0.1 mile) between points of intake, delivery, river crossings, storage fields, crossovers, compressor stations and connections with other pipeline companies.
(3) Direction of flow in the pipelines. If direction of flow can be reversed at compressor stations, so indicate.
(4) Maximum permissible operating pressure for each pipeline at discharge side of each compressor station or other critical point, determined by the Department of Transportation’s safety standards.
(5) Total horsepower of compressor engines installed at each compressor station.
(6) Designed suction pressure for each compressor station, p.s.i.g.
(7) Designed discharge pressure for each station, p.s.i.g.
(8) Maximum volume, Mcf per day that can be compressed at each compressor station under conditions of suction and discharge set forth in paragraphs (b) (6) and (7) of this section. If direction of flow affects these factors provide the information for each direction of flow.
(9) The fuel requirement at each compressor station under conditions described in paragraph (b)(8) of this section.
(10) Pressure in the pipeline at points of emergency interconnection with other pipeline companies which can normally be expected to exist, and the volume which could be delivered or received at such emergency interconnection points at such pressures. Give the name of the interconnecting company.
(11) For each storage field, connected to the system and operated by the respondent pipeline company, the maximum dependable daily and seasonal withdrawal volumes available under normal conditions of operation.
(12) Volumes delivered: (i) The average daily volumes delivered at each takeoff point, (ii) the volumes delivered at each takeoff point on the day of maximum coincidental delivery, and (iii) the maximum daily volumes (noncoincidental) delivered to each customer under rates subject to FERC jurisdiction.
(13) The average daily volume received at each intake point to the transmission pipeline system.
(14) The volume received into the transmission pipeline system at each intake point on the day of maximum coincidental delivery.
(15) The information required by paragraphs (b)(12), (13) and (14), of this section may be furnished in tabular form, or by reference to FERC Form No. 2, providing, that the information is suitably keyed to the diagram by appropriate identifying symbol or number.
§ 260.9 Reports by natural gas pipeline companies on service interruptions and damage to facilities.
(a)(1) Every natural gas company must report to the Director, Division of Pipeline Certificates, at the earliest feasible time:
(i) Damage to any jurisdictional natural gas facilities other than liquefied natural gas facilities caused by a hurricane, earthquake or other natural disaster or terrorist activity that results in a loss of or reduction in pipeline throughput or storage deliverability; and
(ii) Serious interruptions of service to any shipper involving jurisdictional natural gas facilities other than liquefied natural gas facilities. Such serious interruptions of service shall include interruptions of service to communities, major government installations and large industrial plants outside of communities or any other interruptions which are significant in the judgment of the pipeline company. Interruptible service interrupted in accordance with the provisions of filed tariffs, interruptions of service resulting from planned maintenance or construction and interruptions of service of less than three hours duration need not be reported.
(2) In the event of damage to a natural gas company’s jurisdictional natural gas facilities other than liquefied natural gas facilities by reason other than hurricane, earthquake or other natural disaster or terrorist activity, the natural gas company should report such damage if, in the natural gas company’s judgment, such damage creates the potential for serious delivery problems on its own system or the pipeline grid.
(b) Any report of damage to facilities required by paragraph (a)(1)(i) of this section, any report of service interruption required by paragraph (a)(1)(ii) of this section and any report made pursuant to paragraph (a)(2) of this section in a natural gas company’s discretion must be submitted by the natural gas company by e-mail to [email protected] or by facsimile transmission to the Director, Division of Pipeline Certificates, Office of Energy Projects at FAX number (202) 208–2853.
(1) Reports required by paragraph (a)(1)(i) or (ii) or made in a natural gas company’s discretion pursuant to paragraph (a)(2) shall be made at the earliest feasible time and must state:
(i) The location and cause of the service interruption or damage to natural gas pipeline or storage facilities;
(ii) The nature of any damage to pipeline or storage facilities;
(iii) Specific identification of any facilities damaged;
(iv) The time the service interruption or damage to facilities occurred;
(v) The customers affected by the interruption of service or damage to facilities;
(vi) Emergency actions taken to maintain service; and
(vii) Company contact and telephone number.
(2) Following a report required by paragraph (a)(1)(i) of this section of damage to natural gas facilities resulting in loss of pipeline throughput or storage deliverability or a report pursuant to paragraph (a)(2) of this section in a natural gas company’s discretion, the natural gas company shall report to the Director, Division of Pipeline Certificates, at the earliest feasible time when pipeline throughput or storage deliverability has been restored.
(c) If so directed by the Commission or the Director, Division of Pipeline Certificates, the company must provide any supplemental information so as to provide a full report of the circumstances surrounding the occurrence.
(d) In any instance in which an incident or damage report involving jurisdictional natural gas facilities is required by Department of Transportation reporting requirements under the Natural Gas Pipeline Safety Act of 1968, a copy of such report shall be submitted to the Director, Division of Pipeline Certificates, within 30 days of the reportable incident.
(e) When a report of damage to facilities is required by paragraph (a)(1)(i) of this section or a report of service interruption is required by paragraph (a)(1)(ii) of this section, a copy of the e-mail or facsimile report required pursuant to paragraph (b) of this section must be sent to each State commissions for the States in which the reported service interruptions or damage has occurred.
§§ 260.11-260.15 [Reserved]
§ 260.200 Original cost statement of utility property.
Any natural gas company becoming subject to the jurisdiction of the Commission shall file, insofar as applicable, the following statements properly sworn to by the officer in responsible charge of their compilation:
Statement A showing the origin and development of the company, including, particularly, a description (giving names of parties and dates) of each consolidation and merger to which the company, or a predecessor, was a party and each acquisition of a gas operating unit or system. Any affiliation existing between the parties shall be stated.
Statement B showing for each acquisition of a gas operating unit or system by the reporting company or any of its predecessors: (1) The original cost (estimated only if not determinable from existing records), (2) the cost of the acquiring company, (3) the amount entered in the books as of the date of acquisition, (4) the difference between the original cost and the amount entered in the books, (5) a summary of all transactions affecting such difference, including retirements, between the date of each acquisition and the end of the calendar year prior to the year in which the filing is made, and (6) the amount of such difference remaining at the latter date.
If the depreciation, retirement, or amortization reserve was adjusted as of the date of acquisition and in connection therewith, a full disclosure of the pertinent facts shall be made.
The amount to be included in account 114, Gas Plant Acquisition Adjustments, shall be subdivided so as to show the amounts applicable to (a) gas plant in service, (b) gas plant leased to others, and (c) gas plant held for future use.
The procedure followed in determining the original cost of the gas plant acquired as operating units or systems shall be described in sufficient detail so as to permit a clear understanding of the nature of the investigations and analyses which were made for that purpose.
Where estimates are used in arriving at original cost or the amount to be included in account 114, a full disclosure of the method and underlying facts shall be given. The proportion of the original cost of each acquisition which has been determined from actual recorded costs and the proportion estimated shall be shown for each functional class of plant. In addition there shall be furnished in respect to each predecessor or vendor company for which complete construction costs are not available, a description of such plant records as are available, including the years covered thereby.
Statement C showing any amounts arrived at by appraisals in the gas plant accounts (and not eliminated) in lieu of cost to the reporting company. This statement should describe the appraisal and give the complete journal entry at the time the appraisal was originally recorded. If the entry had the effect of appreciating or writing up the gas plant account, the amount of the appreciation or writeup should be traced, by proper description and explanation of changes, from the date recorded through the end of the calendar year prior to the year in which the filing is made.
Statement D showing in detail gas plant as classified in the books of account immediately prior to reclassification in accordance with the Uniform System of Accounts, including, under appropriate descriptive headings, any unclassified amounts applicable jointly to the gas department and other departments of the utility.
Statement E showing the adjustments necessary to state accounts 101, 103–107, 114, and 116, and amount of common utility plant includible in account 118, as prescribed in the Uniform System of Accounts.
Statement F showing gas plant classified according to the accounts prescribed in the Uniform System of Accounts, and showing also the amount includible in account 116, Other Gas Plant Adjustments, and the amount of common utility plant includible in account 118, Other Utility Plant.
Statement G showing a comparative balance sheet reflecting the accounts and amounts appearing in the books before the adjusting entries have been made and after such entries shall have been made. The balance sheet shall be classified by the accounts set forth in the Uniform System of Accounts Prescribed for Natural Gas Companies.
Statement H giving a suggested plan for depreciating, amortizing, or otherwise disposing of, in whole or in part, the amounts includible in account 114, Gas Plant Acquisition Adjustments, and account 116, Other Gas Plant Adjustments.
Statement I furnishing the following statistical information relative to gas plant:
Show separately for each producing plant the name and location of plant, date of original construction, type of plant (whether coal gas, coke ovens, water gas, etc.), rated 24-hour capacity in Mcf of each unit and of the total plant, and date of installation of each unit installed after original construction. Show also the original cost according to the System of Accounts for each plant, by accounts 304 to 319, inclusive.
For each “field” includible in account 101, Gas Plant in Service, furnish the number of acres each of gas producing lands owned, of gas producing lands leased by the company, and of land on which gas rights only are owned, as included in accounts 325.1, 325.2, 325.3, respectively. The same information, classified by subaccounts, shall be furnished for producing and nonproducing acreage includible in account 104, Gas Plant Leased to Others, and in account 105, Gas Plant Held for Future Use.
For each “field” state number of feet of each size pipe used in field gathering lines.
For each “field” state number of wells included in accounts 330 and 331 segregated to show the number of wells on each type of producing lands classified under accounts 325.1, 325.2, 325.3.
When pumping or compressing plants exist within the production plant, include the same information as that requested for compressor stations under transmission plant.
State type and character of purification equipment and residual refining equipment included in accounts 336 and 337, respectively.
Show the original cost according to the System of Accounts for natural gas production plant by each “field” and by accounts 325.1 to 340.
Show separately for each location the name of plant, date of construction, type and total capacity (Mcf) of each gas holder. State also the original cost according to the System of Accounts for each location, by accounts 350.1 to 351, inclusive.
If depleted gas fields are being repressured, the statements furnished shall reflect the number of acres involved and the original cost according to the System of Accounts (accounts 350.1 to 351, inclusive).
State the number of feet of each size of main.
State separately for each compressor boosting station the name of plant, location, date of original construction, rated capacity, type and character of power unit, and rated capacity and type of compressor units. Also state the capacity, type, and date of installation of each additional power or compressor unit. Show for each station the original cost according to the System of Accounts by accounts 365.1, 365.2, 366, 368, and 369.
State number of feet of each size of main and the number of active meters, house regulators, and services. Give a general description of the district regulators and number, by sizes.
Where pumping or compressor stations exist within the distribution plant, include the same information requested for similar stations under transmission plant.
Describe the principal structures and improvements.
State the number and type of transportation vehicles and appurtenant equipment.
Give a description of store, shop, and laboratory equipment and miscellaneous equipment.
Furnish maps, drawn to scale, upon which indicate transmission mains, location of production plants (artificial and natural), producing and nonproducing leaseholds (indicating thereon producing wells, dry holes and depleted wells), gathering systems, booster and compressor stations, communities served (noting as to wholesale or retail), and large industrial consumers. Where gas is purchased from or sold to other gas utilities, indicate location of measuring stations or gates. If scale maps are not available, furnish sketch maps upon which should be indicated approximate distances between the locations above specified.
§ 260.300 FERC Form No. 3–Q, Quarterly financial report of electric utilities, licensees, and natural gas companies.
(a) Prescription. The quarterly report for electric utilities, licensees, and natural gas companies, designated herein as FERC Form No. 3–Q, is prescribed for the reporting quarter ending March 31, 2004, and each quarter thereafter.
(b) Filing requirements—(1) Who must file. Each natural gas company, (as defined in the Natural Gas Act (15 U.S.C. 717, et. seq.) must prepare and file with the Commission a FERC Form No. 3–Q pursuant to the General Instructions set out in that form.
(2) Each Major natural gas company must file this quarterly financial report form as follows:
(i) The quarterly financial report for the period January 1 through March 31, 2004, must be filed on or before July 9, 2004.
(ii) The quarterly financial report for the period April 1 through June 30, 2004, must be filed on or before September 8, 2004.
(iii) The quarterly financial report for the period July 1 through September 30, 2004, must be filed on or before December 9, 2004.
(iv) The quarterly financial report for the period January 1 through March 31, 2005, must be filed on or before May 31, 2005.
(v) The quarterly financial report for the period April 1 through June 30, 2005, must be filed on or before August 29, 2005.
(vi) The quarterly financial report for the period July 1 through September 30, 2005 must be filed on or before November 29, 2005.
(vii) Subsequent quarterly financial reports must be filed within 60 days from the end of the reporting quarter.
(3) Each Nonmajor natural gas company must file a quarterly financial report as follows:
(i) The quarterly financial report for the period January 1 through March 31, 2004, must be filed on or before July 23, 2004.
(ii) The quarterly financial report for the period April 1 through June 30, 2004, must be filed on or before September 22, 2004.
(iii) The quarterly financial report for the period July 1 through September 30, 2004, must be filed on or before December 23, 2004.
(iv) The quarterly financial report for the period January 1 through March 31, 2005, must be filed on or before June 13, 2005.
(v) The quarterly financial report for the period April 1 through June 30, 2005, must be filed on or before September 12, 2005.
(vi) The quarterly financial report for the period July 1 through September 30, 2005 must be filed on or before December 13, 2005.
(vii) Subsequent quarterly financial reports must be filed within 70 days from the end of the reporting quarter.
(4) This report must be filed as prescribed in § 385.2011 of this chapter as indicated in the General Instructions set out in the quarterly financial report form, and must be properly completed and verified. Filing on electronic media pursuant to § 385.2011 of this chapter will be required commencing with the quarterly financial report ending March 31, 2004, due on or before July 9, 2004 for major natural gas companies, and due on or before July 23, 2004 for nonmajor natural gas companies. One copy of the report must be retained by the respondent in its files.
§ 260.400 Cash management programs.
Natural gas companies subject to the provisions of the Commission’s Uniform System of Accounts prescribed in part 201 and § 260.1 or § 260.2 of this title that participate in cash management programs must file these agreements with the Commission. The documentation establishing the cash management program and entry into the program must be filed within 10 days of the effective date of the rule or entry into the program. Subsequent changes to the cash management agreement must be filed with the Commission within 10 days of the change.
§ 260.401 FERC Form No. 552, Annual Report of Natural Gas Transactions.
(a) Prescription. The annual report for natural gas market participants, designated as FERC Form No. 552, is prescribed for the calendar year ending December 31, 2008 and each calendar year thereafter.
(b) Filing requirements—(1) Who must file. Unless otherwise exempted or granted a waiver by Commission rule or order, each natural gas market participant, i.e., any buyer or seller that engaged in physical natural gas transactions the previous calendar year, must prepare and file with the Commission a FERC Form No. 552 pursuant to the definitions and general instructions set forth in that form. However a de minimis exemption, a natural gas market participant is exempt from this filing requirement if:
(i) It engages in reportable physical natural gas sales that amount to less than 2,200,000 MMBtus for the previous calendar year; and
(ii) It engages in reportable physical natural gas purchases that amount to less than 2,200,000 MMBtus for the previous calendar year.
(2) Form No. 552 must be filed as prescribed in § 385.2011 of this chapter as indicated in the General Instructions set out in the annual reporting form, and must be properly completed and verified. Each market participant must file Form No. 552 by May 1, 2009 for calendar year 2008 and by May 1 of each year thereafter for the previous calendar year. Each report must be prepared in conformance with the Commission’s software and guidance posted and available for downloading from the FERC Web site (http://www.ferc.gov). One copy of the report must be retained by the respondent in its files.
SUBCHAPTER H—PROCEDURES GOVERNING DETERMINATIONS FOR TAX CREDIT PURPOSES
PART 270—DETERMINATION PROCEDURES
Subpart A—General Definitions
§ 270.101 General definitions.
(a) NGPA definitions. Terms defined in the Natural Gas Policy Act of 1978 (NGPA) will have the same meaning for purposes of this subchapter as they have under the NGPA, unless further defined in this subchapter.
(b) Subchapter H definitions. For purposes of this part:
(1) NGPA means the Natural Gas Policy Act of 1978.
(2) Surface location means the point on the Earth’s surface from which drilling of a well is commenced except that in the case of a well drilled in permanent surface waters, “the Earth’s surface” means the mean elevation of the surface of the water.
(3) Jurisdictional agency means the state or federal agency identified in § 270.401.
(4) Tight formation gas means natural gas that a jurisdictional agency has determined to be produced from a designated tight formation.
(5) Designated tight formation means the portion of a natural gas bearing formation that was:
(i) Designated as a tight formation by the Commission, pursuant to section 501 of the NGPA, or
(ii) Determined to be a tight formation pursuant to section 503 of the NGPA.
(6) Occluded natural gas produced from coal seams means naturally occurring natural gas released from entrapment from the fractures, pores and bedding planes of coal seams.
(7) Natural gas produced from Devonian shale means natural gas produced from fractures, micropores and bedding planes of shales deposited during the Paleozoic Devonian Period.
(8) Shales deposited during the Paleozoic Devonian Period can be defined as either:
(i) The gross Devonian age stratigraphic interval encountered by a well bore, at least 95 percent of which has a gamma ray index of 0.7 or greater; or
(ii) One continuous interval within the gross Devonian age stratigraphic interval, encountered by a well bore, as long as at least 95 percent of the selected Devonian shale interval has a gamma ray index of 0.7 or greater (but if the interval selected is more than 200 feet thick, the bottom and top 100 foot portions must meet the five percent test independently).
(9) Gamma ray index means when measuring the Devonian age stratigraphic interval, the gamma ray index at any point is to be calculated by dividing the gamma ray log value at that point by the gamma log value at the shale base line established over the entire Devonian age interval penetrated by the well bore.
(10) Mcf means one thousand cubic feet of natural gas at 60 degrees Fahrenheit under a pressure equivalent to that of 30.00 inches of mercury at 32 degrees Fahrenheit, under standard gravitational force (980.665 centimeters per second squared).
(11) Data well means a well for which permeability and/or pre-stimulation production rate data are available for a pay section in the formation for which a tight formation designation is being sought.
Subpart B—Determinations by Jurisdictional Agencies
§ 270.201 Applicability.
(a) This part applies to determinations of jurisdictional agencies for tight formation gas, occluded natural gas produced from coal seams, and natural gas produced from Devonian shale that is produced through:
(1) A well the surface drilling of which began after December 31, 1979, but before January 1, 1993;
(2) A recompletion commenced after January 1, 1993, in a well the surface drilling of which began after December 31, 1979, but before January 1, 1993; or
(3) A recompletion commenced after December 31, 1979, but before January 1, 1993, where such gas could not have been produced from any completion location in existence in the well bore before January 1, 1980.
(b) This part also applies to determinations of jurisdictional agencies that designate a formation, or portion thereof, as a tight formation.
§ 270.202 Definition of determination.
For purposes of this subpart, a determination has been made by a jurisdictional agency when such determination is administratively final before such agency.
§ 270.203 Determinations by jurisdictional agencies.
A jurisdictional agency must make determinations to which this part applies in accordance with procedures applicable to it under the law of its jurisdiction for making such determinations or for making comparable determinations.
§ 270.204 Notice to the Commission.
Within 15 days after making a determination under this part, the jurisdictional agency must give written notice of the determination to the Commission. The notice must include the following:
(a) A list of all participants in the proceeding as well as any persons who submitted or who sought an opportunity to submit written comments (whether or not such persons participated in the proceeding);
(b) A statement indicating whether the matter was opposed before the jurisdictional agency;
(c) A copy of the application together with a copy or description of all other materials upon which the jurisdictional agency relied in the course of making the determination, together with any information which may be inconsistent with the determination.
(d) An explanatory statement, including appropriate factual findings and references, which is sufficient to enable a person examining the notice to ascertain the basis for the determination without reference to information or data not contained in the notice.
Subpart C—Requirements for Filings With Jurisdictional Agencies
§ 270.301 General requirements.
(a) An application for determination may be filed with the jurisdictional agency and signed by any person the jurisdictional agency designates as eligible to make filings with respect to the well for which the application is made.
(b) The documents required by this subpart are the minimum required in support of a request for a determination. The jurisdictional agency may require additional support as it deems appropriate, and may more specifically identify the documents indicated as the minimum required.
(c) Each applicant must pay the fee prescribed in § 381.401 of this chapter. The applicant will be billed annually by the Commission for each jurisdictional agency determination received by the Commission. The applicant must submit the fee, or petition for waiver pursuant to § 381.106 of this chapter, within 30 days following the billing date.
§ 270.302 Occluded natural gas produced from coal seams.
A person seeking a determination that natural gas is occluded natural gas produced from coal seams must file an application with the jurisdictional agency which contains the following items:
(a) FERC Form No. 121;
(b) All well completion reports.
(c) A radioactivity, electric or other log which will define the coal seams.
(d) Evidence to establish that the natural gas was produced from a coal seam;
(e) A statement by the applicant, under oath, that gas is produced from a coal seam through:
(1)(i) A well the surface drilling of which began after December 31, 1979, but before January 1, 1993;
(ii) A recompletion commenced after January 1, 1993, in a well the surface drilling of which began after December 31, 1979, but before January 1, 1993; or
(iii) A recompletion that was commenced after December 31, 1979 but before January 1, 1993, where such gas could not have been produced from any completion location in existence in the well bore before January 1, 1980; and
(2) The applicant has no knowledge of any information not described in the application which is inconsistent with his conclusion.
§ 270.303 Natural gas produced from Devonian shale.
A person seeking a determination that natural gas is produced from Devonian shale shall file an application with the jurisdictional agency which contains the following items:
(a) FERC Form No. 121;
(b) All well completion reports;
(c) A gamma ray log with superimposed indications of the shale base line and the gamma ray index of 0.7 over the Devonian age stratigraphic section designated pursuant to § 270.101(b)(8);
(d) A reference to a standard stratigraphic chart or text establishing that the producing interval is a shale of Devonian age; and
(e) A sworn statement:
(1) Calculating the percentage of footage of the producing interval which is not Devonian shale as indicated by a Gamma ray index of less than 0.7;
(2) Demonstrating that the percentage of potentially disqualifying non-shale footage for the stratigraphic section selected is equal to or less than 5 percent of the Devonian stratigraphic age interval designated pursuant to § 270.101(b)(7);
(3) Attesting that the natural gas is being produced from Devonian shale through:
(i) A well the surface drilling of which began after December 31, 1979, but before January 1, 1993;
(ii) A recompletion commenced after January 1, 1993, in a well the surface drilling of which began after December 31, 1979, but before January 1, 1993; or
(iii) A recompletion that was commenced after December 31, 1979 but before January 1, 1993, where such gas could not have been produced from any completion location in existence in the well bore before January 1, 1980; and
(4) Attesting that the applicant has no knowledge of any information not described in the application which is inconsistent with his conclusion.
§ 270.304 Tight formation gas.
A person seeking a determination that natural gas is tight formation gas must file with the jurisdictional agency an application which contains the following items:
(a) FERC Form No. 121;
(b) All well completion reports;
(c) A map that identifies the surface location of the well and the completion location in the well in the designated tight formation, along with the geographic boundaries of the designated tight formation, or a location plat identifying the surface location of the well and the completion location in the designated tight formation, along with a list of the tract (or tracts) of land that comprise the designated tight formation;
(d) A complete copy of the well log, including the log heading identifying the designated tight formation stratigraphically; and
(e) A statement by the applicant, under oath, that:
(1) The natural gas is being produced from a designated tight formation through:
(i) A well the surface drilling of which began after December 31, 1979, but before January 1, 1993;
(ii) A recompletion commenced after January 1, 1993, in a well the surface drilling of which began after December 31, 1979, but before January 1, 1993; or
(iii) Through a recompletion that was commenced after December 31, 1979 but before January 1, 1993, where such gas could not have been produced from any completion location in existence in the well bore before January 1, 1980; and
(2) The applicant has no knowledge of any information not described in the application which is inconsistent with his conclusion.
§ 270.305 Determination of tight formation areas.
(a) General requirement. A jurisdictional agency determination designating a portion of a formation as a tight formation must be made in the form and manner prescribed in this subpart.
(b) Guidelines for designating tight formations. A jurisdictional agency determination designating a portion of a formation as a tight formation must be made in accordance with the following guidelines:
(1) Within the geographic boundaries of the portion of the formation being recommended for tight formation designation, the estimated in situ gas permeability, throughout the pay section, is expected to be 0.1 millidarcy (md) or less. The expected in situ permeability is to be determined through an arithmetic mean averaging of the known permeabilities obtained from the wells that penetrate, and have a pay section in, such portion of such formation.
(2) Within the geographic boundaries of the portion of the formation being recommended for tight formation designation, the stabilized production rate of natural gas, against atmospheric pressure, of wells completed for production in such portion of such formation, without stimulation, is not expected to exceed the production rate determined in accordance with the table in this paragraph (b)(2). Such expected stabilized, pre-stimulation production rate is to be determined through an arithmetic mean averaging of the known stabilized, pre-stimulation production rates obtained from the wells that penetrate, and have a pay section in, such portion of such formation.
| If the average depth to the top of the formation (in feet) | The maximum allowable production rate of natural gas (in Mcf per day) | |
|---|---|---|
| exceeds— | but does not exceed— | may not exceed— |
| 0 | 1,000 | 44 |
| 1,000 | 1,500 | 51 |
| 1,500 | 2,000 | 59 |
| 2,000 | 2,500 | 68 |
| 2,500 | 3,000 | 79 |
| 3,000 | 3,500 | 91 |
| 3,500 | 4,000 | 105 |
| 4,000 | 4,500 | 122 |
| 4,500 | 5,000 | 141 |
| 5,000 | 5,500 | 163 |
| 5,500 | 6,000 | 188 |
| 6,000 | 6,500 | 217 |
| 6,500 | 7,000 | 251 |
| 7,000 | 7,500 | 290 |
| 7,500 | 8,000 | 336 |
| 8,000 | 8,500 | 388 |
| 8,500 | 9,000 | 449 |
| 9,000 | 9,500 | 519 |
| 9,500 | 10,000 | 600 |
| 10,000 | 10,500 | 693 |
| 10,500 | 11,000 | 802 |
| 11,000 | 11,500 | 927 |
| 11,500 | 12,000 | 1,071 |
| 12,000 | 12,500 | 1,238 |
| 12,500 | 13,000 | 1,432 |
| 13,000 | 13,500 | 1,655 |
| 13,500 | 14,000 | 1,913 |
| 14,000 | 14,500 | 2,212 |
| 14,500 | 15,000 | 2,557 |
(c) Notice to the Commission. Any jurisdictional agency making a determination that a formation, or portion thereof, qualifies as a tight formation will provide timely notice, in writing, of such determination, to the Commission. Such notice shall include the following to substantiate the jurisdictional agency’s findings:
(1) Geological and geographical descriptions of the formation, or portion thereof, which is determined to qualify as a tight formation; and
(2) Geological and engineering data to support the determination, including (but not limited to):
(i) A map of the area for which a tight formation determination is being sought that clearly locates and identifies all data wells and all dry holes that penetrate the subject formation and all wells that are currently producing from the subject formation.
(ii) A well-by-well table of each in situ permeability value (in millidarcies), pre-stimulation stabilized production rate (in Mcf per day), and depth to the top of the formation (in feet) for each well, and the arithmetic mean of each set of data.
(iii) For any data that the jurisdictional agency excludes from the above calculations, a statement explaining why the data was excluded.
(iv) The underlying well test, well logs, cross-sections, or other data sources, and all calculations performed to derive the formation tops, permeability values, and pre-stimulation stabilized production rates shown in the well-by-well table.
(v) Any other information that the jurisdictional agency deems relevant and/or that the jurisdictional agency relied upon in making its determination.
§ 270.306 Devonian shale wells in Michigan.
A person seeking a determination that natural gas is being produced from the Devonian Age Antrim shale in Michigan shall file an application that contains the following items:
(a) FERC Form No. 121;
(b) All well completion reports;
(c) A gamma ray log from the closest available well bore (producing or dry hole) that is within a one mile radius of the well for which a determination is sought, with superimposed indications of:
(1) The shale base line and the gamma ray index of 0.7 over the Devonian age stratigraphic section penetrated by the well bore; and
(2) The boundary between the Antrim shale and the overlying formation (Berea Sandstone, Ellsworth, Bedford, or Sunbury shales, or their equivalents);
(d) A location plat showing the well for which the determination is sought and the well for which a gamma ray log has been filed;
(e) A mud log from the well for which the determination is sought, with a detailed description of samples taken from 10-foot, or less, intervals through-out the Devonian age stratigraphic section penetrated by the well bore;
(f) A driller’s log, or similar report, from the well for which the determination is sought, indicating the general characteristics of the strata penetrated and the corresponding depths at which they are encountered throughout the Devonian age stratigraphic section penetrated by the well bore;
(g) A reference to a standard stratigraphic chart or text establishing that the producing interval is a shale of Devonian age; and
(h) A sworn statement:
(1) Calculating the percentage of footage of the producing interval (or the Antrim Shale in the event the well is a dry hole) in the well for which a gamma ray log was submitted which is not Devonian shall as indicated by a gamma ray index of less than 0.7;
(2) Demonstrating that the percentage of potentially disqualifying non-shale footage for the Devonian age stratigraphic section penetrated by the well bore for which the submitted gamma ray log is equal to or less than 5 percent;
(3) Attesting that the natural gas is being produced from the Devonian Age Antrim shale through:
(i) A well the surface drilling of which began after December 31, 1979, but before January 1, 1993;
(ii) A recompletion commenced after January 1, 1993, in a well the surface drilling of which began after December 31, 1979, but before January 1, 1993; or
(iii) A recompletion that was commenced after December 31, 1979 but before January 1, 1993, where such gas could not have been produced from any completion location in existence in the well bore before January 1, 1980 and
(4) Attesting the applicant has no knowledge of any information not described in the application which is inconsistent with his conclusion.
Subpart D—Identification of State and Federal Jurisdictional Agencies
§ 270.401 Jurisdictional agency.
(a) Definition. With respect to a well the surface location of which is on lands within the boundaries of a State (including Federal lands and offshore State lands), “jurisdictional agency” means the Federal or State agency having regulatory jurisdiction with respect to the production of natural gas.
(b) The jurisdictional agency for wells located on Federal lands in each state are:
(1) Alabama—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(2)(i) Alaska, Anchorage Field Office—Assistant District Manager for Mineral Resources, Bureau of Land Management, 6881 Abbott Loop Road, Anchorage, AK 99507.
(ii) Alaska, Northern Field Office—Assistant District Manager for Mineral Resources, Bureau of Land Management, 1150 University Avenue, Fairbanks, AK 99709.
(3)(i) Arizona, except for the Navaho and Hopi Indian Reservations—Deputy State Director for Mineral Resources, Bureau of Land Management, PO Box 555, Phoenix, AZ 85000–0555.
(ii) Arizona, Navaho and Hopi Indian Reservations—District Manager, Bureau of Land Management, Albuquerque District Office (NGPA), 435 Montano Road, NE., Albuquerque, NM 87107.
(4) Arkansas—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(5) California, except Naval Petroleum Reserve No. 1 (Elk Hills) and No. 2 (Buena Vista)—Chief, Branch of Fluid and Solid Minerals, Bureau of Land Management, Division of Mineral Resources (C–920), 2800 Cottage Way, Suite W–1834, Sacramento, CA 95825.
(6) Colorado—Deputy State Director for Resource Services, Bureau of Land Management, Colorado State Office (CO–930), 2850 Youngfield Street, Lakewood, CO 80215.
(7) Florida and Georgia—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(8) Idaho—Deputy State Director Resources and Science, Bureau of Land Management, Idaho State Office (931), 1387 Vinnell Way, Boise, ID 83709.
(9) Illinois, Indiana, and Iowa—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(10) Kansas—Deputy State Director for Resource Services, Bureau of Land Management, Colorado State Office (CO–931), 2850 Youngfield Street, Lakewood, CO 80215.
(11) Kentucky, Louisiana, Maryland, Michigan, Mississippi, and Missouri—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(12) Montana—Chief, Branch of Fluid and Solid Minerals, Bureau of Land Management, Division of Mineral Resources, PO Box 36800, Billings, MT 59107.
(13) Nebraska—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(14) Nevada—State Director, Bureau of Land Management, Nevada State Office (NV–92000), PO Box 12000, Reno, NV 89520.
(15)(i) New Mexico, Northern New Mexico—Field Office Manager, Bureau of Land Management, Albuquerque Field Office (NGPA), 435 Montano Road, NE., Albuquerque, NM 87107.
(ii) New Mexico, Southern New Mexico—Field Office Manager, Bureau of Land Management, Roswell Field Office (NGPA), 2909 West Second Street, Roswell, NM 88201.
(16) New York and North Carolina—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(17) North Dakota—Chief, Branch of Fluid Minerals, Bureau of Land Management, Division of Mineral Resources, PO Box 36800, Billings, MT 59107.
(18) Ohio—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(19)(i) Oklahoma, except the Osage Reservation—Field Office Manager, Bureau of Land Management, Tulsa Field Office (NGPA), 7906 East 33rd Street, Suite 101, Tulsa, OK 74145.
(ii) Oklahoma, the Osage Reservation only—Superintendent, Osage Indian Agency, Bureau of Indian Affairs, U. S. Department of the Interior, Pawhuska, OK 74056.
(20) Oregon—Deputy State Director, Planning, Use, and Protection, Bureau of Land Management, Oregon State Office, PO Box 2965, Portland, OR 97208.
(21) Pennsylvania and South Carolina—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(22) South Dakota—Chief, Branch of Fluid Minerals, Bureau of Land Management, Division of Mineral Resources, PO Box 36800 Billings, MT 59107.
(23) Tennessee—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(24) (i) Texas, east of the 100th Meridian—Field Office Manager, Bureau of Land Management, Tulsa Field Office (NGPA), 7906 East 33rd Street, Suite 101, Tulsa, OK 74145.
(ii) Texas, west of the 100th Meridian—Field Office Manager, Bureau of Land Management, Roswell Field Office (NGPA), 2909 West Second Street, Roswell, NM 88201.
(25) (i) Utah, except for the Navajo and Hopi Indian Reservations—Deputy State Director for Natural Resources, Bureau of Land Management, Utah State Office (U–930), 324 South State Street, Suite 301, Salt Lake City, UT 84111.
(ii) Utah, the Navajo and Hopi Indian Reservations only—Field Office Manager, Bureau of Land Management, Albuquerque Field Office (NGPA), 435 Montano Road, NE., Albuquerque, NM 87107.
(26) Virginia—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(27) Washington—Deputy State Director for Mineral Resources, Bureau of Land Management, Oregon State Office, PO Box 2965, Portland, OR 97208.
(28) West Virginia—Chief, Branch of Resources, Planning & Protection, Bureau of Land Management, Eastern States Office (931), 7450 Boston Boulevard, Springfield, VA 22153.
(29) (i) Wyoming, excluding Naval Petroleum Reserve No. 3 (Teapot Dome) Casper Field Office—Field Office Manager, Bureau of Land Management, 1701 East E Street, Casper, WY 82601.
(ii) Rawlins Field Office—Field Office Manager, Bureau of Land Management, PO Box 2407, Rawlins, WY 82301.
(iii) Rock Springs Field Office—Field Office Manager, Bureau of Land Management, 280 Highway 191 North, Rock Springs, WY 82901.
(iv) Worland Field Office—Field Office Manager, Bureau of Land Management, PO Box 119, Worland, WY 82401.
(c) The jurisdictional agency for wells located on Other lands in each state are:
(1) Alabama—State Oil and Gas Board, 420 Hackberry Lane, P O Box 869999, Tuscaloosa, AL 35486–9780.
(2) Alaska—Department of Natural Resources, Oil & Gas Division, 550 West 7th Avenue, Anchorage, AK 99501.
(3) Arizona—Oil and Gas Conservation Commission, 416 West Congress Street, Suite 100, Tucson, AZ 85701
(4) Arkansas—Oil & Gas Commission, PO Box 1472, El Dorado, AR 71730-1472.
(5) California—Department of Conservation, Division of Oil & Gas, 801 K Street, MS24–01, Sacramento, CA 95814.
(6) Colorado—Oil & Gas Conservation Commission, 1120 Lincoln, Suite 801, Denver, CO 80203.
(7) Florida—Administrator Oil and Gas, Bureau of Geology, Department of Natural Resources, 903 West Tennessee Street, Tallahassee, FL 32304.
(8) Georgia—Department of Natural Resources, Geologic & Water Resources Division, 19 Martin Luther King Drive, SW, Atlanta, GA 30334.
(9) Idaho—Idaho Public Utilities Commission, Statehouse Mail, Boise, ID 83720.
(10) Illinois—Department of Natural Resources, Oil & Gas Division, 524 South 2nd Street, Springfield, IL 62701.
(11) Indiana—Department of Natural Resources, Oil & Gas Division, 402 West Washington Street, Room 256 Indianapolis, IN 46204.
(12) Kansas—Kansas Corporation Commission, Finney State Office Building, 130 South Market, Room 2078, Wichita, KS 67202–3802.
(13) Kentucky—Public Service Commission, 211 Sower Blvd., PO Box 6615, Frankfort, KY 40602–0615.
(14) Louisiana—Department of Natural Resources, Office of Conservation, PO Box 94275, Baton Rouge, LA 70804.
(15) Maryland—Department of Natural Resources, Tawes State Office Building., Annapolis, MD 21404.
(16) Michigan—Department of Environmental Quality, Geological Survey Division, Hollister Building, PO Box 30473, Lansing MI 48909.
(17) Mississippi—State Oil & Gas Board, 500 Graymont Avenue, Suite E, Jackson, MS 39202.
(18) Missouri—Department of Natural Resources Geology and Survey Division, PO Box 250, 111 Fairgrounds Road, Rolla, MO 65402.
(19) Montana—Department of Natural Resources and Oil and Gas Conservation Division, 2535 St. John’s Avenue, Billings, MT 59102.
(20) Nebraska—Oil & Gas Conservation Commission, Box 399, Sidney, NE 69162.
(21) Nevada—Department of Conservation and Natural Resources, Division of Mineral Resources, Capitol Complex, 201 S. Fall Street, Carson City, NV 89710.
(22) New Mexico—Department of Energy and Minerals and Natural Resources, Oil Conservation Division, 2040 S. Pacheco Street, Sante Fe, NM 87505.
(23) New York—New York State Department of Environmental Conservation, Division of Mineral Resources, Bureau of Oil and Gas Regulation, 50 Wolf Road, Albany, NY 12233–6500.
(24) North Carolina—Department of Natural Resources and Community Development, 512 North Salisbury Street, Raleigh, NC 27611.
(25) North Dakota—Industrial Commission, State Capitol, 600 East Boulevard Avenue, Department 405, Bismarck, ND 58505.
(26) Ohio—Department of Natural Resources, Division of Oil and Gas 4383 Fountain Square Drive, Columbus, OH 43224–1362.
(27) Oklahoma—-Corporation Commission, 300 Jim Thorpe Building, PO Box 52000–2000, Oklahoma City, OK 73152–2000.
(28) Oregon—Department of Geology & Mineral Industries, 800 N.E. Oregon Street, #28 Portland, OR 972332.
(29) Pennsylvania “ Department of Conservation and Natural Resources, PO Box 8767, Harrisburg, PA 17105–8767.
(30) South Carolina—South Carolina Public Service Commission, PO Drawer 11649, Columbia, SC 29211.
(31) South Dakota—Oil and Gas Supervisor, Department of Environment and Natural Resources, 2050 West Main, Suite 1, Rapid City, SD 57702.
(32) Tennessee—Office of Conservation, Division of Geology, 401 Church Street, Nashville, TN 37243.
(33) Texas—Railroad Commission Oil and Gas Division, 1701 North Congress Avenue, PO Box 12967, Austin, TX 78711–2967.
(34) Utah—-Department of Natural Resources, Division of Oil, Gas and Mining, PO Box 145801 West North Temple, Suite 1210, Salt Lake City, UT 84114–5801.
(35) Virginia—Department of Mines, Minerals & Energy, Division of Gas and Oil, PO Box 1416, Abingdon, VA 24210.
(36) Washington—Department of Natural Resources, Geology and Earth Resources Division, PO Box 47001, Olympia, WA 98504.
(37) West Virginia—-Division of Environmental Protection, Office of Oil and Gas, #10 McJunkin Road, Nitro, WV 25143–2506.
(d) Federal lands. For purposes of this section, Federal lands means:
(1) All lands leased under:
(i) The Mineral Lands Leasing Act, as amended, 30 U.S.C. 181 et seq.; and
(ii) The Mineral Leasing Act for Acquired Lands, as amended, 30 U.S.C. 351 et seq.; and
(2) All Indian lands which are under the supervision of the United States Geological Survey or any successor federal agency (30 CFR part 221); and
(3) All Indian lands which are under the supervision of the Osage Indian Agency, Bureau of Indian Affairs, U.S. Department of the Interior.
(e) Divided-interest leases. Unless an agreement under this paragraph provides otherwise, where a well is located on a divided-interest lease involving Federal (or Indian) and private (or State) ownership:
(1) The Federal jurisdictional agency will make the determination where the majority lease interest is Federal (or Indian);
(2) The State jurisdictional agency will make the determination where the majority lease interest is private (or State); and
(3) The State jurisdictional agency will make the determination where the lease is divided equally.
(f) Drilling units. Unless an agreement under paragraph (e) of this section provides otherwise, where a drilling unit is drained by two or more wells, the Federal jurisdictional agency will make the determination if the completion location of the well in question is located on a Federal (or Indian) lease, and the State jurisdictional agency will make the determination if the completion location of the well in question is located on a private (or State) lease.
(g) Agreements. If a jurisdictional agency that has jurisdiction over Federal lands enters into an agreement with a jurisdictional agency that has jurisdiction over State lands that either authorizes the State jurisdictional agency to make determinations for wells located on Federal lands or the Federal agency to make determinations for wells located on State lands, such agreement shall be filed with the Commission. Upon the filing of such an agreement, the agency so authorized will be considered to be the jurisdictional agency for wells on the lands subject to the agreement.
Subpart E—Commission Review of Jurisdictional Agency Determinations
§ 270.501 Publication of notice from jurisdictional agency.
(a) Upon receipt of a notice of determination by a jurisdictional agency under § 270.204, the Commission will send an acknowledgment to the applicant and make the notice available through the Commission’s website, https://www.ferc.gov.
(b) The acknowledgment will contain the following:
(1) The date on which the jurisdictional agency notice was received;
(2) Certain information contained in FERC Form No. 121;
(3) A statement that the application and a copy or description of other materials in the record on which such determination was made is available for inspection, except to the extent the material is treated as confidential under § 270.506, at the offices of the Commission; and
(4) A statement that persons objecting to the final determination may, in accordance with this subpart, file a protest with the Commission within 20 days after the date that notice of receipt of a determination is issued by the Commission pursuant to this section.
§ 270.502 Commission review of final determinations.
(a) Review by Commission. Except as provided in paragraphs (b), (c) and (d) of this section, a determination submitted to the Commission by a jurisdictional agency will become final 45 days after the date on which the Commission received notice of the determination, unless within the 45 day period, the Commission:
(1) Makes a preliminary finding that:
(i) The determination is not supported by substantial evidence in the record on which the determination was made; or
(ii) The determination is not consistent with information which is contained in the public records of the Commission and which was not part of the record on which the jurisdictional agency made the determination, and
(2) Issues written notice of such preliminary finding, including the reasons therefor. Copies of the written notice will be sent to the jurisdictional agency that made the determination, to the persons identified in the notice under § 270.204 of such determination, and to any persons who have filed a protest.
(b) Incomplete notice. Notwithstanding the provisions of paragraph (a) of this section, the 45-day period for Commission review of a determination will not begin if:
(1) The notice forwarded to the Commission pursuant to § 270.204 does not contain all the material specified therein; and
(2) The Commission notifies the jurisdictional agency, within 45 days after the date on which the Commission receives notice of the determination, that the notice is incomplete.
(c) Withdrawal of notice. (1) The jurisdictional agency may withdraw a notice of determination by giving notice as specified in paragraph (c)(2) of this section at any time prior to the issuance of a final order with respect to such determination under paragraphs (g)(1) and (g)(2) of this section, or at any time prior to the date such determination becomes final under paragraph (a) or (g)(4) of this section. Such notice must include the jurisdictional agency’s reasons for the withdrawal.
(2) Withdrawal of a notice of determination will take effect at such time as the jurisdictional agency has notified the Commission, and the parties to the proceeding before the agency, of such withdrawal.
(3) Withdrawal of a notice of determination shall nullify such notice of determination.
(d) Withdrawal of application. (1) An applicant may withdraw an application for a determination which is before the Commission by giving notice as specified in paragraph (d)(2) of this section at any time prior to the issuance of a final order with respect to such determination under paragraphs (g)(1) and (g)(2) of this section, or at any time prior to the date such determination becomes final under paragraph (a) or (g)(4) of this section.
(2) Withdrawal of an application will take effect at such time as the applicant has notified the Commission and the jurisdictional agency.
(3) Withdrawal of an application will nullify such application and the notice of determination on such application.
(e) Public notice. The Commission will publish notice of the preliminary finding in the
(f) Procedures following notice of preliminary finding. Any state or federal agency or any person may submit, within 30 days after issuance of the preliminary finding, written comments, and request an informal conference with the Commission staff. Any jurisdictional agency, any state agency and any person receiving notice under paragraph (a)(2) of this section may request an informal conference with the Commission staff. All timely requests for conferences will be granted. Notice of, and permission to attend, such conferences will be given to persons identified in paragraph (a)(2) of this section and to state or federal agencies or persons who submitted comments under this paragraph.
(g) Final orders. (1) In any case in which a protest was filed with the Commission and a preliminary finding was issued, the Commission will issue a final order within 120 days after issuance of the preliminary finding.
(2) In any case in which no protest was filed with the Commission and a preliminary finding was issued, the Commission may issue a final order within 120 days after issuance of the preliminary finding.
(3) A final order issued under paragraph (g)(1) or (g)(2) of this section will either affirm, reverse, or remand the determination of the jurisdictional agency. Such order will state the specific basis for the Commission’s action. Notice of the issuance of such order will be given to the jurisdictional agency, to participants in the proceeding before the jurisdictional agency, and to participants in the proceeding before the Commission under paragraph (d) of this section and under § 270.503.
(4) In the event that the Commission fails to issue a final order within 120 days after issuance of the preliminary finding, the determination of the jurisdictional agency shall become final.
§ 270.503 Protests to the Commission.
(a) Who may file. Any person may file a protest with the Commission with respect to a determination of a jurisdictional agency within 20 days after the date that notice of receipt of a determination is issued by the Commission pursuant to § 270.204.
(b) Grounds. Protests may be based only on the grounds the final determination is:
(1) Not supported by substantial evidence;
(2) Not consistent with information which is contained in the public records of the Commission and which was not part of the record on which the determination was made;
(3) Not consistent with information submitted with the protests for inclusion in the public records of the Commission, which information was not part of the record on which the determination was made; or
(4) Not based on an application which complied with the filing requirements set forth in this part.
§ 270.504 Contents of protests to the Commission.
Each protest must include:
(a) An identification of the determination protested;
(b) The name and address of the person filing the protest;
(c) A statement of whether or not the person filing the protest participated in the proceeding before the jurisdictional agency, and if not, the reason for the nonparticipation;
(d) A statement of the effect the determination will have on the protestor;
(e) A statement of the precise grounds under § 270.503(f) for the protest, and all supporting documents or references to any information relied on which is in the record on which the determination is based or is in or to be inserted in the public files of the Commission; and
(f) A statement that the protestor has served, in accordance with § 385.2010 of this chapter, a copy of the protest together with all supporting documents on the jurisdictional agency and all persons listed in the notice of determination filed pursuant to § 270.204.
§ 270.505 Procedure for reopening determinations.
(a) Grounds. At any time subsequent to the time a determination becomes final pursuant to this subpart, the Commission, on its own motion, or in response to a petition filed by any person aggrieved or adversely affected by the determination, may reopen the determination if it appears that:
(1) In making the determination, the Commission or the jurisdictional agency relied on any untrue statement of material fact; or
(2) There was omitted a statement of material fact necessary in order to make the statements made not misleading, in light of the circumstances under which they were made to the jurisdictional agency or the Commission.
(b) Contents of petition. A petition to reopen the determination proceedings must contain the following information, under oath:
(1) The name and address of the person filing the petition;
(2) The interest of the petitioner in the outcome of the determination proceeding;
(3) The statement of material fact that is alleged to be untrue or omitted;
(4) A statement explaining why the outcome of the determination proceeding would have been different had the statement or omission not occurred; and
(5) Copies of all documents relied on by the petitioner, or references to such documents if they are contained in the public files of the Commission.
(c) Procedures after reopening. In the event the Commission reopens a determination pursuant to this section it will:
(1) Give notice to the jurisdictional agency and all persons who participated before both that agency and the Commission in the proceedings resulting in the determination in question;
(2) Permit the jurisdictional agency and other persons receiving notice pursuant to paragraph (c)(1) of this section to submit whatever documentary evidence such agency or persons deem relevant; and
(3) Take such other action or hold or cause to be held such proceedings as it deems necessary or appropriate for a full disclosure of the facts.
(d) Final order of Commission. Within 150 days after issuance of the notice under paragraph (c)(1) of this section, the Commission shall issue a final order. If the Commission finds that the grounds referred to in paragraph (a) of this section exist, it will vacate the determination.
§ 270.506 Confidentiality.
(a) Except as provided in paragraph (b) of this section, the Commission will accord confidential protection to, and not disclose to the public, any information submitted by a jurisdictional agency under § 270.204, if:
(1) The jurisdictional agency, on its own motion or on request of the applicant, afforded such information confidential treatment before the jurisdictional agency; and
(2) The agency order or the applicant’s request stated grounds for confidential treatment which fall within one of the exemptions described in paragraphs (1) through (9) of 5 U.S.C. 552(b).
(b) Upon receipt of a request for disclosure of information treated as confidential under paragraph (a) of this section, the Commission will determine in accordance with 5 U.S.C. 552 whether the information is exempt. 5 U.S.C. 552(b). If it determines the information is not exempt, the information will be made public. If it determines the information is exempt, the Commission will not make it public unless determines that its conduct of the proceeding to review the jurisdictional agency determination requires making such information available to the public or to particular parties, subject to conditions (including a protective order) as the Commission may prescribe. Before making any information public under this paragraph, the Commission will provide at least 5 days notice to the person who submitted the information.
SUBCHAPTER I—OTHER REGULATIONS UNDER THE NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES
PART 280—GENERAL PROVISIONS APPLICABLE TO SUBCHAPTER I
§ 280.101 Definitions.
(a) NGPA definitions. Terms defined in the NGPA shall have the same meaning for purposes of this subchapter as they have under the NGPA, unless further defined in this subpart.
(b) Other definitions. For purposes of this subchapter:
(1) NGPA means the Natural Gas Policy Act of 1978.
(2) OCS means the Outer Continental Shelf as defined in section 2(35) of the NGPA.
PART 281—NATURAL GAS CURTAILMENT UNDER THE NATURAL GAS POLICY ACT OF 1978
Subpart A [Reserved]
Subpart B—Permanent Curtailment Rule
§ 281.201 Purpose.
The purpose of this subpart is to implement section 401 of the NGPA in order to provide that effective November 1, 1979, the curtailment plans of interstate pipelines protect, to the maximum extent practicable, deliveries of natural gas for essential agricultural uses and for high-priority uses in accordance with the provisions of this subpart.
§ 281.202 Applicability.
This subpart applies to the following interstate pipe lines:
§ 281.203 Definitions and cross references.
(a) Definitions. For purposes of this subpart:
(1) Direct sale customer means an essential agricultural user of high priority use which purchases natural gas directly from an interstate pipeline and consumes such natural gas for a high-priority use or an essential agricultural use.
(2) Essential agricultural use means any use of natural gas which is certified by the Secretary of Agriculture as an “essential agricultural use” under section 401(c) of the NGPA, as identified in 7 CFR part 2900, et seq.
(3) Essential agricultural user means a person who uses natural gas for an essential agricultural use.
(4) High-priority use means any use of natural gas which qualifies the user as a high-priority user.
(5) High-priority user means any person who uses natural gas:
(i) In a residence;
(ii) In a small commercial establishment;
(iii) In a school or a hospital; or
(iv) For police protection, for fire protection, in a sanitation facility or a correctional facility.
(6) End-use curtailment plan means a provision in the tariff of an interstate pipeline that requires that under circumstances of supply shortage natural gas deliveries will be curtailed based at least in part upon factors which consider the end-use of the natural gas.
(7) Indirect sale customer of an interstate pipeline means an essential agricultural end-user served by a local distribution company which is served directly by the interstate pipeline.
(8) Residence means a dwelling using natural gas predominantly for residential purposes such as space heating, air conditioning, hot water heating, cooking, clothes drying, and other residential uses and includes apartment buildings and other multi-unit buildings.
(9) Small commercial establishment means any establishment (including institutions and local, state and Federal Government agencies) engaged primarily in the sale of goods or services where natural gas is used:
(i) In amounts of less than 50 Mcf on a peak day; and
(ii) For purposes other than those involving manufacturing or electric power generation.
(10) Hospital means a facility, the primary function of which is delivering medical care to patients who remain at the facility including nursing and convalescent homes. Outpatient clinics or doctors’ offices are not included in this definition.
(11) School means a facility, the primary function of which is to deliver instruction to regularly enrolled students in attendance at such facility. Facilities used for both educational and noneducational activities are not included under this definition unless the latter activities are merely incidental to the delivery of instruction.
(12) Local distribution company means a local distribution company served directly by an interstate pipeline.
(13) Rolling base period means a time period in which entitlements of the customers of an interstate pipeline are established pursuant to the pipeline’s currently effective curtailment plan and which is periodically updated to reflect recent gas requirements of such customers.
(14) Entitlements of a direct sale customer or a local distribution company customer with respect to a particular interstate pipeline means the amount of natural gas that customer is permitted to receive under the interstate pipeline’s currently effective curtailment plan.
(15) Interstate pipeline purchaser means an interstate pipeline which received deliveries of natural gas from another interstate pipeline.
(16) Alternative fuel means alternative fuel as it is defined in Subpart C of this part.
(b) Cross references. (1) Essential agricultural requirements are calculated in accordance with § 281.208.
(2) Index of entitlements is that index of entitlements prepared in accordance in § 281.204(b).
§ 281.204 Tariff filing requirements.
(a) General rule. Each interstate pipeline listed in § 281.202 shall file tariff sheets or sections, in accordance with § 154.4 of this chapter, including an index of entitlements, which provides that if the interstate pipeline is in curtailment, natural gas will be delivered in accordance with the provisions of this subpart. If the interstate pipeline has curtailment provisions in its currently effective tariff, the tariff sheets or sections shall amend the existing curtailment provisions. If the interstate pipeline has no curtailment plan in its currently effective tariff, when it files tariff sheets or sections to amend its currently effective tariff to include a curtailment plan such curtailment plan shall comply with the requirements of this subpart. The tariff sheets or sections shall be filed no later than October 1, 1979, with a proposed effective date of November 1, 1979. The Data Verification Committee report prepared in accordance with § 281.213 shall be filed with the tariff sheets or sections.
(b) Index of entitlements. (1) The index of entitlements for an interstate pipeline shall identify the natural gas entitlements in priority of service categories 1 and 2 (established in accordance with § 281.205(a)) for each direct sale customer, each local distribution company customer and each interstate pipeline purchaser on a daily, monthly, seasonal or other periodic basis used in the currently effective curtailment plan.
(2) Periodic update. Each interstate pipeline shall update its index of entitlements annually to reflect changes in Priority 2 entitlements. The new index of requirements shall be filed on September 15 of each year with a proposed effective date of November 1, except that if the interstate pipeline uses a rolling base period in its currently effective curtailment plan it shall file its new index of entitlements on the date upon which other end-uses of the customers of the interstate pipeline are updated in accordance with the currently effective tariff.
(3) Alternative fuel determination. The index of entitlements shall not include the volumes of natural gas for which volumes the essential agricultural user has the ability to use an alternative fuel, as determined under Subpart C of this part. Each interstate pipeline shall amend its index of entitlements pursuant to paragraph (b)(2) of this section to remove from the priority 2 entitlements and place in an appropriate priority of service category any such volumes or natural gas included in any index of entitlements that is effective on or after October 31, 1979.
(c) Other tariff provisions. (1) Every tariff filed under this subpart shall contain provisions that will require the interstate pipeline:
(i) To provide for deliveries of sufficient volumes of natural gas to respond to emergency situations (including environmental emergencies) during periods of curtailment where additional supplies are required to forestall irreparable injury to life or to property; and
(ii) To provide for deliveries of sufficient volumes of natural gas to provide for minimum plant protection when the plant is shut down.
(2) Volumetric delivery requirements. Notwithstanding any other provisions of this subpart, an interstate pipeline which is delivering natural gas in accordance with this subpart shall not be required to deliver to any customer volumes of natural gas on a daily, monthly, seasonal or other periodic basis which exceed the volumes of natural gas that the interstate pipeline may deliver to such customer without causing the interstate pipeline to violate any daily, monthly, seasonal or other periodic volumetric limitations established in the contract between the interstate pipeline and such customer.
§ 281.205 General rules.
(a) Priority of service categories—(1) Priority 1. Each interstate pipeline shall establish a new high-priority use category of service designated priority one (1) which shall include all the high-priority entitlements calculated in accordance with § 281.206 and those storage injection volumes calculated in accordance with paragraph (c)(2) of this section.
(2) Priority 2. Each interstate pipeline shall establish a new priority of service category designated priority two (2) which shall include all the essential agricultural use requirements calculated in accordance with § 281.207 and those storage injection volumes calculated in accordance with paragraph (c)(2) of this section.
(3) Other priority of service categories. Each interstate pipeline may retain the priority of service categories in its currently effective tariff, but such categories shall be placed at priorities below the new priorities 1 and 2. Each interstate pipeline shall reduce the entitlements in all other existing categories of service to the extent such entitlements have been placed into the new priority of service categories 1 or 2.
(b) Method of curtailment. All deliveries to all customers of the interstate pipeline for all volumes of natural gas not included in priorities 1 and 2 shall be fully curtailed by the interstate pipeline before priorities 1 and 2 entitlements are curtailed. Deliveries for priority 2 entitlements shall be fully curtailed by the interstate pipelines (in accordance with the currently effective curtailment plan) before priority 1 entitlements are curtailed by the interstate pipelines. Nothing in this paragraph is intended to alter the operation of any “small customer” or “small distributor” exemption or waiver (as defined in an interstate pipeline’s currently effective curtailment plan).
(c) Storage—(1) General rule. Interstate pipelines shall classify customer storage injection volumes in the same manner as that used in the currently effective curtailment plan.
(2) Storage sprinkling. Interstate pipelines which classify customer storage injection volumes on the basis of the actual end-use of the natural gas shall recalculate storage injection volumes placed in each priority of service category based upon the index of entitlements to be filed on September 15.
(3) Other treatment of storage. Except as provided in paragraph (c)(2) of this section, no interstate pipeline shall recalculate or reclassify any customer storage injection volumes, and no customer storage injection volumes shall be included as priority 1 or 2 entitlements.
§ 281.206 Priority 1 reclassification.
(a) Definitions. For purposes of this section “high-priority entitlements” means, with respect to a particular interstate pipeline.
(1) In the case of a direct sale customer, the volume of natural gas such direct sale customer is entitled to receive for high-priority uses (as defined in § 281.203) under the currently effective curtailment plan of the interstate pipeline;
(2) In the case of a local distribution company, the volume of natural gas which such local distribution company is entitled to receive on account of the high-priority uses (as defined in § 281.203) of its high-priority user customers under the currently effective curtailment plan of the interstate pipeline;
(3) In the case of an interstate pipeline purchaser the volume of natural gas such interstate pipeline purchaser is entitled to receive from an interstate pipeline supplier for the high-priority entitlements of its direct sale customers, local distribution company customers and interstate pipeline customers.
(b) Direct sale customer and local distribution company customers. (1)(i) Subject to paragraph (b)(2) of this section, and § 281.211 each direct sale customer may request each of its direct interstate pipeline suppliers to reclassify its high-priority entitlements in its currently effective curtailment plan as priority 1 entitlements.
(ii) Subject to paragraph (b)(2) of this section, and § 281.211 each local distribution company must request each of its direct interstate pipeline suppliers to reclassify its high priority entitlements in its currently effective curtailment plan as priority 1 entitlements.
(2) The direct sale customer or local distribution company customer shall designate the entitlements in each priority of service category in the currently effective curtailment plan for which priority 1 reclassification is requested. It shall request that those entitlements for which priority 1 reclassification is requested be excluded from the category of service in which they are included in the currently effective plan.
(3) Subject to § 281.210, the interstate pipeline shall reclassify all such high-priority entitlements as priority 1 entitlements and shall reduce by an equal amount the entitlements in such other priority of service categories as designated by the direct sale customer or local distribution company customer, (in accordance with paragraph (b)(2) of this section).
(c) Interstate pipeline. (1) Subject to paragraph (b)(2) of this section, and § 281.211 an interstate pipeline purchaser may request each of its direct interstate pipeline suppliers to reclassify its high-priority entitlements in its currently effective curtailment plan (equal to the attributed priority 1 entitlements calculated in accordance with § 281.209) as priority 1 entitlements in the currently effective curtailment plan of the interstate pipeline supplier.
(2) The interstate pipeline purchaser shall designate the entitlements in each priority of service category in the currently effective curtailment plan for which priority 1 reclassification is requested. It shall request that those entitlements for which priority 1 classification is requested be excluded from the category of service in which they are included in the currently effective plan.
(3) Subject to § 281.210, the interstate pipeline supplier shall reclassify all such high-priority entitlements as priority 1 entitlements and shall reduce the high-priority entitlements in other priority of service categories as designated by the interstate pipeline customer, (in accordance with paragraph (c)(2) of this section).
§ 281.207 Priority 2 classification.
(a) Direct sale customer. (1) Subject to paragraph (a)(2) of this section, and § 281.211 a direct sale customer may request each of its direct interstate pipeline suppliers to classify its essential agricultural requirements (calculated in accordance with § 281.208) as priority 2 entitlements.
(2) The essential agricultural user shall designate the entitlements in each priority of service category in the currently effective curtailment plan which reflect the essential agricultural requirements. It shall request that entitlements which are reflected in priority of service categories in the currently effective curtailment plan are removed from such priority of service categories.
(3) Subject to § 281.210, the interstate pipeline shall classify all such essential agricultural requirements as priority 2 entitlements and reduce the entitlements in such other priority of service categories as designated by the direct sale customer, (in accordance with paragraph (b)(2) of this section).
(b) Indirect sale customer. Subject to § 281.211 an indirect sale customer which is an essential agricultural user may ask each of its local distribution company direct suppliers to request each interstate pipeline supplier to classify the indirect essential agricultural requirements as priority 2 entitlements.
(c) Local distribution companies. (1) The local distribution company shall attribute (in accordance with § 281.209) the indirect essential agricultural requirements for which reclassification is sought under paragraph (b) of this section to its direct interstate pipeline suppliers. Subject to paragraph (b)(2) of this section, and § 281.211 the local distribution company shall request each of its direct interstate pipeline suppliers to classify the attributed indirect essential agricultural requirements as priority 2 entitlements.
(2) The local distribution company shall designate the entitlements in each priority of service in the currently effective curtailment plan which reflect the attributed indirect essential agricultural requirements. It shall request that those entitlements which are reflected in each category in the currently effective curtailment plan are removed from such priority of service category.
(3) Subject to § 281.210, the interstate pipeline shall classify all such attributed indirect essential agricultural requirements as priority 2 entitlements and shall reduce the entitlements of the local distribution company in such other priority of service categories as designated by the local distribution company, (in accordance with paragraph (b)(2) of this section).
(d) Interstate pipeline. (1) Subject to paragraph (d)(2) of this section, and § 281.211 an interstate pipeline purchaser may request each of its direct interstate pipeline suppliers to classify the attributed priority 2 entitlements (calculated under § 281.209) as priority 2 entitlements in the currently effective curtailment plan of the interstate pipeline supplier.
(2) The interstate pipeline purchaser shall designate the entitlements in each priority of service category in the currently effective curtailment plan of the interstate pipeline supplier which reflects the attributed priority 2 entitlements and request that those entitlements which are reflected in such priority of service categories in the currently effective curtailment plan are removed from such priority of service category.
(3) Subject to § 281.210, the interstate pipeline supplier shall classify the attributed priority 2 entitlements as priority 2 entitlements and shall reduce the entitlements of the interstate pipeline purchaser in such other priority of service categories as designated by the interstate pipeline purchaser, (in accordance with paragraph (d)(2) of this section).
§ 281.208 Calculation of essential agricultural requirements and attributable priority 2 entitlements.
(a) Scope. This section sets forth the method by which:
(1) An essential agricultural user calculates total essential agricultural requirements, direct essential agricultural requirements, and indirect essential agricultural requirements;
(2) A local distribution company calculates attributable indirect essential agricultural requirements for its essential agricultural user customers; and
(3) An interstate pipeline purchaser calculates it attributable priority 2 entitlements.
(b) Calculation by an essential agricultural user—(1) Total essential agricultural requirements—(i) General Rule. (A) The essential agricultural requirements of an essential agricultural user are those volumes (expressed in daily, monthly, seasonal or other appropriate periodic volumes) designated by the Secretary of Agriculture and calculated in accordance with 7 CFR 2900.4; less
(B) Alternative fuel volumes (determined under § 281.304).
(ii) Definitions. Current requirements as used in 7 CFR part 2900 means the lesser of
(A) The energy consumption from the most recent 12 month period for which actual data is available, with necessary adjustments; or
(B) The maximum volume of natural gas for which the essential agricultural user has installed capability to use for essential agricultural uses.
(2) Attribution of total essential agricultural requirement and indirect essential agricultural requirements. (i) The essential agricultural user shall attribute its total essential agricultural requirements among all its sources of supply of natural gas in accordance with § 281.209.
(ii) The direct essential agricultural requirement with respect to a particular interstate pipeline supplier is that part of the total essential agricultural requirements attributed under § 281.209 to the direct interstate pipeline supplier. The indirect essential agricultural requirement with respect to a particular local distribution company supplier is that part of the total essential agricultural requirements attributed under § 281.209 to a direct local distribution company supplier.
(c) Calculation by local distribution companies. (1) A local distribution company shall attribute under § 281.209 the indirect essential agricultural requirements of each of its essential agricultural user customers (calculated under paragraph (b)(2) of this section) among all the interstate pipelines which are direct suppliers of the local distribution company.
(2) That part of the indirect essential agricultural requirements which the local distribution company attributes to a particular interstate pipeline supplier is the attributed indirect essential agricultural requirements attributed to that interstate pipeline.
(d) Interstate pipelines. (1) An interstate pipeline purchaser may attribute under § 281.209 the priority 2 entitlements it includes in its index of entitlements among its direct interstate pipeline suppliers.
(2) The attributable priority 2 entitlements attributed to a particular interstate pipeline supplier is that part of the priority 2 entitlements of the interstate pipeline purchaser which it attributes to a particular interstate pipeline supplier.
§ 281.209 Attribution.
(a) Applicability. (1) This section sets forth the rules for attributing total essential agricultural requirements by an essential agricultural user, indirect essential agricultural requirements of an essential agricultural user by its local distribution company supplier and priority 1 and 2 entitlements by an interstate pipeline purchaser.
(2) This section does not apply to an essential agricultural user or local distribution company which receives all its natural gas supplies from a single source, or an interstate pipeline purchaser which does not receive natural gas from any other interstate pipeline.
(b) Natural gas supplies included for purposes of attribution. (1) For purposes of attribution in accordance with this section, natural gas from all direct sources, including but not limited to pipeline production, production by independent producers, production by affiliates, SNG facilities and natural gas purchased from local distribution companies, and interstate pipelines shall be included.
(2)(i) An essential agricultural user, which attributes under paragraph (d) a portion of the volumes which are its total essential agricultural requirements to a direct source of natural gas other than a direct supplier may not seek classification to priority 2 under § 281.207 for such portion of its total essential agricultural requirements.
(ii) A local distribution company which attributes under paragraph (e) a portion of the volumes which are its indirect essential agricultural requirements to a direct source of natural gas other than a direct supplier may not seek classification to priority 2 under § 281.207 for such portion of its indirect essential agricultural requirements.
(iii) An interstate pipeline purchaser which attributes under paragraph (f) a portion of the volumes of its priority 1 or 2 entitlements to a direct source of natural gas other than a direct supplier may not seek reclassification to priority 1 or classification to priority 2, respectively, for such portion of its priority 1 and 2 entitlements.
(c) Definitions. For purposes of this section:
(1) Direct supplier means, with respect to an essential agricultural user, an interstate pipeline or local distribution company which directly supplies such essential agricultural user, with respect to a local distribution company, an interstate pipeline which directly supplies such local distribution company and, with respect to an interstate pipeline purchaser, and interstate pipeline which directly supplies the interstate pipeline purchaser.
(2) Base period of a direct supplier means the fixed historical period in which entitlements of the customer of the direct supplier were established for purposes of the currently effective curtailment plan of such direct supplier.
(3) Annual quantity entitlements with respect to a particular direct supplier means the total entitlements an essential agricultural user, local distribution company or interstate pipeline is entitled to purchase from that direct supplier in a calendar year under the currently effective curtailment plan.
(d) Essential agricultural user. (1) An essential agricultural user shall calculate its attributable essential agricultural requirements attributable to a particular direct supplier by multiplying its total essential agricultural requirements by the Annual Quantity Entitlements from such direct supplier and dividing the product (numerator) by the sum of all Annual Quantity Entitlements and all volumes received from sources not providing an Annual Quantity Entitlement to such user (denominator).
(2) If an essential agricultural user does not have annual quantity entitlements only with respect to one of its direct suppliers, the attributable essential agricultural requirements attributable to such direct supplier shall be that part of the total essential agricultural requirements not attributed under paragraph (d)(1) of this section.
(3) If an essential agricultural user does not have Annual Quantity Entitlements with respect to more than one of its direct suppliers, the attributable essential agricultural requirements attributable to a particular direct supplier shall be calculated by multiplying its total essential agricultural requirements by the total volume of natural gas received from such supplier in 1972 and dividing the product (numerator) by the total supplies of natural gas received from all sources in 1972 (denominator).
(e) Local distribution company. A local distribution company shall calculate its attributable indirect essential agricultural requirements among its direct suppliers in the same manner as it attributed its supplies to its direct suppliers for purposes of establishing entitlements in the currently effective curtailment plans of such direct supplier.
(f) Interstate pipelines. An interstate pipeline shall attribute Priority 1 and 2 entitlements respectively among its direct pipeline suppliers in the same manner as it attributed its supplies to its direct pipeline suppliers for purposes of establishing entitlements in the currently effective curtailment plans of such direct suppliers.
§ 281.210 Conflicting data.
(a) Interstate pipelines. Notwithstanding any other provision of this subpart, if the records of an interstate pipeline contain information which directly conflicts with a request for reclassification of priority 1 entitlements under § 281.206, or classification of priority 2 entitlements under § 281.207, the interstate pipeline may not include such volumes in priority 1 or 2 of its index of entitlements.
(b) Local distribution companies. Notwithstanding the provisions of § 281.207(c), if the records of a local distribution company contain information which directly conflicts with a request from an essential agricultural user to have the local distribution company to seek classification of volumes in priority 2, the local distribution company may not seek classification for such volumes.
§ 281.211 Filing and documentation.
(a) Priority 1—(1) Direct sales customers and local distribution companies. (i) Each request of a direct sale customer and local distribution company customer for reclassification of high-priority entitlements (as defined in § 281.206) to priority 1 entitlements shall be made in writing no later than July 31, 1979, and shall be accompanied by the data described in paragraph (a)(1)(ii) of this section.
(ii)(A) A table indicating high-priority entitlements (as defined in § 281.206) and the end-use of the natural gas in each priority of service category in the currently effective curtailment plan for which priority 1 reclassification is requested.
(B) A copy of the end-use data used to establish the high-priority requirements and designated end-use of the natural gas.
(2) Interstate pipelines. (i) Each interstate pipeline purchaser which reclassifies high-priority requirements of its customers as priority 1 entitlements may request that its high-priority requirements in the currently effective curtailment plan of its interstate pipeline suppliers (equal to the attributable priority 1 entitlements) be reclassified as priority 1 entitlements. Such requests shall be made in writing no later than August 31, 1979 and shall be accompanied by the data described in paragraph (a)(2)(ii) of this section.
(ii)(A) A table indicating high-priority entitlements (as defined in § 281.206) and end-use of the natural gas in each priority of service category in the currently effective curtailment plan of the interstate pipeline supplier for which priority 1 reclassification is requested.
(B) A copy of the end-use data used to establish the high-priority requirements and designated end-use of the natural gas.
(C) A table indicating the volumes and priority of service categories for which each of direct sale customers and local distribution company customers sought reclassification to priority 1.
(b) Priority 2—(1) Essential agricultural users. (i) Each request for classification of essential agricultural requirements as priority 2 entitlements shall be made in writing to the local distribution company supplier or the direct interstate pipeline supplier, as appropriate, no later than June 15 of each year, and shall set forth all calculations made in accordance with this subpart.
(ii) The request shall be accompanied by a statement that;
(A) Indicates the intended end-use(s) and volume(s) of the natural gas for which priority 2 entitlements are requested.
(B) Indicates the SIC Code activities of the essential agricultural user which qualifies it as an essential agricultural user in accordance with 7 CFR 2900.3.
(C) Includes the data and calculations used to determine essential agricultural requirements under 7 CFR 2900.4.
(D) Includes with respect to any essential agricultural user to which Subpart C applies the data and calculations necessary to determine alternative fuel volumes under § 281.304.
(iii) The statement under paragraph (b)(1)(ii) shall be signed by a responsible official of the essential agricultural user. Such official shall swear or affirm that the statements are true to the best of his information, knowledge and belief.
(2) Local distribution companies. Each request for classification of essential agricultural requirements as priority 2 requirements shall be made in writing to the direct interstate pipeline supplier no later than June 30 of each year, and shall set forth all calculations made in accordance with this subpart and all copies of all requests received from its essential agricultural uses under paragraph (b)(1) of this section.
(3) Interstate pipelines. Each request of an interstate pipeline purchaser for classification of attributable priority 2 entitlements as priority 2 entitlements shall be made in writing to the direct interstate pipeline supplier no later than July 15 of each year, and shall set forth all calculations made in accordance with this subpart and shall include copies of all requests of essential agricultural users and local distribution companies under paragraphs (b)(1) and (2) of this section.
(4) Subsequent request. (i) For 1979, changes in priority 2 entitlements for essential agricultural use establishments that have the ability to use an alternative fuel shall be filed under Subpart C of this part.
(ii) For years subsequent to 1979, the data required by this paragraph must be filed only to the extent that there has been a change in essential agricultural requirements.
§ 281.212 Draft tariff and index of entitlements.
(a) Each interstate pipeline shall prepare draft tariff sheets or sections and a draft index of entitlements in accordance with this subpart.
(b) The draft tariff sheets or sections and index of entitlements shall be served on all customers of the interstate pipeline no later than August 1 of each year.
(c) Copies of all documents received by the interstate pipeline under § 281.210, the draft tariff sheets or sections and the draft index of entitlements shall be served on the Data Verification Committee no later than August 1 of each year.
§ 281.213 Data Verification Committee.
(a) Each interstate pipeline shall establish a Data Verification Committee no later than August 1, 1979. It shall include, at a minimum, a representative of the interstate pipeline, Commission staff, a large and small local distribution company, and an essential agricultural user. The appropriate state and local regulatory bodies, and a representative of the United States Department of Agriculture may, at their option, be members.
(b) The Data Verification Committee shall review all calculations behind the draft tariff sheets or sections and the proposed index of entitlements. The Data Verification Committee may request, and the interstate pipeline shall immediately supply, any information requested by the Data Verification Committee.
(c) Any interested person may file a written protest concerning the index of entitlements. Such protests shall be filed with the Data Verification Committee no later than August 15 of each year.
(d) The Data Verification Committee shall review the draft tariff sheets or sections and index of entitlements and shall review the underlying data for uniformity in preparation.
(e) The Data Verification Committee shall prepare a report concerning the proposed index of requirements and the draft tariff sheets or sections for the interstate pipeline. It shall, at a minimum, specify all arithmetic errors and contain an evaluation of all protests. It may contain a proposed settlement of contested draft tariff sheets or sections. The report shall be submitted to the interstate pipeline no later than September 1 of each year.
§ 281.214 Notice, complaint and remedy.
(a) Complaint. Any interested person may file a complaint concerning an alleged violation of this subpart under § 385.206 of this chapter.
(b) Remedy. If the Commission determines that a violation of this subpart has occurred, it shall take whatever action it deems appropriate in the circumstances. Such action may include payback, in kind or in dollars, by the person benefitting from the violation.
§ 281.215 Additional relief.
If an interstate pipeline rejects (under § 281.210 or otherwise) a request for reclassification under § 281.206 or classification under § 281.207 or if a local distribution company does not request (for any reason including the provisions of § 281.210) classification under § 281.206 on behalf of its high priority uses or reclassification on behalf of its essential agricultural users, the person aggrieved by such action may file a request for relief from curtailment under § 385.206 of this chapter. The request shall contain the information required in § 2.78(b) of the Commission Regulations.
Subpart C—Alternative Fuel Determination
§ 281.301 Purpose.
The purpose of this subpart is to determine the economic practicability and reasonable availability of alternative fuels, as prescribed in section 401(b) of the Natural Gas Policy Act of 1978 for use by essential agricultural use establishments that seek priority 2 entitlements for natural gas.
§ 281.302 Applicability.
This subpart applies to—
(a) Any essential agricultural use establishment for which an essential agricultural user:
(1) Has requested that natural gas be classified as priority 2 entitlements by an interstate pipeline under § 281.207; and
(2) Which has requested from any direct supplier priority 2 entitlements in excess of 300 Mcf per day; and
(b) Any essential agricultural use establishment with a new boiler, other than a diesel engine or turbine designed to use distillate fuels as the only alternative to natural gas, that:
(1) Has a capacity in excess of 300 Mcf of natural gas per day; and
(2) Is put into service for the first time after August 29, 1979.
§ 281.303 Definitions.
For purposes of this subpart—
(a) Ability to use a particular alternative fuel means that an essential agricultural use establishment had, on August 29, 1979, or thereafter acquired the installed physical capability to use the alternative fuel and has used that alternative fuel, in any amount, at any time after 1973, for an essential agricultural use.
(b) Alternative fuel means coal or residual fuel oil.
(c) Boiler means any fuel burning device that is used for generating steam or electricity or producing hot water for space heating or manufacturing processes.
(d) Capacity means the volumes of natural gas used if the boiler is operated at nameplate rated capacity for a continuous 16-hour period.
(e) Coal means lignite or any rank of bituminous coal or anthracite coal.
(f) Direct supplier means, with respect to an essential agricultural use establishment, an interstate pipeline or local distribution company which directly supplies such essential agricultural use establishment; with respect to a local distribution company, an interstate pipeline which directly supplies such local distribution company; and, with respect to an interstate pipeline purchaser, an interstate pipeline which directly supplies the interstate pipeline purchaser.
(g) Distillate fuel means Nos. 1 and 2 heating oils, diesel fuel, and No. 4 fuel oil, as defined in the standard specification for fuel oils published by the American Society for Testing and Materials, ASTM, D396 and D975.
(h) Essential agricultural requirements means volumes of natural gas certified by the Secretary of Agriculture and calculated in accordance with 7 CFR 2900.4 and § 281.208(b) of this part.
(i) Essential agricultural use means any use of natural gas, as defined in § 281.203(a)(2) of this chapter and 7 CFR 2900.3.
(j) Essential agricultural user means an essential agricultural user as defined in § 281.203(b)(3).
(k) Essential agricultural use establishment is used as defined in 7 CFR 2900.2.
(l) Local distribution company means a local distribution company served directly by an interstate pipeline.
(m) Priority 2 entitlements means the essential agricultural requirements of an essential agricultural use establishment which requirements are classified by an interstate pipeline as priority 2 in its curtailment plan under Subpart B.
(n) Residual fuel oil means Nos. 5 and 6 oil, Bunker C, and Navy Special as defined in the standard specification for fuel oils published by the American Society for Testing and Materials, ASTM, D396.
§ 281.304 Computation of alternative fuel volume.
(a) General rule. For purposes of § 281.208(b)(1)(i)(B), and § 281.305:
(1) Alternative fuel volume of an essential agricultural user is equal to the sum of the alternative fuel volumes for each agricultural use establishment for which such user has requested from any direct supplier priority 2 entitlements in excess of 300 Mcf.
(2) Alternative fuel volume for an agricultural use establishment is that portion of such establishment’s natural gas requirements for which such establishment has requested priority 2 curtailment and for which the establishment had on August 29, 1979, or thereafter, the ability to use alternative fuel.
(b) New boilers. For purposes of § 281.208(b)(1)(i)(B) and § 281.305: any new boiler of an essential agricultural use establishment shall be deemed to have alternative fuel volumes, if the boiler:
(1) Has a capacity in excess of 300 Mcf of natural gas per day;
(2) Is put into service for the first time after August 29, 1979; and
(3) Is not a diesel engine or turbine designed to use distillate fuels as the only substitute for natural gas.
§ 281.305 General rule.
Any essential agricultural user subject to this subpart that has requested from any direct supplier priority 2 classification for volumes for any essential agricultural use establishment shall reduce its essential agricultural requirements calculated under § 281.208 to reflect the exclusion of volumes of natural gas for which its essential agricultural establishment has alternative fuel volumes under § 281.304.
Appendix A
1 to Part 281—Comparison of Selected Fuel Price Data, FPC Form No. 423 Versus Monthly Energy Review, 1976—January 1980
| Type of fuel | FPC form No. 423 price data 1 | Monthly energy review price data 2 | ||||||||
|---|---|---|---|---|---|---|---|---|---|---|
| 1976 | 1977 | 1978 | 1979 | January 1980 | 1976 | 1977 | 1978 | 1979 | January 1980 | |
| Cents per MMBtu | ||||||||||
| Fuel Oil: | ||||||||||
| No. 2 | 235.1 | 264.3 | 271.9 | 402.1 | 564.4 | 226.4 | 257.3 | 268.2 | 403.1 | 537.2 |
| Low Sulfur No. 6 | 207.1 | 229.1 | 225.1 | 320.2 | 453.3 | 193.6 | 221.3 | 216.8 | 322.4 | 466.5 |
| High Sulfur No. 6 | 168.7 | 199.9 | 186.7 | 264.7 | 361.4 | 165.9 | 195.2 | 186.1 | 261.5 | 349.6 |
| All No. 6 | 195.9 | 220.4 | 212.3 | 299.7 | 423.5 | 182.8 | 210.4 | 202.7 | 297.0 | 417.7 |
| Coal: All Grades | 84.8 | 94.7 | 111.6 | 122.4 | 128.7 | ( 3) | ( 3) | ( 3) | ( 3) | ( 3) |
| Natural Gas | 103.4 | 130.0 | 143.8 | 175.4 | 194.8 | 97.2 | 131.9 | 154.1 | 201.8 | 237.3 |
| Actual price difference (fuel oil and coal versus natural gas) | ||||||||||
| Fuel Oil: | ||||||||||
| No. 2 | 131.7 | 134.3 | 128.1 | 226.7 | 369.6 | 129.2 | 125.4 | 114.1 | 201.3 | 299.9 |
| Low Sulfur No. 6 | 103.7 | 99.1 | 81.3 | 144.8 | 258.5 | 96.4 | 89.4 | 62.7 | 120.6 | 229.2 |
| High Sulfur No. 6 | 65.3 | 69.1 | 42.9 | 89.3 | 166.6 | 68.7 | 66.3 | 32.0 | 59.7 | 112.3 |
| All No. 6 | 92.5 | 90.4 | 68.5 | 124.3 | 228.7 | 85.6 | 78.5 | 48.6 | 95.2 | 180.4 |
| Coal: All Grades | (18.6) | (35.3) | (32.2) | (53.0) | (66.1) | ( 3) | ( 3) | ( 3) | ( 3) | ( 3) |
| Price difference ratio 4 (fuel oil and coal versus natural gas)—ratio | ||||||||||
| Fuel Oil: | ||||||||||
| No. 2 | 1.274 | 1.033 | .891 | 1.292 | 1.897 | 1.329 | .951 | .740 | .998 | 1.264 |
| Low Sulfur No. 6 | 1.003 | .762 | .565 | .826 | 1.327 | .992 | .678 | .407 | .598 | .966 |
| High Sulfur No. 6 | .632 | .538 | .298 | .509 | .855 | .707 | .480 | .208 | .296 | .473 |
| All No. 6 | .895 | .695 | .476 | .709 | 1.174 | .881 | .595 | .315 | .472 | .760 |
| Coal: All Grades | (.180) | (.272) | (.224) | (.302) | (.339) | ( 3) | ( 3) | ( 3) | ( 3) | ( 3) |
1 As reported in DOE/EIA Energy Data Report entitled
2 Fuel oil prices are reported on FEA Form P302–M–1, “Petroleum Industry Monthly Report for Product Prices.” Natural Gas Prices are those paid by industrial customers of major interstate pipeline companies as reported on FPC Form No. 11, “Natural Gas Pipeline Company Monthly Statement.”
3 The price data for coal is the same as shown under FPC Form No. 423 price data.
4 Mathematically the price difference ratio is P
As determined in Docket No. RM79–40 NOPR issued June 3, 1980, corrected for clerical/typographical error.
PART 284—CERTAIN SALES AND TRANSPORTATION OF NATURAL GAS UNDER THE NATURAL GAS POLICY ACT OF 1978 AND RELATED AUTHORITIES
Subpart A—General Provisions and Conditions
§ 284.1 Definitions.
(a) Transportation includes storage, exchange, backhaul, displacement, or other methods of transportation.
(b) Appropriate state regulatory agency means a state agency which regulates intrastate pipelines and local distribution companies within such state. When used in reference to rates and charges, the term includes only those agencies which set rates and charges on a cost-of-service basis.
(c) Market center means an area where gas purchases and sales occur at the intersection of different pipelines.
(d) Major non-interstate pipeline means a pipeline that fits the following criteria:
(1) It is not a “natural gas company” under section 1 of the Natural Gas Act, or is a “natural gas company” and has obtained a service area determination under section 7(f) of the Natural Gas Act from the Commission;
(2) It delivers annually more than fifty (50) million MMBtu (million British thermal units) of natural gas measured in average deliveries for the previous three calendar years; or, if the pipeline has been operational for less than three years, its design capacity permits deliveries of more than fifty (50) million MMBtu of natural gas annually.
§ 284.2 Refunds and interest.
(a) Refunds. Any rate or charge collected for any sale, transportation, or assignment conducted pursuant to this part which exceeds the rates or charges authorized by this part shall be refunded.
(b) Interest. All refunds made pursuant to this section must include interest at an amount determined in accordance with § 154.501(d) of this chapter.
§ 284.3 Jurisdiction under the Natural Gas Act.
(a) For purposes of section 1(b) of the Natural Gas Act, the provisions of such Act and the jurisdiction of the Commission under such Act shall not apply to any transportation or sale in interstate commerce of natural gas if such a transaction is authorized pursuant to section 311 or 312 of the NGPA.
(b) For purposes of the Natural Gas Act, the term “natural gas company” (as defined by section 2(6) of such Act) shall not include any person by reason of, or with respect to, any transaction involving natural gas if the provisions of the Natural Gas Act do not apply to such transaction by reason of paragraph (a) of this section.
(c) The Natural Gas Act shall not apply to facilities utilized solely for transportation authorized by section 311(a) of the NGPA.
§ 284.4 Reporting.
(a) Reports in MMBtu. All reports filed pursuant to this part must indicate quantities of natural gas in MMBtu’s. An MMBtu means a million British thermal units. A British thermal unit or Btu means the quantity of heat required to raise the temperature of one pound avoirdupois of pure water from 58.5 degrees to 59.5 degrees Fahrenheit, determined in accordance with paragraphs (b) and (c) of this section.
(b) Measurement. The Btu content of one cubic foot of natural gas under the standard conditions specified in paragraph (c) of this section is the number of Btu’s produced by the complete combustion of such cubic foot of gas, at constant pressure with air of the same temperature and pressure as the gas, when the products of combustion are cooled to the initial temperature of the gas and air and when the water formed by such combustion is condensed to a liquid state.
(c) Standard conditions. The standard conditions for purposes of paragraph (b) of this section are as follows: The gas is saturated with water vapor at 60 degrees Fahrenheit under a pressure equivalent to that of 30.00 inches of mercury at 32 degrees Fahrenheit, under standard gravitational force (980.665 centimeters per second squared).
§ 284.5 Further terms and conditions.
The Commission may prospectively, by rule or order, impose such further terms and conditions as it deems appropriate on transactions authorized by this part.
§ 284.6 Rate interpretations.
(a) Procedure. A pipeline may obtain an interpretation pursuant to subpart L of part 385 of this chapter concerning whether particular rates and charges comply with the requirements of this part.
(b) Address. Requests for interpretations should be addressed to: FERC Part 284 Interpretations, Office of General Counsel, Federal Energy Regulatory Commission, Washington, DC 20426.
§ 284.7 Firm transportation service.
(a) Firm transportation availability. (1) An interstate pipeline that provides transportation service under subpart B or G or this part must offer such transportation service on a firm basis and separately from any sales service.
(2) An intrastate pipeline that provides transportation service under Subpart C may offer such transportation service on a firm basis.
(3) Service on a firm basis means that the service is not subject to a prior claim by another customer or another class of service and receives the same priority as any other class of firm service.
(4) An interstate pipeline that provided a firm sales service on May 18, 1992, and that offers transportation service on a firm basis under subpart B or G of this part, must offer a firm transportation service under which firm shippers may receive delivery up to their firm entitlements on a daily basis without penalty.
(b) Non-discriminatory access. (1) An interstate pipeline or intrastate pipeline that offers transportation service on a firm basis under subpart B, C or G must provide such service without undue discrimination, or preference, including undue discrimination or preference in the quality of service provided, the duration of service, the categories, prices, or volumes of natural gas to be transported, customer classification, or undue discrimination or preference of any kind.
(2) An interstate pipeline that offers transportation service on a firm basis under subpart B or G of this part must provide each service on a basis that is equal in quality for all gas supplies transported under that service, whether purchased from the pipeline or another seller.
(3) An interstate pipeline that offers transportation service on a firm basis under subpart B or G of this part may not include in its tariff any provision that inhibits the development of market centers.
(c) Reasonable operational conditions. Consistent with paragraph (b) of this section, a pipeline may impose reasonable operational conditions on any service provided under this part. Such conditions must be filed by the pipeline as part of its transportation tariff.
(d) Segmentation. An interstate pipeline that offers transportation service under subpart B or G of this part must permit a shipper to make use of the firm capacity for which it has contracted by segmenting that capacity into separate parts for its own use or for the purpose of releasing that capacity to replacement shippers to the extent such segmentation is operationally feasible.
(e) Reservation fee. Where the customer purchases firm service, a pipeline may impose a reservation fee or charge on a shipper as a condition for providing such service. Except for pipelines subject to subpart C of this part, if a reservation fee is charged, it must recover all fixed costs attributable to the firm transportation service, unless the Commission permits the pipeline to recover some of the fixed costs in the volumetric portion of a two-part rate. A reservation fee may not recover any variable costs or fixed costs not attributable to the firm transportation service. Except as provided in this paragraph, the pipeline may not include in a rate for any transportation provided under subpart B, C or G of this part any minimum bill or minimum take provision, or any other provision that has the effect of guaranteeing revenue.
(f) Limitation. A person providing service under Subpart B, C or G of this part is not required to provide any requested transportation service for which capacity is not available or that would require the construction or acquisition of any new facilities.
§ 284.8 Release of firm capacity on interstate pipelines.
(a) An interstate pipeline that offers transportation service on a firm basis under subpart B or G of this part must include in its tariff a mechanism for firm shippers to release firm capacity to the pipeline for resale by the pipeline on a firm basis under this section.
(b)(1) Firm shippers must be permitted to release their capacity, in whole or in part, on a permanent or short-term basis, without restriction on the terms or conditions of the release. A firm shipper may arrange for a replacement shipper to obtain its released capacity from the pipeline. A replacement shipper is any shipper that obtains released capacity.
(2) The rate charged the replacement shipper for a release of capacity may not exceed the applicable maximum rate, except that no rate limitation applies to the release of capacity for a period of one year or less if the release is to take effect on or before one year from the date on which the pipeline is notified of the release. Payments or other consideration exchanged between the releasing and replacement shippers in a release to an asset manager as defined in paragraph (h)(3) of this section are not subject to the maximum rate.
(c) Except as provided in paragraph (h) of this section, a firm shipper that wants to release any or all of its firm capacity must notify the pipeline of the terms and conditions under which the shipper will release its capacity. The firm shipper must also notify the pipeline of any replacement shipper designated to obtain the released capacity under the terms and conditions specified by the firm shipper.
(d) The pipeline must provide notice of offers to release or to purchase capacity, the terms and conditions of such offers, and the name of any replacement shipper designated in paragraph (b) of this section, on an Internet web site, for a reasonable period.
(e) The pipeline must allocate released capacity to the person offering the highest rate and offering to meet any other terms and conditions of the release. If more than one person offers the highest rate and meets the terms and conditions of the release, the released capacity may be allocated on a basis provided in the pipeline’s tariff, provided however, if the replacement shipper designated in paragraph (b) of this section offers the highest rate, the capacity must be allocated to the designated replacement shipper.
(f) Unless otherwise agreed by the pipeline, the contract of the shipper releasing capacity will remain in full force and effect, with the net proceeds from any resale to a replacement shipper credited to the releasing shipper’s reservation charge.
(g) To the extent necessary, a firm shipper on an interstate pipeline that offers transportation service on a firm basis under subpart B or G of this part is granted a limited-jurisdiction blanket certificate of public convenience and necessity pursuant to section 7 of the Natural Gas Act solely for the purpose of releasing firm capacity pursuant to this section.
(h)(1) The following releases need not comply with the bidding requirements of paragraphs (c) through (e) of this section:
(i) A release of capacity to an asset manager as defined in paragraph (h)(3) of this section;
(ii) A release of capacity to a marketer participating in a state-regulated retail access program as defined in paragraph (h)(4) of this section;
(iii) A release for more than one year at the maximum tariff rate; and
(iv) A release for any period of 31 days or less.
(v) If a release is exempt from bidding under paragraph (h)(1) of this section, notice of the release must be provided on the pipeline’s Internet Web site as soon as possible, but not later than the first nomination, after the release transaction commences.
(2) When a release of capacity is exempt from bidding under paragraph (h)(1)(iv) of this section, a firm shipper may not roll over, extend or in any way continue the release to the same replacement shipper using the 31 days or less bidding exemption until 28 days after the first release period has ended. The 28-day hiatus does not apply to any re-release to the same replacement shipper that is posted for bidding or that qualifies for any of the other exemptions from bidding in paragraph (h)(1) of this section.
(3) A release to an asset manager exempt from bidding requirements under paragraph (h)(1)(i) of this section is any pre-arranged release that contains a condition that the releasing shipper may call upon the replacement shipper to deliver to, or purchase from, the releasing shipper a volume of gas up to 100 percent of the daily contract demand of the released transportation or storage capacity, as provided in paragraphs (h)(3)(i) through (h)(3)(iii) of this paragraph.
(i) If the capacity release is for a period of one year or less, the asset manager’s delivery or purchase obligation must apply on any day during a minimum period of the lesser of five months (or 155 days) or the term of the release.
(ii) If the capacity release is for a period of more than one year, the asset manager’s delivery or purchase obligation must apply on any day during a minimum period of five months (or 155 days) of each twelve-month period of the release, and on five-twelfths of the days of any additional period of the release not equal to twelve months.
(iii) If the capacity release is a release of storage capacity, the asset manager’s delivery or purchase obligation need only be up to 100 percent of the daily contract demand under the release for storage withdrawals or injections, as applicable.
(4) A release to a marketer participating in a state-regulated retail access program exempt from bidding requirements under paragraph (h)(1)(ii) of this section is any prearranged capacity release that will be utilized by the replacement shipper to provide the gas supply requirement of retail consumers pursuant to a retail access program approved by the state agency with jurisdiction over the local distribution company that provides delivery service to such retail consumers.
§ 284.9 Interruptible transportation service.
(a) Interruptible transportation availability. (1) An interstate pipeline that provides firm transportation service under subpart B or G of this part must also offer transportation service on an interruptible basis under that subpart or subparts and separately from any sales service.
(2) An intrastate pipeline that provides transportation service under Subpart C may offer such transportation service on an interruptible basis.
(3) Service on an interruptible basis means that the capacity used to provide the service is subject to a prior claim by another customer or another class of service and receives a lower priority than such other classes of service.
(b) The provisions regarding non-discriminatory access, reasonable operational conditions, and limitations contained in § 284.7 (b), (c), and (f) apply to pipelines providing interruptible service under this section.
(c) Reservation fee. No reservation fee may be imposed for interruptible service. A pipeline’s rate for any transportation service provided under this section may not include any minimum bill provision, minimum take provision, or any other provision that has the effect of guaranteeing revenue.
§ 284.10 Rates.
(a) Applicability. Any rate charged for transportation service under subparts B and G of this part must be established under a rate schedule that is filed with the Commission prior to commencement of such service and that conforms to the requirements of this section.
(b) Rate objectives. Maximum rates for both peak and offpeak periods must be designed to achieve the following three objectives:
(1) Rates for service during peak periods should ration capacity;
(2) Rates for firm service during off-peak periods and for interruptible service during all periods should maximize throughput; and
(3) The pipeline’s revenue requirement allocated to firm and interruptible services should be attained by providing the projected units of service in peak and off-peak periods at the maximum rate for each service.
(c) Rate design—(1) Volumetric rates. Except as provided in § 284.7(e), any rate filed for service subject to this section must be a one-part rate that recovers the costs allocated to the service to the extent that the projected units of that service are actually purchased and may not include a demand charge, a minimum bill or minimum take provision or any other provision that has the effect of guaranteeing revenue. Such rate must separately identify cost components attributable to transportation, storage, and gathering costs.
(2) Based on projected units of service. Any rate filed for service subject to this section must be designed to recover costs on the basis of projected units of service. The fixed costs allocated to capacity reservations, as determined in accordance with § 284.7(e), should be used along with the projected nominations accepted by the pipeline to compute the unit reservation fee. The remaining fixed costs and all variable costs should be used to determine the volumetric rate computed on the basis of projected volumes to be transported. The units projected for the service in rates filed under this section may be changed only in a subsequent rate filing under section 4 of the Natural Gas Act.
(3) Differentiation due to time and distance. Any rate filed for service subject to this section must reasonably reflect any material variation in the cost of providing the service due to:
(i) Whether the service is provided during a peak or an off-peak period; and
(ii) The distance over which the transportation is provided.
(4) Cost basis for rates. (i) Any maximum rate filed under this section must be designed to recover on a unit basis, solely those costs which are properly allocated to the service to which the rate applies.
(ii) Any minimum rate filed under this section must be based on the average variable costs which are properly allocated to the service to which the rate applies.
(5) Rate flexibility. (i) Any rate schedule filed under this section must state a maximum rate and a minimum rate.
(ii)(A) Except as provided in paragraph (d)(5)(ii)(B) of this section the pipeline may charge an individual customer any rate that is neither greater than the maximum rate nor less than the minimum rate on file for that service.
(B) If a pipeline does not hold a blanket certificate under Subpart G of this part, it may not charge, in a transaction involving its marketing affiliate, a rate that is lower than the highest rate it charges in any transaction not involving its marketing affiliate.
(iii) The pipeline may not file a revised or new rate designed to recover costs not recovered under rates previously in effect.
§ 284.11 Environmental compliance.
(a) Any activity involving the construction of, or the abandonment with removal of, facilities that is authorized pursuant to § 284.3(c) and subpart B or C of this part is subject to the terms and conditions of § 157.206(b) of this chapter.
(b) Advance notification—(1) General rule. Except as provided in paragraph (b)(2) of this section, at least 30 days prior to commencing construction a company must file notification with the Commission of any activity described in paragraph (a) of this section.
(2) Exception. The advance notification described in paragraph (b)(1) of this section is not required if the cost of the project does not exceed the cost limit specified in Column 1 of Table I of § 157.208(d) of this chapter.
(c) Contents of advance notification. The advance notification described in paragraph (b)(1) of this section must include the following information:
(1) A brief description of the facilities to be constructed or abandoned with removal of facilities (including pipeline size and length, compression horsepower, design capacity, and cost of construction);
(2) Evidence of having complied with each provision of § 157.206(b) of this chapter;
(3) Current U.S. Geological Survey 7.5-minute series topographical maps showing the location of the facilities; and
(4) A description of the procedures to be used for erosion control, revegetation and maintenance, and stream and wetland crossings.
(d) Reporting requirements. On or before May 1 of each year, a company must file (on electronic media pursuant to § 385.2011 of this chapter, accompanied by 7 paper copies) an annual report that lists for the previous calendar year each activity that is described in paragraph (a) of this section, and which was completed during the previous calendar year and exempt from the advance notification requirement pursuant to paragraph (b)(2) of this section. For each such activity, the company must include all of the information described in paragraph (c) of this section.
§ 284.12 Standards for pipeline business operations and communications.
(a) Incorporation by reference of NAESB standards. (1) An interstate pipeline that transports gas under subparts B or G of this part must comply with the business practices and electronic communications standards as promulgated by the North American Energy Standards Board, as incorporated herein by reference in paragraphs (a)(1)(i) through (vii) of this section.
(i) Additional Standards (Version 3.2, August 15, 2020);
(ii) Nominations Related Standards (Version 3.2, August 15, 2020);
(iii) Flowing Gas Related Standards (Version 3.2, August 15, 2020);
(iv) Invoicing Related Standards (Version 3.2, August 15, 2020);
(v) Quadrant Electronic Delivery Mechanism Related Standards (Version 3.2, August 15, 2020);
(vi) Capacity Release Related Standards (Version 3.2, August 15, 2020); and
(vii) internet Electronic Transport Related Standards (Version 3.2, August 15, 2020).
(2) The material listed in this paragraph (a)(2) is incorporated by reference into this section with the approval of the Director of the Federal Register under 5 U.S.C. 552(a) and 1 CFR part 51. All approved material is available for inspection at the Federal Energy Regulatory Commission (the Commission) and at the National Archives and Records Administration (NARA). Contact the Commission at: https://www.ferc.gov, email [email protected], or via phone call at 202–502–8371. For information on the availability of this material at NARA, visit www.archives.gov/federal-register/cfr/ibr-locations or email [email protected]. The material may be obtained from the North American Energy Standards Board, 801 Travis Street, Suite 1675, Houston, TX 77002, Phone: (713) 356–0060; https://www.naesb.org/.
(b) Business practices and electronic communication requirements. An interstate pipeline that transports gas under subparts B or G of this part must comply with the following requirements. The regulations in this paragraph adopt the abbreviations and definitions contained in the North American Energy Standards Board Wholesale Gas Quadrant standards incorporated by reference in paragraph (a)(1) of this section.
(1) Nominations.
(i) Intra-day nominations.
(A) A pipeline must give scheduling priority to an intra-day nomination submitted by a firm shipper over nominated and scheduled volumes for interruptible shippers. When an interruptible shipper’s scheduled volumes are to be reduced as a result of an intra-day nomination by a firm shipper, the interruptible shipper must be provided with advance notice of such reduction and must be notified whether penalties will apply on the day its volumes are reduced.
(B) An intra-day nomination submitted on the day prior to gas flow will take effect at the start of the gas day at 9 a.m. CCT.
(ii) Capacity release scheduling. (A) Pipelines must permit shippers acquiring released capacity to submit a nomination at the earliest available nomination opportunity after the acquisition of capacity. If the pipeline requires the replacement shipper to enter into a contract, the contract must be issued within one hour after the pipeline has been notified of the release, but the requirement for contracting must not inhibit the ability of the replacement shipper to submit a nomination at the earliest available nomination opportunity.
(B) A pipeline must permit releasing shippers, as a condition of a capacity release, to recall released capacity and renominate such recalled capacity at each nomination opportunity. Each replacement shipper must be provided with advance notice of such recall and must be notified whether penalties will apply on the day its volumes are reduced.
(iii) Within 60 days after a shipper request, a pipeline must file to make appropriate tariff changes at the Commission to allow multiple shippers associated with a designated agent or asset manager to be jointly and severally liable under a single firm transportation service agreement, subject to reasonable terms and conditions.
(2) Flowing gas. (i) Operational balancing agreements. A pipeline must enter into Operational Balancing Agreements at all points of interconnection between its system and the system of another interstate or intrastate pipeline.
(ii) Netting and trading of imbalances. A pipeline must establish provisions permitting shippers and their agents to offset imbalances accruing on different contracts held by the shipper with the pipeline and to trade imbalances with other shippers where such imbalances have similar operational impact on the pipeline’s system.
(iii) Imbalance management. A pipeline with imbalance penalty provisions in its tariff must provide, to the extent operationally practicable, parking and lending or other services that facilitate the ability of its shippers to manage transportation imbalances. A pipeline also must provide its shippers the opportunity to obtain similar imbalance management services from other providers and shall provide those shippers using other providers access to transportation and other pipeline services without undue discrimination or preference.
(iv) Operational flow orders. A pipeline must take all reasonable actions to minimize the issuance and adverse impacts of operational flow orders (OFOs) or other measures taken to respond to adverse operational events on its system. A pipeline must set forth in its tariff clear standards for when such measures will begin and end and must provide timely information that will enable shippers to minimize the adverse impacts of these measures.
(v) Penalties. A pipeline may include in its tariff transportation penalties only to the extent necessary to prevent the impairment of reliable service. Pipelines may not retain net penalty revenues, but must credit them to shippers in a manner to be prescribed in the pipeline’s tariff. A pipeline with penalty provisions in its tariff must provide to shippers, on a timely basis, as much information as possible about the imbalance and overrun status of each shipper and the imbalance of the pipeline’s system.
(3) Communication protocols. (i)(A) All electronic information provided and electronic transactions conducted by a pipeline must be provided on the public Internet. A pipeline must provide, upon request, private network connections using internet tools, internet directory services, and internet communication protocols and must provide these networks with non-discriminatory access to all electronic information. A pipeline may charge a reasonable fee to recover the costs of providing such an interconnection.
(B) A pipeline must implement this requirement no later than June 1, 2000.
(ii) A pipeline must comply with the following requirements for documents constituting public information posted on the pipeline web site:
(A) The documents must be accessible to the public over the public Internet using commercially available web browsers, without imposition of a password or other access requirement;
(B) Users must be able to search an entire document online for selected words, and must be able to copy selected portions of the documents; and
(C) Documents on the web site should be directly downloadable without the need for users to first view the documents on the web site.
(iii) If a pipeline uses a numeric or other designation to represent information, an electronic cross-reference table between the numeric or other designation and the information represented must be available to users, at a cost not to exceed reasonable shipping and handling.
(iv) A pipeline must provide the same content for all information regardless of the electronic format in which it is provided.
(v) A pipeline must maintain, for a period of three years, all information displayed and transactions conducted electronically under this section and be able to recover and regenerate all such electronic information and documents. The pipeline must make this archived information available in electronic form for a reasonable fee.
(vi) A pipeline must post notices of operational flow orders, critical periods, and other critical notices on its Internet web site and must notify affected parties of such notices in either of the following ways to be chosen by the affected party: Internet E-Mail or direct notification to the party’s Internet URL address.
(4) Communication and information sharing among pipelines and public utilities. (i) A pipeline is authorized to share non-public, operational information with a public utility, as defined in § 38.2(a) of this chapter or another pipeline covered by this section, for the purpose of promoting reliable service or operational planning.
(ii) Except as permitted in paragraph (b)(4)(i) of this section, a pipeline and its employees, contractors, consultants, and agents are prohibited from disclosing, or using anyone as a conduit for the disclosure of, non-public, operational information received from a public utility pursuant to § 38.2 of this chapter to a third party or to its marketing function employees as that term is defined in § 358.3(d) of this chapter.
§ 284.13 Reporting requirements for interstate pipelines.
An interstate pipeline that provides transportation service under subparts B or G of this part must comply with the following reporting requirements.
(a) Cross references. The pipeline must comply with the requirements in Part 358, Part 250, and Part 260 of this chapter, where applicable.
(b) Reports on firm and interruptible services. An interstate pipeline must post the following information on its Internet web site, and provide the information in downloadable file formats, in conformity with § 284.12 of this part, and must maintain access to that information for a period not less than 90 days from the date of posting.
(1) For pipeline firm service and for release transactions under § 284.8, the pipeline must post with respect to each contract, or revision of a contract for service, the following information no later than the first nomination under a transaction:
(i) The full legal name of the shipper, and identification number, of the shipper receiving service under the contract, and the full legal name, and identification number, of the releasing shipper if a capacity release is involved or an indication that the pipeline is the seller of transportation capacity;
(ii) The contract number for the shipper receiving service under the contract, and, in addition, for released transactions, the contract number of the releasing shipper’s contract;
(iii) The rate charged under each contract;
(iv) The maximum rate, and for capacity release transactions not subject to a maximum rate, the maximum rate that would be applicable to a comparable sale of pipeline services;
(v) The duration of the contract;
(vi) The receipt and delivery points and the zones or segments covered by the contract, including the location name and code adopted by the pipeline in conformance with paragraph (f) of this section for each point, zone or segment;
(vii) The contract quantity or the volumetric quantity under a volumetric release;
(viii) Special terms and conditions applicable to a capacity release transaction, including all aspects in which the contract deviates from the pipeline’s tariff, and special details pertaining to a pipeline transportation contract, including whether the contract is a negotiated rate contract, conditions applicable to a discounted transportation contract, and all aspects in which the contract deviates from the pipeline’s tariff.
(ix) Whether there is an affiliate relationship between the pipeline and the shipper or between the releasing and replacement shipper.
(x) Whether a capacity release is a release to an asset manager as defined in § 284.8(h)(3) and the asset manager’s obligation to deliver gas to, or purchase gas from, the releasing shipper.
(xi) Whether a capacity release is a release to a marketer participating in a state-regulated retail access program as defined in § 284.8(h)(4).
(2) For pipeline interruptible service, the pipeline must post on a daily basis no later than the first nomination for service under an interruptible agreement, the following information:
(i) The full legal name, and identification number, of the shipper receiving service;
(ii) The rate charged;
(iii) The maximum rate;
(iv) The receipt and delivery points between which the shipper is entitled to transport gas at the rate charged, including the location name and code adopted by the pipeline in conformance with paragraph (f) of this section for each point, zone, or segment;
(v) The quantity of gas the shipper is entitled to transport;
(vi) Special details pertaining to the agreement, including conditions applicable to a discounted transportation contract and all aspects in which the agreement deviates from the pipeline’s tariff.
(vii) Whether the shipper is affiliated with the pipeline.
(c) Index of customers. (1) On the first business day of each calendar quarter, an interstate pipeline must file with the Commission an index of all its firm transportation and storage customers under contract as of the first day of the calendar quarter that complies with the requirements set forth by the Commission. The Commission will establish the requirements and format for such filing. The index of customers must also posted on the pipeline’s Internet web, in accordance with standards adopted in § 284.12 of this part, and made available from the Internet web site in a downloadable format complying with the specifications established by the Commission. The information posted on the pipeline’s Internet web site must be made available until the next quarterly index is posted.
(2) For each shipper receiving firm transportation or storage service, the index must include the following information:
(i) The full legal name, and identification number, of the shipper;
(ii) The applicable rate schedule number under which the service is being provided;
(iii) The contract number;
(iv) The effective and expiration dates of the contract;
(v) For transportation service, the maximum daily contract quantity (specify unit of measurement), and for storage service, the maximum storage quantity (specify unit of measurement);
(vi) The receipt and delivery points and the zones or segments covered by the contract, including the location name and code adopted by the pipeline in conformance with paragraph (f) of this section for each point, zone or segment;
(vii) An indication as to whether the contract includes negotiated rates;
(viii) The name of any agent or asset manager managing a shipper’s transportation service; and
(ix) Any affiliate relationship between the pipeline and a shipper or between the pipeline and a shipper’s asset manager or agent.
(3) The requirements of this section do not apply to contracts which relate solely to the release of capacity under § 284.8, unless the release is permanent.
(4) Pipelines that are not required to comply with the index of customers posting and filing requirements of this section must comply with the index of customer requirements applicable to transportation and sales under Part 157 as set forth under § 154.111(b) and (c) of this chapter.
(5) The requirements for the electronic index are available through the Commission’s website, https://www.ferc.gov.
(d) Capacity and flow information. (1) An interstate pipeline must provide on its Internet web site and in downloadable file formats, in conformity with § 284.12 of this part, equal and timely access to information relevant to the availability of all transportation services whenever capacity is scheduled, including, but not limited to, the availability of capacity at receipt points, on the mainline, at delivery points, and in storage fields, whether the capacity is available directly from the pipeline or through capacity release, the total design capacity of each point or segment on the system, the amount scheduled at each point or segment whenever capacity is scheduled, and all planned and actual service outages or reductions in service capacity. An interstate pipeline must also provide information about the volumes of no-notice transportation provided pursuant to § 284.7(a)(4). This information must be posted at each receipt and delivery point before 11:30 a.m. central clock time three days after the day of gas flow and must reflect the pipeline’s best estimate. Updated information must be posted at each receipt and delivery point as necessary within ten business days after the month of gas flow.
(2) An interstate pipeline must make an annual filing by March 1 of each year showing the estimated peak day capacity of the pipeline’s system, and the estimated storage capacity and maximum daily delivery capability of storage facilities under reasonably representative operating assumptions and the respective assignments of that capacity to the various firm services provided by the pipeline.
(e) Notice of bypass. An interstate pipeline that provides transportation (except storage) to a customer that is located in the service area of a local distribution company and will not be delivering the customer’s gas to that local distribution company, must file with the Commission, within thirty days after commencing such transportation, a statement that the interstate pipeline has notified the local distribution company and the local distribution company’s appropriate regulatory agency in writing of the proposed transportation prior to commencement.
(f) Location codes. An interstate pipeline must maintain a posting on its publicly available Internet Web site of the pipeline’s location names and codes for all current and inactive receipt and delivery points on its system, including, for each point: Direction of flow, the location of the point, the location zone if such exists, the Commission company identification code (CID), if any, of the upstream and/or downstream entity, the location type, the current status as active and inactive, and the date(s) the point becomes active or inactive. The pipeline must provide the information in downloadable file formats, in conformity with the requirements of 18 CFR 284.12 of this chapter.
§ 284.14 Posting requirements of major non-interstate pipelines.
(a) Daily posting requirement. A major non-interstate pipeline must post on a daily basis on a publicly-accessible Internet Web site and in downloadable file format equal and timely access to information regarding receipt or delivery points, including non-physical scheduling points.
(1) A major non-interstate pipeline must post data for each receipt or delivery point, or for any point that operates as both a delivery and receipt point for the major non-interstate pipeline, to which natural gas transportation is scheduled:
(i) With a physically metered design capacity equal to or greater than 15,000 MMBtu (million British thermal units)/day; or
(ii) If a physically metered design capacity is not known or does not exist for such a point, with a maximum volume scheduled to such a point equal to or greater than 15,000 MMBtu on any day within the prior three calendar years.
(2) Notwithstanding the requirements of subsection 284.14(a)(1), a receipt point is not subject to the posting requirements of this section if the maximum scheduled volume at the receipt point was less than 5,000 MMBtu on every day within the prior three calendar years. If a point has operated as both a receipt and delivery point any time within the prior three calendar years, subsection 284.14(a)(2) shall not apply to that point.
(3) A major non-interstate pipeline that must post data for a receipt or delivery point shall do so within 45 days of the date that the point becomes eligible for posting.
(4) For each delivery or receipt point that must be posted, a major non-interstate pipeline must provide the following information by 10:00 p.m. central clock time the day prior to scheduled natural gas flow: Transportation Service Provider Name, Posting Date, Posting Time, Nomination Cycle, Location Name, Additional Location Information if Needed to Distinguish Between Points, Location Purpose Description (Receipt, Delivery, Bilateral, or Non-physical Scheduling Point), Posted Capacity (physically metered design capacity or maximum flow within the last three years), Method of Determining Posted Capacity (Capacity or Maximum Volume), Scheduled Volume, Available Capacity (Calculated as Posted Capacity minus Scheduled Capacity), and Measurement Unit (Dth, MMBtu, or MCf). For receipt or delivery points with bi-directional scheduled flows, the Scheduled Volume for scheduled flow in each direction must be posted. The information in this subsection must remain posted for at least a period of one year.
(5) Newly constructed major non-interstate pipelines, which commence service after the effective date of this section, must comply with the requirements of this section upon their in-service date. Except for newly constructed major non-interstate pipelines, a major non-interstate pipeline that becomes subject to the requirements of this section in any year after the effective date of this section has until June 1 of that year to comply with the requirements of this section.
(b) Exemptions to daily posting requirement. The following categories of major non-interstate pipelines are exempt from the posting requirement of § 284.14(a):
(1) Those that are located upstream of a processing, treatment or dehydration plant;
(2) Those that deliver more than ninety-five percent (95%) of the natural gas volumes they flow directly to end-users or on-system storage as measured in average deliveries for the previous three calendar years;
(3) Storage providers;
(4) Those that deliver the entirety of their transported natural gas directly to an end-user that owns or operates the major non-interstate pipeline.
§ 284.15 Bidding by affiliates in open seasons for pipeline capacity.
(a) Multiple affiliates of the same entity may not participate in an open season for pipeline capacity conducted by any interstate pipeline providing service under subparts B and G of this part, in which the pipeline may allocate capacity on a pro rata basis, unless each affiliate has an independent business reason for submitting a bid.
(b) For purposes of this section, an affiliate is any person that satisfies the definition of affiliate in § 358.3(a)(1) and (3) of this chapter with respect to another entity participating in an open season subject to paragraph (a) of this section.
Subpart B—Certain Transportation by Interstate Pipelines
§ 284.101 Applicability.
This subpart implements section 311(a)(1) of the NGPA and applies to the transportation of natural gas by any interstate pipeline on behalf of:
(a) Any intrastate pipeline; or
(b) Any local distribution company.
§ 284.102 Transportation by interstate pipelines.
(a) Subject to paragraphs (d) and (e) of this section, other provisions of this subpart, and the conditions of subpart A of this part, any interstate pipeline is authorized without prior Commission approval, to transport natural gas on behalf of:
(1) Any intrastate pipeline; or
(2) Any local distribution company.
(b) Any rates charged for transportation under this subpart may not exceed the just and reasonable rates established under subpart A of this part.
(c) An interstate pipeline that engages in transportation arrangements under this subpart must file reports in accordance with § 284.13 of this chapter.
(d) Transportation of natural gas is not on behalf of an intrastate pipeline or local distribution company or authorized under this section unless:
(1) The intrastate pipeline or local distribution company has physical custody of and transports the natural gas at some point; or
(2) The intrastate pipeline or local distribution company holds title to the natural gas at some point, which may occur prior to, during, or after the time that the gas is being transported by the interstate pipeline, for a purpose related to its status and functions as an intrastate pipeline or its status and functions as a local distribution company; or
(3) The gas is delivered at some point to a customer that either is located in a local distribution company’s service area or is physically able to receive direct deliveries of gas from an intrastate pipeline, and that local distribution company or intrastate pipeline certifies that it is on its behalf that the interstate pipeline is providing transportation service.
(e) An interstate pipeline must obtain from its shippers certifications including sufficient information to verify that their services qualify under this section. Prior to commencing transportation service described in paragraph (d)(3) of this section, an interstate pipeline must receive the certification required from a local distribution company or an intrastate pipeline pursuant to paragraph (d)(3) of this section.
§§ 284.103-284.106 [Reserved]
Subpart C—Certain Transportation by Intrastate Pipelines
§ 284.121 Applicability.
This subpart implements section 311(a)(2) of the NGPA and applies to the transportation of natural gas by any intrastate pipeline on behalf of:
(a) Any interstate pipeline, or
(b) Any local distribution company served by any interstate pipeline.
§ 284.122 Transportation by intrastate pipelines.
(a) Subject to paragraph (d) of this section, other provisions of this subpart, and the applicable conditions of Subpart A of this part, any intrastate pipeline may, without prior Commission approval, transport natural gas on behalf of:
(1) Any interstate pipeline; or
(2) Any local distribution company served by an interstate pipeline.
(b) No rate charged for transportation authorized under this subpart may exceed a fair and equitable rate under § 284.123.
(c) Any intrastate pipeline engaged in transportation arrangements authorized under this section must file reports as required by § 284.126.
(d) Transportation of natural gas is not on behalf of an interstate pipeline or local distribution company served by an interstate pipeline or authorized under this section unless:
(1) The interstate pipeline or local distribution company has physical custody of and transports the natural gas at some point; or
(2) The interstate pipeline or local distribution company holds title to the natural gas at some point, which may occur prior to, during, or after the time that the gas is being transported by the intrastate pipeline, for a purpose related to its status and functions as an interstate pipeline or its status and functions as a local distribution company.
§ 284.123 Rates and charges.
(a) General rule. Rates and charges for transportation of natural gas authorized under § 284.122(a) shall be fair and equitable as determined in accordance with paragraph (b) of this section.
(b) Election of rates. (1) Subject to the conditions in §§ 284.7 and 284.9 of this chapter, an intrastate pipeline may elect to:
(i) Base its rates upon the methodology used:
(A) In designing rates to recover the cost of gathering, treatment, processing, transportation, delivery or similar service (including storage service) included in one of its then effective firm sales rate schedules for city-gate service on file with the appropriate state regulatory agency; or
(B) In determining the allowance permitted by the appropriate state regulatory agency to be included in a natural gas distributor’s rates for city-gate natural gas service; or
(ii) To use the rates contained in one of its then effective transportation rate schedules for intrastate service on file with the appropriate state regulatory agency which the intrastate pipeline determines covers service comparable to service under this subpart.
(2)(i) If an intrastate pipeline does not choose to make any election under paragraph (b)(1) of this section, it shall apply for Commission approval, by order, of the proposed rates and charges by filing with the Commission the proposed rates and charges, and information showing the proposed rates and charges are fair and equitable. Each petition for approval filed under this paragraph must be accompanied by the fee set forth in § 381.403 or by a petition for waiver pursuant to § 384.106 of this chapter. Upon filing the petition for approval, the intrastate pipeline may commence the transportation service and charge and collect the proposed rate, subject to refund.
(ii) 150 days after the date on which the Commission received an application filed pursuant to paragraph (b)(2)(i) of this section, the rate proposed in the application will be deemed to be fair and equitable and not in excess of an amount which interstate pipelines would be permitted to charge for providing similar transportation service, unless within the 150 day period, the Commission either extends the time for action, or institutes a proceeding in which all interested parties will be afforded an opportunity for written comments and for the oral presentation of views, data and arguments. In such proceeding, the Commission either will approve the rate or disapprove the rate and order refund, with interest, of any amount which has been determined to be in excess of those shown to be fair and equitable or in excess of the rates and charges which interstate pipelines would be permitted to charge for providing similar transportation service.
(iii) A Commission order approving or disapproving a transportation rate under this paragraph supersedes a rate determined in accordance with paragraph (b)(1) of this section.
(c) Treatment of revenues. The Commission presumes that all revenues received by an intrastate pipeline in connection with transportation authorized under § 284.122(a) and computed in accordance with paragraph (b)(1) of this section have been or will be taken into account by the appropriate state regulatory agency for purposes of establishing transportation charges by the intrastate pipeline for service to intrastate customers.
(d) Presumptions. If the intrastate pipeline is charging a rate computed pursuant to § 284.123(b)(1), the rate charged is presumed to be:
(1) Fair and equitable; and
(2) Not in excess of the rates and charges which interstate pipelines would be permitted to charge for providing similar transportation service.
(e) Filing requirements. Within 30 days of commencement of new service, any intrastate pipeline that engages in transportation arrangements under this subpart must file with the Commission a statement that includes the pipeline’s interstate rates, the rate election made pursuant to paragraph (b) of this section, and a description of how the pipeline will engage in these transportation arrangements, including operating conditions, such as quality standards and financial viability of the shipper. If the pipeline changes its operations, rates, or rate election under this subpart, it must amend the statement and file such amendments not later than 30 days after commencement of the change in operations or the change in rate election.
(f) Electronic filing of statements, and related materials—(1) General rule. All filings made in proceedings initiated under this part must be made electronically, including rates and charges, or parts thereof, and material related thereto, statements, and all workpapers.
(2) Requirements for signature. All filings must be signed in compliance with the following:
(i) The signature on a filing constitutes a certification that the contents are true to the best knowledge and belief of the signer, and that the signer possesses full power and authority to sign the filing.
(ii) A filing must be signed by one of the following:
(A) The person on behalf of whom the filing is made;
(B) An officer, agent, or employee of the company, governmental authority, agency, or instrumentality on behalf of which the filing is made; or,
(C) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.
(iii) All signatures on the filing or any document included in the filing must comply, where applicable, with the requirements in § 385.2005 of this chapter with respect to sworn declarations or statements and electronic signatures.
(3) Format requirements for electronic filing. The requirements and formats for electronic filing are listed in instructions for electronic filing and for each form. These formats are available through the Commission’s website, https://www.ferc.gov.
(g) Election of Notice Procedures—(1) Applicability. An intrastate pipeline filing for approval of rates, a statement of operating conditions, and any amendments or modifications thereto pursuant to this section may use the notice procedures in this paragraph. Any intrastate pipeline electing to use these notice procedures for a filing must clearly state its election to use these procedures in the filing. Such filing is approved and the rates deemed fair and equitable and not in excess of the amount that an interstate pipeline would be permitted to charge for similar transportation service if the requirements in paragraph (g)(8) of this section have been fulfilled.
(2) Rejection of filing. The Director of the Office of Energy Market Regulation or his designee shall reject within 7 days of the date of filing a request which patently fails to comply with the provisions of paragraph (e) or (f) of this section, without prejudice to the intrastate pipeline refiling a complete application. If such filing was required by this section, that filing must be refiled within 14 days of the date of the rejection.
(3) Publication of notice of filing. The Secretary of the Commission shall issue a notice of the filing within 10 days of the date of the filing, which will then be published in the
(4) Protests. (i) Any person or the Commission’s staff may file a protest prior to the deadline for protests.
(ii) Protests shall be filed with the Commission in the form required by Part 385 of this chapter including a detailed statement of the protestor’s interest in the filing and the specific reasons and rationale for the objection and whether the protestor seeks to be an intervenor.
(5) Effect of protest. If a protest is filed in accordance with paragraph (g)(4) of this section, then the intrastate pipeline, the person who filed the protest, any intervenors and Commission staff shall have 30 days from the deadline for filing protests established by the Secretary of the Commission in accordance with paragraph (g)(3) of this section, to resolve the protest, and to file a withdrawal of the protest pursuant to paragraph (g)(6) of this section. Informal settlement conferences may be convened by the Director of the Office of Energy Market Regulation or his designee during this 30 day period. If a protest is not withdrawn or dismissed by end of that 30 day period, the filing shall not be deemed approved pursuant to this paragraph. Within 60 days from the deadline for filing protests established by the Secretary of the Commission in accordance with paragraph (g)(3) of this section the Commission will establish procedures to resolve the proceeding.
(6) Withdrawal of protests. The protestor may withdraw a protest by submitting written notice of withdrawal to the Secretary of the Commission pursuant to § 385.216 of this chapter and serving a copy on the intrastate pipeline, any intervenors, and any person who has filed a motion to intervene in the proceeding.
(7) Amendments or modifications to tariff records prior to approval. An intrastate pipeline may file to amend or modify a tariff record contained in the initial filing pursuant to the procedures under this paragraph (g) which has not yet been approved pursuant to paragraph (g)(8) of this section. Such filing will toll the notice period established in paragraph (g)(3) of this section and the Secretary of the Commission will issue a notice establishing new deadlines for comments and protests for the entire filing pursuant to paragraph (g)(3).
(8) Final approval. (i) If no protest is filed within the time allowed by the Secretary of the Commission under paragraph (g)(3) of this section, the filing by the intrastate pipeline is approved, effective on the date proposed in the filing requesting approval unless the intrastate pipeline withdraws, amends, or modifies its filing or the filing is rejected pursuant to paragraph (g)(2) of this section.
(ii) If any protest is filed within the time allowed by the Secretary of the Commission under paragraph (g)(3) of this section and is subsequently withdrawn before the end of the 30-day reconciliation period provided by paragraph (g)(5) of this section, the filing by the intrastate pipeline is approved effective on the date proposed in the filing requesting approval unless the intrastate pipeline withdraws, amends, or modifies its filing or the filing is rejected pursuant to paragraph (g)(2) of this section.
(9) Periodic rate review. Rates of pipelines approved by the Commission pursuant to this paragraph are required to be periodically reviewed.
(i) Any intrastate pipeline with rates so approved must file an application for rate approval under this section on or before the date five years following the date it filed the application for authorization of rates pursuant to this paragraph. Any Hinshaw pipeline that has been a granted a blanket certificate under § 284.224 of this chapter and with rates approved pursuant to this paragraph must on or before the date five years following the date it filed the application for authorization of the rates pursuant to this paragraph either file under this section cost, throughput, revenue and other data, in the form specified in § 154.313 of this chapter, to allow the Commission to determine whether any change in rates is required pursuant to section 5 of the Natural Gas Act or an application for rate authorization pursuant to this section.
(ii) An intrastate pipeline with rates approved pursuant to the rate election in paragraph (b)(1) of this section that remain unchanged during the five-year review period which were approved based on then effective state rates may file a certification with the Commission pursuant to this paragraph (g) that the rates continue to comply on the same basis with the requirements set forth in paragraph (b)(1) of this section. Such certification of rates will meet the periodic rate review requirement set forth in this paragraph (g)(9) unless the Commission determines that further proceedings concerning the rates are appropriate.
(iii) If the state rate used pursuant to paragraph (b)(1) of this section for approval of a rate pursuant to this paragraph (g) is changed, not later than 30 days after that changed rate becomes effective, the intrastate pipeline must file a new rate election pursuant to paragraph (b) of this section.
(10) Withdrawal of filing prior to approval. A pipeline may, pursuant to paragraph (h) of this section, withdraw in its entirety a filing made pursuant to paragraph (g) that has not been approved by filing a withdrawal motion with the Commission. A filing that is withdrawn will not fulfill the requirements under paragraph (g)(8) of this section.
(h) Withdrawal of filing. A pipeline may withdraw in its entirety a filing pursuant to this section that has not been approved by filing a withdrawal motion with the Commission.
(1) The withdrawal motion must state that any amounts collected subject to refund in excess of the rates authorized the Commission will be refunded with interest calculated and a refund report filed with the Commission in accordance with § 154.501 of this chapter. The refunds must be made within 60 days of the date the withdrawal motion becomes effective.
(2) The withdrawal motion will become effective, and the filing will be deemed withdrawn at the end of 15 days from the date of filing of the withdrawal motion, if no order disallowing the motion is issued within that period. If an answer in opposition is filed within the 15-day period, the withdrawal is not effective until an order accepting the withdrawal is issued.
§ 284.124 Terms and conditions.
Contracts for the transportation of natural gas authorized under this subpart shall provide that the transportation arrangement is subject to the provisions of this subpart.
§ 284.125 [Reserved]
§ 284.126 Reporting requirements.
(a) Notice of bypass. An intrastate pipeline that provides transportation (except storage) under § 284.122 to a customer that is located in the service area of a local distribution company and will not be delivering the customer’s gas to that local distribution company, must file with the Commission within thirty days after commencing such transportation, a statement that the interstate pipeline has notified the local distribution and the local distribution company’s appropriate state regulatory agency in writing of the proposed transportation prior to commencement.
(b) Form No. 549D, Quarterly Transportation and Storage Report of Intrastate Natural Gas and Hinshaw Pipelines.
(1) Each intrastate pipeline must use Form No. 549D to file a quarterly report with the Commission and the appropriate state regulatory agency that contains, for each transportation and storage service provided during the preceding calendar quarter under § 284.122, the following information on each transaction, aggregated by contract:
(i) The full legal name, and identification number, of the shipper receiving the service, including whether there is an affiliate relationship between the pipeline and the shipper;
(ii) The type of service performed (i.e., firm or interruptible transportation, storage, or other service);
(iii) The rate charged under each contract, specifying the rate schedule/name of service and docket where the rates were approved. The report should separately state each rate component set forth in the contract (i.e., reservation, usage, and any other charges);
(iv) The primary receipt and delivery points covered by the contract, identified by the list of points that the pipeline has published with the Commission;
(v) The quantity of natural gas the shipper is entitled to transport, store, or deliver under each contract;
(vi) The duration of the contract, specifying the beginning and (for firm contracts only) ending month and year of the current agreement;
(vii) Total volumes transported, stored, injected or withdrawn for the shipper; and
(viii) Annual revenues received for each shipper, excluding revenues from storage services. The report should separately state revenues received under each component, and need only be reported every fourth quarter.
(2) The quarterly Form No. 549D report for the period January 1 through March 31 must be filed on or before June 1. The quarterly report for the period April 1 through June 30 must be filed on or before September 1. The quarterly report for the period July 1 through September 30 must be filed on or before December 1. The quarterly report for the period October 1 through December 31 must be filed on or before March 1.
(3) Each Form No. 549D report must be filed as prescribed in § 385.2011 of this chapter as indicated in the General Instructions and Data Dictionary set out in the quarterly reporting form. Each report must be prepared and filed in conformance with the Commission’s software or XML Schema, eTariff filing structure, and reporting guidance, so as to be posted and available for downloading from the FERC Web site (http://www.ferc.gov). One copy of the report must be retained by the respondent in its files.
(4) Intrastate pipelines filing Form No. 549D are no longer required to file Form No. 549—Intrastate Pipeline Annual Transportation Report after their March 31, 2011 filing.
Subpart D—Certain Sales by Intrastate Pipelines
§ 284.141 Applicability.
This subpart implements section 311(b) of the NGPA and applies to certain sales of natural gas by intrastate pipelines to:
(a) Interstate pipelines; and
(b) Local distribution companies served by interstate pipelines.
§ 284.142 Sales by intrastate pipelines.
Any intrastate pipeline may, without prior Commission approval, sell natural gas to any interstate pipeline or any local distribution company served by an interstate pipeline. The rates charged by an intrastate pipeline pursuant to this subpart may not exceed the price for gas as negotiated in the contract, plus a fair and equitable transportation rate as determined in accordance with § 284.123.
§§ 284.143-284.148 [Reserved]
Subparts E–F [Reserved]
Subpart G—Blanket Certificates Authorizing Certain Transportation by Interstate Pipelines on Behalf of Others and Services by Local Distribution Companies
§ 284.221 General rule; transportation by interstate pipelines on behalf of others.
(a) Blanket certificate. Any interstate pipeline may apply under this section for a single blanket certificate authorizing the transportation of natural gas on behalf of others in accordance with this subpart. A certificate of public convenience and necessity under this section is granted pursuant to section 7 of the Natural Gas Act.
(b) Application procedure. (1) An application for a blanket certificate under this section must be filed electronically. The format for the electronic application filing available through the Commission’s website, https://www.ferc.gov, and must include:
(i) The name of the interstate pipeline; and
(ii) A statement by the interstate pipeline that it will comply with the conditions in paragraph (c) of this section.
(2) Upon receipt of an application under this section, the Commission will conduct a hearing pursuant to section 7(c) of the Natural Gas Act and § 157.11 of this chapter and, if required by the public convenience and necessity, will issue to the interstate pipeline a blanket certificate authorizing such pipeline company to transport natural gas, as provided under this subpart.
(c) General conditions. Any blanket certificate under this subpart is subject to the conditions of subpart A of this part.
(d) Pre-grant of abandonment. (1) Except as provided in paragraph (d)(2) of this section, abandonment of transportation services is authorized pursuant to section 7(b) of the Natural Gas Act upon the expiration of the contractual term or upon termination of each individual transportation arrangement authorized under a certificate granted under this section.
(2) Paragraph (d)(1) of this section does not apply if the individual transportation arrangement is for firm transportation under a contract with a term of one year or more, and the firm shipper:
(i) Exercises any contractual right to continue such service; or
(ii) Gives notice that it wants to continue its transportation arrangement and will match the longest term and highest rate for its firm service, up to the applicable maximum rate under § 284.10, offered to the pipeline during the period established in the pipeline’s tariff for receiving such offers by any other person desiring firm capacity, and executes a contract matching the terms of any such offer. To be eligible to exercise this right of first refusal, the firm shipper’s contract must be for service for twelve consecutive months or more at the applicable maximum rate for that service, except that a contract for more than one year, for a service which is not available for 12 consecutive months, would be subject to the right of first refusal.
(e) Availability of regular certificates. This subpart does not preclude an interstate pipeline from applying for an individual certificate of public convenience and necessity for any particular transportation service.
(f) Cross references. (1) Any local distribution company served by an interstate pipeline may apply for a blanket certificate to perform certain services under § 284.224 of this chapter.
(2) Any interstate pipeline may apply under subpart F of part 157 of this chapter for a blanket certificate to construct or acquire and operate certain natural gas facilities that are necessary to provide transportation under § 284.223.
(3) Section 157.208 of this chapter provides automatic authorization for the construction, acquisition, operation, replacement, and miscellaneous rearrangement of certain eligible facilities, as defined in § 157.202 of this chapter, subject to limits specified in § 157.208(d) of this chapter and § 284.11.
(4) Authorization for delivery points is subject to the automatic authorization under § 157.211(a)(1) and the prior notice procedures under § 157.211(a)(2) and § 157.205.
(g) Flexible receipt point authority. (1) An interstate pipeline authorized to transport gas under a certificate granted under this section may, at the request of the shipper and without prior notice:
(i) Reduce or discontinue receipts of natural gas at a particular receipt point from a supplier; and
(ii) Commence or increase receipts at a particular receipt point from that supplier or any other supplier.
(2) The total natural gas volumes received by the interstate pipeline following any such reassignment under this paragraph must not exceed the total volume of natural gas that the interstate pipeline may transport on behalf of the shipper under a certificate granted under this section.
(3) The receipt points to which natural gas volumes may be reassigned under this paragraph include eligible facilities under § 157.208 which are authorized to be constructed and operated pursuant to a certificate issued under subpart F of part 157 of this chapter.
(h) Flexible delivery point authority. (1) An interstate pipeline authorized to transport gas under a certificate issued pursuant to this section may at the request of the shipper and without prior notice:
(i) Reduce or discontinue deliveries of natural gas to a particular delivery point; and
(ii) Commence or increase deliveries at a particular delivery point.
(2) The total natural gas volumes delivered by the interstate pipeline following any such reassignment must not exceed the total amount of natural gas that the interstate pipeline is authorized under a certificate issued pursuant to this section to transport on behalf of the shipper.
(3) The delivery points to which natural gas volumes may be reassigned under this paragraph include facilities authorized to be constructed and operated only under § 157.211 and the prior notice conditions of § 157.205 of this chapter.
§ 284.222 [Reserved]
§ 284.223 Transportation by interstate pipelines on behalf of shippers.
Subject to the provisions of this subpart and the conditions of Subpart A of this part, any interstate pipeline issued a certificate under § 284.221 is authorized, without prior notice to or approval by the Commission, to transport natural gas for any duration for any shipper for any end-use by that shipper or any other person.
§ 284.224 Certain transportation and sales by local distribution companies.
(a) Applicability. This section applies to local distribution companies served by interstate pipelines, including persons who are not subject to the jurisdiction of the Commission, by reason of section 1(c) of the Natural Gas Act.
(b) Blanket certificate—(1) Any local distribution company served by an interstate pipeline or any Hinshaw pipeline may apply for a blanket certificate under this section.
(2) Upon application for a certificate under this section, a hearing will be conducted under section 7(c) of the Natural Gas Act, § 157.11 of this chapter, and subpart H of part 385 of this chapter.
(3) The Commission will grant a blanket certificate to such local distribution company or Hinshaw pipeline under this section, if required by the present or future public convenience and necessity. Such certificate will authorize the local distribution company to engage in the sale or transportation of natural gas that is subject to the Commission’s jurisdiction under the Natural Gas Act, to the same extent that and in the same manner that intrastate pipelines are authorized to engage in such activities by subparts C and D of this part, except as otherwise provided in paragraph (e)(2) of this section.
(c) Application procedure. Applications for blanket certificates must be accompanied by the fee prescribed in § 381.207 of this chapter or a petition for waiver pursuant to § 381.106 of this chapter, and shall state:
(1) The exact legal name of applicant; its principal place of business; whether an individual, partnership, corporation or otherwise; the state under the laws of which it is organized or authorized; the agency having jurisdiction over rates and tariffs; and the name, title, and mailing address of the person or persons to whom communications concerning the application are to be addressed;
(2) The volumes of natural gas which:
(i) Were received during the most recent 12-month period by the applicant within or at the boundary of a state, and
(ii) Were exempt from the Natural Gas Act jurisdiction of the Commission by reason of section 1(c) of the Natural Gas Act, if any;
(3) The total volume of natural gas received by the applicant from all sources during the same time period;
(4) Citation to all currently valid declarations of exemption issued by the Commission under section 1(c) of the Natural Gas Act if any;
(5) A statement that the applicant will comply with the conditions in paragraph (e) of this section;
(6) A form of notice suitable for publication in the
(7) A statement of the methodology to be used in calculating rates for services to be rendered, setting forth any elections under § 284.123 or paragraph (e)(2) of this section and a sample calculation employing the methodology using current data. If a rate election is made under paragraph (e)(2) of this section, this statement shall contain the following items (reflecting the 12-month period used to justify costs in the most recently approved rate case conducted by an appropriate state regulatory agency):
(i) Total operating revenues,
(ii) Purchase gas costs,
(iii) Distribution costs (which include that portion of the common costs allocated to the distribution function),
(iv) The volume throughput of the system categorized by sales, transportation and exchange service, and
(v) A study which determines transportation costs on a unit revenue basis in accordance with paragraph (e)(2) of this section, including any supporting work papers.
(d) Effect of certificate. (1) Any certificate granted under this section will authorize the certificate holder to engage in transactions of the type authorized by subparts C and D of this part.
(2) Acceptance of a certificate or conduct of an activity authorized thereunder will:
(i) Not impair the continued validity of any exclusion under section 1(c) of the Natural Gas Act which may be applicable to the certificate holder, and
(ii) Not subject the certificate holder to the Natural Gas Act jurisdiction to the Commission except to the extent necessary to enforce the terms and conditions of the certificate.
(e) General conditions. (1) Except as provided in paragraph (e)(2) of this section, any transaction authorized under a blanket certificate is subject to the same rates and charges, terms and conditions, and reporting requirements that apply to a transaction authorized for an intrastate pipeline under subparts C and D of this part.
(2) Rate election. If the certificate holder does not have any existing rates on file with the appropriate state regulatory agency for city-gate service, the certificate holder may make the rate election specified in § 284.123(b)(1) only if:
(i) The certificate holder’s existing rates are approved by an appropriate state regulatory agency,
(ii) The rates and charges for any transportation are computed by using the portion of the certificate holder weighted average annual unit revenue (per MMBtu) generated by existing rates which is attributable to the cost of gathering, treatment, processing, transportation, delivery or similar service (including storage service), and
(iii) The Commission has approved the method for computing rates and charges specified in paragraph (e)(2)(ii) of this section.
(3) Volumetric test. The volumes of natural gas sold or assigned under the blanket certificate may not exceed the volumes obtained from sources other than interstate supplies.
(4) Filings. Any filings made with the Commission that report individual transactions shall reference the docket number of the proceeding in which the blanket certificate was granted.
(5) Filing Requirements. Filings under this section must comply with the requirements of § 284.123 (f) of this part. The tariff filing requirements of Part 154 of this chapter shall not apply to transactions authorized by the blanket certificate.
(f) Pregrant of abandonment. Abandonment of transportation services or sales, pursuant to section 7(b) of the Natural Gas Act, is authorized upon the expiration of the contractual term of each individual arrangement authorized by a blanket certificate under this section.
(g) Hinshaw pipeline without blanket certificate. A Hinshaw pipeline that does not obtain a blanket certificate under this section is not authorized to sell or transport natural gas as an intrastate pipeline under subparts C and D of this part.
(h) Definitions. For the purposes of this section:
(1) A Hinshaw pipeline means any person engaged in the transportation of natural gas which is not subject to the jurisdiction of the Commission under the Natural Gas Act solely by reason of section 1(c) of the Natural Gas Act.
(2) Interstate supplies means any natural gas obtained, either directly or indirectly, from:
(i) The system supplies of an interstate pipeline, or
(ii) Natural gas reserves which were committed or dedicated to interstate commerce on November 8, 1978.
§§ 284.225-284.226 [Reserved]
§ 284.227 Certain transportation by intrastate pipelines.
(a) Blanket certificate. A blanket certificate shall issue under this section to any intrastate pipeline that receives natural gas produced in adjacent Federal waters or onshore or offshore in an adjacent state, provided that:
(1) The gas must be received by the intrastate pipeline from a gatherer or other intrastate pipeline;
(2) The intrastate pipeline delivers the gas in the intrastate pipeline’s state of operation to an end user or another intrastate pipeline; and
(3) The gas ultimately used by an end user in the same state.
(b) Effective date. If an intrastate pipeline is providing a transportation service described in paragraph (a) of this section as of February 1, 1992, and the service is not a qualifying service under § 284.122 of subpart C of this part, a blanket certificate shall issue under paragraph (a) of this section and become effective as of February 1, 1992. If an intrastate pipeline is not providing a transportation service described in paragraph (a) of this section as of February 1, 1992 the blanket certificate shall issue and become effective on the date that the intrastate pipeline commences such a service that is not a qualifying service under § 284.122 of subpart C of this part.
(c) Acceptance of certificate. An intrastate pipeline shall be deemed to have accepted a blanket certificate under this section if it continues after February 1, 1992, a service described in paragraph (a) of this section that is not a qualifying service under § 284.122 of subpart C or commences such a service after November 4, 1991.
(d) Terms and conditions. An intrastate pipeline’s blanket certificate transportation authority under this section is subject to its compliance with all terms and conditions of subpart C of this part, except that service under this section does not have to be on behalf of an interstate pipeline or local distribution company served by an interstate pipeline.
(e) Pregrant of abandonment. Abandonment of transportation services, pursuant to section 7(b) of the Natural Gas Act, is authorized upon the expiration of the contractual term of each individual arrangement authorized by a blanket certificate under this section.
(f) Effect of certificate. Acceptance of a certificate issued under this section or conduct of activity authorized under this section will not subject the certificate holder to the Natural Gas Act jurisdiction of the Commission except to the extent necessary to enforce the terms and conditions of the certificate.
Subpart H [Reserved]
Subpart I—Emergency Natural Gas Sale, Transportation, and Exchange Transactions
§ 284.261 Purpose.
This subpart exempts a person who engages in an emergency natural gas transaction, as defined for purposes of this subpart, in interstate commerce from the certificate requirements of section 7 of the Natural Gas Act and from the conditions of § 284.10, except as provided in § 284.266, and §§ 284.7–284.9 and §§ 284.11–284.13 of subpart A of this chapter.
§ 284.262 Definitions.
For purposes of this subpart:
Emergency means:
(1) Any situation in which an actual or expected shortage of gas supply or capacity would require an interstate pipeline company, intrastate pipeline, local distribution company, or Hinshaw pipeline to curtail deliveries of gas or provide less than the projected level of service to any pipeline customer, including any situation in which additional supplies or capacity are necessary to ensure a pipeline’s contracted level of service to any customer, but not including any situation in which additional supplies or capacity are needed to increase the contracted level of service to an existing customer or to provide service to a new customer; or
(2) A sudden unanticipated loss of natural gas supply or capacity; or
(3) An anticipated loss of natural gas supply or capacity due to a foreseeable facility outage resulting from a landslide or riverbed erosion or other natural forces beyond the participant’s control. Participants may seek a temporary certificate under §§ 157.17 of this chapter if the facilities to remedy the emergency cannot be constructed automatically under § 2.55(b) or § 157.208(a) of this chapter.
(4) A situation in which the participant, in good faith, determines that immediate action is required or is reasonably anticipated to be required for protection of life or health or for maintenance of physical property.
Emergency does not mean any situation resulting from a failure by any person to transport natural gas under subpart B, C, or G of this part.
Projected level of service means the level of gas volumes to be delivered by the company for each customer and additional gas volumes needed by a customer due solely to a weather-induced increase in requirements.
Emergency natural gas means natural gas sold, transported, or exchanged in an emergency natural gas transaction.
Emergency natural gas transaction means the sale, transportation, or exchange of natural gas (including the construction and operation of necessary facilities) conducted pursuant to this subpart, that is:
(1) Necessary to alleviate an emergency; and
(2) Not anticipated to extend for more than 60 days in duration.
Emergency facilities means any facilities necessary to alleviate the emergency within the time frame established in § 284.264(b). Participants can seek permanent authority to operate the emergency facilities either under the temporary certificate provisions of § 157.17 of this chapter or the prior notice provisions of § 157.208(b) of this chapter.
Participant means any first seller, interstate pipeline, intrastate pipeline, local distribution company or Hinshaw pipeline that participates in an emergency natural gas transaction under this subpart.
Recipient means:
(1) In the case of a sale of emergency natural gas, the purchaser of such gas; or
(2) In the case of a transportation or exchange of natural gas when there is no sale of emergency natural gas under this subpart, the participant who receives the gas.
Hinshaw pipeline means a pipeline that is exempt from the Natural Gas Act jurisdiction of the Commission by reason of section 1(c) of the Natural Gas Act.
§ 284.263 Exemption from section 7 of Natural Gas Act and certain regulatory conditions.
Any participant that engages in an emergency natural gas transaction conducted in accordance with this subpart is exempt from the requirements of section 7 of the Natural Gas Act and the conditions of § 284.10, except as provided in § 284.266, and from the requirements of §§ 284.7–284.9 and §§ 284.11–284.13 of subpart A of this part. Participation in any emergency natural gas transaction will not subject any participant to the jurisdiction of the Commission under section 7 of the Natural Gas Act except to the extent such transaction is provided for in this subpart.
§ 284.264 Terms and conditions.
(a) General conditions. (1) A participant must make every reasonable attempt to minimize use of emergency natural gas transactions.
(2) Before deliveries of emergency natural gas commence, a responsible official of the recipient must provide any participants in the emergency natural gas transaction sufficient information to enable the participants to form a good faith belief that an emergency exists or is imminent.
(3) No participant may engage in an emergency natural gas transaction if its participation will adversely affect service to its existing customers.
(4) A participant may not sell emergency natural gas if, during the term of the sale, it is also purchasing emergency natural gas under this subpart, except when natural gas is being sold to relieve an emergency on another, separate segment of the participant’s system.
(5) An interstate pipeline, acting in an emergency gas transaction as a broker or agent on behalf of another participant or any other person, may not receive compensation for such brokerage or agency service.
(6) A recipient of emergency natural gas that directly benefits from the service must:
(i) Provide line loss and the fuel volumes required to transport the emergency natural gas; and
(ii) Pay for the facilities required to be constructed to conduct the emergency natural gas transaction.
(b) Duration—(1) Emergency sale or transportation. An emergency natural gas transaction is limited to 60 consecutive calendar days, except that such transaction may be continued for an additional 60 consecutive days if:
(i) Fifteen days prior to the end of the initial 60-day period, the recipient of emergency natural gas files a petition that:
(A) Describes fully the continued emergency,
(B) Requests a waiver of the initial 60-day limitation and permission for an extension of the transaction for an additional 60 days; and
(ii) Within the 15-day period, the Commission does not, by order, prohibit continuation of the emergency natural gas transaction for the additional 60-day period.
(2) Redelivery in emergency exchange. The redelivery of emergency natural gas received under an exchange arrangement must occur within 180 consecutive days following the termination of deliveries of the emergency natural gas.
§ 284.265 Cost recovery by interstate pipeline.
(a) Except as provided in paragraph (b), an interstate pipeline that provides emergency natural gas, whether from its system supply or by special purchase, must directly assign the emergency gas costs to the recipient.
(b) If an interstate pipeline cannot identify individual recipients, the interstate pipeline must roll the emergency gas costs into its general system supply costs.
§ 284.266 Rates and charges for interstate pipelines.
(a) Transportation rates—(1) Rate on file. If an interstate pipeline has on file with the Commission an effective transportation rate schedule that conforms to § 284.10, it must use volumetric rates based upon fully-allocated costs and adjusted only for time and distance.
(2) Rate not on file. If an interstate pipeline does not have on file with the Commission a transportation rate schedule that conforms to § 284.10, it may:
(i) Base its rates upon the methodology used in designing rates to recover the transmission and related storage costs included in one of its then-effective sales rates schedules; or
(ii) Use the rates contained in one of its transportation rate schedules on file with the Commission which the interstate pipeline determines covers service comparable to transportation service authorized under this subpart.
(b) Interstate pipeline costs excluded from rate base. An interstate pipeline may not include in its jurisdictional rate base any cost associated with facilities installed and operated in connection with an emergency natural gas transaction unless a certificate of public convenience and necessity has been issued authorizing the costs. Absent a certificate, such facilities may only be used to conduct emergency natural gas transactions or transactions authorized under section 311 of the NGPA.
§ 284.267 Intrastate pipeline emergency transportation rates.
General rule. Rates and charges for transportation of emergency gas by intrastate pipelines authorized under this subpart must be determined in accordance with § 284.123 of this chapter.
§ 284.268 Local distribution company emergency transportation rates.
(a) Rate on file. A local distribution company that has a rate on file with an appropriate state regulatory agency for city-gate transportation services must determine its rates and charges for transportation of emergency natural gas in accordance with § 284.123 of this chapter.
(b) Rate not on file. A local distribution company that does not have a rate on file with an appropriate state regulatory agency for city-gate transportation services must determine its rates and charges for transportation of emergency natural gas (per unit volume of emergency natural gas transported) in accordance with § 284.224(e)(2)(ii) of this chapter.
§ 284.269 Intrastate pipeline and local distribution company emergency sales rates.
An intrastate pipeline or local distribution company must determine its rates for sales of emergency natural gas under this subpart in accordance with § 284.142.
§ 284.270 Reporting requirements.
(a) Forty-eight hour report for sales transactions. Within 48 hours after deliveries of emergency natural gas commence, the purchasing participant must notify the Commission by email, facsimile or other written report of the sale, stating, in the following sequences:
(1) That the report is submitted pursuant to § 284.270 for an emergency natural gas transaction;
(2) The date deliveries commenced;
(3) The specific nature of the situation, explained in sufficient detail to demonstrate how the situation qualifies as an emergency under § 284.262 and under the conditions of § 284.264, and anticipated duration of the emergency;
(4) The estimated total amount and average daily amount of emergency natural gas to be purchased during the term of the transaction;
(5) The purchase price of the emergency natural gas;
(6) The transportation rate; and
(7) The identity of all participants involved in the transaction, including any customers to whom the emergency natural gas is to be assigned.
(b) Forty-eight hour report for transportation (excluding exchanges). Within 48 hours after deliveries commence in an emergency natural gas transaction which does not involve the sale of emergency natural gas, the recipient of emergency natural gas shall notify the Commission by email, facsimile or other written report of the transportation, stating, in the following sequence:
(1) That the report is submitted pursuant to § 284.270 for an emergency transaction;
(2) The date deliveries commenced;
(3) The specific nature of the situation, explained in sufficient detail to demonstrate how the situation qualifies as an emergency under § 284.262 and under the conditions of § 284.264, and anticipated duration of the emergency;
(4) The estimated total amount and average daily amount of emergency natural gas to be transported during the term of the transaction;
(5) The transportation rate; and
(6) The identity of all the participants involved in the transaction.
(c) Forty-eight hour report for exchanges. Within 48 hours after an exchange transaction for emergency natural gas commences, the initial recipient of the exchange volumes must notify the Commission by email, facsimile or other written report of the exchange, stating, in the following sequence:
(1) That the report is for and submitted pursuant to § 284.270 for an emergency transaction;
(2) The date the exchange commenced;
(3) The specific nature of the situation, explained in sufficient detail to clearly demonstrate how the situation qualifies as an emergency under § 284.262 and under the conditions of § 284.264, and anticipated duration of the emergency;
(4) The estimated total amount and average daily amount of emergency natural gas to be exchanged during the term of the transaction;
(5) The identity of all participants involved in the transaction;
(6) Whether the exchange is simultaneous or deferred, or any imbalances in the volumes;
(7) Whether the exchange is on a thermal or volumetric basis; and
(8) The rates or charges, if any, for the exchange service.
(d) Termination report. Within thirty days after the emergency natural gas transaction ends, the participant that received the emergency natural gas shall file with the Commission a sworn statement and two conformed copies thereof, which must include the following information in the following sequence:
(1) A description of the emergency natural gas transaction, including sufficient information to clearly demonstrate how the situation qualifies as an emergency under § 284.262 and under the conditions of § 284.264; the commencement and termination dates; the date of the 48-hour report, and the method of resolving the emergency;
(2) Any corrections to the 48-hour report information supplied to the Commission under paragraphs (a) through (c) of this section or a statement that the information was correct;
(3) The volumes of the emergency natural gas delivered during the transaction;
(4) The total compensation received by the seller for the emergency sale;
(5) The total compensation paid for the emergency natural gas transportation or exchange service, if any;
(6) The methods by which such compensation was derived;
(7) The total volumes of natural gas whose cost was assigned to specific customers, and the total volumes whose cost was included in system supply;
(8) The information supplied to any other participant pursuant to § 284.264(a)(2); and
(9) A statement that the emergency natural gas transaction was carried out in accordance with this subpart, and that identifies the circumstances demonstrating an emergency existed or was imminent so as to require an emergency natural gas transaction.
§ 284.271 Waiver.
The Commission may, by order, waive the requirements of this subpart in connection with any emergency natural gas transaction to the extent required by the public interest.
Subpart J—Blanket Certificates Authorizing Certain Natural Gas Sales by Interstate Pipelines
§ 284.281 Applicability.
This subpart applies to any interstate pipeline that offers transportation service under subpart B or G of this part.
§ 284.282 Definitions.
(a) Bundled sales service is gas sales service that is not sold separately from transportation service.
(b) Sales service includes firm or interruptible gas sales.
(c) Unbundled sales service is gas sales service that is sold separately from transportation service.
(d) Small customer is a customer that purchases gas from a pipeline under the pipeline’s one-part imputed load factor rate schedule on the effective date of the blanket certificate.
§ 284.283 Point of unbundling.
A sales service is unbundled when gas is sold at a point before it enters a mainline system, at an entry point to a mainline system from a production area, or at an intersection with another pipeline system.
§ 284.284 Blanket certificates for unbundled sales services.
(a) Authorization. An interstate pipeline that offers transportation service under subpart B or G of this part is granted a blanket certificate of public convenience and necessity pursuant to section 7 of the Natural Gas Act authorizing it to provide unbundled firm or interruptible sales in accordance with the provisions of this section.
(b) Conversion to unbundled firm sales service and firm transportation service. On the effective date of the pipeline’s blanket certificate for unbundled sales services under paragraph (a) of this section, firm sales entitlements under any firm sales service agreement for a bundled sales service are converted to an equivalent amount of unbundled firm sales service and an equivalent amount of unbundled firm transportation service.
(c) Conversion to unbundled interruptible sales service and interruptible transportation service. On the effective date of the pipeline’s blanket certificate for unbundled sales services under paragraph (a) of this section, interruptible sales volumes under any interruptible sales service agreement for a bundled sales service are converted to an equivalent amount of unbundled sales service and an equivalent amount of unbundled interruptible transportation service.
(d) A pipeline that provides unbundled sales service under this section may serve as an agent of the sales customer to arrange for any pipeline-provided service necessary to deliver gas to the customer.
(e) Small customer cost-based rate. A pipeline that provided bundled sales service to a small customer before the effective date of the blanket certificate granted in paragraph (a) of this section is required to offer a sales service to that customer at a cost-based rate for one year from the effective date of the certificate. The obligation to sell at the cost-based rate expires one year after the effective date of the certificate.
§ 284.285 Pregrant of abandonment of unbundled sales services.
Abandonment of unbundled sales services is authorized pursuant to section 7(b) of the Natural Gas Act upon the expiration of the contractual term or upon termination of each individual sales arrangement authorized under § 284.284.
§ 284.286 Standards of conduct for unbundled sales service.
(a) To the maximum extent practicable, the pipeline must organize its unbundled sales and transportation operating employees so that they function independently of each other.
(b) The pipeline must conduct its business to conform to the requirements set forth in § 284.7(b)(2) and § 284.9(b)(2) with respect to the equality of service by not giving shippers of gas sold by the pipeline any preference over shippers of gas sold by any other merchant in matters relating to part 284 transportation.
(c) The pipeline must comply with part 358 by considering its unbundled sales operating employees as an operational unit which is the functional equivalent of a marketing affiliate.
(d) The pipeline must comply with § 250.16 of this chapter by considering its unbundled sales operating employees as an operational unit which is the functional equivalent of a marketing affiliate.
(e) A pipeline that provides unbundled sales service under § 284.284 must have tariff provisions on file with the Commission indicating how the pipeline is complying with the standards of this section.
§ 284.287 Implementation and effective date.
(a) Prior to offering any sales service under this subpart J, a pipeline must file revised tariff sheets incorporating the provisions of this subpart J.
(b) A blanket certificate issued under § 284.284 will be effective on the effective date (as approved by the Commission) of the tariff sheets implementing service under that certificate.
§ 284.288 Code of conduct for unbundled sales service.
(a) To the extent Seller engages in reporting of transactions to publishers of electricity or natural gas indices, Seller must provide accurate and factual information, and not knowingly submit false or misleading information or omit material information to any such publisher, by reporting its transactions in a manner consistent with the procedures set forth in the Policy Statement on Natural Gas and Electric Price Indices, issued by the Commission in Docket No. PL03–3–000 and any clarifications thereto. Seller must notify the Commission as part of its FERC Form No. 552 annual reporting requirement in § 260.401 of this chapter whether it reports its transactions to publishers of electricity and natural gas indices. In addition, Seller must adhere to any other standards and requirements for price reporting as the Commission may order.
(b) A pipeline that provides unbundled natural gas sales service under § 284.284 shall retain, for a period of five years, all data and information upon which it billed the prices it charged for natural gas it sold pursuant to its market based sales certificate or the prices it reported for use in price indices.
Subpart K—Transportation of Natural Gas on the Outer Continental Shelf by Interstate Natural Gas Pipelines on Behalf of Others
§ 284.301 Applicability.
This subpart implements section 5 of the Outer Continental Shelf Land Act (OCSLA) and applies to any jurisdictional interstate natural gas pipeline that holds a certificate under section 7 of the Natural Gas Act (NGA) authorizing the construction and operation of facilities on the Outer Continental Shelf (OCS).
§ 284.302 Definitions.
For the purposes of this subpart, the term:
(a) Outer Continental Shelf (OCS) has the same meaning as found in section 2(a) of the OCSLA (43 U.S.C. 1331(a)); and
(b) OCS pipeline means an interstate natural gas pipeline that holds a certificate under section 7 of the NGA authorizing the construction and operation of facilities on the OCS, and includes all of the OCS pipeline’s facilities that fall within the scope of the Commission’s jurisdiction under section 7 of the NGA to the full extent that such facilities are used or necessary to transport natural gas on or across the OCS between:
(1) Any locations on the OCS (if the pipeline does not have an interconnection off the OCS), or
(2) The OCS and the first point of interconnection on the shoreward side of the OCS where the pipeline delivers or receives natural gas to or from either:
(i) A natural gas conditioning or processing facility, or
(ii) Another pipeline, or
(iii) A distributor or end user of natural gas.
§ 284.303 OCS blanket certificates.
Every OCS pipeline [as that term is defined in § 284.302(b)] is required to provide open-access, nondiscriminatory transportation service pursuant to a blanket transportation certificate issued under subpart G of this part.
Subpart L—Certain Sales for Resale by Non-interstate Pipelines
§ 284.401 Definitions.
Affiliated marketer. For purposes of this subpart, an “affiliated marketer” is a person engaged in the “marketing” of natural gas that is an “affiliate” of an interstate pipeline as those terms are defined in § 161.2 of this chapter.
§ 284.402 Blanket marketing certificates.
(a) Authorization. Any person who is not an interstate pipeline is granted a blanket certificate of public convenience and necessity pursuant to section 7 of the Natural Gas Act authorizing the certificate holder to make sales for resale at negotiated rates in interstate commerce of any category of gas that is subject to the Commission’s Natural Gas Act jurisdiction. A blanket certificate issued under Subpart L is a certificate of limited jurisdiction which will not subject the certificate holder to any other regulation under the Natural Gas Act jurisdiction of the Commission, other than that set forth in this Subpart L, by virtue of the transactions under this certificate.
(b) The authorization granted in paragraph (a) of this section will become effective on January 7, 1993 except as otherwise provided in paragraph (c) of this section.
(c)(1) The authorization granted in paragraph (a) of this section will become effective for an affiliated marketer with respect to transactions involving affiliated pipelines when an affiliated pipeline receives its blanket certificate pursuant to § 284.284.
(2) Should a marketer be affiliated with more than one pipeline, the authorization granted in paragraph (a) of this section will not be effective for transactions involving other affiliated interstate pipelines until such other pipelines’ meet the criterion set forth in paragraph (c)(1) of this section. The authorization granted in paragraph (a) of this section is not extended to affiliates of persons who transport gas in interstate commerce and who do not have a tariff on file with the Commission under part 284 of this subchapter with respect to transactions involving that person.
(d) Abandonment of the sales service authorized in paragraph (a) of this section is authorized pursuant to section 7(b) of the Natural Gas Act upon the expiration of the contractual term or upon termination of each individual sales arrangement.
§ 284.403 Code of conduct for persons holding blanket marketing certificates.
(a) To the extent Seller engages in reporting of transactions to publishers of electricity or natural gas indices, Seller must provide accurate and factual information, and not knowingly submit false or misleading information or omit material information to any such publisher, by reporting its transactions in a manner consistent with the procedures set forth in the Policy Statement on Natural Gas and Electric Price Indices, issued by the Commission in Docket No. PL03–3–000 and any clarifications thereto. Seller must notify the Commission as part of its FERC Form No. 552 annual reporting requirement in § 260.401 of this chapter whether it reports its transactions to publishers of electricity and natural gas indices. In addition, Seller shall adhere to any other standards and requirements for price reporting as the Commission may order.
(b) A blanket marketing certificate holder shall retain, for a period of five years, all data and information upon which it billed the prices it charged for the natural gas sold pursuant to its market based sales certificate or the prices it reported for use in price indices.
Subpart M—Applications for Market-Based Rates for Storage
§ 284.501 Applicability.
Any pipeline or storage service provider that provides or will provide service under subparts B, C, or G of this part, and that wishes to provide storage and storage-related services at market-based rates must conform to the requirements in subpart M.
§ 284.502 Procedures for applying for market-based rates.
(a) Applications for market-based rates may be filed with certificate applications. Service, notice, intervention, and protest procedures for such filings will conform with those applicable to the certificate application.
(b) With respect to applications not filed as part of certificate applications,
(1) Applicants providing service under subpart B or subpart G of this part must file a request for declaratory order and comply with the service and filing requirements of part 154 of this chapter. Interventions and protests to applications for market-based rates must be filed within 30 days of the application unless the notice issued by the Commission provides otherwise. An applicant providing service under subpart B or subpart G of this part cannot charge market-based rates under this subpart of this part until its application has been accepted by the Commission. Once accepted, the applicant can make the appropriate filing necessary to set its market-based rates into effect.
(2) Applicants providing service under subpart C of this part must file in accordance with the requirements of that subpart.
§ 284.503 Market-power determination.
An applicant may apply for market-based rates by filing a request for a market-power determination that complies with the following:
(a) The applicant must set forth its specific request and adequately demonstrate that it lacks market power in the market to be served, and must include an executive summary of its statement of position and a statement of material facts in addition to its complete statement of position. The statement of material facts must include citation to the supporting statements, exhibits, affidavits, and prepared testimony.
(b) The applicant must include with its application the following information:
(1) Statement A—geographic market. This statement must describe the geographic markets for storage services in which the applicant seeks to establish that it lacks significant market power. It must include the market related to the service for which it proposes to charge market-based rates. The statement must explain why the applicant’s method for selecting the geographic markets is appropriate.
(2) Statement B—product market. This statement must identify the product market or markets for which the applicant seeks to establish that it lacks significant market power. The statement must explain why the particular product definition is appropriate.
(3) Statement C—the applicant’s facilities and services. This statement must describe the applicant’s own facilities and services, and those of all parent, subsidiary, or affiliated companies, in the relevant markets identified in Statements A and B in paragraphs (b)(1) and (2) of this section. The statement must include all pertinent data about the storage facilities and services.
(4) Statement D—competitive alternatives. This statement must describe available alternatives in competition with the applicant in the relevant markets and other competition constraining the applicant’s rates in those markets. Such proposed alternatives may include an appropriate combination of other storage, local gas supply, LNG, financial instruments and pipeline capacity. These alternatives must be shown to be reasonably available as a substitute in the area to be served soon enough, at a price low enough, and with a quality high enough to be a reasonable alternative to the applicant’s services. Capacity (transportation, storage, LNG, or production) owned or controlled by the applicant and affiliates of the applicant in the relevant market shall be clearly and fully identified and may not be considered as alternatives competing with the applicant. Rather, the capacity of an applicant’s affiliates is to be included in the market share calculated for the applicant. To the extent available, the statement must include all pertinent data about storage or other alternatives and other constraining competition.
(5) Statement E—potential competition. This statement must describe potential competition in the relevant markets. To the extent available, the statement must include data about the potential competitors, including their costs, and their distance in miles from the applicant’s facilities and major consuming markets. This statement must also describe any relevant barriers to entry and the applicant’s assessment of whether ease of entry is an effective counter to attempts to exercise market power in the relevant markets.
(6) Statement F—maps. This statement must consist of maps showing the applicant’s principal facilities, pipelines to which the applicant intends to interconnect and other pipelines within the area to be served, the direction of flow of each line, the location of the alternatives to the applicant’s service offerings, including their distance in miles from the applicant’s facility. The statement must include a general system map and maps by geographic markets. The information required by this statement may be on separate pages.
(7) Statement G—market-power measures. This statement must set forth the calculation of the market concentration of the relevant markets using the Herfindahl-Hirschman Index. The statement must also set forth the applicant’s market share, inclusive of affiliated service offerings, in the markets to be served. The statement must also set forth the calculation of other market-power measures relied on by the applicant. The statement must include complete particulars about the applicant’s calculations.
(8) Statement H—other factors. This statement must describe any other factors that bear on the issue of whether the applicant lacks significant market power in the relevant markets. The description must explain why those other factors are pertinent.
(9) Statement I—prepared testimony. This statement must include the proposed testimony in support of the application and will serve as the applicant’s case-in-chief, if the Commission sets the application for hearing. The proposed witness must subscribe to the testimony and swear that all statements of fact contained in the proposed testimony are true and correct to the best of his or her knowledge, information, and belief.
(a) Applicants granted the authority to charge market-based rates under § 284.503 that provide cost-based service(s) must separately account for all costs and revenues associated with facilities used to provide the market-based services. When it files to change its cost-based rates, applicant must provide a summary of the costs and revenues associated with market-based rates with applicable cross references to §§ 154.312 and 154.313 of this chapter. The summary statement must provide the formulae and explain the bases used in the allocation of common costs between the applicant’s cost-based services and its market-based services.
(b) A storage service provider granted the authority to charge market-based rates under § 284.503 is required to notify the Commission within 10 days of acquiring knowledge of significant changes occurring in its market power status. Such notification should include a detailed description of the new facilities/services and their relationship to the storage service provider. Significant changes include, but are not limited to:
(1) The storage provider expanding its storage capacity beyond the amount authorized in this proceeding;
(2) The storage provider acquiring transportation facilities or additional storage capacity;
(3) An affiliate providing storage or transportation services in the same market area; and
(4) The storage provider or an affiliate acquiring an interest in or is acquired by an interstate pipeline.
§ 284.505 Market-based rates for storage providers without a market-power determination.
(a) Any storage service provider seeking market-based rates for storage capacity, pursuant to the authority of section 4(f) of the Natural Gas Act, related to a specific facility put into service after August 8, 2005, may apply for market-based rates by complying with the following requirements:
(1) The storage service provider must demonstrate that market-based rates are in the public interest and necessary to encourage the construction of the storage capacity in the area needing storage services; and
(2) The storage service provider must provide a means of protecting customers from the potential exercise of market power.
(b) Any storage service provider seeking market-based rates for storage capacity pursuant to this section will be presumed by the Commission to have market power.
PART 286—ACCOUNTS, RECORDS, MEMORANDA AND DISPOSITION OF CONTESTED AUDIT FINDINGS AND PROPOSED REMEDIES
§ 286.101 Application for stay.
(a) General rule. Any person who believes that any provision of a final or interim regulation issued under the Natural Gas Policy Act of 1978 is unlawful as applied to such person may file an application for stay.
(b) Content of application. The application shall state, clearly and concisely:
(1) The provision of the regulation, by section, paragraph, subparagraph and clause, as appropriate, which applicant seeks to have stayed;
(2) The conditions which the applicant believes require the stay, including the irreparable injury which the applicant believes will result if the stay is not granted; and
(3) The factual and legal basis for applicant’s contention that the final or interim regulation is unlawful.
(c) Filing requirements. The application shall be under oath. An original and three conformed copies shall be filed with the Secretary of the Commission.
(d) Commission action. The Commission may grant the application, in whole or in part, by issuing an order specifying the scope of the stay granted and the effective dates of the stay.
§ 286.102 Application for rehearing.
(a) General rule. Any person aggrieved by any order or regulation or any amendment to a regulation issued under the NGPA and subject to judicial review under section 506(a) or (b) thereof shall file a petition for rehearing within 30 days after the order or regulation is issued by the Commission or February 3, 1979, whichever is later. There has not been an exhaustion of administrative remedies until a petition for rehearing has been filed under this section and the proceeding is complete by the denial of the request, or if rehearing is granted, an order affirming, modifying or revoking the challenged order or regulation is issued.
(b) Specifications of error. The application for rehearing shall state clearly and concisely with respect to the challenged order or regulation:
(1) The provision of the order or the regulation, by section, and where appropriate, by paragraph;
(2) Applicant’s interest in the particular provision; and
(3) The facts and legal analysis upon which the request for rehearing is based.
(c) Procedural requirements. Except as otherwise provided in this section, the procedures for rehearing in § 385.713 of this chapter shall apply.
(d) Commission action upon the application. (1) The Commission may grant the request for rehearing, in whole or in part, by issuing an order specifying the scope of rehearing. If, and to the extent that rehearing is granted, the Commission may request Staff, applicant or any other party to file briefs. In every case where rehearing is granted, the Commission will issue an order affirming, modifying or revoking the challenged order or regulation.
(2) The Commission may modify the original order or regulation without further hearing.
(3) Unless the Commission acts upon the application within 30 days after it is filed, such application shall be considered to have been denied. If the Commission grants rehearing in part, any part of the application outside the scope of the order granting rehearing shall be considered to have been denied.
Disposition of Contested Audit Findings and Proposed Remedies
§ 286.103 Notice to audited person.
An audit conducted by the Commission’s staff under authority of the Natural Gas Policy Act may result in a notice of deficiency or audit report or similar document containing a finding or findings that the audited person has not complied with a requirement of the Commission with respect to, but not limited to, the following: A filed tariff or tariffs, contracts, data, records, accounts, books, communications or papers relevant to the audit of the audited person; matters under the Standards of Conduct or the Code of Conduct; and the activities or operations of the audited person. The notice of deficiency, audit report or similar document may also contain one or more proposed remedies that address findings of noncompliance. Where such findings, with or without proposed remedies, appear in a notice of deficiency, audit report or similar document, such document shall be provided to the audited person, and the finding or findings, and any proposed remedies, shall be noted and explained. The audited person shall timely indicate in a written response any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees. The audited person shall have 15 days from the date it is sent the notice of deficiency, audit report or similar document to provide a written response to the audit staff indicating any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees, and such further time as the audit staff may provide in writing to the audited person at the time the document is sent to the audited person. The audited person may move the Commission for additional time to provide a written response to the audit staff and such motion shall be granted for good cause shown. Any initial order that the Commission subsequently may issue with respect to the notice of deficiency, audit report or similar document shall note, but not address on the merits, the finding or findings, or the proposed remedy or remedies, or both, in any combination, with which the audited person disagreed. The Commission shall provide the audited person 30 days to respond to the initial Commission order concerning a notice of deficiency, audit report or similar document with respect to the finding or findings or any proposed remedy or remedies, or both, in any combination, with which it disagreed.
§ 286.104 Response to notification.
Upon issuance of a Commission order that notes a finding or findings, with or without proposed remedies, with which the audited person has disagreed, the audited person may: Acquiesce in the findings and proposed remedies by not timely responding to the Commission order, in which case the Commission may issue an order approving them or taking other action; or challenge the finding or findings and any proposed remedies with which it disagreed by timely notifying the Commission in writing that it requests Commission review by means of a shortened procedure, or, if there are material facts in dispute which require cross-examination, a trial-type hearing.
§ 286.105 Shortened procedure.
If the audited person subject to a Commission order described in § 286.103 notifies the Commission that it seeks to challenge one or more audit findings, or proposed remedies, or both, in any combination, by the shortened procedure, the Commission shall thereupon issue a notice setting a schedule for the filing of memoranda. The person electing the use of the shortened procedure, and any other interested entities, including the Commission staff, shall file, within 45 days of the notice, an initial memorandum that addresses the relevant facts and applicable law that support the position or positions taken regarding the matters at issue. Reply memoranda shall be filed within 20 days of the date by which the initial memoranda are due to be filed. Only participants who filed initial memoranda may file reply memoranda. Subpart T of part 385 of this chapter shall apply to all filings. Within 20 days after the last date that reply memoranda under the shortened procedure may be timely filed, the audited person who elected the shortened procedure may file a motion with the Commission requesting a trial-type hearing if new issues are raised by a party. To prevail in such a motion, the audited person must show that a party to the shortened procedure raised one or more new issues of material fact relevant to resolution of a matter in the shortened procedure such that fundamental fairness requires a trial-type hearing to resolve the new issue or issues so raised. Parties to the shortened procedure and the Commission staff may file responses to the motion. In ruling upon the motion, the Commission may determine that some or all of the issues be litigated in a trial-type hearing.
§ 286.106 Form and style.
Each copy of such memorandum must be complete in itself. All pertinent data should be set forth fully, and each memorandum should set out the facts and argument as prescribed for briefs in § 385.706 of this chapter.
§ 286.107 Verification.
The facts stated in the memorandum must be sworn to by persons having knowledge thereof, which latter fact must affirmatively appear in the affidavit. Except under unusual circumstances, such persons should be those who would appear as witnesses if hearing were had to testify as to the facts stated in the memorandum.
§ 286.108 Determination.
If no formal hearing is had the matter in issue will be determined by the Commission on the basis of the facts and arguments submitted.
§ 286.109 Assignment for oral hearing.
Except when there are no material facts in dispute, when a person does not consent to the shortened procedure, the Commission will assign the proceeding for hearing as provided by subpart E of part 385 of this chapter. Notwithstanding a person’s not giving consent to the shortened procedure, and instead seeking assignment for hearing as provided for by subpart E of part 385 of this chapter, the Commission will not assign the proceeding for a hearing when no material facts are in dispute. The Commission may also, in its discretion, at any stage in the proceeding, set the proceeding for hearing.
SUBCHAPTER J—REGULATIONS UNDER THE POWERPLANT AND INDUSTRIAL FUEL USE ACT OF 1978
PART 287—RULES GENERALLY APPLICABLE TO POWERPLANT AND INDUSTRIAL FUEL USE
§ 287.101 Determination of powerplant design capacity.
For the purpose of section 103 of the Powerplant and Industrial Fuel Use Act of 1978, a powerplant’s design capacity shall be determined as follows:
(a) Steam-electric generating unit. The design capacity of a steam-electric generating unit shall be maximum generator nameplate rating measured in kilowatts or, if the nameplate does not have a rating measured in kilowatts, the product of the generator’s kilovolt-amperes nameplate rating and power factor nameplate rating.
(b) Combustion turbine. The design capacity of a combustion turbine shall be its nameplate rating measured in kilowatts, adjusted for peaking service at an ambient temperature of 59 degrees Fahrenheit (15 degrees Celsius) and at the unit’s site elevation.
(c) Combined cycle unit. The design capacity of a combined cycle shall be the sum of its combustion turbine nameplate rating measured in kilowatts, based on baseload operation adjusted for site elevation, and the maximum generator nameplate rating measured in kilowatts of the steam turbine portion of the unit.
(d) Internal combustion engine. The design capacity of an internal combustion engine shall be the generator’s nameplate rating measured in kilowatts.
SUBCHAPTER K—REGULATIONS UNDER THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978
PART 290—COLLECTION OF COST OF SERVICE INFORMATION UNDER SECTION 133 OF THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978
Subpart A—Coverage, Compliance and Definitions
§ 290.101 Applicability and exemptions.
(a) Except as provided in paragraph (b), this part shall apply to each electric utility, in any calendar year, if the total sales of electric energy by such utility for purposes other than resale exceed 500 million kilowatt-hours during any calendar year beginning after December 31, 1975, and before the immediately preceding calendar year.
(b) The Commission exempts from compliance with this part any utility:
(1) Listed by name in Appendix A to this part; or
(2) That has total sales of electric energy for purposes other than resale of less than 2 billion kilowatt-hours per year.
§ 290.102 Information gathering and filing.
All nonexempt electric utilities must file the data required by section 133(a) of the Public Utility Regulatory Policies Act of 1978, 16 U.S.C. § 2643, with their state regulatory authorities. All nonexempt, nonregulated electric utilities shall, to the extent the data are collected and compiled, make these data publicly available. All nonexempt electric utilities shall file an affidavit with the Commission certifying that the requisite state filing was made. All nonexempt, nonregulated electric utilities shall file an affidavit with the Commission certifying that the data were made publicly available.
§ 290.103 Time of filing and reporting period.
All nonexempt electric utilities must file with any state regulatory authority having ratemaking authority for such utilities the information gathered pursuant to § 290.102, and all nonexempt, nonregulated electric utilities must make such information available to the public as follows:
(a) Biennial filing. Information required to be filed under § 290.102 must be filed biennially in even-numbered years on or before June 30 of that year.
(b) Reporting period. The reporting period is the calendar year immediately preceding the filing year. Information for previous years and projected information for future years must be reported on a calendar year basis.
(c) Alternate reporting period. Use of an alternate reporting period is permitted as follows:
(1) Except as provided in paragraph (c)(2) of this section, if a nonexempt electric utility has gathered all of the information specified in § 290.102 and has filed such information, based on a recent 12-month reporting period, either with its state regulatory authority or governing authority in connection with a retail rate proceeding, the nonexempt electric utility may substitute such information for the equivalent information required by this part in fulfillment of the biennial filing requirements.
(2) If a nonexempt electric utility not subject to the jurisdiction of a state regulatory authority maintains accounting records other than on a calendar year basis, such utility may use such other basis as the reporting period for purposes of compliance with this part, provided such reporting period is a 12-month period.
Appendix A to Part 290—Nonexempt Electric Utilities
Electric utilities that are not exempt from part 290, as of the date of publication of the Commission’s Order No. 545 are as follows:
PART 292—REGULATIONS UNDER SECTIONS 201 AND 210 OF THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978 WITH REGARD TO SMALL POWER PRODUCTION AND COGENERATION
Subpart A—General Provisions
§ 292.101 Definitions.
(a) General rule. Terms defined in the Public Utility Regulatory Policies Act of 1978 (PURPA) shall have the same meaning for purposes of this part as they have under PURPA, unless further defined in this part.
(b) Definitions. The following definitions apply for purposes of this part.
(1) Qualifying facility means a cogeneration facility or a small power production facility that is a qualifying facility under Subpart B of this part.
(i) A qualifying facility may include transmission lines and other equipment used for interconnection purposes (including transformers and switchyard equipment), if:
(A) Such lines and equipment are used to supply power output to directly and indirectly interconnected electric utilities, and to end users, including thermal hosts, in accordance with state law; or
(B) Such lines and equipment are used to transmit supplementary, standby, maintenance and backup power to the qualifying facility, including its thermal host meeting the criteria set forth in Union Carbide Corporation, 48 FERC ¶ 61,130, reh’g denied, 49 FERC ¶ 61,209 (1989), aff’d sub nom., Gulf States Utilities Company v. FERC, 922 F.2d 873 (D.C. Cir. 1991); or
(C) If such lines and equipment are used to transmit power from other qualifying facilities or to transmit standby, maintenance, supplementary and backup power to other qualifying facilities.
(ii) The construction and ownership of such lines and equipment shall be subject to any applicable Federal, state, and local siting and environmental requirements.
(2) Purchase means the purchase of electric energy or capacity or both from a qualifying facility by an electric utility.
(3) Sale means the sale of electric energy or capacity or both by an electric utility to a qualifying facility.
(4) System emergency means a condition on a utility’s system which is likely to result in imminent significant disruption of service to customers or is imminently likely to endanger life or property.
(5) Rate means any price, rate, charge, or classification made, demanded, observed or received with respect to the sale or purchase of electric energy or capacity, or any rule, regulation, or practice respecting any such rate, charge, or classification, and any contract pertaining to the sale or purchase of electric energy or capacity.
(6) Avoided costs means the incremental costs to an electric utility of electric energy or capacity or both which, but for the purchase from the qualifying facility or qualifying facilities, such utility would generate itself or purchase from another source.
(7) Interconnection costs means the reasonable costs of connection, switching, metering, transmission, distribution, safety provisions and administrative costs incurred by the electric utility directly related to the installation and maintenance of the physical facilities necessary to permit interconnected operations with a qualifying facility, to the extent such costs are in excess of the corresponding costs which the electric utility would have incurred if it had not engaged in interconnected operations, but instead generated an equivalent amount of electric energy itself or purchased an equivalent amount of electric energy or capacity from other sources. Interconnection costs do not include any costs included in the calculation of avoided costs.
(8) Supplementary power means electric energy or capacity supplied by an electric utility, regularly used by a qualifying facility in addition to that which the facility generates itself.
(9) Back-up power means electric energy or capacity supplied by an electric utility to replace energy ordinarily generated by a facility’s own generation equipment during an unscheduled outage of the facility.
(10) Interruptible power means electric energy or capacity supplied by an electric utility subject to interruption by the electric utility under specified conditions.
(11) Maintenance power means electric energy or capacity supplied by an electric utility during scheduled outages of the qualifying facility.
(12) Locational marginal price means the price for energy at a particular location as determined in a market defined in § 292.309(e), (f), or (g).
(13) Competitive Price means a Market Hub Price or a Combined Cycle Price.
(14) Market Hub Price means a price for as-delivered energy determined pursuant to § 292.304(b)(7)(i).
(15) Combined Cycle Price means a price for as-delivered energy determined pursuant to § 292.304(b)(7)(ii).
(16) Competitive Solicitation Price means a price for energy and/or capacity determined pursuant to § 292.304(b)(8).
Subpart B—Qualifying Cogeneration and Small Power Production Facilities
§ 292.201 Scope.
This subpart applies to the criteria for and manner of becoming a qualifying small power production facility and a qualifying cogeneration facility under sections 3(17)(C) and 3(18)(B), respectively, of the Federal Power Act, as amended by section 201 of the Public Utility Regulatory Policies Act of 1978 (PURPA).
§ 292.202 Definitions.
For purposes of this subpart:
(a) Biomass means any organic material not derived from fossil fuels;
(b) Waste means an energy input that is listed below in this subsection, or any energy input that has little or no current commercial value and exists in the absence of the qualifying facility industry. Should a waste energy input acquire commercial value after a facility is qualified by way of Commission certification pursuant to § 292.207(b), or self-certification pursuant to § 292.207(a), the facility will not lose its qualifying status for that reason. Waste includes, but is not limited to, the following materials that the Commission previously has approved as waste:
(1) Anthracite culm produced prior to July 23, 1985;
(2) Anthracite refuse that has an average heat content of 6,000 Btu or less per pound and has an average ash content of 45 percent or more;
(3) Bituminous coal refuse that has an average heat content of 9,500 Btu per pound or less and has an average ash content of 25 percent or more;
(4) Top or bottom subbituminous coal produced on Federal lands or on Indian lands that has been determined to be waste by the United States Department of the Interior’s Bureau of Land Management (BLM) or that is located on non-Federal or non-Indian lands outside of BLM’s jurisdiction, provided that the applicant shows that the latter coal is an extension of that determined by BLM to be waste.
(5) Coal refuse produced on Federal lands or on Indian lands that has been determined to be waste by the BLM or that is located on non-Federal or non-Indian lands outside of BLM’s jurisdiction, provided that applicant shows that the latter is an extension of that determined by BLM to be waste.
(6) Lignite produced in association with the production of montan wax and lignite that becomes exposed as a result of such a mining operation;
(7) Gaseous fuels, except:
(i) Synthetic gas from coal; and
(ii) Natural gas from gas and oil wells unless the natural gas meets the requirements of § 2.400 of this chapter;
(8) Petroleum coke;
(9) Materials that a government agency has certified for disposal by combustion;
(10) Residual heat;
(11) Heat from exothermic reactions;
(12) Used rubber tires;
(13) Plastic materials; and
(14) Refinery off-gas.
(c) Cogeneration facility means equipment used to produce electric energy and forms of useful thermal energy (such as heat or steam), used for industrial, commercial, heating, or cooling purposes, through the sequential use of energy;
(d) Topping-cycle cogeneration facility means a cogeneration facility in which the energy input to the facility is first used to produce useful power output, and at least some of the reject heat from the power production process is then used to provide useful thermal energy;
(e) Bottoming-cycle cogeneration facility means a cogeneration facility in which the energy input to the system is first applied to a useful thermal energy application or process, and at least some of the reject heat emerging from the application or process is then used for power production;
(f) Supplementary firing means an energy input to the cogeneration facility used only in the thermal process of a topping-cycle cogeneration facility, or only in the electric generating process of a bottoming-cycle cogeneration facility;
(g) Useful power output of a cogeneration facility means the electric or mechanical energy made available for use, exclusive of any such energy used in the power production process;
(h) Useful thermal energy output of a topping-cycle cogeneration facility means the thermal energy:
(1) That is made available to an industrial or commercial process (net of any heat contained in condensate return and/or makeup water);
(2) That is used in a heating application (e.g., space heating, domestic hot water heating);
(3) That is used in a space cooling application (i.e., thermal energy used by an absorption chiller); or
(4) That is used by a fuel cell system with an integrated steam hydrocarbon reformation process for production of fuel for electricity generation.
(i) Total energy output of a topping-cycle cogeneration facility is the sum of the useful power output and useful thermal energy output;
(j) Total energy input means the total energy of all forms supplied from external sources;
(k) Natural gas means either natural gas unmixed, or any mixture of natural gas and artificial gas;
(l) Oil means crude oil, residual fuel oil, natural gas liquids, or any refined petroleum products; and
(m) Energy input in the case of energy in the form of natural gas or oil is to be measured by the lower heating value of the natural gas or oil.
(n) Electric utility holding company means a holding company, as defined in section 2(a)(7) of the Public Utility Holding Company Act of 1935, 15 U.S.C. 79b(a)(7) which owns one or more electric utilities, as defined in section 2(a)(3) of that Act, 15 U.S.C. 79b(a)(3), but does not include any holding company which is exempt by rule or order adopted or issued pursuant to sections 3(a)(3) or 3(a)(5) of the Public Utility Holding Company Act of 1935, 15 U.S.C. 79c(a)(3) or 79c(a)(5).
(o) Utility geothermal small power production facility means a small power production facility which uses geothermal energy as the primary energy resource and of which more than 50 percent is owned either:
(1) By an electric utility or utilities, electric utility holding company or companies, or any combination thereof.
(2) By any company 50 percent or more of the outstanding voting securities of which of which are directly or indirectly owned, controlled, or held with power to vote by an electric utility, electric utility holding company, or any combination thereof.
(p) New dam or diversion means a dam or diversion which requires, for the purposes of installing any hydroelectric power project, any construction, or enlargement of any impoundment or diversion structure (other than repairs or reconstruction or the addition of flashboards of similar adjustable devices);
(q) Substantial adverse effect on the environment means a substantial alteration in the existing or potential use of, or a loss of, natural features, existing habitat, recreational uses, water quality, or other environmental resources. Substantial alteration of particular resource includes a change in the environment that substantially reduces the quality of the affected resources; and
(r) Commitment of substantial monetary resources means the expenditure of, or commitment to expend, at least 50 percent of the total cost of preparing an application for license or exemption for a hydroelectric project that is accepted for filing by the Commission pursuant to § 4.32(e) of this chapter. The total cost includes (but is not limited to) the cost of agency consultation, environmental studies, and engineering studies conducted pursuant to § 4.38 of this chapter, and the Commission’s requirements for filing an application for license exemption.
(s) Sequential use of energy means:
(1) For a topping-cycle cogeneration facility, the use of reject heat from a power production process in sufficient amounts in a thermal application or process to conform to the requirements of the operating standard; or
(2) For a bottoming-cycle cogeneration facility, the use of reject heat from a thermal application or process, at least some of which is then used for power production.
(t) Electrical generating equipment means all boilers, heat recovery steam generators, prime movers (any mechanical equipment driving an electric generator), electrical generators, photovoltaic solar panels, inverters, fuel cell equipment and/or other primary power generation equipment used in the facility, excluding equipment for gathering energy to be used in the facility.
§ 292.203 General requirements for qualification.
(a) Small power production facilities. Except as provided in paragraph (c) of this section, a small power production facility is a qualifying facility if it:
(1) Meets the maximum size criteria specified in § 292.204(a);
(2) Meets the fuel use criteria specified in § 292.204(b); and
(3) Unless exempted by paragraph (d), has filed with the Commission a notice of self-certification, pursuant to § 292.207(a); or has filed with the Commission an application for Commission certification, pursuant to § 292.207(b)(1), that has been granted.
(b) Cogeneration facilities. A cogeneration facility, including any diesel and dual-fuel cogeneration facility, is a qualifying facility if it:
(1) Meets any applicable standards and criteria specified in §§ 292.205(a), (b) and (d); and
(2) Unless exempted by paragraph (d), has filed with the Commission a notice of self-certification, pursuant to § 292.207(a); or has filed with the Commission an application for Commission certification, pursuant to § 292.207(b)(1), that has been granted.
(c) Hydroelectric small power production facilities located at a new dam or diversion. (1) A hydroelectric small power production facility that impounds or diverts the water of a natural watercourse by means of a new dam or diversion (as that term is defined in § 292.202(p)) is a qualifying facility if it meets the requirements of:
(i) Paragraph (a) of this section; and
(ii) Section 292.208.
(2) [Reserved]
(d) Exemptions and waivers from filing requirement. (1) Any facility with a net power production capacity of 1 MW or less is exempt from the filing requirements of paragraphs (a)(3) and (b)(2) of this section.
(2) The Commission may waive the requirement of paragraphs (a)(3) and (b)(2) of this section for good cause. Any applicant seeking waiver of paragraphs (a)(3) and (b)(2) of this section must file a petition for declaratory order describing in detail the reasons waiver is being sought.
§ 292.204 Criteria for qualifying small power production facilities.
(a) Size of the facility—(1) Maximum size. Except as provided in paragraph (a)(4) of this section, the power production capacity of a facility for which qualification is sought, together with the power production capacity of any other small power production qualifying facilities that use the same energy resource, are owned by the same person(s) or its affiliates, and are located at the same site, may not exceed 80 megawatts.
(2) Method of calculation. (i)(A) For purposes of this paragraph (a)(2), there is an irrebuttable presumption that affiliated small power production qualifying facilities that use the same energy resource and are located one mile or less from the facility for which qualification or recertification is sought are located at the same site as the facility for which qualification or recertification is sought.
(B) For purposes of this paragraph (a)(2), for facilities for which qualification or recertification is filed on or after December 31, 2020 there is an irrebuttable presumption that affiliated small power production qualifying facilities that use the same energy resource and are located 10 miles or more from the facility for which qualification or recertification is sought are located at separate sites from the facility for which qualification or recertification is sought.
(C) For purposes of this paragraph (a)(2), for facilities for which qualification or recertification is filed on or after December 31, 2020, there is a rebuttable presumption that affiliated small power production qualifying facilities that use the same energy resource and are located more than one mile and less than 10 miles from the facility for which qualification or recertification is sought are located at separate sites from the facility for which qualification or recertification is sought.
(D) For hydroelectric facilities, facilities are considered to be located at the same site as the facility for which qualification or recertification is sought if they are located within one mile of the facility for which qualification or recertification is sought and use water from the same impoundment for power generation.
(ii) For purposes of making the determinations in paragraph (a)(2)(i), the distance between two facilities shall be measured from the edge of the closest electrical generating equipment for which qualification or recertification is sought to the edge of the nearest electrical generating equipment of the other affiliated small power production qualifying facility using the same energy resource.
(3) Waiver. The Commission may modify the application of paragraph (a)(2) of this section, for good cause.
(4) Exception. Facilities meeting the criteria in section 3(17)(E) of the Federal Power Act (16 U.S.C. 796(17)(E)) have no maximum size, and the power production capacity of such facilities shall be excluded from consideration when determining the size of other small power production facilities less than 10 miles from such facilities.
(b) Fuel use. (1)(i) The primary energy source of the facility must be biomass, waste, renewable resources, geothermal resources, or any combination thereof, and 75 percent or more of the total energy input must be from these sources.
(ii) Any primary energy source which, on the basis of its energy content, is 50 percent or more biomass shall be considered biomass.
(2) Use of oil, natural gas and coal by a facility, under section 3(17)(B) of the Federal Power Act, is limited to the minimum amounts of fuel required for ignition, startup, testing, flame stabilization, and control uses, and the minimum amounts of fuel required to alleviate or prevent unanticipated equipment outages, and emergencies, directly affecting the public health, safety, or welfare, which would result from electric power outages. Such fuel use may not, in the aggregate, exceed 25 percent of the total energy input of the facility during the 12-month period beginning with the date the facility first produces electric energy and any calendar year subsequent to the year in which the facility first produces electric energy.
§ 292.205 Criteria for qualifying cogeneration facilities.
(a) Operating and efficiency standards for topping-cycle facilities—(1) Operating standard. For any topping-cycle cogeneration facility, the useful thermal energy output of the facility must be no less than 5 percent of the total energy output during the 12-month period beginning with the date the facility first produces electric energy, and any calendar year subsequent to the year in which the facility first produces electric energy.
(2) Efficiency standard. (i) For any topping-cycle cogeneration facility for which any of the energy input is natural gas or oil, and the installation of which began on or after March 13, 1980, the useful power output of the facility plus one-half the useful thermal energy output, during the 12-month period beginning with the date the facility first produces electric energy, and any calendar year subsequent to the year in which the facility first produces electric energy, must:
(A) Subject to paragraph (a)(2)(i)(B) of this section be no less than 42.5 percent of the total energy input of natural gas and oil to the facility; or
(B) If the useful thermal energy output is less than 15 percent of the total energy output of the facility, be no less than 45 percent of the total energy input of natural gas and oil to the facility.
(ii) For any topping-cycle cogeneration facility not subject to paragraph (a)(2)(i) of this section there is no efficiency standard.
(b) Efficiency standards for bottoming-cycle facilities. (1) For any bottoming-cycle cogeneration facility for which any of the energy input as supplementary firing is natural gas or oil, and the installation of which began on or after March 13, 1980, the useful power output of the facility during the 12-month period beginning with the date the facility first produces electric energy, and any calendar year subsequent to the year in which the facility first produces electric energy must be no less than 45 percent of the energy input of natural gas and oil for supplementary firing.
(2) For any bottoming-cycle cogeneration facility not covered by paragraph (b)(1) of this section, there is no efficiency standard.
(c) Waiver. The Commission may waive any of the requirements of paragraphs (a) and (b) of this section upon a showing that the facility will produce significant energy savings.
(d) Criteria for new cogeneration facilities. Notwithstanding paragraphs (a) and (b) of this section, any cogeneration facility that was either not a qualifying cogeneration facility on or before August 8, 2005, or that had not filed a notice of self-certification or an application for Commission certification as a qualifying cogeneration facility under § 292.207 of this chapter prior to February 2, 2006, and which is seeking to sell electric energy pursuant to section 210 of the Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 824a–1, must also show:
(1) The thermal energy output of the cogeneration facility is used in a productive and beneficial manner; and
(2) The electrical, thermal, chemical and mechanical output of the cogeneration facility is used fundamentally for industrial, commercial, residential or institutional purposes and is not intended fundamentality for sale to an electric utility, taking into account technological, efficiency, economic, and variable thermal energy requirements, as well as state laws applicable to sales of electric energy from a qualifying facility to its host facility.
(3) Fundamental use test. For the purpose of satisfying paragraph (d)(2) of this section, the electrical, thermal, chemical and mechanical output of the cogeneration facility will be considered used fundamentally for industrial, commercial, or institutional purposes, and not intended fundamentally for sale to an electric utility if at least 50 percent of the aggregate of such output, on an annual basis, is used for industrial, commercial, residential or institutional purposes. In addition, applicants for facilities that do not meet this safe harbor standard may present evidence to the Commission that the facilities should nevertheless be certified given state laws applicable to sales of electric energy or unique technological, efficiency, economic, and variable thermal energy requirements.
(4) For purposes of paragraphs (d)(1) and (2) of this section, a new cogeneration facility of 5 MW or smaller will be presumed to satisfy the requirements of those paragraphs.
(5) For purposes of paragraph (d)(1) of this section, where a thermal host existed prior to the development of a new cogeneration facility whose thermal output will supplant the thermal source previously in use by the thermal host, the thermal output of such new cogeneration facility will be presumed to satisfy the requirements of paragraph (d)(1).
§ 292.207 Procedures for obtaining qualifying status.
(a) Self-certification—(1) FERC Form No. 556. The qualifying facility status of an existing or a proposed facility that meets the requirements of § 292.203 may be self-certified by the owner or operator of the facility or its representative by properly completing a FERC Form No. 556 and filing that form with the Commission, pursuant to § 131.80 of this chapter, and complying with paragraph (e) of this section.
(2) Factors. For small power production facilities pursuant to § 292.204, the owner or operator of the facility or its representative may, when completing the FERC Form No. 556, provide information asserting factors showing that the facility for which qualification or recertification is sought is at a separate site from other facilities using the same energy resource and owned by the same person(s) or its affiliates.
(3) Commission action. Self-certification and self-recertification are effective upon filing. If no protests to a self-certification or self-recertification are timely filed pursuant to paragraph (c) of this section, no further action by the Commission is required for a self-certification or self-recertification to be effective. If protests to a self-certification or self-recertification are timely filed pursuant to paragraph (c) of this section, a self-certification or self-recertification will remain effective until the Commission issues an order revoking QF certification. The Commission will act on the protest within 90 days from the date the protest is filed; provided that, if the Commission requests more information from the protester, the entity seeking qualification or recertification, or both, the time for the Commission to act will be extended to 60 days from the filing of a complete answer to the information request. In addition to any extension resulting from a request for information, the Commission also may toll the 90-day period for one additional 60-day period if so required to rule on a protest. Authority to toll the 90-day period for this purpose is delegated to the Secretary or the Secretary’s designee. Absent Commission action before the expiration of the tolling period, a protest will be deemed denied, and the self-certification or self-recertification will remain effective.
(b) Optional procedure—Commission certification—(1) Application for Commission certification. In lieu of the self-certification procedures in paragraph (a) of this section, an owner or operator of an existing or a proposed facility, or its representative, may file with the Commission an application for Commission certification that the facility is a qualifying facility. The application must be accompanied by the fee prescribed by part 381 of this chapter, and the applicant for Commission certification must comply with paragraph (c) of this section.
(2) General contents of application. The application must include a properly completed FERC Form No. 556 pursuant to § 131.80 of this chapter. For small power production facilities pursuant to § 292.204, the owner or operator of the facility or its representative may, when completing the FERC Form No. 556, provide information asserting factors showing that the facility for which qualification is sought is at a separate site from other facilities using the same energy resource and owned by the same person(s) or its affiliates.
(3) Commission action. (i) Within 90 days of the later of the filing of an application or the filing of a supplement, amendment or other change to the application, the Commission will either: Inform the applicant that the application is deficient; or issue an order granting or denying the application; or toll the time for issuance of an order. Any order denying certification shall identify the specific requirements which were not met. If the Commission does not act within 90 days of the date of the latest filing, the application shall be deemed to have been granted.
(ii) For purposes of paragraph (b) of this section, the date an application is filed is the date by which the Office of the Secretary has received all of the information and the appropriate filing fee necessary to comply with the requirements of this Part.
(c) Protests and Interventions—(1) Filing a Protest. Any person, as defined in § 385.102(d) of this chapter, who opposes either a self-certification or self-recertification making substantive changes to the existing certification filed pursuant to paragraph (a) of this section or an application for Commission certification or Commission recertification making substantive changes to the existing certification filed pursuant to paragraph (b) of this section for which qualification or recertification is filed on or after December 31, 2020, may file a protest with the Commission. Any protest to and any intervention in a self-certification or self-recertification must be filed in accordance with §§ 385.211 and 385.214 of this chapter, on or before 30 days from the date the self-certification or self-recertification is filed. Any protestor must concurrently serve a copy of such filing pursuant to § 385.211 of this chapter. Any protest must be adequately supported, and provide any supporting documents, contracts, or affidavits to substantiate the claims in the protest.
(2) Limitations on protest. Protests may be filed to any initial self-certification or application for Commission certification filed on or after the effective date of this final rule, and to any self-recertification or application for Commission recertification that are filed on or after December 31, 2020 that makes substantive changes to the existing certification. Once the Commission has certified an applicant’s qualifying facility status either in response to a protest opposing a self-certification or self-recertification, or in response to an application for Commission certification or Commission recertification, any later protest to a self-recertification or application for Commission recertification making substantive changes to a qualifying facility’s certification must demonstrate changed circumstances that call into question the continued validity of the certification.
(d) Response to protests. Any response to a protest must be filed on or before 30 days from the date of filing of that protest and will be allowed under § 385.213(a)(2) of this chapter.
(e) Notice requirements—(1) General. An applicant filing a self-certification, self-recertification, application for Commission certification or application for Commission recertification of the qualifying status of its facility must concurrently serve a copy of such filing on each electric utility with which it expects to interconnect, transmit or sell electric energy to, or purchase supplementary, standby, back-up or maintenance power from, and the State regulatory authority of each state where the facility and each affected electric utility is located. The Commission will publish a notice in the
(2) Facilities of 500 kW or more. An electric utility is not required to purchase electric energy from a facility with a net power production capacity of 500 kW or more until 90 days after the facility notifies the facility that it is a qualifying facility or 90 days after the utility meets the notice requirements in paragraph (c)(1) of this section.
(f) Revocation of qualifying status. (1)(i) If a qualifying facility fails to conform with any material facts or representations presented by the cogenerator or small power producer in its submittals to the Commission, the notice of self-certification or Commission order certifying the qualifying status of the facility may no longer be relied upon. At that point, if the facility continues to conform to the Commission’s qualifying criteria under this part, the cogenerator or small power producer may file either a notice of self-recertification of qualifying status pursuant to the requirements of paragraph (a) of this section, or an application for Commission recertification pursuant to the requirements of paragraph (b) of this section, as appropriate.
(ii) The Commission may, on its own motion or on the motion of any person, revoke the qualifying status of a facility that has been certified under paragraph (b) of this section, if the facility fails to conform to any of the Commission’s qualifying facility criteria under this part.
(iii) The Commission may, on its own motion or on the motion of any person, revoke the qualifying status of a self-certified or self-recertified qualifying facility if it finds that the self-certified or self-recertified qualifying facility does not meet the applicable requirements for qualifying facilities.
(2) Prior to undertaking any substantial alteration or modification of a qualifying facility which has been certified under paragraph (b) of this section, a small power producer or cogenerator may apply to the Commission for a determination that the proposed alteration or modification will not result in a revocation of qualifying status. This application for Commission recertification of qualifying status should be submitted in accordance with paragraph (b) of this section.
§ 292.208 Special requirements for hydroelectric small power production facilities located at a new dam or diversion.
(a) A hydroelectric small power production facility that impounds or diverts the water of a natural watercourse by means of a new dam or diversion (as that term is defined in § 292.202(p)) is a qualifying facility only if it meets the requirements of:
(1) Paragraph (b) of this section;
(2) Section 292.203(c); and
(3) Part 4 of this chapter.
(b) A hydroelectric small power production described in paragraph (a) is a qualifying facility only if:
(1) The Commission finds, at the time it issues the license or exemption, that the project will not have a substantial adverse effect on the environment (as that term is defined in § 292.202(q)), including recreation and water quality;
(2) The Commission finds, at the time the application for the license or exemption is accepted for filing under § 4.32 of this chapter, that the project is not located on any segment of a natural watercourse which:
(i) Is included, or designated for potential inclusion in, a State or National wild and scenic river system; or
(ii) The State has determined, in accordance with applicable State law, to possess unique natural, recreational, cultural or scenic attributes which would be adversely affected by hydroelectric development; and
(3) The project meets the terms and conditions set by the appropriate fish and wildlife agencies under the same procedures as provided for under section 30(c) of the Federal Power Act.
(c) For the Commission to make the findings in paragraph (b) of this section an applicant must:
(1) Comply with the applicable hydroelectric licensing requirements in Part 4 of this chapter, including:
(i) Completing the pre-filing consultation process under § 4.38 of this chapter, including performing any environmental studies which may be required under §§ 4.38(b)(2)(i)(D) through (F) of this chapter; and
(ii) Submitting with its application an environmental report that meets the requirements of § 4.41(f) of this chapter, regardless of project size;
(2) State whether the project is located on any segment of a natural watercourse which:
(i) Is included in or designated for potential inclusion in:
(A) The National Wild and Scenic River System (28 U.S.C. 1271–1278 (1982)); or
(B) A State wild and scenic river system;
(ii) Crosses an area designated or recommended for designation under the Wilderness Act (16 U.S.C. 1132) as:
(A) A wilderness area; or
(B) Wilderness study area; or
(iii) The State, either by or pursuant to an act of the State legislature, has determined to possess unique, natural, recreational, cultural, or scenic attributes that would be adversely affected by hydroelectric development.
(d) If the project is located on any segment of a natural watercourse that meets any of the conditions in paragraph (c)(2) of this section, the applicant must provide the following information in its application:
(1) The date on which the natural watercourse was protected;
(2) The statutory authority under which the natural watercourse was protected; and
(3) The Federal or state agency, or political subdivision of the state, that is in charge of administering the natural watercourse.
§ 292.209 Exceptions from requirements for hydroelectric small power production facilities located at a new dam or diversion.
(a) The requirements in §§ 292.208(b)(1) through (3) do not apply if:
(1) An application for license or exemption is filed for a project located at a Government dam, as defined in section 3(10) of the Federal Power Act, at which non-Federal hydroelectric development is permissible; or
(2) An application for license or exemption was filed and accepted before October 16, 1986.
(b) The requirements in §§ 292.208(b) (1) and (3) do not apply if an application for license or exemption was filed before October 16, 1986, and is accepted for filing by the Commission before October 16, 1989.
(c) The requirements in § 292.208(b)(3) do not apply to an applicant for license or exemption if:
(1) The applicant files a petition pursuant to § 292.210; and
(2) The Commission grants the petition.
(d) Any application covered by paragraph (a), (b), or (c) of this section is excepted from the moratorium imposed by section 8(e) of the Electric Consumers Protection Act of 1986, Pub. L. No. 99–495.
§ 292.210 Petition alleging commitment of substantial monetary resources before October 16, 1986.
(a) An applicant covered by § 292.203(c) whose application for license or exemption was filed on or after October 16, 1986, but before April 16, 1988, may file a petition for exception from the requirement in § 292.208(b)(3) and the moratorium described in § 292.203(c)(2). The petition must show that prior to October 16, 1986, the applicant committed substantial monetary resources (as that term is defined in § 292.202(r)) to the development of the project.
(b) Subject to rebuttal under paragraph (d)(7)(ii) of this section, a showing of the commitment of substantial monetary resources will be presumed if the applicant held a preliminary permit for the project and had completed environmental consultations pursuant to § 4.38 of this chapter before October 16, 1986.
(c) Time of filing petition—(1) General rule. Except as provided in paragraph (c)(2) of this section, the applicant must:
(i) File the petition with the application for license or exemption; or
(ii) Submit with the application for license or exemption a request for an extension of time, not to exceed 90 days or April 16, 1988, whichever occurs first, in which to file the petition.
(2) Exception. If the application for license or exemption was filed on or after October 16, 1986, but before March 23, 1987, the petition must have been filed by June 22, 1987.
(d) Filing requirements. A petition filed under this section must include the following information or refer to the pages in the application for license or exemption where it can be found:
(1) A certificate of service, conforming to the requirements set out in § 385.2010(h) of this chapter, certifying that the applicant has served the petition on the Federal and State agencies required to be consulted by the applicant pursuant to § 4.38 of this chapter;
(2) Documentation of any issued preliminary permits for the project;
(3) An itemized statement of the total costs expended on the application;
(4) An itemized schedule of costs the applicant expended, or committed to be expended, before October 16, 1986, on the application, accompanied by supporting documentation including but not limited to:
(i) Dated invoices for maps, surveys, supplies, geophysical and geotechnical services, engineering services, legal services, document reproduction, and other items related to the preparation of the application, and
(ii) Written contracts and other written documentation demonstrating a commitment made before October 16, 1986, to expend monetary resources on the preparation of the application, together with evidence that those monetary resources were actually expended; and
(5) Correspondence or other documentation to support the items listed in paragraphs (d)(3) and (d)(4) of this section to show that the expenses presented were directly related to the preparation of the application.
(6) The applicant must include in its total cost statement and in its schedule of the costs expended or committed to be expended before October 16, 1986, the value of services that were performed by the applicant itself instead of contracted out.
(7)(i) If the applicant held a preliminary permit for the project and had completed pre-filing consultation pursuant to § 4.38 of this chapter prior to October 16, 1986, the applicant may, instead of submitting the information listed in paragraphs (d)(3), (d)(4), and (d)(5) of this section, submit a statement identifying the preliminary permit by project number.
(ii) If any interested person objects (pursuant to § 385.211 of this chapter) to the presumption in paragraph (b) of this section, the applicant must supply the information listed in paragraphs (d)(3), (d)(4), and (d)(5) of this section.
(8) If the application is deficient pursuant to § 4.32(e) of this chapter, the applicant must include with the information correcting those deficiencies a statement of the costs expended to make the corrections.
(e) Processing of petition. (1) The Commission will issue a notice of the petition filed under this section and publish the notice in the
(2) Comments on the petition. The Commission will provide the public 45 days from the date the notice of the petition is issued to submit comments. The applicant for license or exemption has 15 days after the expiration of the public comment period to respond to the comments filed with the Commission.
(3) Commission action on petition. The Director of the Office of Energy Projects will determine whether or not the applicant for license or exemption has made the showing required under this section.
§ 292.211 Petition for initial determination on whether a project has a substantial adverse effect on the environment (AEE petition).
(a) An applicant that has filed a petition under § 292.210 may also file an AEE petition with the Commission for an initial determination on whether the project satisfies the requirement that it has no substantial adverse effect on the environment as specified in § 292.208(b)(1).
(b) The filing of the AEE petition does not relieve the applicant of the filing requirements of § 292.208(c).
(c) The Commission will act on the AEE petition only if the Commission has granted the applicant’s commitment of resources petition under § 292.210.
(d) Time of filing petition. The applicant may file the AEE petition with the application for license or exemption or at any time before the Commission issues the license or exemption.
(e) Contents of petition. The AEE petition must identify the project and request that the Commission make an initial determination on the adverse environmental effects requirements in § 292.208(b)(1).
(f) The Director of the Office of Energy Projects will make the initial determination on the AEE petition. In making this determination, the Director will consider the following:
(1) Any proposed mitigative measures;
(2) The consistency of the proposal with local, regional, and national resource plans and programs;
(3) The mandatory terms and conditions of fish and wildlife agencies under section 210(j) of PURPA, or section 30(c) of the Federal Power Act; or the recommended terms and conditions of fish a wildlife agencies under Section 10(j) of the Federal Power Act, whichever is appropriate; and
(4) Any other information which the Director believes is relevant to consider.
(g) Initial finding on the petition. The Director of the Office of Energy Projects will make the initial determination on the AEE petition after the close of the public notice period for the accepted application. If the Director’s initial determination finds:
(1) No substantial adverse effect on the environment, the Commission must wait at least 45 days before making a final determination that the project satisfies the requirements of § 292.208(b)(1).
(2) A substantial adverse effect on the environment, the applicant may file, within 90 days of the initial finding that the project does not satisfy the requirements in § 292.208(b)(1), proposed measures to mitigate the adverse environmental effects found.
(3)(i) The Commission will provide written notice of the Director’s initial finding on the petition to the applicant, to the federal and state agencies that the applicant must consult under § 4.38 of this chapter and to any intervenors in the proceeding.
(ii) The Commission will publish notice of the Director’s initial finding in the
(h) Notice and comment on the mitigative measures. (1) The Commission will issue notice of the mitigative measures filed by an applicant under paragraph (g)(2) of this section and will publish the notice in the
(2) The Commission will provide the State and interested persons within 90 days from the date the notice is issued to review and submit comments on the mitigative measures. The applicant for license or exemption has 15 days after the expiration of the public comment period to respond to the comments filed with the Commission.
(i) Material amendments to application. The proposed mitigative measures filed under paragraph (g)(2) of this section will not be considered a material amendment to the application unless the Commission finds that the proposed measures are unnecessary to, or exceed the scope of, mitigating substantial adverse effects. If the Commission finds the proposed mitigative measures constitute a material amendment, the application will be considered filed with the Commission on the date on which the applicant filed the proposed mitigative measures, and all other provisions of § 4.35(a) of this chapter will apply.
(j) Final determination on the petition. The Commission will make a final determination on the petition at the time the Commission issues a license or exemption for the project.
(k) Presumption. (1) If, between the Commission’s initial and final findings on the AEE petition, the State does not take any action under § 292.208(b)(2), the failure to take action can be the basis for a presumption that there is not substantial adverse effect on the environment (as that term is defined in § 292.202(q)).
(2) If the presumption in paragraph (k)(1) of this section comes into effect, it:
(i) Is only available for those adverse effects related to the natural, recreational, cultural, or scenic attributes of the environment;
(ii) Can only operate during the time between the Commission’s initial and final findings on the AEE petition; and
(iii) Has no affect on the Commission’s independent obligation to find that the project will not have a substantial adverse effect on the environment under § 292.208(b)(1).
(3) The presumption in paragraph (k)(1) of this section does not take effect if the State, the Commission or an interested person demonstrates that the State has acted to protect the natural watercourse under § 292.208(b)(2).
(4) The presumption in paragraph (k)(1) of this section can be rebutted if:
(i) The Commission determines that the project will have a substantial adverse effect on the environment related to the environmental attributes listed in paragraph (k)(2)(i) of this section; or
(ii) Any interested person, including a State, demonstrates that the project will have a substantial adverse effect on the environment related to the environmental attributes listed in paragraph (k)(2)(i) of this section.
Subpart C—Arrangements Between Electric Utilities and Qualifying Cogeneration and Small Power Production Facilities Under Section 210 of the Public Utility Regulatory Policies Act of 1978
§ 292.301 Scope.
(a) Applicability. This subpart applies to the regulation of sales and purchases between qualifying facilities and electric utilities.
(b) Negotiated rates or terms. Nothing in this subpart:
(1) Limits the authority of any electric utility or any qualifying facility to agree to a rate for any purchase, or terms or conditions relating to any purchase, which differ from the rate or terms or conditions which would otherwise be required by this subpart; or
(2) Affects the validity of any contract entered into between a qualifying facility and an electric utility for any purchase.
§ 292.302 Availability of electric utility system cost data.
(a) Applicability. (1) Except as provided in paragraph (a)(2) of this section, paragraph (b) applies to each electric utility, in any calendar year, if the total sales of electric energy by such utility for purposes other than resale exceeded 500 million kilowatt-hours during any calendar year beginning after December 31, 1975, and before the immediately preceding calendar year.
(2) Each utility having total sales of electric energy for purposes other than resale of less than one billion kilowatt-hours during any calendar year beginning after December 31, 1975, and before the immediately preceding year, shall not be subject to the provisions of this section until June 30, 1982.
(b) General rule. To make available data from which avoided costs may be derived, not later than November 1, 1980, June 30, 1982, and not less often than every two years thereafter, each regulated electric utility described in paragraph (a) of this section shall provide to its State regulatory authority, and shall maintain for public inspection, and each nonregulated electric utility described in paragraph (a) of this section shall maintain for public inspection, the following data:
(1) The estimated avoided cost on the electric utility’s system, solely with respect to the energy component, for various levels of purchases from qualifying facilities. Such levels of purchases shall be stated in blocks of not more than 100 megawatts for systems with peak demand of 1000 megawatts or more, and in blocks equivalent to not more than 10 percent of the system peak demand for systems of less than 1000 megawatts. The avoided costs shall be stated on a cents per kilowatt-hour basis, during daily and seasonal peak and off-peak periods, by year, for the current calendar year and each of the next 5 years;
(2) The electric utility’s plan for the addition of capacity by amount and type, for purchases of firm energy and capacity, and for capacity retirements for each year during the succeeding 10 years; and
(3) The estimated capacity costs at completion of the planned capacity additions and planned capacity firm purchases, on the basis of dollars per kilowatt, and the associated energy costs of each unit, expressed in cents per kilowatt hour. These costs shall be expressed in terms of individual generating units and of individual planned firm purchases.
(c) Special rule for small electric utilities. (1) Each electric utility (other than any electric utility to which paragraph (b) of this section applies) shall, upon request:
(i) Provide comparable data to that required under paragraph (b) of this section to enable qualifying facilities to estimate the electric utility’s avoided costs for periods described in paragraph (b) of this section; or
(ii) With regard to an electric utility which is legally obligated to obtain all its requirements for electric energy and capacity from another electric utility, provide the data of its supplying utility and the rates at which it currently purchases such energy and capacity.
(2) If any such electric utility fails to provide such information on request, the qualifying facility may apply to the State regulatory authority (which has ratemaking authority over the electric utility) or the Commission for an order requiring that the information be provided.
(d) Substitution of alternative method. (1) After public notice in the area served by the electric utility, and after opportunity for public comment, any State regulatory authority may require (with respect to any electric utility over which it has ratemaking authority), or any non-regulated electric utility may provide, data different than those which are otherwise required by this section if it determines that avoided costs can be derived from such data.
(2) Any State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or nonregulated utility which requires such different data shall notify the Commission within 30 days of making such determination.
(e) State Review. (1) Any data submitted by an electric utility under this section shall be subject to review by the State regulatory authority which has ratemaking authority over such electric utility.
(2) In any such review, the electric utility has the burden of coming forward with justification for its data.
§ 292.303 Electric utility obligations under this subpart.
(a) Obligation to purchase from qualifying facilities. Each electric utility shall purchase, in accordance with § 292.304, unless exempted by § 292.309 and § 292.310, any energy and capacity which is made available from a qualifying facility:
(1) Directly to the electric utility; or
(2) Indirectly to the electric utility in accordance with paragraph (d) of this section.
(b) Obligation to sell to qualifying facilities. Each electric utility shall sell to any qualifying facility, in accordance with § 292.305, unless exempted by § 292.312, energy and capacity requested by the qualifying facility.
(c) Obligation to interconnect. (1) Subject to paragraph (c)(2) of this section, any electric utility shall make such interconnection with any qualifying facility as may be necessary to accomplish purchases or sales under this subpart. The obligation to pay for any interconnection costs shall be determined in accordance with § 292.306.
(2) No electric utility is required to interconnect with any qualifying facility if, solely by reason of purchases or sales over the interconnection, the electric utility would become subject to regulation as a public utility under part II of the Federal Power Act.
(d) Transmission to other electric utilities. If a qualifying facility agrees, an electric utility which would otherwise be obligated to purchase energy or capacity from such qualifying facility may transmit the energy or capacity to any other electric utility. Any electric utility to which such energy or capacity is transmitted shall purchase such energy or capacity under this subpart as if the qualifying facility were supplying energy or capacity directly to such electric utility. The rate for purchase by the electric utility to which such energy is transmitted shall be adjusted up or down to reflect line losses pursuant to § 292.304(e)(4) and shall not include any charges for transmission.
(e) Parallel operation. Each electric utility shall offer to operate in parallel with a qualifying facility, provided that the qualifying facility complies with any applicable standards established in accordance with § 292.308.
§ 292.304 Rates for purchases.
(a) Rates for purchases. (1) Rates for purchases shall:
(i) Be just and reasonable to the electric consumer of the electric utility and in the public interest; and
(ii) Not discriminate against qualifying cogeneration and small power production facilities.
(2) Nothing in this subpart requires any electric utility to pay more than the avoided costs for purchases.
(b) Relationship to avoided costs. (1) For purposes of this paragraph, “new capacity” means any purchase from capacity of a qualifying facility, construction of which was commenced on or after November 9, 1978.
(2) Subject to paragraph (b)(3) of this section, a rate for purchases satisfies the requirements of paragraph (a) of this section if the rate equals the avoided costs determined after consideration of the factors set forth in paragraph (e) of this section
(3) A rate for purchases (other than from new capacity) may be less than the avoided cost if the State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or the nonregulated electric utility determines that a lower rate is consistent with paragraph (a) of this section, and is sufficient to encourage cogeneration and small power production.
(4) Rates for purchases from new capacity shall be in accordance with paragraph (b)(2) of this section, regardless of whether the electric utility making such purchases is simultaneously making sales to the qualifying facility.
(5) In the case in which the rates for purchases are based upon estimates of avoided costs over the specific term of the contract or other legally enforceable obligation, the rates for such purchases do not violate this subpart if the rates for such purchases differ from avoided costs at the time of delivery.
(6) Locational Marginal Price. There is a rebuttable presumption that a state regulatory authority or nonregulated electric utility may use a Locational Marginal Price as a rate for as-available qualifying facility energy sales to electric utilities located in a market defined in § 292.309(e), (f), or (g).
(7) Competitive Price. A state regulatory authority or nonregulated electric utility may use a Competitive Price as a rate for as-available qualifying facility energy sales to electric utilities located outside a market defined in § 292.309(e), (f), or (g). A Competitive Price may be either a Market Hub Price or a Combined Cycle Price, determined as follows:
(i) A Market Hub Price is a price established at a liquid market hub which a state regulatory authority or nonregulated electric utility determines represents an appropriate measure of the electric utility’s avoided cost for as-available energy, and is a hub to which the electric utility has reasonable access, based on an evaluation by the state regulatory authority or nonregulated electric utility of the relevant factors, including but not limited to the following:
(A) Whether the hub is sufficiently liquid that prices at the hub represent a competitive price;
(B) Whether prices developed at the hub are sufficiently transparent;
(C) Whether the electric utility has the ability to deliver power from such hub to its load, even if its load is not directly connected to the hub; and
(D) Whether the hub represents an appropriate market to derive an energy price for the electric utility’s purchases from the relevant qualifying facility given the electric utility’s physical proximity to the hub or other factors.
(ii) A Combined Cycle Price is a price determined pursuant to a formula established by a state regulatory authority or nonregulated electric utility using published natural gas price indices, a proxy heat rate, and variable operations and maintenance costs for an efficient natural gas combined-cycle generating facility. Before establishing such a formula rate, a state regulatory authority or nonregulated electric utility must determine that the resulting Combined Cycle Price represents an appropriate measure of the purchasing electric utility’s avoided cost for energy, based on its evaluation of the relevant factors, including but not limited to the following:
(A) Whether the cost of energy from an efficient natural gas combined cycle generating facility represents a reasonable measure of a competitive price in the purchasing electric utility’s region;
(B) Whether natural gas priced pursuant to particular proposed natural gas price indices would be available in the relevant market;
(C) Whether there should be an adjustment to the natural gas price to appropriately reflect the cost of transporting natural gas to the relevant market; and
(D) Whether the proxy heat rate used in the formula should be updated regularly to reflect improvements in generation technology.
(8) Competitive Solicitation Price. (i) A state regulatory authority or nonregulated electric utility may use a price determined pursuant to a competitive solicitation process to establish qualifying facility energy and/or capacity rates for sales to electric utilities, provided that such competitive solicitation process is conducted pursuant to procedures ensuring the solicitation is conducted in a transparent and non-discriminatory manner including, but not limited to, the following:
(A) The solicitation process is an open and transparent process that includes, but is not limited to, providing equally to all potential bidders substantial and meaningful information regarding transmission constraints, levels of congestion, and interconnections, subject to appropriate confidentiality safeguards;
(B) Solicitations are open to all sources, to satisfy that electric utility’s capacity needs, taking into account the required operating characteristics of the needed capacity;
(C) Solicitations are conducted at regular intervals;
(D) Solicitations are subject to oversight by an independent administrator; and
(E) Solicitations are certified as fulfilling the above criteria by the relevant state regulatory authority or nonregulated electric utility through a post-solicitation report.
(ii) To the extent that the electric utility procures all of its capacity, including capacity resources constructed or otherwise acquired by the electric utility, through a competitive solicitation process conducted pursuant to paragraph (b)(8)(i) of this section, the electric utility shall be presumed to have no avoided capacity costs unless and until it determines to acquire capacity outside of such competitive solicitation process. However, the electric utility shall nevertheless be required to purchase energy from qualifying small power producers and qualifying cogeneration facilities.
(iii) To the extent that the electric utility does not procure all of its capacity through a competitive solicitation process conducted pursuant to paragraph (b)(8)(i) of this section, then there shall be no presumption that the electric utility has no avoided capacity costs.
(c) Standard rates for purchases. (1) There shall be put into effect (with respect to each electric utility) standard rates for purchases from qualifying facilities with a design capacity of 100 kilowatts or less.
(2) There may be put into effect standard rates for purchases from qualifying facilities with a design capacity of more than 100 kilowatts.
(3) The standard rates for purchases under this paragraph:
(i) Shall be consistent with paragraphs (a) and (e) of this section; and
(ii) May differentiate among qualifying facilities using various technologies on the basis of the supply characteristics of the different technologies.
(d) Purchases “as available” or pursuant to a legally enforceable obligation. (1) Each qualifying facility shall have the option either:
(i) To provide energy as the qualifying facility determines such energy to be available for such purchases, in which case the rates for such purchases shall be based on the electric utility’s avoided cost for energy calculated at the time of delivery; or
(ii) To provide energy or capacity pursuant to a legally enforceable obligation for the delivery of energy or capacity over a specified term, in which case the rates for such purchases shall, except as provided in paragraph (d)(2) of this section, be based on either:
(A) The avoided costs calculated at the time of delivery; or
(B) The avoided costs calculated at the time the obligation is incurred.
(iii) The rate for delivery of energy calculated at the time the obligation is incurred may be based on estimates of the present value of the stream of revenue flows of future locational marginal prices, or Competitive Prices during the anticipated period of delivery.
(2) Notwithstanding paragraph (d)(1)(ii)(B) of this section, a state regulatory authority or nonregulated electric utility may require that rates for purchases of energy from a qualifying facility pursuant to a legally enforceable obligation vary through the life of the obligation, and be set at the electric utility’s avoided cost for energy calculated at the time of delivery.
(3) Obtaining a legally enforceable obligation. A qualifying facility must demonstrate commercial viability and financial commitment to construct its facility pursuant to criteria determined by the state regulatory authority or nonregulated electric utility as a prerequisite to a qualifying facility obtaining a legally enforceable obligation. Such criteria must be objective and reasonable.
(e) Factors affecting rates for purchases. (1) A state regulatory authority or nonregulated electric utility may establish rates for purchases of energy from a qualifying facility based on a purchasing electric utility’s locational marginal price calculated by the applicable market defined in § 292.309(e), (f), or (g), or the purchasing electric utility’s applicable Competitive Price. Alternatively, a state regulatory authority or nonregulated electric utility may establish rates for purchases of energy and/or capacity from a qualifying facility based on a Competitive Solicitation Price. To the extent that capacity rates are not set pursuant to this section, capacity rates shall be set pursuant to subsection (2).
(2) To the extent that a state regulatory authority or nonregulated electric utility does not set energy and/or capacity rates pursuant to paragraph (e)(1) of this section, the following factors shall, to the extent practicable, be taken into account in determining rates for purchases from a qualifying facility:
(i) The data provided pursuant to § 292.302(b), (c), or (d), including State review of any such data;
(ii) The availability of capacity or energy from a qualifying facility during the system daily and seasonal peak periods, including:
(A) The ability of the electric utility to dispatch the qualifying facility;
(B) The expected or demonstrated reliability of the qualifying facility;
(C) The terms of any contract or other legally enforceable obligation, including the duration of the obligation, termination notice requirement and sanctions for non-compliance;
(D) The extent to which scheduled outages of the qualifying facility can be usefully coordinated with scheduled outages of the electric utility’s facilities;
(E) The usefulness of energy and capacity supplied from a qualifying facility during system emergencies, including its ability to separate its load from its generation;
(F) The individual and aggregate value of energy and capacity from qualifying facilities on the electric utility’s system; and
(G) The smaller capacity increments and the shorter lead times available with additions of capacity from qualifying facilities; and
(iii) The relationship of the availability of energy or capacity from the qualifying facility as derived in paragraph (e)(2)(ii) of this section, to the ability of the electric utility to avoid costs, including the deferral of capacity additions and the reduction of fossil fuel use; and
(iv) The costs or savings resulting from variations in line losses from those that would have existed in the absence of purchases from a qualifying facility, if the purchasing electric utility generated an equivalent amount of energy itself or purchased an equivalent amount of electric energy or capacity.
(f) Periods during which purchases not required. (1) Any electric utility which gives notice pursuant to paragraph (f)(2) of this section will not be required to purchase electric energy or capacity during any period during which, due to operational circumstances, purchases from qualifying facilities will result in costs greater than those which the utility would incur if it did not make such purchases, but instead generated an equivalent amount of energy itself.
(2) Any electric utility seeking to invoke paragraph (f)(1) of this section must notify, in accordance with applicable State law or regulation, each affected qualifying facility in time for the qualifying facility to cease the delivery of energy or capacity to the electric utility.
(3) Any electric utility which fails to comply with the provisions of paragraph (f)(2) of this section will be required to pay the same rate for such purchase of energy or capacity as would be required had the period described in paragraph (f)(1) of this section not occurred.
(4) A claim by an electric utility that such a period has occurred or will occur is subject to such verification by its State regulatory authority as the State regulatory authority determines necessary or appropriate, either before or after the occurrence.
§ 292.305 Rates for sales.
(a) General rules. (1) Rates for sales:
(i) Shall be just and reasonable and in the public interest; and
(ii) Shall not discriminate against any qualifying facility in comparison to rates for sales to other customers served by the electric utility.
(2) Rates for sales which are based on accurate data and consistent systemwide costing principles shall not be considered to discriminate against any qualifying facility to the extent that such rates apply to the utility’s other customers with similar load or other cost-related characteristics.
(b) Additional services to be provided to qualifying facilities. (1) Upon request of a qualifying facility, each electric utility shall provide:
(i) Supplementary power;
(ii) Back-up power;
(iii) Maintenance power; and
(iv) Interruptible power.
(2) The State regulatory authority (with respect to any electric utility over which it has ratemaking authority) and the Commission (with respect to any nonregulated electric utility) may waive any requirement of paragraph (b)(1) of this section if, after notice in the area served by the electric utility and after opportunity for public comment, the electric utility demonstrates and the State regulatory authority or the Commission, as the case may be, finds that compliance with such requirement will:
(i) Impair the electric utility’s ability to render adequate service to its customers; or
(ii) Place an undue burden on the electric utility.
(c) Rates for sales of back-up and maintenance power. The rate for sales of back-up power or maintenance power:
(1) Shall not be based upon an assumption (unless supported by factual data) that forced outages or other reductions in electric output by all qualifying facilities on an electric utility’s system will occur simultaneously, or during the system peak, or both; and
(2) Shall take into account the extent to which scheduled outages of the qualifying facilities can be usefully coordinated with scheduled outages of the utility’s facilities.
§ 292.306 Interconnection costs.
(a) Obligation to pay. Each qualifying facility shall be obligated to pay any interconnection costs which the State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or nonregulated electric utility may assess against the qualifying facility on a nondiscriminatory basis with respect to other customers with similar load characteristics.
(b) Reimbursement of interconnection costs. Each State regulatory authority (with respect to any electric utility over which it has ratemaking authority) and nonregulated utility shall determine the manner for payments of interconnection costs, which may include reimbursement over a reasonable period of time.
§ 292.307 System emergencies.
(a) Qualifying facility obligation to provide power during system emergencies. A qualifying facility shall be required to provide energy or capacity to an electric utility during a system emergency only to the extent:
(1) Provided by agreement between such qualifying facility and electric utility; or
(2) Ordered under section 202(c) of the Federal Power Act.
(b) Discontinuance of purchases and sales during system emergencies. During any system emergency, an electric utility may discontinue:
(1) Purchases from a qualifying facility if such purchases would contribute to such emergency; and
(2) Sales to a qualifying facility, provided that such discontinuance is on a nondiscriminatory basis.
§ 292.308 Standards for operating reliability.
Any State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or nonregulated electric utility may establish reasonable standards to ensure system safety and reliability of interconnected operations. Such standards may be recommended by any electric utility, any qualifying facility, or any other person. If any State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or nonregulated electric utility establishes such standards, it shall specify the need for such standards on the basis of system safety and reliability.
§ 292.309 Termination of obligation to purchase from qualifying facilities.
(a) After August 8, 2005, an electric utility shall not be required, under this part, to enter into a new contract or obligation to purchase electric energy from a qualifying cogeneration facility or a qualifying small power production facility if the Commission finds that the qualifying cogeneration facility or qualifying small power facility production has nondiscriminatory access to:
(1)(i) Independently administered, auction-based day ahead and real time wholesale markets for the sale of electric energy; and
(ii) Wholesale markets for long-term sales of capacity and electric energy; or
(2)(i) Transmission and interconnection services that are provided by a Commission-approved regional transmission entity and administered pursuant to an open access transmission tariff that affords nondiscriminatory treatment to all customers; and
(ii) Competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term and real-time sales, to buyers other than the utility to which the qualifying facility is interconnected. In determining whether a meaningful opportunity to sell exists, the Commission shall consider, among other factors, evidence of transactions within the relevant market; or
(3) Wholesale markets for the sale of capacity and electric energy that are, at a minimum, of comparable competitive quality as markets described in paragraphs (a)(1) and (a)(2) of this section.
(b) For purposes of § 292.309(a), a renewal of a contract that expires by its own terms is a “new contract or obligation” without a continuing obligation to purchase under an expired contract.
(c) For purposes of paragraphs (a)(1), (2) and (3) of this section, with the exception of paragraph (d) of this section, there is a rebuttable presumption that a qualifying facility has nondiscriminatory access to the market if it is eligible for service under a Commission-approved open access transmission tariff or Commission-filed reciprocity tariff, and Commission-approved interconnection rules.
(1) If the Commission determines that a market meets the criteria of paragraphs (a)(1), (2) or (3) of this section, and if a qualifying facility in the relevant market is eligible for service under a Commission-approved open access transmission tariff or Commission-filed reciprocity tariff, a qualifying facility may seek to rebut the presumption of access to the market by demonstrating, inter alia, that it does not have access to the market because of operational characteristics or transmission constraints.
(2) For purposes of paragraphs (a)(1), (2), and (3) of this section, a qualifying small power production facility with a capacity between 5 megawatts and 20 megawatts may additionally seek to rebut the presumption of access to the market by demonstrating that it does not have access to the market in light of consideration of other factors, including, but not limited to:
(i) Specific barriers to connecting to the interstate transmission grid, such as excessively high costs and pancaked delivery rates;
(ii) Unique circumstances impacting the time or length of interconnection studies or queues to process the small power production facility’s interconnection request;
(iii) A lack of affiliation with entities that participate in the markets in paragraphs (a)(1), (2), and (3) of this section;
(iv) The qualifying small power production facility has a predominant purpose other than selling electricity and should be treated similarly to qualifying cogeneration facilities;
(v) The qualifying small power production facility has certain operational characteristics that effectively prevent the qualifying facility’s participation in a market; or
(vi) The qualifying small power production facility lacks access to markets due to transmission constraints. The qualifying small power production facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.
(d)(1) For purposes of paragraphs (a)(1), (2), and (3) of this section, there is a rebuttable presumption that a qualifying cogeneration facility with a capacity at or below 20 megawatts does not have nondiscriminatory access to the market.
(2) For purposes of paragraphs (a)(1), (2), and (3) of this section, there is a rebuttable presumption that a qualifying small power production facility with a capacity at or below 5 megawatts does not have nondiscriminatory access to the market.
(3) Nothing in paragraphs (d)(1) through (3) affects the rights the rights or remedies of any party under any contract or obligation, in effect or pending approval before the appropriate State regulatory authority or non-regulated electric utility on or before February 16, 2021, to purchase electric energy or capacity from or to sell electric energy or capacity to a small power production facility between 5 megawatts and 20 megawatts under this Act (including the right to recover costs of purchasing electric energy or capacity).
(4) For purposes of implementing paragraphs (d)(1) and (2) of this section, the Commission will not be bound by the standards set forth in § 292.204(a)(2).
(e) Midcontinent Independent System Operator, Inc. (MISO), PJM Interconnection, L.L.C. (PJM), ISO New England Inc. (ISO–NE), and New York Independent System Operator, Inc. (NYISO) qualify as markets described in paragraphs (a)(1)(i) and (ii) of this section, and there is a rebuttable presumption that small power production facilities with a capacity greater than 5 megawatts and cogeneration facilities with a capacity greater than 20 megawatts have nondiscriminatory access to those markets through Commission-approved open access transmission tariffs and interconnection rules, and that electric utilities that are members of such regional transmission organizations or independent system operators should be relieved of the obligation to purchase electric energy from the qualifying facilities.
(1) A qualifying facility above 20 MW may seek to rebut this presumption by demonstrating, inter alia, that:
(i) The qualifying facility has certain operational characteristics that effectively prevent the qualifying facility’s participation in a market; or
(ii) The qualifying facility lacks access to markets due to transmission constraints. The qualifying facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.
(2) A small power producer qualifying facility between 5 megawatts and 20 megawatts may show it does not have access to the market in light of consideration of other factors, including, but not limited to:
(i) Specific barriers to connecting to the interstate transmission grid, such as excessively high costs and pancaked delivery rates;
(ii) Unique circumstances impacting the time or length of interconnection studies or queues to process the small power production facility’s interconnection request;
(iii) A lack of affiliation with entities that participate in the markets in section § 292.309(a)(1), (2), and (3);
(iv) The qualifying small power production facility has a predominant purpose other than selling electricity and should be treated similarly to qualifying cogeneration facilities;
(v) The qualifying small power production facility has certain operational characteristics that effectively prevent the qualifying facility’s participation in a market; or
(vi) The qualifying small power production facility lacks access to markets due to transmission constraints. The qualifying small power production facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.
(f) The Electric Reliability Council of Texas (ERCOT) qualifies as a market described in paragraph (a)(3) of this section, and there is a rebuttable presumption that small power production facilities with a capacity greater than five megawatts and cogeneration facilities with a capacity greater than 20 megawatts have nondiscriminatory access to that market through Public Utility Commission of Texas (PUCT) approved open access protocols, and that electric utilities that operate within ERCOT should be relieved of the obligation to purchase electric energy from the qualifying facilities.
(1) A qualifying facility above 20 MW may seek to rebut this presumption by demonstrating, inter alia, that:
(i) The qualifying facility has certain operational characteristics that effectively prevent the qualifying facility’s participation in a market; or
(ii) The qualifying facility lacks access to markets due to transmission constraints. The qualifying facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.
(2) A small power producer qualifying facility between 5 megawatts and 20 megawatts may show it does not have access to the market in light of consideration of other factors, including, but not limited to:
(i) Specific barriers to connecting to the interstate transmission grid, such as excessively high costs and pancaked delivery rates;
(ii) Unique circumstances impacting the time or length of interconnection studies or queues to process the small power production facility’s interconnection request;
(iii) A lack of affiliation with entities that participate in the markets in section § 292.309(a)(1), (2), and (3);
(iv) The qualifying small power production facility has a predominant purpose other than selling electricity and should be treated similarly to qualifying cogeneration facilities;
(v) The qualifying small power production facility has certain operational characteristics that effectively prevent the qualifying facility’s participation in a market; or
(vi) The qualifying small power production facility lacks access to markets due to transmission constraints. The qualifying small power production facility may show that it is located in an area where persistent transmission constraints in effect cause the qualifying facility not to have access to markets outside a persistently congested area to sell the qualifying facility output or capacity.
(g) The California Independent System Operator and Southwest Power Pool, Inc. satisfy the criteria of § 292.309(a)(2)(i).
(h) No electric utility shall be required, under this part, to enter into a new contract or obligation to purchase from or sell electric energy to a facility that is not an existing qualifying cogeneration facility unless the facility meets the criteria for new qualifying cogeneration facilities established by the Commission in § 292.205.
(i) For purposes of § 292.309(h), an “existing qualifying cogeneration facility” is a facility that:
(1) Was a qualifying cogeneration facility on or before August 8, 2005; or
(2) Had filed with the Commission a notice of self-certification or self-recertification, or an application for Commission certification, under § 292.207 prior to February 2, 2006.
(j) For purposes of § 292.309(h), a “new qualifying cogeneration facility” is a facility that satisfies the criteria for qualifying cogeneration facilities pursuant to § 292.205.
§ 292.310 Procedures for utilities requesting termination of obligation to purchase from qualifying facilities.
(a) An electric utility may file an application with the Commission for relief from the mandatory purchase requirement under § 292.303(a) pursuant to this section on a service territory-wide basis. Such application shall set forth the factual basis upon which relief is requested and describe why the conditions set forth in § 292.309(a)(1), (2) or (3) have been met. After notice, including sufficient notice to potentially affected qualifying cogeneration facilities and qualifying small power production facilities, and an opportunity for comment, the Commission shall make a final determination within 90 days of such application regarding whether the conditions set forth in § 292.309(a)(1), (2) or (3) have been met.
(b) Sufficient notice shall mean that an electric utility must identify with names and addresses all potentially affected qualifying facilities in an application filed pursuant to paragraph (a).
(c) An electric utility must submit with its application for each potentially affected qualifying facility: The docket number assigned if the qualifying facility filed for self-certification or an application for Commission certification of qualifying facility status; the net capacity of the qualifying facility; the location of the qualifying facility depicted by state and county, and the name and location of the substation where the qualifying facility is interconnected; the interconnection status of each potentially affected qualifying facility including whether the qualifying facility is interconnected as an energy or a network resource; and the expiration date of the energy and/or capacity agreement between the applicant utility and each potentially affected qualifying facility. All potentially affected qualifying facilities shall include:
(1) Those qualifying facilities that have existing power purchase contracts with the applicant;
(2) Other qualifying facilities that sell their output to the applicant or that have pending self-certification or Commission certification with the Commission for qualifying facility status whereby the applicant will be the purchaser of the qualifying facility’s output;
(3) Any developer of generating facilities with whom the applicant has agreed to enter into power purchase contracts, as of the date of the application filed pursuant to this section, or are in discussion, as of the date of the application filed pursuant to this section, with regard to power purchase contacts;
(4) The developers of facilities that have pending state avoided cost proceedings, as of the date of the application filed pursuant to this section; and
(5) Any other qualifying facilities that the applicant reasonably believes to be affected by its application filed pursuant to paragraph (a) of this section.
(d) The following information must be filed with an application:
(1) Identify whether applicant seeks a finding under the provisions of § 292.309(a)(1), (2), or (3).
(2) A narrative setting forth the factual basis upon which relief is requested and describing why the conditions set forth in § 292.309(a)(1), (2), or (3) have been met. Applicant should also state in its application whether it is relying on the findings or rebuttable presumptions contained in § 292.309(e), (f) or (g). To the extent applicant seeks relief from the purchase obligation with respect to a qualifying facility 20 megawatts or smaller, and thus seeks to rebut the presumption in § 292.309(d), applicant must also set forth, and submit evidence of, the factual basis supporting its contention that the qualifying facility has nondiscriminatory access to the wholesale markets which are the basis for the applicant’s filing.
(3) Transmission Studies and related information, including:
(i) The applicant’s long-term transmission plan, conducted by applicant, or the RTO, ISO or other relevant entity;
(ii) Transmission constraints by path, element or other level of comparable detail that have occurred and/or are known and expected to occur, and any proposed mitigation including transmission construction plans;
(iii) Levels of congestion, if available;
(iv) Relevant system impact studies for the generation interconnections, already completed;
(v) Other information pertinent to showing whether transfer capability is available; and
(vi) The appropriate link to applicant’s OASIS, if any, from which a qualifying facility may obtain applicant’s available transfer capability (ATC) information.
(4) Describe the process, procedures and practices that qualifying facilities interconnected to the applicant’s system must follow to arrange for the transmission service to transfer power to purchasers other than the applicant. This description must include the process, procedures and practices of all distribution, transmission and regional transmission facilities necessary for qualifying facility access to the market.
(5) If qualifying facilities will be required to execute new interconnection agreements, or renegotiate existing agreements so that they can effectuate wholesale sales to third-party purchasers, explain the requirements, charges and the process to be followed. Also, explain any differences in these requirements as they apply to qualifying facilities compared to other generators, or to applicant-owned generation.
(6) Applicants seeking a Commission finding pursuant to § 292.309(a)(2) or (3), except those applicants located in ERCOT, also must provide evidence of competitive wholesale markets that provide a meaningful opportunity to sell capacity, including long-term and short-term sales, and electric energy, including long-term, short-term and real-time sales, to buyers other than the utility to which the qualifying facility is interconnected. In demonstrating that a meaningful opportunity to sell exists, provide evidence of transactions within the relevant market. Applicants must include a list of known or potential purchasers, e.g., jurisdictional and non-jurisdictional utilities as well as retail energy service providers.
(7) Signature of authorized individual evidencing the accuracy and authenticity of information provided by applicant.
(8) Person(s) to whom communications regarding the filed information may be addressed, including name, title, telephone number, and mailing address.
§ 292.311 Reinstatement of obligation to purchase.
At any time after the Commission makes a finding under §§ 292.309 and 292.310 relieving an electric utility of its obligation to purchase electric energy, a qualifying cogeneration facility, a qualifying small power production facility, a State agency, or any other affected person may apply to the Commission for an order reinstating the electric utility’s obligation to purchase electric energy under this section. Such application shall set forth the factual basis upon which the application is based and describe why the conditions set forth in § 292.309(a), (b) or (c) are no longer met. After notice, including sufficient notice to potentially affected electric utilities, and opportunity for comment, the Commission shall issue an order within 90 days of such application reinstating the electric utility’s obligation to purchase electric energy under this section if the Commission finds that the conditions set forth in § 292.309(a), (b), or (c) which relieved the obligation to purchase, are no longer met.
§ 292.312 Termination of obligation to sell to qualifying facilities.
(a) Any electric utility may file an application with the Commission for relief from the mandatory obligation to sell under this section on a service territory-wide basis or a single qualifying facility basis. Such application shall set forth the factual basis upon which relief is requested and describe why the conditions set forth in paragraphs (b)(1) and (b)(2) of this section have been met. After notice, including sufficient notice to potentially affected qualifying facilities, and an opportunity for comment, the Commission shall make a final determination within 90 days of such application regarding whether the conditions set forth in paragraphs (b)(1) and (b)(2) of this section have been met.
(b) After August 8, 2005, an electric utility shall not be required to enter into a new contract or obligation to sell electric energy to a qualifying small power production facility, an existing qualifying cogeneration facility, or a new qualifying cogeneration facility if the Commission has found that;
(1) Competing retail electric suppliers are willing and able to sell and deliver electric energy to the qualifying cogeneration facility or qualifying small power production facility; and
(2) The electric utility is not required by State law to sell electric energy in its service territory.
§ 292.313 Reinstatement of obligation to sell.
At any time after the Commission makes a finding under § 292.312 relieving an electric utility of its obligation to sell electric energy, a qualifying cogeneration facility, a qualifying small power production facility, a State agency, or any other affected person may apply to the Commission for an order reinstating the electric utility’s obligation to purchase electric energy under this section. Such application shall set forth the factual basis upon which the application is based and describe why the conditions set forth in Paragraph (b)(1) and (b)(2) of this section are no longer met. After notice, including sufficient notice to potentially affected utilities, and opportunity for comment, the Commission shall issue an order within 90 days of such application reinstating the electric utility’s obligation to sell electric energy under this section if the Commission finds that the conditions set forth in paragraphs (b)(1) and (b)(2) of this section are no longer met.
§ 292.314 Existing rights and remedies.
Nothing in this section affects the rights or remedies of any party under any contract or obligation, in effect or pending approval before the appropriate State regulatory authority or non-regulated electric utility on or before August 8, 2005, to purchase electric energy or capacity from or to sell electric energy or capacity to a qualifying cogeneration facility or qualifying small power production facility under this Act (including the right to recover costs of purchasing electric energy or capacity).
Subpart D—Implementation
§ 292.401 Implementation of certain reporting requirements.
Any electric utility which fails to comply with the requirements of § 292.302(b) shall be subject to the same penalties to which it may be subjected for failure to comply with the requirements of the Commission’s regulations issued under section 133 of PURPA.
§ 292.402 Waivers.
(a) State regulatory authority and nonregulated electric utility waivers. Any State regulatory authority (with respect to any electric utility over which it has ratemaking authority) or nonregulated electric utility may, after public notice in the area served by the electric utility, apply for a waiver from the application of any of the requirements of subpart C (other than § 292.302 thereof).
(b) Commission action. The Commission will grant such a wavier only if an applicant under paragraph (a) of this section demonstrates that compliance with any of the requirements of subpart C is not necessary to encourage cogeneration and small power production and is not otherwise required under section 210 of PURPA.
Subpart E [Reserved]
Subpart F—Exemption of Qualifying Small Power Production Facilities and Cogeneration Facilities from Certain Federal and State Laws and Regulations
§ 292.601 Exemption to qualifying facilities from the Federal Power Act.
(a) Applicability. This section applies to qualifying facilities, other than those described in paragraph (b) of this section. This section also applies to qualifying facilities that meet the criteria of section 3(17)(E) of the Federal Power Act (16 U.S.C. 796(17)(E)), notwithstanding paragraph (b).
(b) Exclusion. This section does not apply to a qualifying small power production facility with a power production capacity which exceeds 30 megawatts, if such facility uses any primary energy source other than geothermal resources.
(c) General rule. Any qualifying facility described in paragraph (a) of this section shall be exempt from all sections of the Federal Power Act, except:
(1) Sections 205 and 206; however, sales of energy or capacity made by qualifying facilities 20 MW or smaller, or made pursuant to a contract executed on or before March 17, 2006 or made pursuant to a state regulatory authority’s implementation of section 210 the Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 824a–1, shall be exempt from scrutiny under sections 205 and 206;
(2) Section 1–18, and 21–30;
(3) Sections 202(c), 210, 211, 212, 213, 214, 215, 220, 221 and 222;
(4) Sections 305(c); and
(5) Any necessary enforcement provision of part III of the Federal Power Act (including but not limited to sections 306, 307, 308, 309, 314, 315, 316 and 316A) with regard to the sections listed in paragraphs (c)(1), (2), (3) and (4) of this section.
§ 292.602 Exemption to qualifying facilities from the Public Utility Holding Company Act of 2005 and certain State laws and regulations.
(a) Applicability. This section applies to any qualifying facility described in § 292.601(a), and to any qualifying small power production facility with a power production capacity over 30 megawatts if such facility produces electric energy solely by the use of biomass as a primary energy source.
(b) Exemption from the Public Utility Holding Company Act of 2005. A qualifying facility described in paragraph (a) of this section or a utility geothermal small power production facility shall be exempt from the Public Utility Holding Company Act of 2005, 42 U.S.C. 16,451–63.
(c) Exemption from certain State laws and regulations. (1) Any qualifying facility described in paragraph (a) of this section shall be exempted (except as provided in paragraph (c)(2) of this section) from State laws or regulations respecting:
(i) The rates of electric utilities; and
(ii) The financial and organizational regulation of electric utilities.
(2) A qualifying facility may not be exempted from State laws and regulations implementing subpart C.
(3) Upon request of a state regulatory authority or nonregulated electric utility, the Commission may consider a limitation on the exemptions specified in paragraph (b)(1) of this section.
(4) Upon request of any person, the Commission may determine whether a qualifying facility is exempt from a particular State law or regulation.
PART 294—PROCEDURES FOR SHORTAGES OF ELECTRIC ENERGY AND CAPACITY UNDER SECTION 206 OF THE PUBLIC UTILITY REGULATORY POLICIES ACT OF 1978
§ 294.101 Shortages of electric energy and capacity.
(a) Definition of shortages of electric energy and capacity. For purposes of this section, the term anticipated shortages of electric or energy means:
(1) Any situation anticipated to occur in which the generating and bulk purchased power capability of a public utility will not be sufficient to meet its anticipated demand plus appropriate reserve margins and this shortage would affect the utility’s capability adequately to supply electric services to its firm power wholesale customers; or
(2) Any situation anticipated to occur in which the energy supply capability of a public utility is not sufficient to meet its customers’ energy requirements and this shortage would affect the utility’s capability adequately to supply electric services to its firm power wholesale customers.
(b) Accommodation of shortages. (1) Each public utility now serving firm power wholesale customers, shall submit a brief statement indicating how it would accommodate any shortages of electric energy or capacity affecting its firm power wholesale customers.
(2) This statement shall:
(i) Describe how the utility would assure that direct and indirect customers are treated without undue prejudice or disadvantage; and
(ii) It shall also identify any agreement, law, or regulation which might impair the utility’s ability to accommodate such a shortage.
(3) Each utility shall file a copy of its statement with any appropriate State regulatory agency and all firm power wholesale customers.
(4) If a plan for accommodating any shortages of electric energy or capacity affecting its firm power wholesale customers as described in the brief statement submitted pursuant to paragraph (b)(1) of this section is modified, the utility must submit to the Commission and the persons described in paragraph (b)(3) of this section within 15 days of any such modification, a supplemental statement informing the Commission of those modifications.
(5) Notwithstanding any other provision of this section, a public utility need not file the statement with the Commission if the public utility provides in its rate schedules to firm power wholesale customers that:
(i) During electric energy and capacity shortages it will treat without undue discrimination or preference, prejudice, or disadvantage firm power wholesale customers; and
(ii) It will report any modifications to its contingency plans for accommodating shortages within 15 days to:
(A) The appropriate State regulatory agency and
(B) To the affected wholesale customers.
(c) Reporting requirements. Each public utility shall immediately report to the Commission, to any State regulatory authority and to firm power wholesale customers, any anticipated shortage of electric energy or capacity. The report shall include the following information:
(1) The nature and projected duration of the anticipated capacity or energy supply shortage;
(2) A list showing all firm power wholesale customers affected or likely to be affected by the anticipated shortage;
(3) Procedures for accommodating the shortage, if different from those described in paragraph (b) of this section;
(4) An estimate of the effects (reduced power and energy usage) of use of these procedures upon the utility’s wholesale and retail customers; and
(5) The name, title, address and telephone number of an officer or employee of the utility who may be contacted for further information regarding the shortage and planned actions of the utility.
(d) Reports to other government entities. Any report filed with another governmental entity that contains the information that must be reported under this part may be filed to comply with this part.
(e) Reporting Procedure. Any public utility that reports under this part must provide an electronic filing to this Commission at [email protected] and one copy to any state regulatory authority and firm power wholesale customers, unless otherwise required by the Commission.
(f) Report of anticipated shortage. Notwithstanding any other provision of this part, if a public utility provides in its rate schedule that it will make such reports to the appropriate state regulatory agency and to its firm power wholesale requirements customers, then it need only report to the Commission the nature and projected duration of the anticipated capacity or energy supply shortage and supply a list of the firm power wholesale customers affected or likely to be affected by the shortage. Upon receiving the public utility’s report of anticipated shortage of electric energy or capacity, the Commission will decide what further reports, if any, to require.
SUBCHAPTER L—REGULATIONS FOR FEDERAL POWER MARKETING ADMINISTRATIONS
PART 300—CONFIRMATION AND APPROVAL OF THE RATES OF FEDERAL POWER MARKETING ADMINISTRATIONS
Subpart A—General Provisions
§ 300.1 Applicability and definitions.
(a) Applicability. This part sets forth procedures governing the filing, review and disposition of the rate schedules for the sale or transmission of power and energy established by the Alaska, Bonneville, Southeastern, Southwestern and Western Area Power Administrations. Except as otherwise provided by rule or order, the Commission’s general rules of practice and procedure (part 385 of this chapter) will apply to any filings, hearings or other procedures under this part, as applicable.
(b) Definitions. For purposes of this part, the following definitions apply:
(1) Administrator means the administrator of a power marketing administration.
(2) Electric service means any transmission or sale of electric power and energy, including capacity sales, energy sales, firm power sales, transmission services, or any combination of these services, and the utilization, by means of ownership, contractual arrangements, leasing, or other arrangements, of any facility to provide such sales or services.
(3) Historic period means the period commencing with the date of first commercial operation of a powerplant or transmission facility and ending on the last day of the latest year for which actual cost data are available, provided that the period does not end more than 18 months before the date on which the Administrator tenders the rate schedule for filing with the Commission, or such longer period requested by the Deputy Secretary of Energy or Administrator and granted by the Commission.
(4) Initial capital investment means the cost of acquisition or construction of a power facility or non-power facility which has been assigned to be repaid from the power revenues, including but not limited to any cost of planning, design, land acquisition, construction, interest during construction, and testing incurred before the date on which the facility becomes operational or revenue-producing.
(5) Power repayment study or PRS means a study of the annual repayment of production and transmission investments and other costs through the application of revenues during the repayment period.
(6) Proposed rate approval period means the period for which confirmation and approval of the rate schedules is requested. This period must not exceed five years.
(7) Rate schedule means a statement describing:
(i) Type of service to which the rate is to be applied;
(ii) Rates and charges for, or in connection with, electric service; and
(iii) Classifications and other provisions which directly affect such rates and charges.
(8) Rate test or cost evaluation period means a period, commencing with the end of the historic period, as defined in paragraph (b)(3) of this section, and continuing through the proposed rate approval period as defined in paragraph (b)(6) of this section, during which future estimates of costs and revenues should be modified by the Administrator to reflect changing conditions.
(9) Replacement means any substitution of a unit of property with another unit of like character.
§ 300.2 Informal conference.
The Administrator or a designee may confer with Commission staff prior to submitting an application under subpart B, with respect to the appropriate form and content of such application.
Subpart B—Filing Requirements
§ 300.10 Application for confirmation and approval.
(a) General provisions—(1) Contents of filing. Any application under this subpart for confirmation and approval of rate schedules must include, as described in this section a letter of request for rate approval, a form of notice suitable for publication in the
(2) Incorporation of information by reference. Any information required under this subpart that has previously been submitted to the Commission in substantially the same form as specified in this section may be incorporated by reference only.
(3) Time of filing. (i) Rate schedules put into effect on an interim basis by the Secretary of the Department of Energy, or a designee, and filed for final Commission approval must be filed not later than five days after interim approval is granted.
(ii) Rate schedules of the Bonneville Power Administration for which interim approval by the Commission is requested must be filed not later than 60 days in advance of the proposed effective date.
(iii) Rate schedules for which interim approval is not requested must be filed not later than 180 days in advance of the proposed effective date.
(4) Electronic filing. All material must be filed electronically in accordance with the requirements of § 35.7 of this chapter.
(b) Letter of request for rate approval. A letter of request for rate approval must contain the following information:
(1) A description of the period for which Commission approval is requested, delineated by an effective date and an expiration date, and, for the Bonneville Power Administration, a request, if any, for interim approval of the rates;
(2) A brief description of the proposed rates and charges under existing and proposed rate schedules and the expected changes, if any, in annual revenues; and
(3) A description of how the filed rate differs in rate level or rate structure from the rate schedule currently effective.
(c) Notice of filing. The notice of filing, suitable for publication in the
(1) The identification number or description of the rate schedule or contract;
(2) If the rate schedule includes changes in rates, the dollar amount and percent increase or decrease in rates;
(3) If the rate schedule includes changes other than rates, a brief description of the changes;
(4) A brief explanation of the reasons for any proposed change in the rate schedule;
(5) A statement whether interim approval of Bonneville Power Administration rates is requested;
(6) The proposed effective date of the rate schedule; and
(7) The proposed rate approval period.
(d) Rate schedules. A filed rate schedule, as defined in § 300.1(b)(7), must describe the following, as appropriate:
(1) The class of service to which each rate schedule will apply and service areas or zones which will be affected by the filed rate;
(2) The rate to be applied to capacity and energy services or other services;
(3) Special provisions, such as discounts, penalties, power factor adjustments, service interruptions, unauthorized overruns and other similar provisions which may affect the rate and charges; and
(4) The period during which the rates will be effective.
(e) Statement of revenue and related costs. Each filing shall include a statement which includes cost (if available) and revenue data for each class of service as specified in each rate schedule for the proposed period.
(f) Explanation of rate development process and supporting documents. (1) The Administrator must file the entire record on which the final decision establishing a rate scheduled is based.
(2) The Administrator must file a Record of Decision, if one is made, or an explanation of the rate development process, if a Record of Decision is not made. The Record of Decision or the explanation of the rate development process must include:
(i) A discussion of issues raised by customers or the public and how such issues were resolved;
(ii) A discussion of all statutory, regulatory, or other requirements which governed the Administrator’s decision;
(iii) A description of any methodology used for determining revenue requirements and for developing appropriate rate structures;
(iv) A list identifying all documents submitted for Commission consideration; and
(g) Certification. The Administrator must file a statement certifying that the rate is consistent with applicable laws and that it is the lowest possible rate consistent with sound business principles.
(h) Additional filing requirements. (1) The Administrator must file with the Commission any other information relevant to the Commission’s ratemaking decision.
(2) The Administrator must file any other information requested by the Office of Energy Market Regulation as needed for Commission analysis of the rate filing.
§ 300.11 Technical support for the rate schedule.
(a) Filing requirement. The Administrator must submit, in conjunction with any application under § 300.10, the technical support data described under paragraph (b) of this section and the analysis of data described under § 300.12 of this subpart.
(b) Data—(1) Statement A—Sales and Revenues. Statement A must include:
(i) Sales and revenues for each rate schedule for the last five years of the historic period, as defined in section 300.1(b)(3);
(ii) For the rate test period, the estimated annual sales and revenues for the existing and each proposed rate schedule, including a separate aggregation of any revenues from sources not covered by the rate schedule according to general classifications of such revenues; and
(iii) Brief explanations of how sales and revenue estimates are prepared and explanations of any changes in sales or revenues during the last five years of the historic period.
(2) Statement B—Power Resources. Statement B must contain a list of the capacity and energy resources for the last five years of the historic period and for the rate test period, used to support the sales and revenues figures contained in Statement A. The statement should identify resources according to the powerplant and any purchase or exchange agreement.
(3) Statement C—Capitalized investments or costs. (i) Statement C must account for all capitalized investments to be repaid from power revenues.
(ii) The statement shall include a listing, by year, of the following:
(A) All initial investments and additions to plant, including interest during construction, that produced revenue during the historic period or are expected to produce revenue during the rate test period;
(B) Capitalized deferred expenses; and
(C) Replacements made during the historic period and replacements projected to be made during the balance of the repayment period.
(iii) For each such investment, the statement shall specify:
(A) Whether the investment is an initial investment, an addition, a replacement, or a capitalized deferred annual expense;
(B) The date the investment was made;
(C) The year in which repayment is due to be completed;
(D) Whether the investment was financed through the issuance of revenue bonds, the appropriate interest rate, and the terms and conditions for such bonds; and
(E) The authority or administrative procedure used for the adoption of such interest rate.
(iv) If available, the amount repaid on each investment to date must be stated, except that if repayment on individual investments is not recorded, the amount repaid to date on each group of investments having common interest rates should be stated.
(v) For each year, the sum of unpaid individual investments or the unpaid portion of interest groups shown above must equal the unamortized investment shown in the power repayment study for that year.
(vi) The statement must describe the methods used to forecast replacements and the price level used to estimate replacement costs.
(4) Statement D—Interest Expenses; Repayment of Investments and Debt Capital. (i) For each capitalized investment and cost listed in Statement C, Statement D must describe, by interest group:
(A) The total unpaid balance outstanding at the end of the historic period;
(B) Payments made on principal and interest during each of the last five years of the historic period; and
(C) Annual payments expected to be made through the cost evaluation period.
(ii) The statement must describe how the interest expense was determined for each type of investment and include examples of such computations.
(5) Statement E—Operation, Maintenance and Other Annual Expenses. Statement E must contain, for the last five years of the historic period and for the rate test period, as appropriate, a tabulation of actual and projected operation and maintenance, administrative and general, purchased power, wheeling, and any other expenses, other than interest. Statement E must:
(i) List expenses for each individual source, if purchased power and other similar expenses are derived from more than one source;
(ii) Explain any significant deviations from trends in expenses or any extraordinary expenses; and
(iii) Explain the price level used for estimating expenses.
(6) Statement F—Cost Allocations. (i) Statement F must contain, for each multiple-purpose reservoir project, unit, division, or system, a table or other summary showing total investment costs, the total annual operation and maintenance costs, and the allocation of all such costs among the various authorized purposes.
(ii) The statement must show the amount of power costs suballocated to irrigation functions, any changes from previous allocations, and the procedure used in allocating such costs. Currently valid allocations previously submitted to the Commission need not be furnished, if referenced.
§ 300.12 Analysis of supporting data.
(a) An analysis of the data provided under § 300.11 must be supported by an appropriate methodology developed by the Administrator.
(b) Revenue recovery study. (1) A study must be provided which supports the filed rate and charges, including a narrative statement that explains how the rates and charges meet the objective of recovering the revenue necessary to repay the Federal investment and other costs in a reasonable period of time.
(2) Any Power Repayment Study (PRS) submitted for this purpose must be developed using currently approved rates for estimating future revenues. If the filed rates differ from the current rates, the Administrator must provide a PRS which uses the level of revenues produced by the proposed rates. Unless otherwise required by statute, a PRS must contain only those investments in plant which will be in commercial operation during the proposed rate approval period, except replacements. Forecasts of costs beyond the rate test period must be based on conditions prevailing during the period, unless unusual circumstances warrant otherwise.
(3) A PRS must include, but need not be limited to, those items listed below:
(i) Operating revenues;
(ii) Operating expenses;
(iii) Interest expense;
(iv) Investment placed in service (using totals if the supporting statement annually shows a breakdown into the appropriate subcategories under each major heading), including the initial project, additions, replacements, and the total investment;
(v) Investment amortized;
(vi) Remaining unamortized investment;
(vii) Allowable unamortized investment (using totals if the supporting statement annually shows a breakdown into the appropriate subcategories under each major heading), including initial project, additions, replacements, and total investment;
(viii) Irrigation investment assigned to be repaid from power revenues (using totals if the supporting statement annually shows a breakdown into the appropriate subcategories under each major heading), including irrigation investment assigned to power, investment repaid, remaining unpaid investment, and allowable unpaid investment; and
(ix) Cumulative status of repayment.
(c) Cost of service study. For any project or system which provides more than one class of service for which differing rates are proposed, a cost of service study, if available, must be provided which shows how the costs of providing each service have been determined. If rates and charges have not been formulated on a cost related basis, the basis for each rate or charge should be explained.
§ 300.13 Waiver of filing requirements.
The Administrator must request waiver of any requirement of this subpart if an application that does not fully comply with that requirement is not to be considered deficient. The request must state the Administrator’s reasons for such noncompliance and show good cause for any waiver.
§ 300.14 Filings under section 7(k).
Any application for Commission review and approval of a rate or rate schedules established by the Administrator of the Bonneville Power Administration pursuant to section 7(k) of the Pacific Northwest Electric Power Planning and Conservation Act must be filed in compliance with the provisions of § 35.13(a)(2) of part 35 of this chapter and with the provisions of this part, and must include the classifications, practices, rules and regulations affecting the rate and charges and all contracts which in any manner affect or relate to such rate, charges, classifications, services, rules, regulations, or practices. However, such classifications, practices, rules, regulations or contracts which may affect or relate to rates will not be subject to Commission approval unless they are determined to be rates or rate schedules.
Subpart C—Commission Rate Review and Approval
§ 300.20 Interim acceptance and review of Bonneville Power Administration rates.
(a) Opportunity to comment. The Commission will publish in the
(b) Action on request for interim rate acceptance—(1) Deficient applications. Upon receipt of an application that does not comply with the requirements of this part, the Commission may:
(i) Accept the application and order the rate schedule into effect on an interim basis, effective on the date requested by the Administrator or at such time as the Commission may otherwise order, on the condition that any deficiencies in the filing are corrected by the Administrator to the satisfaction of and within such time specified by the Director of the Office of Energy Market Regulation; or
(ii) Deny the Administrator’s interim rate request and reject the application, if the Commission determines that the Administrator’s application:
(A) Is patently deficient with respect to the filing requirements of this part; or
(B) Fails to comply with the applicable provisions of the Northwest Power Act or such other Acts as may be applicable.
(2) Applications that are in compliance. Upon receipt of an application that complies with the requirements of this part, the Commission may:
(i) Order the rate schedule into effect on an interim basis, effective on the date requested by the Administrator or at such time as the Commission may otherwise order; or
(ii) Deny the Administrator’s interim rate request and review the application for final confirmation and approval of the rate schedule pursuant to the provisions of this part.
(c) Condition of acceptance. Any rate schedule the Commission allows to become effective on an interim basis under paragraph (b) of this section is subject to refund with interest.
(d) Notice of action on interim approval. The Commission will publish in the
§ 300.21 Final confirmation and approval.
(a) Opportunity to comment and intervene. (1) The Commission will publish notice in the
(i) To submit initial and reply comments on any filing made under subpart B; and
(ii) To intervene in any proceeding held on such filing.
(2) With respect to the Bonneville Power Administration:
(i) Such notice will also give interested persons an opportunity to comment on whether it is necessary to hold a hearing on non-regional rates under section 7(k) of the Northwest Power Act and the issues to be resolved at such hearing.
(ii) This notice may be part of any Commission order granting interim approval under § 300.20 of this part.
(b) Proceedings under section 7(k). For the Bonneville Power Administration, the Commission will publish a separate order if it determines that a hearing is necessary under section 7(k) of the Northwest Power Act. This order will, if appropriate, delineate the issues to be resolved at such hearing. Such hearing will be held in accordance with the procedures established for ratemaking by the Commission pursuant to the Federal Power Act.
(c) Standards of review for the Bonneville Power Administration—(1) Rates under section 7(a). The Commission will review any rate established by the Administrator under section 7(a) of the Northwest Power Act for compliance with the following standards:
(i) The rates must be sufficient to ensure repayment of the Federal investment in the Federal Columbia River Power System over a reasonable number of years after first meeting the Administrator’s other costs.
(ii) The rates must be based upon the Administrator’s total system costs.
(iii) With respect to transmission rates, the rates must equitably allocate the costs of the Federal transmission system between Federal and non-federal power utilizing such system.
(2) Rates under section 7(k). The Commission will review any rate established by the Administrator under section 7(k) of the Pacific Northwest Electric Power Planning and Conservation Act for compliance with the requirements of the Bonneville Project Act, the Flood Control Act of 1944, and the Federal Columbia River Transmission System Act.
(d) Standards of review for other power marketing administrations. The Commission will review the rates of the Alaska, Southeastern, Southwestern, and Western Area Power Marketing Administrations in accordance with the terms of any delegation made by the Secretary of Energy.
(e) Action on request for final confirmation and approval of rates. Filed rates will be considered for final confirmation and approval if the relevant filing complies with the filing requirements of subpart B of these regulations. The Commission may take any of the following actions:
(1) Confirm and approve the rate schedules for the period beginning with the date such rates where placed in effect on an interim basis or the effective date requested in the application to the expiration date requested in the application but not to exceed a five-year period, or for such lesser period, as the Commission deems appropriate;
(2) Remand the filing for further development of the record to support the filed rate schedules;
(3) Order an evidentiary hearing if there are questions of fact which can not be resolved from the record or through staff evaluation;
(4) Disapprove the filed rates; or
(5) Take such other action that the Commission considers appropriate.
(f) Procedures upon disapproval. If the Commission disapproves the rates, the Administrator will be provided a 120-day period, or other period as the Commission may deem appropriate, to prepare substitute rates that resolve the Commission’s concerns. If the filed rates have been approved on an interim basis, the rates will continue in effect on an interim basis until the Commission takes final action.
(g) Refund and interest—(1) Refund. If a rate collected by any power marketing administration on an interim basis exceeds the rate which is confirmed and approved by the Commission as a final rate, the Administrator, pursuant to any conditions established by the Commission, must refund with interest any portion of the rate increase collected during the interim period which exceeds the final rate. The Administrator may make refunds by means of a net energy billing which reflects the value of any overcharge or other appropriate methods.
(2) Interest. Except as otherwise provided by the Commission, the Administrator must compute any amount of interest based on the revenues collected subject to refund and required to be refunded under this paragraph by using:
(i) With respect to the rates of the Bonneville Power Administration, the rate of interest or a weighted average of all rates of interest charged to the Bonneville Power Administration by the U.S. Treasury during the period for which the computation is made;
(ii) With respect to the rates of other Power Marketing Administrations, the rates of interest computed in accordance with the formula contained in DOE Order No. RA 6120.2, available from the Department of Energy (Office of Power Marketing Coordination) and the Power Marketing Administrations.
(h) Notice of action on final approval. The Commission’s Secretary will publish in the
PART 301—AVERAGE SYSTEM COST METHODOLOGY FOR SALES FROM UTILITIES TO BONNEVILLE POWER ADMINISTRATION UNDER NORTHWEST POWER ACT
§ 301.1 Applicability.
The regulations in this part apply to the sales of electric power by any Utility to the Bonneville Power Administration (Bonneville) under section 5(c) of the Pacific Northwest Electric Power Planning and Conservation Act (Northwest Power Act). 16 U.S.C. 839c(c).
§ 301.2 Definitions.
For purposes of this section, the following definitions apply:
Account(s). The Accounts prescribed in the Commission’s Uniform System of Accounts in part 101 of this chapter.
Appendix 1. Appendix 1 is the electronic form on which a Utility reports its Contract System Cost, Contract System Load, and other necessary data to Bonneville for the calculation of the Utility’s Average System Cost.
Average System Cost (ASC). The rate charged by a Utility to Bonneville for the agency’s purchase of power from the Utility under section 5(c) of the Northwest Power Act for each Exchange Period, and the quotient obtained by dividing Contract System Cost by Contract System Load. 16 U.S.C. 839c(c).
Average System Cost delta (ASC delta). The change in a Utility’s ASC during the Exchange Period resulting from the inclusion in the Average System Cost forecast model of costs, loads, revenues, and other information related to the commercial operation of a major resource addition or reduction that was identified in the Utility’s ASC filing.
Average System Cost forecast model (ASC forecast model). The model Bonneville uses to escalate a Utility’s costs, revenues, and other information contained in the Appendix 1 to calculate the Exchange Period ASC.
Average System Cost review process (ASC review process). The administrative proceeding conducted before Bonneville under Bonneville’s ASC review procedures in which a Utility’s ASC is determined.
Base Period. The calendar year of the most recent Form 1 data.
Base Period ASC. The ASC determined in the Review Period using the Utility’s Base Period data and additional specified data.
Contract High Water Mark (CHWM). The average MW amount used to define access to Tier 1 Priced-Power. CHWM is equal to the adjusted historical load for each customer proportionately scaled to Tier 1 System Resources and adjusted for conservation achieved. The CHWM is specified in each eligible customer’s CHWM Contract.
Commission. Federal Energy Regulatory Commission.
Consumer-owned Utility. A public body or cooperative that is eligible to purchase preference power from Bonneville under section 5(b) of the Northwest Power Act. 16 U.S.C. 839c(b).
Contract System Cost. The Utility’s costs for production and transmission resources, including power purchases and conservation measures, which costs are includable in, and subject to, the provision of Appendix 1. Under no circumstances will Contract System Cost include costs excluded from ASC by section 5(c)(7) of the Northwest Power Act. 16 U.S.C. 839c(c)(7).
Contract System Load. The total regional retail load included in the most recently filed FERC Form 1 or, for a Consumer-owned Utility, the total retail load from the most recent annual audited financial statement, as adjusted pursuant to the ASC methodology.
Direct Analysis. An analysis, including supporting documentation, prepared by the Utility that assigns the costs, debits, credits, and revenues in an Account to the Production, Transmission, and/or Distribution/Other functions of the Utility.
Escalator. A factor used to adjust an Account in the Base Period ASC filing to the value for the period of the Exchange Period ASC.
Exchange Load. All residential, apartment, seasonal dwelling and farm electrical loads eligible for the Residential Exchange Program under the terms of a Utility’s Residential Purchase and Sales Agreement.
Exchange Period(s). The period during which a Utility’s Bonneville-approved ASC is effective for the calculation of the Utility’s Residential Exchange Program benefits. The initial Exchange Period under this ASC methodology is from October 1, 2008, through September 30, 2009. Subsequent Exchange Periods will be the period of time concurrent with Bonneville’s wholesale power rate periods beginning October 1 or, if not beginning October 1, then beginning on the effective date of Bonneville’s subsequent wholesale power rate periods.
Exchange Period ASC. The Base Period ASC escalated to a year(s) consistent with the Exchange Period.
FERC Form 1. The annual filing submitted to the Federal Energy Regulatory Commission, required by 18 CFR 141.1.
Functionalization. The process of assigning a Utility’s costs, debits, credits, and revenues in an Account to the Production, Transmission, and/or Distribution/Other functions of the Utility.
Global Insight. The company that provides the escalation factors identified in § 301.4(a)(3) that are used in the ASC forecasting model, or the successor or replacement of that company, as determined by Bonneville.
Jurisdiction. The service territory of the Utility within which a particular regulatory body has authority to approve the Utility’s retail rates. Jurisdictions must be within the Pacific Northwest region as defined in section 3(14) of the Northwest Power Act. 16 U.S.C. 839a(14).
Labor Ratios. The ratios that assign costs on a pro rata basis using salary and wage data for Production, Transmission, and Distribution/Other functions included in the Utility’s most recently filed FERC Form 1. For Consumer-owned Utilities, comparable data will be utilized based on the cost-of-service study used as the basis for retail rates at the time of review.
Net Requirements. The amount of Federal power that a Consumer-owned Utility is entitled to purchase from Bonneville under section 5(b) of the Northwest Power Act. 16 U.S.C. 839c(b).
New Large Single Load. That load defined in section 3(13) of the Northwest Power Act, and determined by Bonneville as specified in power sales contracts and Residential Purchase and Sales Agreements with its Regional Power Sales Customers. 16 U.S.C. 839a(13).
Priority Firm Power. Priority Firm Power is electric power (capacity and energy) that Bonneville will make continuously available for direct consumption or resale to public bodies, cooperatives, and Federal Agencies (under the Priority Firm Preference rate) and to Utilities participating in the Residential Exchange Program (under the Priority Firm Exchange rate). Utilities participating in the Residential Exchange Program under section 5(c) of the Northwest Power Act may purchase Priority Firm Power under their Residential Purchase and Sales Agreements with Bonneville. Priority Firm Power is not available to serve New Large Single Loads. Deliveries of Priority Firm Power may be reduced or interrupted as permitted by the terms of the Utilities’ power sales contracts and/or Residential Purchase and Sales Agreements with Bonneville.
Public Purpose Charge. Any charge based on a Utility’s total retail sales in a Jurisdiction that is provided to independent entities or agencies of state and local governments for the purpose of funding within the Utility’s service territory one or both of the following:
(a) Conservation programs in lieu of Utility conservation programs; or
(b) Acquisition of renewable resources.
Rate Period. The period during which Bonneville’s wholesale power rates are effective. The period is coincident with the Exchange Period.
Rate Period High Water Mark (RHWM). The amount used to define each customer’s eligibility to purchase Tier 1 Priced Power for the relevant Rate Period, subject to the customer’s Net Requirement expressed in average megawatts (aMW). RHWM is equal to the customer’s CHWM as adjusted for changes in Tier 1 System Resources. The RHWM is determined for each eligible customer in the RHWM Process preceding each Bonneville wholesale power rate case.
Rate Period High Water Mark Process (RHWM Process). The process or processes where each eligible Consumer-owned Utility RHWM is determined.
Regional Power Sales Customer. Any entity that contracts directly with Bonneville for the purchase of power under sections 5(b) (16 U.S.C. 839c(b)), 5(c) (16 U.S.C. 839c(c)), or 5(d) (16 U.S.C. 839c(d)) of the Northwest Power Act for delivery in the Pacific Northwest region as defined by section 3(14) of the Northwest Power Act. 16 U.S.C. 839a(14).
Residential Purchase and Sales Agreement. The contract under section 5(c) of the Northwest Power Act between Bonneville and a Utility that defines and implements the power purchase and sale under the Residential Exchange Program.
Review Period. The period of time during which a Utility’s Appendix 1 is under review by Bonneville. The Review Period begins on or about June 1, and ends on or about November 15 of the fiscal year prior to the fiscal year Bonneville implements a change in wholesale power rates.
Regulatory Body. A state commission, Consumer-owned Utility governing body, or other entity authorized to establish retail electric rates in a Jurisdiction.
RHWM Exchange Load. The Exchange Load as determined in section 20 of the Residential Purchase and Sales Agreement.
RHWM System Resources. The Rate Period High Water Mark (RHWM) as calculated in section 4.2.1 of the Tiered Rates Methodology plus the resource amounts used in calculating a customer’s Contract High Water Mark (CHWM).
Tier 1 Priced-Power. Priority Firm Power as defined in Bonneville’s Tiered Rates Methodology.
Tier 1 System Resources. Resources as defined in Bonneville’s Tiered Rates Methodology.
Tiered Rates Methodology. The long-term methodology established by Bonneville for the determination of tiered wholesale power rates.
Utility. A Regional Power Sales Customer that has executed a Residential Purchase and Sales Agreement.
§ 301.3 Filing procedures.
(a) Bonneville’s ASC review procedures. The procedures established by Bonneville’s Administrator provide the filing requirements for all Utilities that file an Appendix 1 with Bonneville. Utilities must file Appendix 1s, ASC forecast models, and other required documents with Bonneville in compliance with Bonneville’s ASC review procedures.
(b) Exchange Period. The Exchange Period will be equal to the term of Bonneville’s Rate Period. ASCs will change during the Exchange Period only for the reasons provided in § 301.4.
§ 301.4 Exchange Period Average System Cost determination.
(a) Escalation to Exchange Period. (1) This section describes the method Bonneville will use to escalate the Base Period ASC to and through the Exchange Period to calculate the Exchange Period ASC.
(2) Bonneville will escalate the Bonneville-approved Base Period ASC to the midpoint of the fiscal year for a one-year Rate Period/Exchange Period, and to the midpoint of the two-year period for a two-year Rate Period/Exchange Period to calculate Exchange Period ASCs.
(3) For purposes of the escalation referenced in paragraph (a)(2) of this section, Bonneville will use the following codes in the ASC forecast model to calculate the Exchange Period ASCs:
(i) A&G—Administrative and General.
(ii) CACNT—Customer Account.
(iii) CD—Construction, Distribution Plant.
(iv) CONSTANT—Constant.
(v) CSALES—Customer Sales.
(vi) CSERVE—Customer Service.
(vii) COAL—Coal.
(viii) DMN—Distribution Maintenance.
(ix) DOPS—Distribution Operations
(x) HMN—Hydro Maintenance.
(xi) HOPS—Hydro Operations.
(xii) INF—Inflation.
(xiii) NATGAS—Natural Gas.
(xiv) NFUEL—Nuclear Fuel.
(xv) NMN—Nuclear Maintenance.
(xvi) NOPS—Nuclear Operations.
(xvii) OMN—Other Production Maintenance.
(xviii) OOPS—Other Production Operations.
(xix) SNM—Steam Maintenance.
(xx) SOPS—Steam Operations.
(xxi) TMN—Transmission Maintenance.
(xxii) TOPS—Transmission Operations.
(xxiii) WAGES—Wages.
(4) Table 1 identifies which codes from paragraph (a)(3) of this section apply to the line items and associated FERC Accounts in the Appendix 1. Bonneville will use Global Insight as the source of data for the escalation codes identified in paragraph (a)(3) of this section, except for the NATGAS and CONSTANT codes. For the NATGAS code identified in paragraph (a)(3)(xiii) of this section, Bonneville will calculate the escalation rate using Bonneville’s most current forecast of natural gas prices. The code CONSTANT in paragraph (a)(3)(iv) of this section indicates that no escalation to the Account will be made.
(5) Bonneville will base the costs of power products purchased from Bonneville on Bonneville’s forecast of prices for its products.
(6) Bonneville will escalate the Public Purpose Charge forward to the midpoint of the Exchange Period by the same rate of growth as total Contract System Load.
(7) If any of the escalators specified in paragraph (a) of this section are no longer available, Bonneville will designate a replacement source of such escalator(s) that, as near as possible, replicates the results produced by the prior escalator. If a replacement source is not available, Bonneville will use the INF escalation code identified in paragraph (a)(3)(xii) of this section as the replacement escalator.
(b) Calculation of sales for resale and power purchases—(1) Long-term and intermediate-term sales for resale and power purchases. Bonneville will use the INF escalation code identified in paragraph (a)(3)(xii) of this section to escalate long-term and intermediate-term (as defined by the Commission) firm purchased power costs and long-term and intermediate-term sales for resale revenues.
(2) Short-term sales for resale and power purchases. (i) The short-term purchases and short-term sales for resale for the Base Period will be used as the starting values. A Utility will be allowed to include new plant additions, and to use a utility-specific forecast for the price of purchased power and for the price of sales for resale in order to value purchased power expenses and sales for resale revenue to be included in the Exchange Period ASC.
(ii) Bonneville will use the following method to determine separate market prices to forecast short-term purchased power expenses and sales for resale revenues to calculate Exchange Period ASCs:
(A) The Utility’s average short-term purchased power price and short-term sales for resale price will be calculated for each year for the most recent three years of actual data (Base Period and prior two years).
(B) The midpoint between the Utility’s average short-term purchased power price and the average short-term sales for resale price will be calculated for each of the years in paragraph (b)(2)(ii)(A) of this section.
(C) The percentage spread around the Utility’s midpoint between the average short-term purchase power price and short-term sales for resale price will be calculated for each of the years identified in paragraph (b)(2)(ii)(A) of this section.
(D) A weighted average spread for the Utility’s most recent three years of actual data (Base Period and prior two years) will be calculated. The following weighting scale will be used:
(1) Three (3) times Base Period spread.
(2) Two (2) times (Base Period minus 1) spread.
(3) One (1) time (Base Period minus 2) spread.
(E) The Base Period midpoint calculated in paragraph (b)(2)(ii)(B) of this section will be escalated at the same rate as Bonneville’s electric market price forecast.
(F) The weighted average spread calculated in paragraph (b)(2)(ii)(D) of this section will be applied to the escalated midpoint price calculated in paragraph (b)(2)(ii)(E) of this section to determine the purchased power price and sales for resale price to value purchased power expenses and sales for resale revenues to be included in the Exchange Period ASC.
(iii) The method described in paragraph (b)(2)(ii) of this section will be used to forecast the electric market price for power purchases needed to meet load growth not met by major resource additions, and to forecast the electric market price for any additional surplus power sales resulting from major resource additions.
(c) Major resource additions and reductions and materiality thresholds. (1) During the Exchange Period, Bonneville will allow changes to a Utility’s ASC to account for major resource additions or reductions that are used to meet a Utility’s retail load. These changes, however, must meet the requirements of paragraph (c)(3) of this section and the materiality threshold described in paragraph (c)(4) of this section in order for Bonneville to allow an ASC to change. The ASC reflecting the major resource addition or reduction will be determined by Bonneville in the ASC review process during the Review Period.
(2) For major resource additions, the change to ASC will become effective when the resource begins commercial operation, or power is received under the purchased power contract. For major resource reductions, the change to ASC will become effective when the resource is sold, retired, or transferred.
(3) A major resource addition or reduction must be related to one or more of the following categories to be eligible for consideration as a major resource:
(i) Production or generating resource investments;
(ii) Transmission investments;
(iii) Long-term generating contracts;
(iv) Pollution control and environmental compliance investments relating to generating resources;
(v) Long-term transmission contracts;
(vi) Hydroelectric relicensing costs and fees; and
(vii) Plant rehabilitation investments.
(4) Major resource additions or reductions that meet the criteria identified in paragraph (c)(3) of this section will be allowed to change a Utility’s ASC within an Exchange Period provided that the major resource addition or reduction results in a 2.5 percent or greater change in a Utility’s Base Period ASC. Bonneville will allow a Utility to submit stacks of individual resources that, when combined, meet the 2.5 percent or greater materiality threshold, provided, however, that each resource in the stack must result in a change to the Utility’s Base Period ASC of 0.5 percent or more.
(5) At the time the Utility submits its Appendix 1 filing, the Utility will provide its forecast of major resource additions or reductions and all associated costs. The forecast will cover the period from the end of the Base Period to the end of the Exchange Period.
(6) Bonneville will calculate new transmission wheeling revenues associated with new transmission investment using the following formula:
(7) The forecast of major resource additions or reduction costs to be included in the Utility’s Exchange Period ASC will be reviewed by Bonneville in the ASC review process that is conducted during the Review Period.
(8) All major resources included in an ASC calculation prior to the start of the Exchange Period will be projected forward to the midpoint of the Exchange Period.
(9) For each major resource addition or reduction that is forecasted to occur during the Exchange Period, Bonneville will calculate the difference in ASC between the ASC without the major resource addition or reduction and the ASC with the major resource addition or reduction (ASC delta) at the midpoint of the Exchange Period.
(10) Once the major resource addition or reduction becomes effective, as determined by paragraph (c)(2) of this section, Bonneville will add the ASC delta to the Utility’s existing ASC to determine its new ASC.
(11) For purposes of calculating ratios with Distribution Plant, Bonneville will escalate the Base Period average per-MWh cost of Distribution Plant forward to the midpoint of the Exchange Period, and use the escalated average cost to determine the distribution-related cost of meeting load growth since the Base Period.
(12) Bonneville will escalate the cost of General Plant, Accounts 389 through 399.1, forward to the midpoint of the Exchange Period by calculating the ratio of each Account’s value in the Base Period to the sum of Production, Transmission, and Distribution plant values in the Base Period, and then multiplying the Base Period ratio times the forecasted value for Production, Transmission, and Distribution plant.
(13) Bonneville will issue procedural rules to ensure the confidentiality of information provided by Utilities regarding any major resource additions or reductions as part of its review process. Bonneville will provide parties with an opportunity to comment on the rules prior to their implementation in the review process. Failure to provide needed information may result in exclusion of the related costs from the Utility’s ASC. However, load growth will be assumed to be met with purchases in the wholesale market, as described in paragraph (e) of this section. If the Utility fails to supply confidential resource data, it loses the difference between the cost of the resource and the price of electricity in the wholesale market.
(d) Forecasted Contract System Load and Exchange Load. All Utilities are required to provide a forecast of their Contract System Load and associated Exchange Load, as well as a current distribution loss analysis as described in Endnote e of Appendix 1, with their Appendix 1 filings. The load forecast for Contract System Load and Exchange Load will start with the Base Period and extend through four (4) years after the Exchange Period. The load forecast for Contract System Load and Exchange Load will be provided on a monthly basis for the Exchange Period.
(e) Load growth not met by major resource additions. All forecast load growth not met by major resource additions will be met by purchased power at the forecasted utility-specific, short-term purchased power price.
(1) The Utility’s forecast Load Growth will be met with electric market purchases priced at the Utility’s forecast short-term purchased power price as determined in paragraph (b) of this section unless the Utility forecasts major resource additions.
(2) In the event of major resource additions, forecast Load Growth will be met by the major resource(s). If the major resource is less than total forecast load growth, the unmet Load Growth will be met with electric market purchases priced at the Utility’s forecast short-term purchased power price.
(3) In the event the power provided by a major resource exceeds the Utility’s forecast Load Growth, the excess power will be used to reduce the Utility’s short-term purchases. If short-term power purchases are reduced to zero, any remaining power will be sold as surplus power at the short-term sales for resale price as determined in paragraph (b) of this section.
(f) Changes to service territory. In the event a Utility forecasts that it will acquire a new service territory, or lose a portion of its existing service territory, and the gain or loss of that territory results in a 2.5 percent or greater change to the Utility’s Base Period ASC, the Utility must file two Appendix 1 filings with Bonneville as follows:
(1) First, a Base Period ASC that does not reflect the acquisition or loss of service territory; and
(2) Second, a Base Period ASC that incorporates the following changes:
(i) A forecast of the increase or reduction in Contract System Load associated with the acquisition or reduction in service territory.
(ii) A forecast of the increase or reduction in Contract System Cost associated with the acquisition or reduction of the service territory.
(iii) A forecast of capital and operating cost increases or reductions associated with the change in service territory.
(iv) A forecast of the changes in purchased power expenses, sales for resale revenues, and other debits or credits based on the changes in the service territory.
(3) Because the date of the actual change to the Utility’s service territory could differ from the forecast date used to determine the ASC during the Review Period, Bonneville will not adjust the Utility’s ASC until the change in service territory takes place.
(g) ASC determination for Consumer-owned Utilities that elect to execute Regional Dialogue High Water Mark contracts. For Consumer-owned Utilities that elect to execute Regional Dialogue CHWM contracts, Bonneville will use the following approach:
(1) Use the RHWM System Resources as determined in the Tiered Rates Methodology (TRM) process.
(2) Determine the RHWM Exchange Load.
(3) Calculate the Utility’s Contract System Cost as described in the ASC Methodology.
(4) Determine the fully allocated cost of resources used to meet Contract System Load that is not met by:
(i) The lesser of the Utility’s RHWM or Forecast New Requirement, plus
(ii) Existing Resources for CHWM (as defined in the Tiered Rates Methodology).
(5) RHWM Contract System Cost = Contract System Cost minus fully allocated cost of resources (from paragraph (g)(4) of this section).
(6) RHWM Average System Cost = RHWM Contract System Cost (from paragraph (g)(5) of this section)/RHWM System Resource (from paragraph (g)(1) of this section).
(h) Filing of Appendix 1. Utilities must file an Appendix 1, including ASC information, by June 1 of each year, as required in § 301.3, for Bonneville’s review and determination of a Base Period ASC. Utilities will file multiple, contingent, Base Period ASC filings to reflect changes to service territories as required in paragraph (f) of this section.
§ 301.5 Changes in Average System Cost methodology.
(a) The Administrator, at his or her discretion, or upon written request from three-quarters of the utilities that are parties to contracts authorized by section 5(c) of the Northwest Power Act, or from three-quarters of Bonneville’s preference customers, or from three-quarters of Bonneville’s direct-service industrial customers may initiate a consultation process as provided in section 5(c) of the Northwest Power Act. After completion of this process, Bonneville’s Administrator may file the new ASC methodology with the Commission.
(b) The Administrator will not initiate any consultation process until one year of experience has been gained under the then-existing ASC methodology, that is, one year after the then-existing ASC methodology is adopted by Bonneville and approved by the Commission, through interim or final approval, whichever occurs first.
(c) The Administrator may, from time to time, issue interpretations of the ASC methodology. The Administrator also may modify the functionalization code of any Account to comply with the limitations identified in sections 5(c)(7)(A)–(C) of the Northwest Power Act or to conform to Commission revisions to the Uniform System of Accounts.
§ 301.6 Appendix 1 instructions.
(a) Appendix 1 is the form on which a Utility reports its Contract System Cost, Contract System Load, and other necessary data for the calculation of ASC. Appendix 1 is an electronic template consisting of seven schedules and several supporting files that must be completed by the Utility in accordance with these instructions and with the provisions of the endnotes following the schedules.
(b) Appendix 1 filings must be accompanied by an attestation statement of the Chief Financial Officer of the Utility or other responsible official who possesses the financial and accounting knowledge necessary to complete the attestation statement.
(c) The primary source of data for the Investor-owned Utilities’ Appendix 1 filings is the Utility’s prior year FERC Form 1 filings with the Commission. Any items not applicable to the Utility must be identified.
(d) For Consumer-owned Utilities that do not follow the Commission’s Uniform System of Accounts, filings must include reconciliation between Utility Accounts and the items allowed as Contract System Cost. In addition, the cost-of-service report must be reviewed by an independent accounting or consulting firm, and must be accompanied by a report from that independent accounting or consulting firm that outlines the review work that was performed in preparing the cost-of-service report along with an assurance statement that the information contained in the cost-of-service report is presented fairly in all material respects.
(e) The Appendix 1 template is available electronically at http://www.bpa.gov/corporate/finance/ascm/. The primary schedules are:
(1) Schedule 1: Plant Investment/Rate Base
(2) Schedule 1A: Cash Working Capital
(3) Schedule 2: Capital Structure and Rate of Return
(4) Schedule 3: Expenses
(5) Schedule 3A: Taxes
(6) Schedule 3B: Other Included Items
(7) Schedule 4: Average System Cost
(f) The filing Utility must reference and attach work papers, documentation and other required information that support costs and loads, including details of allocation and functionalization. All references to the Commission’s Accounts are to the Commission’s Uniform System of Accounts, as amended by subsequent Commission actions. The costs includable in the attached schedules are those includable by reason of the definitions in the Commission’s Accounts. If the Commission’s Accounts are later revised or renumbered, any changes will be incorporated into the Appendix 1 by reference, except to the extent Bonneville determines that a particular change results in a change in the type of costs allowable for Residential Exchange Program purposes. In that event, Bonneville will address the changes, including escalation rules, in its review process for the following Exchange Period.
(g) Bonneville may require a Utility to account for all transactions with affiliated entities as though the affiliated entities were owned in whole or in part by the Utility, if necessary, to properly determine and/or functionalize the Utility’s costs.
(h) A Utility operating in more than one Pacific Northwest Jurisdiction must file one Appendix 1.
(i)(1) A Utility operating in a Jurisdiction within the Pacific Northwest and within Jurisdictions outside the Pacific Northwest must allocate its total system costs among its Jurisdictions within the Pacific Northwest and outside the Pacific Northwest in accord with the same allocation methods and procedures used by the Regulatory Body(ies) to establish Jurisdictional costs and resulting revenue requirements. The Utility’s Appendix filing must include details of the allocation.
(2) The allocation must exclude all costs of additional resources used to meet loads outside the Pacific Northwest, as required by section 5(c)(7) of the Northwest Power Act. All schedule entries and supporting data must be in accord with Generally Accepted Accounting Principles and Practices as these principles and practices apply to the electric utility industry.
(j) A Utility must file an attestation statement with each Appendix 1 filing and supporting documentation for each Review Period.
§ 301.7 Average System Cost methodology functionalization.
(a) Functionalization of each Account included in a Utility’s ASC must be according to the functionalization prescribed in Table 1, Functionalization and Escalation Codes. Direct analysis on an Account may be performed only if Table 1 states specifically that a Utility may perform a direct analysis on the Account, with the exception of conservation costs. Utilities will be able to functionalize all conservation-related costs to Production, regardless of the Account in which they are recorded. The direct analysis must be consistent with the directions provided in this section.
(b) Functionalization codes.
(1) DIRECT—Direct Analysis.
(2) PROD—Production.
(3) TRANS—Transmission.
(4) DIST—Distribution/Other.
(5) PTD—Production, Transmission, Distribution/Other Ratio.
(6) TD—Transmission, Distribution/Other Ratio.
(7) GP—General Plant Ratio.
(8) GPM—General Plant Maintenance Ratio.
(9) PTDG—Production, Transmission, Distribution/Other, General Plant Ratio.
(10) LABOR—Labor Ratio.
(c) Functionalization requirements.
(1) Functionalization of certain Accounts may be based on Direct Analysis or with a default ratio associated with that specific Account as shown in Table 1. Once a Utility uses a specific functionalization method for an Account, the Utility may not change the functionalization method for that Account without prior written approval from Bonneville.
(2) The Utility must submit with its Appendix 1 all work papers, documents, or other materials that demonstrate that the functionalization under its Direct Analysis assigns costs, revenues, debits or credits based upon the actual and/or intended functional use of those items. Failure to submit the documentation will result in the entire account being functionalized to Distribution/Other, or Production, or Transmission, as appropriate.
(d) Functionalization methods. (1) Direct analysis, if allowed or required by Table 1, assigns costs, revenues, debits and credits to the Production, Transmission, and/or Distribution/Other function of the Utility. The only exception to this requirement is for Accounts that include conservation-related costs. Subject to the provisions of paragraph (d)(4) of this section, a Utility may conduct a Direct Analysis on any Account that contains conservation-related costs. The Direct Analysis performed by a Utility is subject to Bonneville review and approval.
(2) Bonneville will not allow a Utility to use a combination of Direct Analysis and a prescribed functionalization method for the same Account. The Utility can develop and use a functionalization ratio, or use a prescribed functionalization method, if the Utility, through Direct Analysis, can justify how the ratio reflects the functional nature of the costs, revenues, debits, or credits included in any Account.
(3) A Utility that wishes to include advertising and promotion costs related to conservation will use Direct Analysis.
(4) If a Utility records conservation costs in an Account that is functionalized to Distribution/Other, the Utility will identify and document the conservation-related costs included in the Account, and the balance of the costs will be functionalized to Distribution/Other. The presence of conservation-related costs in an Account does not authorize the Utility to perform a Direct Analysis on the entire Account. This option allows a Utility to assign conservation costs in the specified Account to Production based on analysis and support from the Utility that demonstrates the cost assignment is appropriate. The Utility must submit with its ASC filing all work papers, documents, and other materials that demonstrate the functionalization contained in its Direct Analysis and assign costs based upon the actual and/or intended functional use of those items. Failure to submit the documentation will result in the entire Account being functionalized to Distribution/Other for all schedules with the exception of items included in Schedule 3B, Other Included Items, where certain Accounts must be functionalized to Production as appropriate.
Table 1 to Part 301—Functionalization and Escalation Codes
Appendix 1 to Part 301—ASC Utility Filing Template
SUBCHAPTERS M–O [RESERVED]
SUBCHAPTER P—REGULATIONS UNDER THE INTERSTATE COMMERCE ACT
PART 340—RATE SCHEDULES AND TARIFFS
§ 340.1 Suspended rate schedules; procedure; refund requirement; administered by the Federal Energy Regulatory Commission.
(a) Effectiveness of suspended rate schedules. If a rate suspension proceeding initiated under section 15(7) of the Interstate Commerce Act has not been concluded and an order has not been issued by the Commission at the expiration of the suspension period, the proposed rate, charge, classification, or service shall go into in effect so long as the pipeline company complies with all of the requirements of this section.
(b) Recordkeeping. Any pipeline company whose proposed rates or charges were suspended and have gone into effect pending final order of the Commission pursuant to section 15(7) of the Interstate Commerce Act shall keep accurate accounts in detail of all amounts received by reason of the rates or charges made effective as provided in the Commission’s order, for each billing period, including the following information by billing period, and by shipper:
(1) The monthly billing determinants of petroleum or petroleum by-products transported to each consignee under the suspended tariffs;
(2) The revenues which would result from such transportation services if they were computed under the rates in effect immediately prior to the date the proposed change became effective, if applicable;
(3) The revenues resulting from such transportation services as computed under the proposed increased rates or charges that became effective after the suspension period; and
(4) The difference between the revenues computed in paragraphs (b)(2) and (3) of this section, if applicable.
(c) Refunds. (1) Any pipeline company that collects charges pursuant to this section shall refund at such time, in such amounts, and in such manner as may be required by final order of the Commission, the portion of any rates and charges found by the Commission in that proceeding not to be justified, together with interest as required in paragraph (c)(2) of this section.
(2) Interest shall be computed from the date of collection until the date refunds are made as follows:
(i) At an average prime rate for each calendar quarter on amounts held on or after February 11, 1983. The applicable average prime rate for each calendar quarter shall be the arithmetic mean, to the nearest one-hundredth of one percent, of the prime rate values published in the Federal Reserve Bulletin, or in the Federal Reserve’s “Selected Interest Rates” (Statistical Release G. 13) for the most recent three months preceding the beginning of the calendar quarter; and
(ii) The interest required to be paid under paragraph (c)(2)(i) of this section shall be compounded quarterly.
(3) Any pipeline company required to make refunds pursuant to this section shall bear all costs of such refunding.
(4) If any rate or charge described in paragraph (a) of this section that is found not to be justified by the Commission is shared between two or more pipeline companies, each pipeline company which shared in the unjustified rates or charges is required to refund to the pipeline company that published the tariff, not less than five days prior to the refund date ordered by the Commission under paragraph (c)(1) of this section,
(i) That portion of the unjustified rates or charges shared, and
(ii) The appropriate interest as required in paragraph (c)(2) of this section for the period during which the refundable amounts were held.
PART 341—OIL PIPELINE TARIFFS: OIL PIPELINE COMPANIES SUBJECT TO SECTION 6 OF THE INTERSTATE COMMERCE ACT
§ 341.0 Definitions; application.
(a) Definitions. (1) Carrier means an oil pipeline subject to the Commission’s jurisdiction under the Interstate Commerce Act.
(2) Concurrence means the agreement of a carrier to participate in the joint rates or regulations published by another carrier.
(3) Local rate means a rate for service over the lines or routes of only one carrier.
(4) Local tariffs means tariffs which contain only local rates.
(5) Joint rate means a rate that applies for service over the lines or routes of two or more carriers made by an agreement between the carriers, effected by a concurrence or power of attorney.
(6) Joint tariffs means tariffs which contain only joint rates.
(7) Posting or post means making current and proposed and tariffs suspended for more than a nominal period available on a carriers’ public Web site.
(8) Proportional rates means rates published to apply only to traffic having a prior transportation movement, a subsequent transportation movement, or both.
(9) Rule means any regulation or condition of service stated in the tariff which affects any rate or service provided by the carrier.
(10) Subscriber means a shipper or a person who regularly is furnished a copy of a particular tariff publication (including reissues and amendments) by the publishing carrier or agent.
(11) Tariff publication means all parts of a filed tariff, including revised pages, supplements and sections.
(12) Through rates means the total rates from point of origin to destination. They may be local rates, joint rates, or a combination of separately established rates.
(13) Section means an individual portion of a tariff that is tracked and accorded appropriate legal status (proposed, suspended, effective). A section is the smallest portion of a tariff that can be submitted as part of a tariff filing.
(b) General application. (1) Each carrier must publish, post, and file with the Commission tariff publications which contain in clear, complete, and specific form all the rules and regulations governing the rates and charges for services performed in accordance with the tariff. Tariffs must be published in a format that ensures the tariffs are readable and that their terms and conditions are easy to understand and apply.
(2) The Commission may reject, or may require modification, correction, or reissuance of, any tariff publication or other document not in compliance with the law.
(3) All tariffs filed on or after December 6, 1993 must conform to the regulations of this part. Tariffs which are on file as of that date will not have to be reissued solely to conform to this part.
(4) Each carrier must post and maintain a complete and current set of all proposed, current, and suspended tariff publications which it has issued or to which it is a party. The carrier must identify in its posted tariff files any tariff publication under suspension and investigation. Each carrier must afford inquirers reasonable opportunity to examine its posted tariff files.
(a) General rule. Filings of tariff publications and related materials must be made electronically.
(b) Requirement for signature. All filings must be signed in compliance with the following:
(1) The signature on a filing constitutes a certification that the contents are true to the best knowledge and belief of the signer, and that the signer possesses full power and authority to sign the filing.
(2) A filing must be signed by one of the following:
(i) The person on behalf of whom the filing is made;
(ii) An officer, agent, or employee of the company, governmental authority, agency, or instrumentality on behalf of which the filing is made; or,
(iii) A representative qualified to practice before the Commission under § 385.2101 of this chapter who possesses authority to sign.
(3) All signatures on the filing or any document included in the filing must comply, where applicable, with the requirements in § 385.2005 of this chapter with respect to sworn declarations or statements and electronic signatures.
(c) Format requirements for electronic filing. The requirements and formats for electronic filing are listed in instructions for electronic filing and for each form. These formats are available through the Commission’s website, https://www.ferc.gov.
(d) Only filings filed and designated as filings with statutory action dates in accordance with these electronic filing requirements and formats will be considered to have statutory action dates. Filings not properly filed and designated as having statutory action dates will not become effective, pursuant to the Interstate Commerce Act, should the Commission not act by the requested action date.
§ 341.2 Filing requirements.
(a) Service of filings. (1) Carriers must serve tariff publications and justifications to each shipper and subscriber. Such service shall be made in accordance with the requirements of § 385.2010 of this chapter.
(2) Unless it seeks a waiver of electronic service, each customer or party entitled to service under this paragraph (a) must notify the company of the e-mail address to which service should be directed. A customer or party may seek a waiver of electronic service by filing a waiver request under Part 390 of this chapter providing good cause for its inability to accept electronic service.
(b) Notice period. All tariff publications (except for suspension supplements, adoption notices, adoption supplements, and tariff indexes) must be filed with the Commission and posted not less than 30, nor more than 60, days prior to the proposed effective date, unless a different notice period is authorized by the Commission. The notice period shall begin the first full day after the tariff publication is filed with the Commission and shall end on the last day prior to the tariff publication effective date.
(c) Transmittal letter—(1) Contents. Letters of transmittal must describe the filing and explain any changes to the carrier’s rates, rules, terms or conditions of service; state if a waiver is being requested, and specify the statute, section, regulation, policy or order requested to be waived; and identify the tariffs supplemental numbers, or tariff sections and the proposed effective date of the tariff publication. Carriers must provide to the Commission, in the letter of transmittal accompanying the filing of a tariff publication containing a joint carrier, the address, phone number, and a contact for each joint carrier listed in the tariff publication.
(2) Certification. Letters of transmittal must certify that the filing has been sent to each subscriber of the tariff publication pursuant to paragraph (a) of this section. For service made on paper, the letters of transmittal must certify that the filing has been sent to each customer or party by first class mail or other agreed-upon means. If there are no subscribers, letters of transmittal must so certify.
§ 341.3 Form of tariff.
(a) Tariffs may be filed either by dividing the tariff into tariff sections or as an entire document.
(b) Contents of tariff. All tariff publications must contain the following information in the following order:
(1) Title page. The title page of each tariff must contain the following information:
(i) The FERC tariff number designation, in the upper right hand corner, numbered consecutively, and the FERC tariff number designation of the tariff that is canceled, if any, under it;
(ii) The corporate name of the carrier;
(iii) The type of rates, e.g., local, joint, or proportional, and the commodity to which the tariff applies, e.g., crude, petroleum product, or jet fuel;
(iv) Governing tariffs, e.g., separate “rules and regulations” tariffs, if any;
(v) The specific Commission order pursuant to which the tariff is issued;
(vi) The issue date, which must be shown on the lower left side, and the effective date, which must be shown on the lower right side;
(vii) The expiration date, if applicable;
(viii) The name of the issuing officer or duly appointed official issuing the tariff, the complete street and mailing address of the carrier, and the name and phone number of the individual responsible for compiling the tariff publication.
(2) Table of contents. Tariffs of more than nine pages in length must contain a table of contents. A table of contents is optional for tariffs which are less than 10 pages in length.
(3) A list of carriers participating in joint tariffs.
(4) Index of Commodities.
(5) Explanatory statements. These statements must explain the proper application of rates and rules.
(6) Rules governing tariff publications. (i) All rules affecting the rates or the services provided for in the tariff publication must be included. A special rule affecting a particular item or rate must be referred to specifically in that item or in connection with that rate.
(ii) Each rule must be given a separate item number, (e.g., Item No. 1), and the title of each rule must be distinctive.
(iii) Except as provided in § 341.10, tariffs may not include any rules that substitute for any rates named in the tariff or found in any other tariff. Rules may not provide that traffic of any nature will be “transported only by special agreement” or any other provision of similar meaning.
(iv) Rules may be separately published in a general rules tariff when it is not desirable or practicable to include the governing rules in the rate tariff. Rate tariffs that do not contain rules must make specific reference, by FERC Tariff number, to the governing general rules tariff.
(v) When joint rate tariffs refer to a separate governing rules tariff, such separate tariff must be concurred in by all joint carriers.
(7) Statement of rates. Rates must be stated explicitly in cents, or in dollars and cents, per barrel or other specified unit. The names or designations of the places from and to which the rates apply must be arranged in a simple and systematic manner. Any related services performed by the carrier in connection with the rates must be clearly identified and explained. Duplicative or conflicting rates for the same service are prohibited.
(8) Routing. Routing over which the rates apply must be stated so that the actual routes may be ascertained. This may be accomplished by stating that the rates apply via all routes of the carrier except as otherwise specifically stated in the tariff.
(9) Explanation of abbreviations and reference marks. Reference marks, abbreviations, and note references must be explained at the end of each tariff publication. U.S. Postal Service state abbreviations and other commonly used abbreviations need not be explained.
(10) Changes to be indicated in tariff or supplement.
(i) All tariff publications must identify where changes have been made in existing rates or charges, rules, regulations or practices, or classifications. One of the following letter designations or uniform symbols may be used to indicate the change, and insertions, other than to tables and rates, must be indicated by either highlight, background shading, bold, or underline, with deleted text indicated by strike-through:
| Description | Option 1 | Option 2 |
|---|---|---|
| Increase | > | [I] |
| Decrease | [D] | |
| Change in wording only | ‸ | [W] |
| Cancel | / | [C] |
| Reissued Item | ∼ | [R] |
| Unchanged Rate | = | [U] |
| New | + | [N] |
(ii) Reissued items must include in the square or brackets the number of the tariff supplement where the item was first issued or amended. If the letter designation is used, the number of the supplement must be shown together with the letter. The references must be explained at the end of the tariff. For example: “[R2] Reissued from Supplement No. 2, effective [specify date].”
(iii) The symbols and letter designations contained in paragraph (b)(10)(i) of this section must not be used for any other purpose.
(iv) When the same change is made in all or in substantially all rates in a tariff, a tariff supplement, or a tariff or tariff supplement page, that fact and the nature of the change must be indicated in distinctive type at the top of the title page of the issue, or at the top of each page, as appropriate. For example: “All rates in this issue are increased,” or “All rates on this page are reduced unless otherwise indicated.”
(v) When a tariff publication that cancels a previous tariff publication does not include points of origin or destination, or rates, rules, or routes that were contained in the prior tariff publication, the new tariff publication must indicate the cancellation. If such omissions effect changes in charges or services, that fact must be indicated by the use of the symbols prescribed in paragraph (b)(10)(i) of this section.
(vi) Only revisions to tariff provisions identified in the filing constitute the tariff filing. Revisions to unidentified portions of the rate schedule or tariff are not considered part of the filing nor will any acceptance of the filing by the Commission constitute acceptance of such unmarked changes.
(11) Tariff publications must be consecutively numbered.
§ 341.4 Amendments of tariff filings.
A carrier may file to amend or modify a tariff contained in a tariff filing at any time during the pendency of the filing. Such filing will toll the notice period as provided in § 341.2(b) for the original filing, and the filing becomes provisionally effective 31 days from the original filing and, in the absence of Commission action, fully effective 31 days from the date of the filing of amendment or modification.
§ 341.5 Cancellation of tariffs.
Carriers must cancel tariffs when the service or transportation movement is terminated. If the service in connection with the tariff is no longer in interstate commerce, the tariff publication must so state. Carrier must file such cancellations within 30 days of the termination of service.
§ 341.6 Adoption of tariff by a successor.
Whenever the tariff(s), or a portion thereof, of a carrier on file with the Commission are to be adopted by another carrier as a result of an acquisition, merger, or name change, the succeeding company must file with the Commission, and post within 30 days after such succession, the tariff, or portion thereof, that has been adopted in the electronic format required by § 341.1 bearing the name of the successor company.
§ 341.7 Concurrences.
Concurrences must be shown in the carrier’s tariff and maintained consistent with the requirements of Part 341 of this chapter.
§ 341.8 Terminal and other services.
Carriers must publish in their tariffs rules governing such matters as prorationing of capacity, demurrage, odorization, carrier liability, quality bank, reconsignment, in-transit transfers, storage, loading and unloading, gathering, terminalling, batching, blending, commingling, and connection policy, and all other charges, services, allowances, absorptions and rules which in any way increase or decrease the amount to be paid on any shipment or which increase or decrease the value of service to the shipper.
§ 341.9 Index of tariffs.
(a) In general. Each carrier with more than two tariffs or concurrences must post on its public Web site a complete index of all effective tariffs to which it is a party, either as an initial, intermediate, or delivering carrier. The index must be arranged in sections as indicated in paragraphs (b), (c), and (d) of this section and must show as to each tariff:
(1) The FERC Tariff number;
(2) The full name of the issuing carrier or agent;
(3) The type of tariff or description of the traffic to which it applies, including origin and destination points; and
(4) Whether the tariff contains rates for transportation by mode other than pipeline.
(5) Product Shipped and Origin. Each index must identify, for each tariff, the product or products being shipped and the origin and destination points specific to each product or products.
(b) Updates. The index of tariffs must be updated within 90 days of any change to an effective tariff.
§ 341.10 Application of rates to intermediate points.
(a) Applicability. (1) A carrier may provide in its tariff that existing rates between points named in the tariff will be applied to transportation movements from intermediate origin points not named in the tariff to named destination points, and from named origin points to intermediate destination points not named in the tariff.
(2) A carrier must file a tariff publication applicable to the transportation movements within 30 days of the start of the service if the intermediate point is to be used on a continuous basis for more than 30 days.
(b) Intermediate point commodity rate regulations—(1) Intermediate origin points. The rate for service provided to a published destination point from an origin point not specifically named in the tariff, but located intermediate to published origin and destination points, must be the same as the published rate from the next more distant origin point. Application of this provision is subject to the following:
(i) If branch or diverging lines create two or more “next more distant” points, the carrier must apply the rate which results in the lowest charge.
(ii) If the intermediate point is located between two published origin points, the carrier must apply the rate which results in the higher charge.
(iii) If the intermediate point is between more than two published origin points due to branch or diverging lines, the carrier must eliminate all such points except that from which the lowest charge is applicable.
(iv) If there is in any other tariff a commodity rate from the proposed intermediate origin point that is applicable to the same movement, the carrier should not apply this rule from such intermediate point.
(2) Intermediate destination points. The rate for service provided from a published origin point to a destination point not specifically named in the tariff, but located intermediate to published origin and destination points, must be the same as the published rate to the next more distant destination point. Application of this provision is subject to the following:
(i) If branch or diverging lines create two or more “next more distant” points, the carrier must apply the rate which results in the lowest charge.
(ii) If the intermediate point is located between two published destination points, the carrier must apply the rate which results in the higher charge.
(iii) If the intermediate point is between more than two published destination points due to branch or diverging lines, the carrier must eliminate all such points except that from which the lowest charge is applicable.
(iv) If there is in any other tariff a commodity rate to the proposed intermediate destination point that is applicable to the same movement, the carrier should not apply the provisions of this rule to such intermediate point.
(3) Intermediate origin and destination points. Both paragraphs (b)(1) and (b)(2) of this section may apply in connection with the same rate. In this instance, both regulations should be used to establish rates from intermediate points of origin to intermediate points of destination.
§ 341.11 Rejection of tariff publications and other filed materials.
(a) Basis for rejection. The Commission may reject tariff publications or any other material submitted for filing that fail to comply with the requirements set forth in this part or violate any statute, or any regulation, policy or order of the Commission.
(b) Numbering and notating tariff publications. The FERC Tariff number assigned to a tariff publication that has been rejected may not be used again.
§ 341.12 Informal submissions.
Carriers may informally submit tariff publications or related material for suggestions of Staff prior to the filing of the tariff publications with the Commission.
§ 341.13 Withdrawal of proposed tariff publications.
(a) Proposed tariff publications. A proposed tariff publication which is not yet effective may be withdrawn at any time by filing a notice with the Commission with a certification that all subscribers have been notified by copy of such withdrawal.
(b) Tariff publications that are subject to investigation. A tariff publication that has been permitted to become effective subject to investigation may be withdrawn at any time by filing a notice with the Commission, which includes a transmittal letter, a certification that all subscribers have been notified of the withdrawal, and the previous tariff provisions that are to be reinstated upon withdrawal of the tariff publication under investigation. Such withdrawal shall be effective immediately upon the submission of the notice, unless a specific effective date is set forth in the notice, and must have the following effects:
(1) Any proceeding with respect to such tariff publication shall be terminated;
(2) The previous tariff rate shall be reinstated; and
(3) Any amounts collected under the withdrawn tariff publication which are in excess of the previous tariff rate shall be refunded within 30 days of the withdrawal with interest as calculated by § 340.1 of this chapter.
(c) Numbering and notating tariff publications. The FERC Tariff number assigned to a tariff publication which has been withdrawn may not be used again.
§ 341.14 Special permission.
(a) Procedure. Applications for waiver of the notice and tariff requirements of section 6(3) of the interstate Commerce Act must be filed by the carrier concurrently with the tariff publication being proposed. The letter of transmittal must identify the filing as requesting a waiver under section 6(3) of the Interstate Commerce Act. The application must state in detail any unusual circumstance or emergency situation that supports the requested waiver. If the application requests permission to make changes in joint tariffs, it must state that it is made on behalf of all carriers party to the proposed change. Tariff publications issued on short notice must contain the following statement on the Title Pages:
Issued on [insert number] days notice under authority of 18 CFR 341.14. This tariff publication is conditionally accepted subject to refund pending a 30 day review period.
(b) Conditional acceptance subject to refund. To permit short-notice filings to become effective as requested, the tariff publications filed concurrently with special permission requests for short (less than 30 days) notice will be deemed conditionally accepted for filing, subject to refund, until the Commission has had a full 30-day review period in which to process the filing. Refunds will be collected with interest as calculated according to § 340.1 of this chapter. The refund obligation will automatically terminate with no refunds due at the end of the full 30-day notice period absent an order to the contrary issued by the Commission.
(c) Granting automatic permission. The special permission requested will be deemed automatically granted at the end of the full 30-day notice period absent an order denying such request.
§ 341.15 Long and short haul or aggregate of intermediate rates.
(a) Requests for relief from section 4. Carriers may file requests for relief from the provisions of section 4 of the Interstate Commerce Act in order to charge a greater amount for a shorter distance over the same line or route in the same direction, or to charge greater compensation as a through rate than the aggregate of the intermediate rates. Such request will be deemed granted unless the Commission denies the request within 30 days of the filing.
(b) Information required to be filed. A request for section 4 relief must contain the following information:
(1) The names of the carriers for which the relief is being requested.
(2) The FERC tariff numbers which contain the rates or charges referred to in the application, and identification of all the particular and related rates in question delineating origin and destination points.
(3) An accurate and complete statement giving the basis and reasoning why section 4 relief is necessary.
(4) A statement that the lower rates for longer than for shorter hauls over the same line or route are reasonably compensatory.
(5) A map showing the pipelines and origin and destination points in question and other pertinent information.
(c) Filing tariff publications concurrent with application. Applications for section 4 relief must be filed concurrently with the tariff publication filing establishing those rates. The transmittal letter must identify the filing as requesting section 4 relief.
(d) Tariff statement. Tariff publications filed containing such rates shall plainly state on the title page of the tariff publication that the rates contained therein contravene section 4 of the Interstate Commerce Act.
(e) Rounding through rates. When a carrier aggregates intermediate rates to make up through rates, it may round the resulting through rate to the nearest 0.5 whole cent.
PART 342—OIL PIPELINE RATE METHODOLOGIES AND PROCEDURES
§ 342.0 Applicability.
(a) Except as provided in paragraph (b) of this section, rate changes by oil pipelines shall be governed by this part.
(b) Exception for the Trans-Alaska Pipeline. This part shall not apply to the Trans-Alaska Pipeline authorized by the Trans-Alaska Pipeline Authorization Act (43 U.S.C. 1651, et seq.) or to any pipeline delivering oil directly or indirectly to the Trans-Alaska Pipeline.
§ 342.1 General rule.
Each carrier subject to the jurisdiction of the Commission under the Interstate Commerce Act:
(a) Must establish its initial rates subject to such Act pursuant to § 342.2; and
(b) Must make any change in existing rates pursuant to § 342.3 or § 342.4, whichever is applicable, unless directed otherwise by the Commission.
§ 342.2 Establishing initial rates.
A carrier must justify an initial rate for new service by:
(a) Filing cost, revenue, and throughput data supporting such rate as required by part 346 of this chapter; or
(b) Filing a sworn affidavit that the rate is agreed to by at least one non-affiliated person who intends to use the service in question, provided that if a protest to the initial rate is filed, the carrier must comply with paragraph (a) of this section.
§ 342.3 Indexing.
(a) Rate changes. A rate charged by a carrier may be changed, at any time, to a level which does not exceed the ceiling level established by paragraph (d) of this section, upon compliance with the applicable filing and notice requirements and with paragraph (b) of this section. A filing under this section proposing to change a rate that is under investigation and subject to refund, must take effect subject to refund.
(b) Information required to be filed with rate changes. The carrier must comply with Part 341 of this title. Carriers must specify in their letters of transmittal required in § 341.2(c) of this chapter the rate schedule to be changed, the proposed new rate, the prior rate, the prior ceiling level, and the applicable ceiling level for the movement. No other rate information is required to accompany the proposed rate change.
(c) Index year. The index year is the period from July 1 to June 30.
(d) Derivation of the ceiling level. (1) A carrier must compute the ceiling level for each index year by multiplying the previous index year’s ceiling level by the most recent index published by the Commission. The index will be published by the Commission prior to June 1 of each year.
(2) The index published by the Commission will be based on the change in the final Producer Price Index for Finished Goods (PPI-FG), seasonally adjusted, as published by the U.S. Department of Labor, Bureau of Labor Statistics, for the two calendar years immediately preceding the index year. The index will be calculated by dividing the PPI-FG for the calendar year immediately preceding the index year, by the previous calendar year’s PPI-FG.
(3) A carrier must compute the ceiling level each index year without regard to the actual rates filed pursuant to this section. All carriers must round their ceiling levels each index year to the nearest hundredth of a cent.
(4) For purposes of computing the ceiling level for the period January 1, 1995 through June 30, 1995, a carrier must use the rate in effect on December 31, 1994 as the previous index year’s ceiling level in the computation in paragraph (d)(1) of this section. If the rate in effect on December 31, 1994 is subsequently lowered by Commission order pursuant to the Interstate Commerce Act, the ceiling level based on such rate must be recomputed, in accordance with paragraph (d)(1) of this section, using the rate established by such Commission order in lieu of the rate in effect on December 31, 1994.
(5) When an initial rate, or rate changed by a method other than indexing, takes effect during the index year, such rate will constitute the applicable ceiling level for that index year. If such rate is subsequently lowered by Commission order pursuant to the Interstate Commerce Act, the ceiling level based on such rate must be recomputed, in accordance with paragraph (d)(1) of this section, using the rate established by such Commission order as the ceiling level for the index year which includes the effective date of the rate established by such Commission order.
(e) Rate decreases. If the ceiling level computed pursuant to § 342.3(d) is below the filed rate of a carrier, that rate must be reduced to bring it into compliance with the new ceiling level; provided, however, that a carrier is not required to reduce a rate below the level deemed just and reasonable under section 1803(a) of the Energy Policy Act of 1992, if such section applies to such rate or to any prior rate. The rate decrease must be accomplished by filing a revised tariff publication with the Commission to be effective July 1 of the index year to which the reduced ceiling level applies.
§ 342.4 Other rate changing methodologies.
(a) Cost-of-service rates. A carrier may change a rate pursuant to this section if it shows that there is a substantial divergence between the actual costs experienced by the carrier and the rate resulting from application of the index such that the rate at the ceiling level would preclude the carrier from being able to charge a just and reasonable rate within the meaning of the Interstate Commerce Act. A carrier must substantiate the costs incurred by filing the data required by part 346 of this chapter. A carrier that makes such a showing may change the rate in question, based upon the cost of providing the service covered by the rate, without regard to the applicable ceiling level under § 342.3.
(b) Market-based rates. A carrier may attempt to show that it lacks significant market power in the market in which it proposes to charge market-based rates. Until the carrier establishes that it lacks market power, these rates will be subject to the applicable ceiling level under § 342.3.
(c) Settlement rates. A carrier may change a rate without regard to the ceiling level under § 342.3 if the proposed change has been agreed to, in writing, by each person who, on the day of the filing of the proposed rate change, is using the service covered by the rate. A filing pursuant to this section must contain a verified statement by the carrier that the proposed rate change has been agreed to by all current shippers.
PART 343—PROCEDURAL RULES APPLICABLE TO OIL PIPELINE PROCEEDINGS
§ 343.0 Applicability.
(a) General rule. The Commission’s Rules of Practice and Procedure in part 385 of this chapter will govern procedural matters in oil pipeline proceedings under part 342 of this chapter and under the Interstate Commerce Act, except to the extent specified in this part.
§ 343.1 Definitions.
For purposes of this part, the following definitions apply:
(a) Complaint means a filing challenging an existing rate or practice under section 13(1) of the Interstate Commerce Act.
(b) Protest means a filing, under section 15(7) of the Interstate Commerce Act, challenging a tariff publication.
§ 343.2 Requirements for filing interventions, protests and complaints.
(a) Interventions. Section 385.214 of this chapter applies to oil pipeline proceedings.
(b) Standing to file protest. Only persons with a substantial economic interest in the tariff filing may file a protest to a tariff filing pursuant to the Interstate Commerce Act. Along with the protest, a verified statement that the protestor has a substantial economic interest in the tariff filing in question must be filed.
(c) Other requirements for filing protests or complaints—(1) Rates established under § 342.3 of this chapter. A protest or complaint filed against a rate proposed or established pursuant to § 342.3 of this chapter must allege reasonable grounds for asserting that the rate violates the applicable ceiling level, or that the rate increase is so substantially in excess of the actual cost increases incurred by the carrier that the rate is unjust and unreasonable, or that the rate decrease is so substantially less than the actual cost decrease incurred by the carrier that the rate is unjust and unreasonable. In addition to meeting the requirements of the section, a complaint must also comply with all the requirements of § 385.206, except § 385.206(b)(1) and (2).
(2) Rates established under § 342.4(c) of this chapter. A protest or complaint filed against a rate proposed or established under § 342.4(c) of this chapter must allege reasonable grounds for asserting that the rate is so substantially in excess of the actual cost increases incurred by the carrier that the rate is unjust and unreasonable. In addition to meeting the requirements of the section, a complaint must also comply with all the requirements of § 385.206, except § 385.206(b)(1) and (2).
(3) Non-rate matters. A protest or complaint filed against a carrier’s operations or practices, other than rates, must allege reasonable grounds for asserting that the operations or practices violate a provision of the Interstate Commerce Act, or of the Commission’s regulations. In addition to meeting the requirements of this section, a complaint must also comply with the requirements of § 385.206.
(4) A protest or complaint that does not meet the requirements of paragraphs (c)(1), (c)(2), or (c)(3) of this section, whichever is applicable, will be dismissed.
§ 343.3 Filing of protests and responses.
(a) Protests. Any protest pursuant to section 15(7) of the Interstate Commerce Act must be filed not later than 15 days after the filing of a tariff publication. If the carrier submits a separate letter with the filing, providing a telefax number and contact person, and requesting all protests to be telefaxed to the carrier by a protestant, any protest must be so telefaxed to the pipeline at the time the protest is filed with the Commission. Only persons with a substantial economic interest in the tariff filing may file a protest to a tariff filing pursuant to the Interstate Commerce Act. Along with the protest, the protestant must file a verified statement which must contain a reasonably detailed description of the nature and substance of the protestant’s substantial economic interest in the tariff filing.
(b) Responses. The carrier may file a response to a protest no later than 5 days from the filing of the protest.
(c) Commission action. Commission action, including any hearings or other proceedings, on a protest will be limited to the issues raised in such protest. If a filing is protested, before the effective date of the tariff publication or within 30 days of the tariff filing, whichever is later, the Commission will determine whether to suspend the tariff and initiate a formal investigation.
(d) Termination of investigation. Withdrawal of the protest, or protests, that caused the initiation of an investigation automatically terminates the investigation.
§ 343.4 Procedure on complaints.
(a) Responses. The carrier must file an answer to a complaint filed pursuant to section 13(1) of the Interstate Commerce Act within 20 days after the filing of the complaint in accordance with Rule 206.
(b) Commission action. Commission action, including any hearings or other proceedings, on a complaint will be limited to the issues raised in the complaint.
§ 343.5 Required negotiations.
The Commission or other decisional authority may require parties to enter into good faith negotiations to settle oil pipeline rate matters. The Commission will refer all protested rate filings to a settlement judge pursuant to § 385.603 of this chapter for recommended resolution. Failure to participate in such negotiations in good faith is a ground for decision against the party so failing to participate on any issue that is the subject of negotiation by other parties.
PART 344—FILING QUOTATIONS FOR U.S. GOVERNMENT SHIPMENTS AT REDUCED RATES
§ 344.1 Applicability.
The provisions of this part will apply to quotations or tenders made by all pipeline common carriers to the United States Government, or any agency or department thereof, for the transportation, storage, or handling of petroleum and petroleum products at reduced rates as permitted by section 22 of the Interstate Commerce Act. Excepted are filings which involve information, the disclosure of which would endanger the national security.
§ 344.2 Manner of submitting quotations.
(a) The quotation or tender must be submitted to the Commission concurrently with the submittal of the quotation or tender to the Federal department or agency for whose account the quotation or tender is offered or the proposed services are to be rendered.
(b) [Reserved]
(c) Filing procedure. (1) The quotation must be filed with a letter of transmittal that prominently indicates that the filing is in accordance with section 22 of the Interstate Commerce Act.
(2) All filings pursuant to this part must be filed electronically consistent with §§ 341.1 and 341.2 of this chapter.
(d) Numbering. The copies of quotations or tenders which are filed with the Commission by each carrier must be numbered consecutively.
(e) Supersession of a quotation or tender. A quotation or tender which supersedes a prior quotation or tender must, by a statement shown immediately under the number of the new document, cancel the prior document number.
PART 346—OIL PIPELINE COST-OF-SERVICE FILING REQUIREMENTS
§ 346.1 Content of filing for cost-of-service rates.
A carrier that seeks to establish rates pursuant to § 342.2(a) of this chapter, or a carrier that seeks to change rates pursuant to § 342.4(a) of this chapter, or a carrier described in § 342.0(b) of this chapter that seeks to establish or change rates by filing cost, revenue, and throughput data supporting such rates, other than pursuant to a Commission-approved settlement, must file, consistent with the requirements of §§ 341.1 and 341.2 of this chapter:
(a) A letter of transmittal which conforms to §§ 341.2(c) and 342.4(a) of this chapter;
(b) The proposed tariff; and
(c) The statements and supporting workpapers set forth in § 346.2.
§ 346.2 Material in support of initial rates or change in rates.
A carrier that files for rates pursuant to § 342.2(a) or § 342.4(a) of this chapter, or a carrier described in § 342.0(b) that files to establish or change rates by filing cost, revenue, and throughput data supporting such rates, other than pursuant to a Commission-approved settlement, must file the following statements, schedules, and supporting workpapers. The statement, schedules, and workpapers must be based upon an appropriate test period.
(a) Base and test periods defined. (1) For a carrier which has been in operation for at least 12 months:
(i) A base period must consist of 12 consecutive months of actual experience. The 12 months of experience must be adjusted to eliminate nonrecurring items (except minor accounts). The filing carrier may include appropriate normalizing adjustments in lieu of nonrecurring items.
(ii) A test period must consist of a base period adjusted for changes in revenues and costs which are known and are measurable with reasonable accuracy at the time of filing and which will become effective within nine months after the last month of available actual experience utilized in the filing. For good cause shown, the Commission may allow reasonable deviation from the prescribed test period.
(2) For a carrier which has less than 12 months’ experience, the test period may consist of 12 consecutive months ending not more than one year from the filing date. For good cause shown, the Commission may allow reasonable deviation from the prescribed test period.
(3) For a carrier which is establishing rates for new service, the test period will be based on a 12-month projection of costs and revenues.
(b) Cost-of-service summary schedule. This schedule must contain the following information:
(1) Total carrier cost of service for the test period.
(2) Throughput for the test period in both barrels and barrel-miles.
(3) For filings pursuant to § 342.4(a) of this chapter, the schedule must include the proposed rates, the rates which would be permitted under § 342.3 of this chapter, and the revenues to be realized from both sets of rates.
(c) Content of statements. Any cost-of-service rate filing must include supporting statements containing the following information for the test period.
(1) Statement A—total cost of service. This statement must summarize the total cost of service for a carrier (operating and maintenance expense, depreciation and amortization, return, and taxes) developed from Statements B through G described in paragraphs (c) (2) through (7) of this section.
(2) Statement B—operation and maintenance expense. This statement must set forth the operation, maintenance, administration and general, and depreciation expenses for the test period. Items used in the computations or derived on this statement must consist of operations, including salaries and wages, supplies and expenses, outside services, operating fuel and power, and oil losses and shortages; maintenance, including salaries and wages, supplies and expenses, outside services, and maintenance and materials; administrative and general, including salaries and wages, supplies and expenses, outside services, rentals, pensions and benefits, insurance, casualty and other losses, and pipeline taxes; and depreciation and amortization.
(3) Statement C—overall return on rate base. This statement must set forth the rate base for return purposes from Statement E in paragraph (c)(5) of this section and must also state the claimed rate of return and the application of the claimed rate of return to the overall rate base. The claimed rate of return must consist of a weighted cost of capital, combining the rate of return on debt capital and the real rate of return on equity capital. Items used in the computations or derived on this statement must include deferred earnings, equity ratio, debt ratio, weighted cost of capital, and costs of debt and equity.
(4) Statement D—income taxes. This statement must set forth the income tax computation. Items used in the computations or derived on this statement must show: return allowance, interest expense, equity return, annual amortization of deferred earnings, depreciation on equity AFUDC, underfunded or overfunded ADIT amortization amount, taxable income, tax factor, and income tax allowance.
(5) Statement E—rate base. This statement must set forth the return rate base. Items used in the computations or derived on this statement must include beginning balances of the rate base at December 31, 1983, working capital (including materials and supplies, prepayments, and oil inventory), accrued depreciation on carrier plant, accrued depreciation on rights of way, and accumulated deferred income taxes; and adjustments and end balances for original cost of retirements, interest during construction, AFUDC adjustments, original cost of net additions and retirements from land, original cost of net additions and retirements from rights of way, original cost of plant additions, original cost accruals for depreciation, AFUDC accrued depreciation adjustment, original cost depreciation accruals added to rights of way, net charge for retirements from accrued depreciation, accumulated deferred income taxes, changes in working capital (including materials and supplies, prepayments, and oil inventory), accrued deferred earnings, annual amortization of accrued deferred earnings, and amortization of starting rate base write-up.
(6) Statement F—allowance for funds used during construction. This statement must set forth the computation of allowances for funds used during construction (AFUDC) including the AFUDC for each year commencing in 1984 and a summary of AFUDC and AFUDC depreciation for the years 1984 through the test year.
(7) Statement G—revenues. This statement must set forth the gross revenues for the actual 12 months of experience as computed under both the presently effective rates and the proposed rates. If the presently effective rates are not at the maximum ceiling rate established under § 342.3 of this chapter, then gross revenues must also be computed and set forth as if the ceiling rates were effective for the 12 month period.
§ 346.3 Asset retirement obligations.
(a) A carrier that files material in support of initial rates or change in rates under § 346.2 and has recorded asset retirement obligations on its books must provide a schedule, as part of the supporting workpapers, identifying all cost components related to the asset retirement obligations that are included in the book balances of all accounts reflected in the cost of service computation supporting the proposed rates. However, all cost components related to asset retirement obligations that would impact the calculation of rate base, such as carrier property and related accumulated depreciation and accumulated deferred income taxes, may not be reflected in rates and must be removed from the rate base calculation through a single adjustment.
(b) A carrier seeking to recover nonrate base costs related to asset retirement costs in rates must provide, with its filing under § 346.2 of this part, a detailed study supporting the amounts proposed to be collected in rates.
(c) A carrier who has recorded asset retirement obligations on its books but is not seeking recovery of the asset retirement costs in rates, must remove all asset retirement obligations related cost components from the cost of service supporting its proposed rates.
PART 347—OIL PIPELINE DEPRECIATION STUDIES
§ 347.1 Material to support request for newly established or changed property account depreciation studies.
(a) Means of filing. Filing of a request for new or changed property account depreciation rates must be made with the Secretary of the Commission.
(b) All filings under this Part must be made electronically pursuant to the requirements of §§ 341.1 and 341.2 of this chapter.
(c) Transmittal letter. Letters of transmittal must give a general description of the change in depreciation rates being proposed in the filing. Letters of transmittal must also certify that the letter of transmittal (not including the information to be provided, as identified in paragraphs (d) and (e) of this section) has been sent to each shipper and to each subscriber. If there are no subscribers, letters of transmittal must so state.
(d) Effectiveness of property account depreciation rates. (1) The proposed depreciation rates being established in the first instance must be used until they are either accepted or modified by the Commission. Rates in effect at the time of the proposed revision must continue to be used until the proposed revised rates are approved or modified by the Commission.
(2) When filing for approval of either new or changed property account depreciation rates, a carrier must provide information in sufficient detail to fully explain and justify its proposed rates.
(e) Information to be provided. The information in paragraphs (e)(1) through (5) of this section must be provided as justification for depreciation changes. Modifications, additions, and deletions to these data elements should be made to reflect the individual circumstances of the carrier’s properties and operations. Any information in paragraphs (e)(1) through (5) of this section, the release of which would violate section 15(13) of the Interstate Commerce Act, must be provided in a format that will protect individual shippers.
(1) A brief summary relating to the general principles on which the proposed depreciation rates are based (e.g., why the economic life of the pipeline section is less then the physical life).
(2) An explanation of the organization, ownership, and operation of the pipeline.
(3) A table of the proposed depreciation rates by account.
(4) An explanation of the average remaining life on a physical basis and on an economic basis.
(5) The following specific background data must be submitted at the time of and concurrently with any request for the establishment of, or modification to, depreciation rates for carriers. If the information listed is not applicable, it may be omitted from the filing:
(i) Up-to-date engineering maps of the pipeline including the location of all gathering facilities, trunkline facilities, terminals, interconnections with other pipeline systems, and interconnections with refineries/plants. Maps must indicate the direction of flow.
(ii) A brief description of the carrier’s operations and an estimate of any major near-term additions or retirements including the estimated costs, location, reason, and probable year of transaction.
(iii) The present depreciation rates being used by account.
(iv) For the most current year available and for the two prior years, a breakdown of the throughput (by type of product, if applicable) received with source (e.g. name of well, pipeline company) at each receipt point and throughput delivered at each delivery point.
(v) The daily average capacity (in barrels per day) and the actual average capacity (in barrels per day) for the most current year, by line section.
(vi) A list of shipments and their associated receipt points, delivery points, and volumes (in barrels) by type of product (where applicable) for the most current year.
(vii) For each primary carrier account, the latest month’s book balances for gross plant and for accumulated reserve for depreciation.
(viii) An estimate of the remaining life of the system (both gathering and trunk lines) including the basis for the estimate.
(ix) For crude oil, a list of the fields or areas from which crude oil is obtained.
(x) If the proposed depreciation rate adjustment is based on the remaining physical life of the properties, a complete, or updated, if applicable, Service Life Data Form (FERC Form No. 73) through the most current year.
(xi) Estimated salvage value of properties by account.
PART 348—OIL PIPELINE APPLICATIONS FOR MARKET POWER DETERMINATIONS
§ 348.1 Content of application for a market power determination.
(a) If, under § 342.4(b) of this chapter, a carrier seeks to establish that it lacks significant market power in the market in which it proposes to charge market-based rates, it must file and provide an application for such a determination. An application must include a statement of position and the information required by paragraph (c) of this section.
(b) The carrier’s statement of position required by paragraph (a) of this section must include an executive summary of its statement of position and a statement of material facts in addition to its complete statement of position. The statement of material facts must include citation to the supporting statements, exhibits, affidavits, and prepared testimony.
(c) The carrier must include with its application the following information:
(1) Statement A—geographic market. This statement must describe the geographic markets in which the carrier seeks to establish that it lacks significant market power. The carrier must include the origin market and the destination market related to the service for which it proposes to charge market-based rates. The statement must explain why the carrier’s method for selecting the geographic markets is appropriate.
(2) Statement B—product market. This statement must identify the product market or markets for which the carrier seeks to establish that it lacks significant market power. The statement must explain why the particular product definition is appropriate.
(3) Statement C—the carrier’s facilities and services. This statement must describe the carrier’s own facilities and services in the relevant markets identified in statements A and B in paragraphs (c) (1) and (2) of this section. The statement must include all pertinent data about the pipeline’s facilities and services.
(4) Statement D—competitive alternatives. This statement must describe available transportation alternatives in competition with the carrier in the relevant markets and other competition constraining the carrier’s rates in those markets. To the extent available, the statement must include all pertinent data about transportation alternatives and other constraining competition.
(5) Statement E—potential competition. This statement must describe potential competition in the relevant markets. To the extent available, the statement must include data about the potential competitors, including their costs, and their distance in miles from the carrier’s terminals and major consuming markets.
(6) Statement F—maps. This statement must consist of maps showing the carrier’s principal transportation facilities, the points at which service is rendered under its tariff, the direction of flow of each line, the location of each of its terminals, the location of each of its major consuming markets, and the location of the alternatives to the carrier, including their distance in miles from the carrier’s terminals and major consuming markets. The statement must include a general system map and maps by geographic markets. The information required by this statement may be on separate pages.
(7) Statement G—market power measures. This statement must set forth the calculation of the market concentration of the relevant markets using the Herfindahl-Hirschman Index. The statement must also set forth the carrier’s market share based on receipts in its origin markets and deliveries in its destination markets, if the Herfindahl-Hirschman Index is not based on those factors. The statement must also set forth the calculation of other market power measures relied on by the carrier. The statement must include complete particulars about the carrier’s calculations.
(8) Statement H—other factors. This statement must describe any other factors that bear on the issue of whether the carrier lacks significant market power in the relevant markets. The description must explain why those other factors are pertinent.
(9) Statement I—prepared testimony. This statement must include the proposed testimony in support of the application and will serve as the carrier’s case-in-chief, if the Commission sets the application for hearing. The proposed witness must subscribe to the testimony and swear that all statements of fact contained in the proposed testimony are true and correct to the best of his or her knowledge, information, and belief.
§ 348.2 Procedures.
(a) All filings under this part must be made electronically pursuant to the requirements of §§ 341.1 and 341.2 of this chapter. A carrier seeking privileged treatment for all or any part of its filing must submit a request for privileged treatment in accordance with § 388.112 of this chapter.
(b) A carrier must provide a copy of its letter of transmittal and its proposed form of protective agreement to each shipper and subscriber on or before the day the material is transmitted to the Commission for filing.
(c) A letter of transmittal must describe the market-based rate filing, including an identification of each rate that would be market-based, and the pertinent tariffs, state if a waiver is being requested and specify the statute, section, subsection, regulation, policy or order requested to be waived. Letters of transmittal must be certified pursuant to § 341.1(b) of this chapter.
(d) An interested person must make a written request to the carrier for a copy of the carrier’s complete application within 20 days after the filing of the application. The request must include an executed copy of the protective agreement. Any objection to the proposed form of protective agreement must be filed under § 385.212 of this chapter.
(e) A carrier must provide a copy of the complete application to the requesting person within seven days after receipt of the written request and an executed copy of the protective agreement.
(f) A carrier must provide copies as required by paragraphs (b) and (e) of this section by first-class mail or by other means of transmission agreed upon in writing.
(g) Any intervention or protest to the application must be filed within 60 days after the filing of the application and must be filed pursuant to §§ 343.2 (a) and (b) of this chapter. A protest must also be telefaxed if required by § 343.3(a) of this chapter.
(h) A protest filed against an application for a market power determination must set forth in detail the grounds for opposing the carrier’s application, including responding to its position and information and, if desired, presenting information pursuant to § 348.1(c).
(i) After expiration of the date for filing protests, the Commission will issue an order in which it will summarily rule on the application or, if appropriate, establish additional procedures and the scope of the investigation.
PART 349—DISPOSITION OF CONTESTED AUDIT FINDINGS AND PROPOSED REMEDIES
§ 349.1 Notice to audited person.
An audit conducted by the Commission or its staff under authority of the Interstate Commerce Act may result in a notice of deficiency or audit report or similar document containing a finding or findings that the audited person has not complied with a requirement of the Commission with respect to, but not limited to, the following: A filed tariff or tariffs, contracts, data, records, accounts, books, communications or papers relevant to the audit of the audited person; and the activities or operations of the audited person. The notice of deficiency, audit report or similar document may also contain one or more proposed remedies that address findings of noncompliance. Where such findings, with or without proposed remedies, appear in a notice of deficiency, audit report or similar document, such document shall be provided to the audited person, and the finding or findings, and any proposed remedies, shall be noted and explained. The audited person shall timely indicate in a written response any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees. The audited person shall have 15 days from the date it is sent the notice of deficiency, audit report or similar document to provide a written response to the audit staff indicating any and all findings or proposed remedies, or both, in any combination, with which the audited person disagrees, and such further time as the audit staff may provide in writing to the audited person at the time the document is sent to the audited person. The audited person may move the Commission for additional time to provide a written response to the audit staff and such motion shall be granted for good cause shown. Any initial order that the Commission subsequently may issue with respect to the notice of deficiency, audit report or similar document shall note, but not address on the merits, the finding or findings, or the proposed remedy or remedies, or both, in any combination, with which the audited person disagreed. The Commission shall provide the audited person 30 days to respond to the initial Commission order concerning a notice of deficiency, audit report or similar document with respect to the finding or findings or any proposed remedy or remedies, or both, in any combination, with which it disagreed.
§ 349.2 Response to notification.
Upon issuance of a Commission order that notes a finding or findings, or proposed remedy or remedies, or both, in any combination, with which the audited person has disagreed, the audited person may: Acquiesce in the findings and/or proposed remedies by not timely responding to the Commission order, in which case the Commission may issue an order approving them or taking other action; or challenge the finding or findings and/or any proposed remedies with which it disagreed by timely notifying the Commission in writing that it requests Commission review by means of a shortened procedure, or, if there are material facts in dispute which require cross-examination, a trial-type hearing.
§ 349.3 Shortened procedure.
If the audited person subject to a Commission order described in § 349.1 notifies the Commission that it seeks to challenge one or more audit findings, or proposed remedy or remedies, or both, in any combination, by the shortened procedure, the Commission shall thereupon issue a notice setting a schedule for the filing of memoranda. The person electing the use of the shortened procedure, and any other interested entities, including the Commission staff, shall file, within 45 days of the notice, an initial memorandum that addresses the relevant facts and applicable law that support the position or positions taken regarding the matters at issue. Reply memoranda shall be filed within 20 days of the date by which the initial memoranda are due to be filed. Only participants who filed initial memoranda may file reply memoranda. Subpart T of part 385 of this chapter shall apply to all filings. Within 20 days after the last date that reply memoranda under the shortened procedure may be timely filed, the audited person who elected the shortened procedure may file a motion with the Commission requesting a trial-type hearing if new issues are raised by a party. To prevail in such a motion, the audited person must show that a party to the shortened procedure raised one or more new issues of material fact relevant to resolution of a matter in the shortened procedure such that fundamental fairness requires a trial-type hearing to resolve the new issue or issues so raised. Parties to the shortened procedure and the Commission staff may file responses to the motion. In ruling upon the motion, the Commission may determine that some or all of the issues be litigated in a trial-type hearing.
§ 349.4 Form and style.
Each copy of such memorandum must be complete in itself. All pertinent data should be set forth fully, and each memorandum should set out the facts and argument as prescribed for briefs in § 385.706 of this chapter.
§ 349.5 Verification.
The facts stated in the memorandum must be sworn to by persons having knowledge thereof, which latter fact must affirmatively appear in the affidavit. Except under unusual circumstances, such persons should be those who would appear as witnesses if hearing were had to testify as to the facts stated in the memorandum.
§ 349.6 Determination.
If no formal hearing is had the matter in issue will be determined by the Commission on the basis of the facts and arguments submitted.
§ 349.7 Assignment for oral hearing.
Except when there are no material facts in dispute, when a person does not consent to the shortened procedure, the Commission will assign the proceeding for hearing as provided by subpart E of part 385 of this chapter. Notwithstanding a person’s not giving consent to the shortened procedure, and instead seeking assignment for hearing as provided for by subpart E of part 385 of this chapter, the Commission will not assign the proceeding for a hearing when no material facts are in dispute. The Commission may also, in its discretion, at any stage in the proceeding, set the proceeding for hearing.
SUBCHAPTER Q—ACCOUNTS UNDER THE INTERSTATE COMMERCE ACT
PART 351—FINANCIAL STATEMENTS RELEASED BY CARRIERS
§ 351.1 Financial statements released by carriers.
Carriers desiring to do so may prepare and publish financial statements in reports to stockholders and others, except in reports to this Commission, based on generally accepted accounting principles for which there is authoritative support, provided that any variance from this Commission’s prescribed accounting rules contained in such statements is clearly disclosed in footnotes to the statements.
PART 352—UNIFORM SYSTEMS OF ACCOUNTS PRESCRIBED FOR OIL PIPELINE COMPANIES SUBJECT TO THE PROVISIONS OF THE INTERSTATE COMMERCE ACT
Definitions. Definitions of terms used in this system of accounts:
1. Accounts means the accounts prescribed in this system of accounts.
2. Actually issued, as applied to securities issued or assumed by the carrier, means those which have been sold to bona fide purchasers or holders for a valuable consideration, those issued in exchange for other securities or other property, and those issued as dividends on stock; and the purchasers or holders secured them free from control by the carrier.
3. Actually outstanding, as applied to securities issued or assumed by the carrier, means those which have been actually issued and are neither retired nor held by or for the carrier.
4. Additions means facilities, equipment, and structures added to existing property exclusive of replacements.
5. Affiliated companies means companies or persons that directly, or indirectly through one or more intermediaries, control, or are controlled by, or are under common control with, the accounting carrier.
6. Amortization means the gradual extinguishment of an amount in an account by distributing such amount over a fixed period, over the life of the asset or liability to which it applies, or over the period during which it is anticipated the benefit will be realized.
7. Book cost means the amount at which assets are recorded in the accounts without deduction of related provisions for accrued depreciation, amortization, or for other purposes.
8. Carrier means a common carrier by pipeline subject to the Interstate Commerce Act.
9. Commission means the Federal Energy Regulatory Commission.
10. Control (including the terms controlling, controlled by, and under common control with) means the possession, directly or indirectly, of the power to direct or cause the direction of the management and policies of a company, whether such power is exercised through one or more intermediary companies, or alone, or in conjunction with, or pursuant to an agreement, and whether such power is established through a majority or minority ownership or voting of securities, common directors, officers or stockholders, voting trusts, holding trusts, associated companies, contract or any other direct or indirect means. When there is doubt about an existence of control in any particular situation, the carrier shall report all pertinent facts to the Commission for determination.
11. Cost means the amount of money actually paid for property or services or the current cash value of the consideration given when it is other than money.
12. Cost of removal means cost of demolishing, dismantling, tearing down, or otherwise removing property including costs of handling and transportation. It does not include the cost of removal activities associated with asset retirement obligations that are capitalized as part of the tangible long-lived assets that give rise to the obligation. (See General Instruction 1–19).
13. Date of retirement means the date that property is withdrawn from service.
14. Debt expense means all expense in connection with the issuance and sale of evidences of debt, such as fees for drafting mortgages and trusts; fees and taxes for issuing or recording evidences of debt; cost of engraving and printing bonds, certificates of indebtedness, and other evidences of debt; fees paid to trustees; specific costs of obtaining governmental authority; fees for legal services; fees and commissions paid underwriters, brokers, and salesmen for marketing evidences of debt; fees and expenses of listing on exchanges; and other like costs.
15. Depreciation means the loss in service value not restored by current maintenance and incurred in connection with the consumption or prospective retirement of property in the course of service from causes against which the carrier is not protected by insurance, and the effect of which can be forecast with a reasonable approach to accuracy.
16. Discount, as applied to securities issued or assumed by the carrier, means the excess of the par or face value of the securities plus interest or dividends accrued at the date of the sale over the cash value of the consideration received from their sale.
17. Group plan means the plan under which depreciation charges are computed on the book cost of all property included in each depreciable account by application of a composite rate of depreciation based on the weighted average service lives of such property.
18. Improvements means alterations or changes in structural design of property which result in increased service life or efficiency.
19. Minor items of property means the associated parts or items of which units of property are composed.
20. Net salvage value means salvage value of property retired less the cost of removal.
21. Nominally issued, as applied to securities issued or assumed by the carrier, means those which have been signed, certified, or otherwise executed, and placed with the proper officer for sale and delivery, or pledged, or otherwise placed in some special fund of the accounting company.
22. Nominally outstanding, as applied to securities issued or assumed by the carrier, means those which, after being actually issued, have been reacquired by or for the accounting company under such circumstances which require them to be considered as held alive and not retired and canceled.
23. Premium, as applied to securities issued or assumed by the carrier, means the excess of the cash value of the consideration received from their sale over the sum of their par (stated value of no-par stocks) or face value and interest or dividends accrued at the date of sale.
24. Property retired means units of property which have been removed, sold, abandoned, destroyed, or which for any cause have been withdrawn from service; also, minor items of property not replaced.
25. Replacement means the substitution of a part or of a complete unit of property with a new part or unit.
26. Salvage value means the amount received or estimated to be received for property retired less any expenses incurred in connection with the sale or preparing the property for sale; or, if retained, the value at which the recovered material is chargeable to the material and supplies account or other appropriate account.
27. Service life means the period between the date that property is placed in service and the date of its retirement.
28. Service value means the book cost less the actual or estimated net salvage value of property.
29. Straight-line method, as applied to depreciation and amortization accounting, means the plan under which the service value of property is charged to expense and credited to the related accrued depreciation or amortization account through equal monthly charges during the service life of the property.
30. (a) Income taxes means taxes based on income determined under provisions of the United States Internal Revenue Code and foreign, state and other taxes (including franchise taxes) based on income.
(b) Income tax expense means the amount of income taxes (whether or not currently payable or refundable) allocable to a period in the determination of net income.
(c) Pretax accounting income means income or loss for a period, exclusive of related income tax expense.
(d) Taxable income means the excess of revenues over deductions or the excess of deductions over revenues to be reported for income tax purposes for a period.
(e) “Temporary difference” means a difference between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years when the reported amount of the asset or liability is recovered or settled, respectively. Some events recognized in financial statements do not have tax consequences. Certain revenues are exempt from taxation and certain expenses are not deductible. Events that do not have tax consequences do not give rise to temporary differences.
(f) “Deductible temporary difference” means temporary differences that result in deductible amounts in future years when the related asset or liability is recovered or settled, respectively.
(g) “Deferred tax asset” means the deferred tax consequences attributable to deductible temporary differences and carryforwards. A deferred tax asset is measured using the applicable enacted tax rate and provisions of the enacted tax law. A valuation allowance should be recognized if it is more likely than not (a likelihood of more than 50 percent) that some portion or all of the deferred tax asset will not be realized.
(h) “Deferred tax liability” means the deferred tax consequences attributable to taxable temporary differences. A deferred tax liability is measured using the applicable enacted tax rate and provisions of the enacted tax law.
(i) Interperiod tax allocation means the process of apportioning income taxes among periods.
(j) “Tax allocation within a period” means the process of allocating income tax expense applicable to a given period among continuing operations, discontinued operations, extraordinary items, and items charged or credited directly to shareholders’ equity.
31. (a) Investor means a business entity that holds an investment in voting stock of another company.
(b) Investee means a corporation that issued voting stock held by an investor.
(c) Corporate joint venture is a company owned and operated by a small group of businesses as a separate and specific business or project for the mutual benefit of the members of the group.
(d) Dividends, unless otherwise specified, means dividends paid or payable in cash, other assets, or another class of stock and does not include stock dividends or stock splits.
(e) Earnings or losses of an investee and financial position of an investee refer to net income (or net loss) and financial position of an investee determined in accordance with generally accepted accounting principles.
(f) Undistributed earnings of an investee means net income less dividends declared whether received or not.
(g) Date of acquisition is the date on which the investor assumes the rights of ownership. Ordinarily this is the date assets are received and other assets are given or securities issued.
32. (a) Segment of a business refers to a component of an entity whose activities represent a separate major line of business or class of customer. A segment may be in the form of a subsidiary, a division, or a department, and in some cases a joint venture or other nonsubsidiary investee, provided that its assets, results of operations, and activities can be clearly distinguished, physically and operationally and for financial reporting purposes, from the other assets, results of operations, and activities of the entity. The fact that the results of operations of the segment being sold or abandoned cannot be separately identified strongly suggests that the transaction should not be classified as a segment of business.
(b) Measurement date means the date on which the management having authority to approve the action commits itself to a formal plan to dispose of a segment of the business, whether by abandonment or sale. The measurement date for disposals requiring Commission approval shall be the service date of the Order authorizing the disposal.
(c) Disposal date refers to the date of closing the sale if the disposal is by sale or the date that operations cease if the disposal is by abandonment.
33. Compensating balance means the portion of any demand deposit (or any time deposit or certificate of deposit) maintained by a carrier (or by any person on behalf of the carrier) which constitutes support for existing borrowing arrangements of the carrier (or any person) with a lending institution. Such arrangements include both outstanding borrowings and the assurance of future credit availability. (The compensating balance requirement should be adjusted by the amount of float unless such adjustment would cause the compensating balance to be greater than the cash balance per carrier’s books. The float adjustment is made by subtracting the float from the compensating balance requirement if the collected bank ledger balance exceeds the cash balance per carrier’s books or by adding the float to the compensating balance requirement if the collected bank ledger balance is less than the cash balance per carrier’s books.)
34. Float means deposits and withdrawals in transit which constitute a difference between the collected bank ledger balance and the cash balance per carrier’s books.
35. (a) Equity security encompasses any instrument representing ownership shares (e.g., common, preferred, and other capital stock), or the right to acquire (e.g., warrants, rights, and call options) or dispose of (e.g., put options) ownership shares in an enterprise at fixed or determinable prices. The term does not encompass preferred stock that by its terms either must be redeemed by the issuing enterprise or is redeemable at the option of the investor, nor does it include treasury stock or convertible bonds.
(b) Marketable, as applied to an equity security, means an equity security as to which sales prices or bid and ask prices are currently available on a national securities exchange (i.e., those registered with the Securities and Exchange Commission) or in the over-the-counter market. In the over-the-counter market, an equity security shall be considered marketable when a quotation is publicly reported by the National Association of Securities Dealers Automatic Quotations System or by the National Quotations Bureau, Inc. (Provided, in the later case, That quotations are available from at least three dealers.) Equity securities traded in foreign markets shall be considered marketable when such markets are of a breadth and scope comparable to those referred to above. This definition is not met by restricted stock (securities for which sale is restricted by a governmental or contractual requirement except where such requirement terminates within one year or where the holder has the power to cause the requirement to be met within one year). Any portion of the stock which can reasonably be expected to qualify for sale within one year, such as may be the case under Rule 144 or similar rules of the Securities and Exchange Commission, is not considered restricted.
(c) Market value refers to the aggregate of the market price of a single share or unit times the number of shares or units of each marketable equity security in the portfolio. When an entity has taken positions involving short sales, sales of calls, and purchases of puts for marketable equity securities and the same securities are included in the portfolio, those contracts shall be taken into consideration in the determination of market value of the marketable equity securities.
(d) Cost, as applied to a marketable equity security, refers to the original cost as adjusted for unrealized holding gains and losses.
1–1 Classification of accounts. Accounts are prescribed to record the cost of property used in transportation and related operations and for revenues, expenses, taxes, rents, and other items of income for such operations. Separate accounts are prescribed for cost of property not used in transportation operations and for income and expenses pertaining thereto; for other investments and related income; for extraordinary and prior period items, including applicable income taxes; and for assets and liabilities.
In addition, stockholders’ equity accounts, designed to segregate directly contributed capital from appropriated and unappropriated retained income, are provided. Retained income accounts form the connecting link between the income account and the equity section of the balance sheet. They are provided to record the transfer of net income or loss for the year; certain capital transactions; and, when authorized by the Commission, other items.
1–2 Records. (a) Carriers shall keep their accounts and records in accordance with the prescribed accounts. In addition, clearing accounts, temporary accounts, and subdivisions of any account may be kept provided the integrity of the prescribed accounts is not impaired. Each carrier shall keep its books of account, and all other books, records and memoranda which support the entries in such books of account, so as to be able to furnish readily full information as to any item included in any account. Each entry shall be supported by such detailed information as will permit ready identification, analysis, and verification of all facts relevant thereto.
(b) The books and records referred to herein include not only accounting records in a limited technical sense, but all records, such as minute books, stock books, reports, correspondence, memorandums, etc., which may be useful in developing the history of or facts regarding any transaction.
(c) No carrier shall destroy any books, records, memoranda, etc., which support entries to its accounts unless destruction is permitted by the regulations governing preservation of records, Part 356 of this chapter.
(49 U.S.C. 5b, 304, 320, 904, 913, 917, 1003, 1012)
1–3 Accounting period. (a) Each carrier shall keep its books on a monthly basis so that all transactions, as nearly as may be ascertained, shall be entered in the accounts not later than 60 days after the last day of the period for which the accounts are stated, except that the time within which the final entries for the year ending December 31 shall be made may be extended to such date in the following March as shall not interfere with the preparation and filing of the annual report.
(b) Changes shall not be made in the accounts for periods covered by reports that have been filed with the Commission unless the changes have first been authorized by the Commission.
1–4 Accounting method. (a) This system of accounts shall be kept by the accrual method of accounting. The basis used for accruing income and expense items each month shall be consistently applied and any change in such basis or any unusual accruals involving material amounts shall be promptly reported to the Commission.
(b) When the amount of any transaction cannot be accurately determined in time for inclusion in the applicable month’s accounts, an estimated amount shall be entered in the proper accounts. Appropriate adjustments shall be made as soon as the actual amounts become known or at the time a substantial change is indicated. Carriers are not required to anticipate minor items which do not appreciably affect the accounts.
1–5 Delayed items. Ordinary delayed items and adjustments arising during the current year which are applicable to prior years shall be included in the same account which would have been charged or credited if the item had been taken up or the adjustments made in the year to which it pertained. When the amount of a delayed item or adjustment is relatively so large that its inclusion in net income for a single month would seriously distort the accounts for the month (but not for the year), such amount may be distributed in equal monthly charges or credits, as the case may be, to the remaining months of the calendar year. See instruction 1–6 for instructions covering extraordinary and prior period items of a nonrecurring nature.
1–6 Extraordinary, unusual or infrequent items, prior period adjustments, discontinued operations and accounting changes. (a) Extraordinary Items. All items of profit and loss recognized during the year are includible in ordinary income unless evidence clearly supports their classification as extraordinary items. Extraordinary items are characterized by both their unusual nature and infrequent occurrence taking into account the environment in which the firm operates; they must also meet the materiality standard.
Unusual means the event or transaction must possess a high degree of abnormality and be of a type clearly unrelated to, or only incidentally related to the ordinary and typical activities of the entity.
Infrequent occurrence means the event or transaction shall be of a type not reasonably expected to recur in the foreseeable future.
(b) Unusual or Infrequent Items. Material events unusual in nature or infrequent in occurrence but not both, thus not meeting both criteria for classification as extraordinary, shall be includible in the accounts provided as separate components of income/expense from continuing operations. Such items are not to be reported net of income taxes.
(c) Discontinued Operations. The results of continuing operations shall be reported separately from discontinued operations and any gain or loss resulting from disposal of a segment of a business (see definition 32(a)) shall be reported in conjunction with the related results of discontinued operations and not as an extraordinary item. The disposal of a segment of a business shall be distinguished from other disposals of assets incident to the evolution of the entity’s business, such as the disposal of part of a line of business, the shifting of production or marketing activities for a particular line of business from one location to another, the phasing out of a product line or class of service, and other changes occasioned by technological improvements. If a loss is expected from the proposed sale or abandonment of a segment, the estimated loss shall be provided for at the measurement date (see definition 32(b)). If a gain is expected, it shall be recognized when realized, which ordinarily is the disposal date (see definition 32(c)).
(d) Prior Period Adjustments. The correction of an error in the financial statements of a prior period and adjustments that result from realization of income tax benefits of preacquisition loss carryforwards of purchased subsidiaries shall be accounted for as prior period adjustments and excluded from the determination of net income from the current year. All other revenues, expenses, gains, and losses recognized during a period shall be included in the net income of that period.
(e) Accounting Changes. A change in accounting principle or accounting entity should be referred to this Commission for approval. The cumulative effect of a change in accounting principle should ordinarily be reflected in the account provided for in determining net income; in certain cases accounting changes may be reflected as prior period adjustments. Changes in accounting estimates should ordinarily be reflected prospectively.
(f) Materiality. As a general standard an item shall be considered material when it exceeds 10 percent of annual income (loss) before extraordinary items. An item may also be considered in relation to the trend of annual earnings before extraordinary items or other appropriate criteria. Items shall be considered individually and not in the aggregate in determining materiality. However, the effects of a series of related transactions arising from a single specific and identifiable event or plan of action shall be aggregated to determine materiality.
(g) Commission Approval and accountant’s letter. Items shall be included in the accounts provided for extraordinary items, unusual or infrequent items, discontinued operations, prior period adjustments and cumulative effect of changes in accounting principles only upon approval of the Commission. If the carrier retains the service of an independent accountant, a request for using these accounts shall be accompanied by a letter from the independent accountant approving or otherwise commenting on the request.
The carrier may refer to generally accepted accounting principles for further guidance in applying instruction 1–6.
1–7 Items in texts of accounts. Items appearing in instructions and in the texts of various accounts are merely representative and are not intended to cover all of the items includible therein.
1–8 Depreciation accounting—Carrier property.
(a) Method. Monthly depreciation charges shall be made by the straight-line method to operating expenses in conformity with the group plan of accounting applicable to all carrier property except property included in accounts 101, 151, 171, Land, and 187, Construction Work in Progress.
(b) Rates. (1) Separate composite annual percentage rates will be prescribed for each depreciable account except that the Commission may authorize the use of component rates upon specific request from a carrier. Carriers becoming subject to this system of accounts and carriers acquiring property for which no rates have been previously prescribed shall file, within six months, composite annual percentage rates applicable to the book cost of each class of depreciable carrier property as will distribute the service value, by the straight-line method, in equal annual charges to operating expenses during the service life of the property. These rates shall be used by the carrier until the rates prescribed by the Commission become effective. Such rates shall, for each primary account comprised of more than one class of property, produce a depreciation charge equal to the sum of the amounts that would otherwise be chargeable for each of the various classes of property included in the account. Carriers shall base these percentage rates on estimated service values and service lives developed from engineering and other studies. The rates filed shall be accompanied by a statement showing the bases and the methods employed in the rate determination.
(2) Carriers shall be prepared at any time upon the direction of the Commission to compute and submit revised percentage rate studies. When a carrier believes that any rate prescribed by the Commission is no longer applicable, it shall submit the rate which it believes should be established supported by full particulars for consideration by the Commission.
(3) A carrier shall keep records of property and property retirements that will reflect the service life of property which has been retired, or will permit the determination of service life indications by mortality, turnover, or other appropriate methods; and also such records as will reflect the percentage of net salvage value for property retired from each class of depreciable carrier property.
(c) Charges. In computing monthly charges, the annual percentage rates shall be applied to the depreciation base as of the first of each month and the result divided by twelve.
(d) Retirements. Except as provided in paragraph (e) of this section, upon the retirement of depreciable property the service value shall be charged in its entirety to account 31, Accrued Depreciation—Carrier Property. Any amounts of insurance recovered from casualty losses involving depreciable property retired shall be credited thereto.
(e) Special accounting authority. (1) When circumstances indicate that newly acquired property should be subject to amortization, or that the prescribed depreciation rates based on the service lives of certain property are no longer applicable, because the source of traffic will be exhausted before the end of the physical service life, the carrier shall submit to the Commission for approval amortization or depreciation rates based on the estimated remaining service life of the property accompanied by full information justifying the request.
(2) A carrier may request, or the Commission may direct, that special accounting be applied in situations causing undue inflation or deflation of depreciation reserves, such as premature or unusual retirements or sales of depreciable property, or related insurance recoveries. A carrier’s request for special accounting shall contain full particulars concerning the situation, including the basis for its proposal. Alternative accounting techniques shall be applied to the extent approved or directed by the Commission.
1–9 Depreciation accounting—Noncarrier property. Monthly depreciation charges for all depreciable property recorded in account 34, Noncarrier Property, shall be made to account 620, Income from Noncarrier Property, with concurrent credits to account 35, Accrued Depreciation—Noncarrier Property. The depreciation charges shall be such as to distribute the service values equitably over the service life of the property.
1–10 Amortization of intangibles. Monthly charges shall be made to account 540, Depreciation and Amortization, to amortize the cost of fixed life intangibles such as permits, patents and franchises which are directly related to pipeline operations. Monthly charges shall be made to account 660, Miscellaneous Income Charges, to amortize the cost of intangibles such as goodwill which are not directly associated with pipeline operations. The amortization charges shall be such as to distribute the cost by the straight-line method in equal annual charges over the life or expected period of benefit.
1–11 Interpretation of rules. To maintain uniformity of accounting, carriers shall submit questions of doubtful interpretation to the Commission for consideration and decision.
1–12 Accounting for income taxes. (a) The interperiod tax allocation method of accounting shall be applied to all material temporary differences (see definition 30(e)) between the tax basis of an asset or liability and its reported amount in the financial statements that will result in taxable or deductible amounts in future years. Carriers may elect, as provided by the Revenue Act of 1971, to account for the investment tax credit by either the flow through method or the deferred method of accounting. See paragraphs (d) and (e) below. All income taxes (Federal, State, and other) currently accruable for income tax return purposes shall be charged to account 670, Income taxes on income from continuing operations, and account 695, Income taxes on extraordinary items, as applicable.
(b) Under the interperiod tax allocation method of accounting a deferred tax liability or asset is to be recognized for all temporary differences (see definition 30(e)) that result in taxable amounts in future years when the related asset or liability is recovered or settled. Deferred taxes are classified as current or noncurrent based on the classification of the related asset or liability. A carrier shall apply the applicable enacted tax rate in determining the amount of deferred taxes. The carrier shall adjust its deferred tax liabilities and assets for the effect of the change in tax law or rates in the period that the change is enacted. The adjustment shall be recorded in the proper deferred tax balance sheet accounts based on the nature of the temporary difference and the related classification requirements of the account.
(c) An entity shall record the income tax effects of a net operating loss carryforward or a tax credit carryforward as a deferred tax asset in the year the loss occurs. In the event that it is more likely than not (a likelihood of more than 50 percent) that some portion of its deferred tax assets will not be realized, a carrier shall reduce the asset by a valuation allowance. The valuation allowance should be recorded in a separate subaccount of the deferred tax asset account. The carrier shall disclose full particulars as to the nature and amount of each type of operating loss and tax credit carryforward in the notes to its financial statements.
(d) Carriers electing to account for the investment tax credit by the flow through method shall credit account 670, Income taxes on income from continuing operations, or account 695, Income taxes on extraordinary items, as applicable, and charge to account 56, Taxes payable, with the amount of investment tax credit utilized in the current accounting period. When the flow through method is followed for the investment tax credit, account 671, Provision for deferred taxes, shall reflect the difference between the tax payable (after recognition of allowable investment tax credit) based on taxable income and tax expense (with full recognition of investment tax credit that would be allowable based on accounting income) based on accounting income.
(e) Carriers electing to account for the investment tax credit by the deferred method shall concurrently with making the entries prescribed in (d) above charge account 671, “Provision for deferred taxes” or account 696, “Provision for deferred taxes—extraordinary items,” as applicable, and shall credit account 64, Accumulated Deferred Income Tax Liabilities with the investment tax credit utilized as a reduction of the current year’s tax liability but deferred for accounting purposes. The investment tax credit so deferred shall be amortized by credits to account 671, “Provision for deferred taxes”.
Any change in practice of accounting for the investment tax credit shall be reported promptly to the Commission. Carriers desiring to clear deferred investment tax credits because of a change from the deferral method to the flow through method shall submit the proposed journal entry to the Commission for consideration and advice.
The carrier shall follow generally accepted accounting principles where an interpretation of the accounting rules for income taxes is needed or obtain an interpretation from its public accountant or the Commission.
1–13 Transactions with affiliated companies. (a) The records and supporting data of all transactions with affiliated companies shall be maintained in a separate file. The types of transactions referred to in this paragraph are for management services or any other type of services rendered, sale or use of facilities or any other type of assets or property. The file shall be maintained so as to enable the carrier, to furnish accurate information with supporting documentation about particular transactions within 15 days of the request. We do not intend the file to include data relating to ordinary carrier operations (e.g. lawful tariff charges).
(b) Each bill rendered by an affiliated company shall state specifically the basis used for determining charges, unless the file contains other information to support the specific basis for charges.
(c) Punched cards, magnetic tapes, discs, or other machine-sensible device used for recording, consolidating, and summarizing accounting transactions and records with a carrier’s electronic or automatic data processing system may constitute a file within the meaning of this instruction.
(d) The carrier shall record, as the cost of assets or services received from an affiliated supplier, the invoice price (plus any incidental costs related to those transactions) in those cases where the invoice price can be determined from a prevailing price list of the affiliated supplier available to the general public in the normal course of business. If no such price list exists, the charges shall be recorded at the lower of their cost to the originating affiliated supplier (less all applicable valuation reserves in case of asset sales), or their estimated fair market value determined on the basis of a representative study of similar competitive and arm’s-length or bargained transactions.
Any difference between actual transaction price and the above, as well as charges that are not transportation related, shall be considered of a financing nature and shall be recorded, accordingly, as nonoperating charges or credits. (See Instruction 1–14).
(e) Nothing contained herein shall be construed as restraining the carrier from subdividing accounts (see Instruction 1–2(a)) for the purpose of recording separately transactions with affiliated companies.
1–14 Charges to be just and reasonable. All charges to the accounts prescribed in this system of accounts for carrier property, operating revenues, operating and maintenance expenses, and other carrier expenses, shall be just, reasonable and not exceed amounts necessary to the honest and efficient operations and management of carrier business. Payments shall not exceed the fair market value of goods and services acquired in an arm’s-length transaction. Any payments in excess of such just and reasonable charges shall be included in account 660, Miscellaneous Income Charges.
1–15 Accounting for marketable securities owned.
(a) Accounts 11 “Temporary investments,” 20 “Investments in affiliated companies,” and 21 “Other investments” shall be maintained in such a manner as to reflect the marketable equity portion (see definition 35) and other securities or investments.
(b) For the purpose of determining net ledger value, the marketable equity securities in account 11 shall be considered the current portfolio and the marketable equity securities in accounts 20 and 21 (combined) shall be considered the noncurrent portfolio.
(c) Carriers will categorize their security investments as held-to-maturity, trading, or available-for-sale. Unrealized holding gains and losses on trading type investment securities will be recorded in accounts 640, miscellaneous income, and 660, miscellaneous income charges, as appropriate. Unrealized holding gains and losses on available-for-sale type investment securities shall be recorded in account 77, accumulated other comprehensive income.
1–16 Accounting for inaccurate reporting of income taxes on income from continuing operations which occurred prior to reporting year 1979. To the extent that any oil pipeline company, required to file annual reports with the Commission, did not correctly report State or other income taxes on continuing operations for the 1976, 1977, and 1978 reporting years, such company is ordered to disclose the amount of the accounting change in the space for notes and remarks provided in its 1979 Annual Report Form P, Schedule 300–A, of the Commission.
1–17 Accounting for other comprehensive income.
(a) Carriers shall record items of other comprehensive income in account 77, accumulated other comprehensive income. Amounts included in this account shall be maintained by each category of other comprehensive income. Examples of categories of other comprehensive income include, foreign currency items, minimum pension liability adjustments, unrealized gains and losses on available-for-sale type securities and cash flow hedge amounts. Supporting records shall be maintained for account 77 so that the company can readily identify the cumulative amount of other comprehensive income for each item included in this account.
(b) When an item of other comprehensive income enters into the determination of net income in the current or subsequent periods, a reclassification adjustment shall be recorded in account 77 to avoid double counting of that amount.
1–18 Accounting for derivative instruments and hedging activities.
(a) A carrier shall recognize derivative instruments as either assets or liabilities in the financial statements and measure those instruments at fair value, except those falling within recognized exceptions, the most common of which being the normal purchases and sales scope exception. Normal purchases or sales are contracts that provide for the purchase or sale of goods that will be delivered in quantities expected to be used or sold by the utility over a reasonable period in the normal course of business. A derivative instrument is a financial instrument or other contract with all three of the following characteristics:
(1) It has one or more underlyings and a notional amount or payment provision. Those terms determine the amount of the settlement or settlements, and, in some cases, whether or not a settlement is required.
(2) It requires no initial net investment or an initial net investment that is smaller than would be required for other types of contracts that would be expected to have similar response to changes in market factors.
(3) Its terms require or permit net settlement, can readily be settled net by a means outside the contract, or provides for delivery of an asset that puts the recipient in a position not substantially different from net settlement.
(b) The accounting for the changes in the fair value of derivative instruments depends upon its intended use and designation. Changes in the fair value of derivative instruments not designated as fair value or cash flow hedges shall be recorded in account 46, derivative instrument assets, or account 65, derivative instrument liabilities, as appropriate, with the gains recorded in account 640, miscellaneous income, and losses recorded in account 660, miscellaneous income charges.
(c) A derivative instrument may be specifically designated as a fair value or cash flow hedge. A hedge may be used to manage risk to price, interest rates, or foreign currency transactions. An entity shall maintain documentation of the hedge relationship at the inception of the hedge that details the risk management objective and strategy for undertaking the hedge, the nature of the risk being hedged, and how hedge effectiveness will be determined.
(d) If the carrier designates the derivative instrument as a fair value hedge against exposure to changes in the fair value of a recognized asset, liability, or a firm commitment, it shall record the change in fair value of the derivative instrument designated as a fair value hedge to account 47, derivative instrument assets-hedges, or account 66, derivative instrument liabilities-hedges, as appropriate, with a corresponding adjustment to the subaccount of the item being hedged. The ineffective portion of the hedge transaction shall be reflected in the same income or expense account that will be used when the hedged item enters into the determination of net income. In the case of a fair value hedge of a firm commitment, a new asset or liability is created. As a result of the hedge relationship, the new asset or liability will become part of the carrying amount of the item being hedged.
(e) If the carrier designates the derivative instrument as a cash flow hedge against exposure to variable cash flows of a probable forecasted transaction, it shall record changes in the fair value of the derivative instrument in account 47, derivative instrument assets-hedges, or account 66, derivative instrument liabilities-hedges, as appropriate, with a corresponding amount in account 77, accumulated other comprehensive income, for the effective portion of the hedge. The ineffective portion of the hedge transaction shall be reflected in the same income or expense account that will be used when the hedged item enters into the determination of net income. Amounts recorded in other comprehensive income shall be reclassified into earnings in the same period or periods that the hedged forecasted item enters into the determination of net income.
1–19 Accounting for asset retirement obligations.
(a) An asset retirement obligation represents a liability for the legal obligation associated with the retirement of a tangible long-lived asset that a utility is required to settle as a result of an existing or enacted law, statute, ordinance, or written or oral contract or by legal construction of a contract under the doctrine of promissory estoppel. An asset retirement cost represents the amount capitalized when the liability is recognized for the long-lived asset that gives rise to the legal obligation. The amount recognized for the liability and an associated asset retirement cost shall be stated at the fair value of the asset retirement obligation in the period in which the obligation is incurred.
(b) The carrier shall initially record a liability for an asset retirement obligation in account 67, Asset retirement obligations, and charge the associated asset retirement costs to account 30, Carrier property, and account 34, Noncarrier property, as appropriate, related to the property that gives rise to the legal obligation. The asset retirement cost shall be depreciated over the useful life of the related asset that gives rise to the obligations. For periods subsequent to the initial recording of the asset retirement obligation, a carrier shall recognize the period to period changes of the asset retirement obligation that result from the passage of time due to the accretion of the liability and any subsequent measurement revisions to the initial liability for the legal obligation recorded in account 67, Asset retirement obligations, as follows:
(1) The carrier shall record the accretion of the liability by debiting account 591, Accretion expense, for carrier property, account 620, Income (net) from noncarrier property, for noncarrier property and crediting account 67, Asset retirement obligations; and
(2) The carrier shall recognize any subsequent measurement changes of the liability initially recorded in account 67, Asset retirement obligations, for each specific asset retirement obligation as an adjustment of that liability in account 67 with the corresponding adjustment to carrier property and noncarrier property accounts, as appropriate. The utility shall on a timely basis monitor any measurement changes of the asset retirement obligations.
(c) Gains or losses resulting from the final settlement of asset retirement obligations for carrier plant resulting from the difference between the amount of the liability for the asset retirement obligation in account 67, Asset retirement obligations, and the actual amount to settle the obligation, shall be recorded in account 592, Gains or losses on asset retirement obligations.
(d) Gains or losses resulting from the final settlement of asset retirement obligations for noncarrier plant resulting from the difference between the amount of the liability for the asset retirement obligation in account 67, Asset retirement obligations, and the actual amount to settle the obligation, shall be recorded in account 620, Income (net) from noncarrier property.
(e) Separate subsidiary records shall be maintained for each asset retirement obligation showing the initial liability and associated asset retirement cost, any incremental amounts of the liability incurred in subsequent reporting periods for additional layers of the original liability and related asset retirement cost, the accretion of the liability, the subsequent measurement changes to the asset retirement obligation, the depreciation and amortization of the asset retirement costs and related accumulated depreciation, and the settlement date and actual amount paid to settle the obligation. For purposes of analyses a carrier shall maintain supporting documentation so as to be able to furnish accurately and expeditiously with respect to each asset retirement obligation the full details of the identity and nature of the legal obligation, the year incurred, the identity of the plant giving rise to the obligation, the full particulars relating to each component and supporting computations related to the measurement of the asset retirement obligation.
2–1 Current assets. In the group of accounts designated as current assets shall be included cash and other assets or resources commonly identified as those which are reasonably expected to be realized in cash or sold or consumed within a one-year period. There shall not be included any amount the collection of which is not reasonably assured by the known financial condition of the debtor or otherwise. Items of current character but of doubtful value shall be written down or written off to account 510, Supplies and Expenses, or to account 660, Miscellaneous Income Charges, as appropriate.
2–2 Investments and special funds. (a) This group of accounts shall include the cost of long-term investments in securities other than those of the accounting carrier, investment advances, sinking and other funds, cash value of life insurance policies, and other items of similar nature.
(b) Investment in securities shall be recorded at cost at time of acquisition excluding amounts paid for accrued interest and dividends. When securities with a fixed maturity date are purchased at a discount or premium, such discount or premium shall be amortized over the remaining life of the securities by periodical debits or credits to the account in which the cost of the securities is recorded with corresponding credits or debits to interest income. If the amount of the discount or premium is minor, the investment may be maintained at actual cost without adjustment, and the amount of discount or premium recorded in the interest income account at the time the securities mature.
(c)(1) For financial statement purposes the carrier shall follow the principles of equity accounting for (1) all investments in corporate joint ventures (see definition 31(c)), and (2) all investments in voting stock of affiliated companies giving the carrier the ability to significantly influence the operating and financial policies of an investee (see definition 31(b)). For purposes of this instruction an investment of 20 percent or more of the outstanding voting stock of an investee will indicate the ability to exercise significant influence over an investee in the absence of evidence to the contrary.
(2) Since the equity method is not to be effected by entries in the books of accounts but is to apply only in financial reports to the Commission, the carrier shall establish worksheet or memorandum accounts. Three basic worksheet or memorandum accounts are needed:
(a) An investment account to include (1) equity in the undistributed earnings or losses of the investee since the date of acquisition (see definition 31(g)); (2) accumulated amortization of the difference between cost and net assets at date of acquisition (see (c)(3) below); and other adjustments for disposition or writedown of investments.
(b) An income account to include (1) the investor’s share of the investee’s undistributed profits or losses for each reporting period subsequent to acquisition of the investment except that in the year of acquisition such amount shall be determined from the date of acquisition; (2) amortization for the reporting period of the difference between cost and net assets at date of acquisition. This account shall be closed at year-end to the retained income memorandum account discussed in paragraph (c) below.
(c) A retained income account to include (1) equity in the undistributed earnings or losses of the investee since the date of acquisition; (2) accumulated amortization of the difference between cost and net assets acquired at date of acquisition (see (c)(3) below).
(d) Other memorandum accounts will be needed for such adjustments as gains and losses on disposition of investments, recognition of impairments in value, the investor’s share of extraordinary and prior period items reported in the investee’s financial statements (see instruction 1–6), and provision for deferred taxes where it is reasonable to assume that undistributed earnings of an investee will be transferred to the investor in a taxable distribution. These memorandum accounts shall be closed at year-end to the retained income memorandum account discussed in paragraph (c) above.
(3) The carrier shall retain the following information for each investee in support of the worksheet or memorandum accounts:
(a) Original cost of investment.
(b) Equity in net assets of investee at date of acquisition.
(c) Allocation of difference between cost and equity in net assets, namely, to specific assets of investee or to goodwill.
(d) Accumulated amortization of difference between cost and equity in net assets.
(e) Unamortized balance of difference between cost and equity in net assets.
(f) Equity in undistributed earnings/losses for each year since date of acquisition.
(g) Dividends received since date of acquisition if determinable.
(h) Proceeds from sale of investments.
(4) Any difference between the investor’s cost and its share of the net assets of the investee at date of acquisition shall be allocated to specific assets of the investee to the extent the difference is attributable to them. When the difference is allocated to depreciable or amortizable assets, depreciation and amortization (through the investment and income memorandum accounts) should absorb the difference over the remaining life of the related assets. If the difference is not related to specific accounts, it should be considered goodwill and amortized over a reasonable period not to exceed 40 years. For investments made prior to November 1, 1970, amortization of goodwill is not required in the absence of evidence that the goodwill has a limited term of existence.
(5) The financial statements of the investee that are used for equity accounting should be timely. If the accounting year of the investee differs from that of the investor then the most recent available financial statements may be used. The lag in reporting should be consistent from period to period.
(6) Material profits or losses on transactions between the investor and investee shall be eliminated until realized by either company as if the two were consolidated.
(7) A transaction of the investee of a capital nature that affects the investor’s share of the investee’s stockholder’s equity should be reported in the financial statements as if the two were consolidated.
(8) The investor shall deduct any dividends applicable to outstanding cumulative preferred stock whether or not declared, and any other dividends declared when computing its share of undistributed earnings or losses.
(9) The investor shall suspend application of the equity method when the investment (including the investment memorandum account) together with any net advances made to the investee is reduced to zero. Additional losses shall not be provided for unless the investor has guaranteed obligations of the investee or is otherwise committed to provide further financial support for the investee. If the investee subsequently reports net income the investor shall resume applying the equity method at such time as its share of that net income equals the share of net losses not recognized during the period of suspension.
(10) When the investor’s voting stock interest falls below the level of ownership described in paragraph (c)(1) of this instruction, the investment no longer qualifies for the equity method. Should dividends received on the investment in subsequent periods exceed the investor’s share of earnings for such periods, the investment memorandum and income memorandum accounts shall be reduced by the excess amount.
(11) When the level of ownership of an investment increases to that described in paragraph (c)(1) of this instruction, the equity method shall be applied. The memorandum accounts for the investment, income (for current year’s equity in undistributed earnings less amortization), and retained income (for prior years’ equity in undistributed earnings less amortization) shall be adjusted retroactively on a step-by-step basis determining the equity in net assets at date of acquisition, amortization adjustment, and equity in undistributed earnings or losses at each level of ownership. Where small purchases are made over a period of time and then a purchase is made which qualifies the investment for the equity method, the date of latest purchase may be used as date of acquisition. In those situations where the information needed to apply the equity method is not determinable, the date of acquisition may be considered as January 1, 1974.
(12) Information having significance with respect to the investor’s ownership in investees shall be disclosed in notes to financial statements of annual reports filed with the Commission in accordance with generally accepted accounting principles.
The carrier shall follow generally accepted accounting principles where an interpretation of the rules for equity accounting is needed or obtain an interpretation from its public accountant or the Commission.
2–3 Tangible property. The cost of property owned that is devoted to transportation service shall be recorded in account 30, Carrier Property, and in account 33, Operating Oil Supply. This includes carrier’s investment in jointly-owned transportation property in which it has an undivided ownership interest. The cost of other property not directly associated with pipeline operations shall be included in account 34, Noncarrier Property. Property used in both carrier and noncarrier services shall be classified in account 30 or account 34 according to its dominant use.
2–4 Other assets and deferred charges. Account 40, Organization Costs and Other Intangibles, is prescribed for organization costs and other intangible assets, such as patents and franchises. These intangible assets shall be recorded at cost. Accounts are also prescribed for assets not otherwise provided for and for charges applicable to future periods.
2–5 Current liabilities. In this group of accounts shall be included obligations which are payable on demand or mature or become due within one year from the date of the balance sheet.
2–6 Noncurrent liabilities. Includible under this category of account are those obligations which are not due to be liquidated within one year from the date of the balance sheet. Estimates of future fire losses or other contingencies shall not be accounted for as current expenses or recorded as liabilities. Such contingencies may be provided for by appropriations of retained income, the losses to be recognized in income when sustained.
2–7 Contingent assets and liabilities.
(a) A contingency is an existing condition, situation, or set of circumstances involving uncertainty as to possible gain or loss to a carrier that will ultimately be resolved when one or more future events occur or fail to occur. Resolution of the uncertainty may confirm the acquisition of an asset or the reduction of a liability or the loss or impairment of an asset or the incurrence of a liability.
(b) An estimated loss from a contingent liability shall be charged to income if it is probable that an asset had been impaired or a liability had been incurred and the amount of the loss can be reasonably estimated. The carrier shall disclose in a footnote in its annual report any accrued contingent liabilities, along with any contingent liabilities not meeting both conditions for accrual if there is a reasonable possibility that a liability may have been incurred.
(c) Contingent assets should not be reflected in the accounts. The carrier shall disclose in a footnote in its annual report any contingencies that might result in an asset.
3–1 Property acquired. (a) In general the carrier property accounts shall be charged with the cost of property purchased or constructed and with the cost of additions and improvements. However, the acquisition of properties comprising a distinct operating system, or an integral portion thereof, when the purchase price exceeds $250,000, shall be accounted for in accordance with the provisions set forth in instruction 3–11.
(b) The cost of purchased property is the net price paid on a cash basis, or if other than money is given, the current value of that consideration. Cost includes the purchase price; sales, use, and excise taxes, and ad valorem taxes during periods of construction; transportation charges; insurance in transit; installation charges; and expenditures for testing and final preparation for use.
(c) Property acquired from an affiliated company through purchase or transfer shall be recorded together with the related accrued depreciation and liabilities assumed, if any, in the appropriate property accounts at the same amount that it was recorded on the books of the affiliate. When the purchase price exceeds the net book value of the property acquired, the difference shall be charged to retained income. When the purchase price is less than the net book value, the difference shall be credited to account 73, Additional Paid-in Capital. This does not apply to small miscellaneous purchases or transfers.
(d) The purchase of a proportionate share of a pipeline system or facility owned in undivided interests shall be recorded at the amount that the percentage of interest acquired bears to the whole. Any excess of deficiency of purchase price over the amount so recorded shall be debited to account 44, Other Deferred Charges, or credited to account 63, Other Noncurrent Liabilities, as appropriate, and amortized in equal periodic amounts over the remaining service life of the system or facility through income.
3–2 [Reserved]
3–3 Cost of property constructed. The cost of constructing property chargeable to the carrier property accounts shall include direct and other costs as described hereunder:
(1) Cost of labor includes the amount paid for labor performed by the carrier’s own employees and officers. This includes payroll taxes, vacation pay, pensions, holiday pay and traveling and other incidental expenses of employees. No charge shall be made to these accounts for pay and expenses of officers and employees who merely render services incidentally in connection with extensions, additions or replacements.
(2) Cost of material and supplies includes the purchase price (less purchase and trade discounts) of material and supplies, including small tools, at the point of free delivery; costs of inspection and loading borne by the carrier; transportation charges; sales, use and excise taxes; and when applicable a proportionate share of stores expenses. In calculating the cost of material and supplies used, proper allowance shall be made for the value of unused portions and other salvage, for the value of the material recovered from temporary scaffolding, cofferdams and other temporary structures used in construction: and for the value of small tools recovered and used for other purposes.
(3)(i) Cost of special machine service includes the cost of labor expended and of materials and supplies consumed in maintaining and operating vehicles, equipment, and other machines used in construction work; and rents paid for the use of such machines.
(ii) When machines are purchased primarily for a construction project, their cost shall be charged to account 187, Construction Work in Progress. Upon completion of the construction project, account 187 shall be credited with amounts received for machines sold or the book cost (less a fair allowance for depreciation during the construction period) of machines retained for use in carrier service. The net book cost shall be included in the appropriate carrier property accounts.
(iii) The cost of repairs to vehicles and other work equipment and of machine tools and machinery which are used both in construction and maintenance work shall be apportioned equitably to the work in connection with which the equipment is used.
(4) Cost of transportation includes the amounts paid to other companies or individuals for the transportation of employees, material and supplies, special machine outfits, appliances, and tools in connection with construction and also the cost of hauling performed by the carrier’s own forces and facilities. The cost of the transportation of construction material to the point where material is received by the carrier shall be included, so far as practicable, as a part of the cost of such material.
(5) Cost of contract work includes amounts paid for construction work performed under contract by other companies, firms, or individuals, and cost incident to the award of the contract.
(6) Cost of protection includes expenditures for protection in connection with construction. This includes the cost of protection against fires, cost of detecting and prosecuting incendiaries, amounts paid to municipal corporations and others for fire protection, cost of protecting property of others from damages, and analogous items.
(7) Cost of injuries and damages includes expenditures for injuries to persons or damage to property when incident to construction projects, and shall be included in the cost of the related construction work. It also includes that portion of premiums paid for insuring property prior to the completion or coming into service of the property insured. Insurance recovered for compensation paid for injuries to persons incident to construction shall be credited to the accounts to which such compensation is charged. Any insurance recovered for damages to property incident to construction shall be credited to the accounts chargeable with the expenditures necessary for restoring the damaged property. The cost of injuries and damages in connection with the removal of old structures which are encumbrances on newly acquired lands shall be included in the cost of land, or rights of way.
(8) Cost of privileges and permits includes compensation for temporary privileges, such as the use of private or public property or of streets, in connection with construction work.
(9) Taxes include taxes on property during construction and before the facilities are completed and ready for service. This includes taxes on land held under a definite plan for its use in pipeline service for the period prior to the completion of pipeline facilities thereon and other taxes separately assessed on property during construction, or assessed under conditions which permit separate identification or allocation of the amount chargeable to construction.
(10) Rent includes payments for use of facilities, such as motor vehicles, special tools or machines, and quarters used for construction work.
(11)(i) Interest during construction includes interest expense on bonds, notes and other interest bearing debt incurred in the construction of carrier property (less interest, if any, earned on funds temporarily invested) after such funds become available for use and before the receipt or the completion or coming into service of the property. The interest shall be included in the accounts charged with the cost of the property to which related.
(ii) There shall be deducted from such interest charges a proportion of premium on securities sold. There shall be added a proportion of discount and expense on funded debt issued for the acquisition or construction of carrier property. The amount of premium and discount and expense thus related shall be determined by the ratio which the period between the date the proceeds from the securities issued become available and the receipt, completion, or coming into service of the property bears to the entire life of the securities issued.
(iii) Interest during construction shall not be recognized on the asset retirement costs incurred during the construction of carrier and noncarrier property.
(12) Cost of disposing of excavated material shall be included in the cost of construction except that when such material is used for filling, the cost of loading, hauling, and dumping shall be equitably apportioned between the work for which removal is made and the work for which the material is used.
(13) Asset retirement costs that are recognized as a result of asset retirement obligations incurred during construction shall be included in the cost of construction costs.
3–4 Additions. Each carrier shall maintain a written property units listing for use in accounting for additions and retirements of carrier plant and apply the listing consistently. When property units are added to Carrier plant, the cost thereof shall be added to the appropriate carrier plant account as set forth in the policy.
3–5 Improvements. Costs of improvements, shall be accounted for as follows:
(a) The cost of items replaced shall be retired and the cost of the improvement shall be charged to the appropriate property account.
(b) If the improvement does not involve a replacement, the cost of the improvement shall be charged to the appropriate property account.
3–6 Replacements. Replacements are substitutions of a part or of a complete unit of property with a new part or unit. Costs of replacements shall be accounted for as follows:
(a) In replacing a complete unit of property, the old unit shall be retired and the cost of the replacement recorded in the appropriate primary property account.
(b) In replacing a minor item without improvement, the cost of such replacement shall be charged to the maintenance expense account.
3–7 Retirements. When property units are retired from carrier plant, with or without replacement, the cost thereof and the cost of minor items of property retired and not replaced shall be credited to the carrier plant account in which it is included. The retirement of carrier property shall be accounted for as follows:
(a) Land. The book cost of land retired shall be removed from the property accounts. Gain or loss on the sale of land shall be recorded in account 640, Miscellaneous Income, or account 660, Miscellaneous Income Charges.
(b) Property. (1) The book cost, as set forth in paragraph c below, of units of property retired and of minor items of property retired and not replaced shall be written out of the property account as of date of retirement, and the service value shall be charged to account 31, Accrued Depreciation—Carrier Property.
(2) In case of casualty loss, insurance proceeds recovered shall be credited to account 31, Accrued Depreciation—Carrier Property, in an amount not to exceed the book cost of the property involved. Any excess amount shall be credited to account 640, Miscellaneous Income.
(3) Carrier property no longer used nor held for carrier operations but used or intended for use in noncarrier operations shall be transferred, along with the amount of past accrued depreciation, estimated if necessary, to noncarrier property.
(c) The book cost of carrier property retired shall be determined from the carrier’s records and if this cannot be done it shall be estimated. When it is impracticable to determine the book cost of each unit, due to the relatively large number or small cost thereof, an appropriate average book cost of the units, with due allowance for any differences in size and character, shall be used as the book cost of the units retired. Oil pipelines must furnish the particulars of such estimates to the Commission, if requested.
3–8 Salvage. (a) When retired property is salvaged for material or parts which are to be reused by the carrier, the salvage shall be priced at current second-hand value, not to exceed original cost, and charged to account 17, Material and Supplies, or other appropriate account.
(b) When retired property is held without being dismantled, the estimated value of the salvage less the estimated cost of salvaging shall be included in account 19, Other Current Assets, if to be recovered within a year, otherwise, in account 43, Miscellaneous Other Assets.
3–9 Relocation of line. (a) If a line is relocated in the same gathering field serving the same lease or purpose, all of the relocating expenses whether or not a unit of property is involved shall be charged to maintenance expense, provided that the same size pipe is used in such relocation. Resulting increases or decreases in the length of the line shall be accounted for as additions or retirements of property.
(b) In accounting for relocation of trunk lines involving units of property, the replaced property shall be retired and the cost of the new property included in the appropriate primary property accounts. When public improvement projects are involved, the cost of the new property shall be (1) the book cost less depreciation or amortization of the replaced property, less the net salvage value recovered, plus (2) costs incurred by the carrier, less any amounts contributed by governmental agencies or others.
3–10 Property contributed. (a) The value of contributions or property received from others including governmental agencies shall not be recorded in the property accounts; however, memorandum entries should be made in the records of the carrier describing the property received, the value thereof, and all other pertinent information related thereto.
(b) Property contributed by an affiliate shall be recorded in the property accounts together with the related accrued depreciation at the same amounts that were recorded on the books of the affiliate provided, however, that the amount of contribution made by non-carrier affiliates shall not exceed the fair value of the property received.
3–11 Acquisition by merger, consolidation or purchase. Accounting for property acquired by business combination of two or more corporations, or the acquisition of properties comprising a distinct operating system, or integral portion thereof as specified in section 3–1, shall depend on whether there has been (1) a merger or consolidation in a “pooling of interests” or (2) a “purchase.” A “pooling of interests” may exist when holders of all or substantially all of the ownership interests, usually common stock, in the constituent corporations or entities become the owners of a surviving corporation or a new corporation which owns the assets and business of the constituent corporations or entities directly or through one or more subsidiaries. However, when the stockholders of one of the constituent corporations obtain 90 percent or more of the voting interest in the combined enterprise; or when there is a plan or firm intention and understanding to retire a substantial part of the capital stock issued to the owners of one or more of the constituent corporations or substantial changes in ownership which occurred shortly before or planned to occur shortly after the combination, the combination may be considered a “purchase.”
(a) Accounting under a “pooling in interest.” (1) In accounting for a “pooling of interests,” no new basis of accountability arises. The assets and liabilities of the constituent companies or entities and the related accrued depreciation and amortization accounts along with the retained income or deficit accounts shall be carried forward, adjusted, if necessary, to conform with the accounting rules of the Commission.
(2) When the total par value or stated value of no-par capital stock of the succeeding corporation is greater than that of the constituent corporations, the excess shall be charged first to the amount in account 73, Additional Paid-in Capital, that is not otherwise restricted, and the Balance to account 75, Unappropriated Retained Income.
(3) When the par value or stated value of no-par capital stock of the succeeding corporation is less than that of the constituent corporations, the difference shall be credited to account 73, Additional Paid-in Capital.
(b) Accounting under a “purchase.” In accounting for a “purchase,” the assets shall be recorded on the books of the acquiring carrier at cost as of the date of acquisition or, if other than money is given, at the fair value of such consideration. Liabilities assumed shall be recorded in the appropriate accounts according to the accounting rules of the Commission.
(c) Approval of accounting. (1) Tentative journal entries recording the acquisition of pipeline properties shall be submitted to the Commission for consideration and approval. The entries shall give a complete description of the property purchased and the basis upon which the amounts of the entries have been determined. Any portion of the purchase price attributable to intangible property shall be separately recorded as hereinafter provided in account 40, Organization Costs and Other Intangibles.
(2) When the costs of individual or groups of transportation property are not specified in the agreement or in supporting documents, or when separate costs are not provided for the physical property and the intangible property, the total purchase price shall be equitably apportioned among the appropriate property or other accounts, based on the percentage relationship between the purchase price and the original cost of property shown in the valuation records of the Commission or the fair market value of the properties. The portion of the total price assignable to the physical property shall be supported by independent appraisal or such other information as the Commission may consider appropriate. In no event shall amounts recorded for physical properties and other assets acquired exceed the total purchase price.
(3)(a) Where the purchase price is in excess of amounts recorded for the net assets acquired, such excess shall be included in account 40, Organization Costs and Other Intangibles.
(b) The excess of the purchase price over amounts includable in the primary carrier property accounts shall be amortized through account 660, “Miscellaneous income charges,” or otherwise disposed of, as the Commission may approve or direct.
3–12 Reorganizations. When a carrier is involved in receivership or bankruptcy so as to effect a reorganization, all accounting relating to the plan of reorganization shall be submitted to this Commission for consideration and approval.
3–13 Disposition of former Account 193, Acquisition Adjustment. Amounts included in former account 193, Acquisition Adjustment, attributable to mergers, consolidations, reorganizations, and purchases of property shall be cleared from that account as the Commission may authorize or direct upon submission of proposal for distribution of the amounts therein.
4–1 Detail of accounts. The carrier shall keep the prescribed accounts with sufficient particularity to permit the reporting of operating revenues and expenses for crude oil lines and for product lines separately, and to permit the allocation of operating expenses by service functions (see 4–3 Operating Expenses).
4–2 Operating revenues. The operating revenue accounts are designed to show the amount of money which the carrier becomes entitled to receive or which accrues to its benefit for transportation and services incidental thereto.
4–3 Operating expenses. The operating expense accounts are designed to show the costs of pipeline operations by service functions. The expenses of pipeline operations are to be allocated to the following functions:
(a) Gathering. This includes the gathering and collection of oil, oil products and other commodities from oil field, refinery, or other source (other than carrier’s own terminal and delivery facilities), and transmission to point of connection to meters, working or storage tanks, or intake side of the manifold at the trunk line receiving site or station, or at a terminal.
(b) Trunk. This includes the trunk line transportation of crude oil, oil products and other commodities from origin or receiving station to point of connection with other carriers, consignee facilities at destination, or to the discharge side of the manifold or connection to working or storage tanks at the destination station.
(c) Delivery. This includes the receiving, storage, and delivering at terminal and delivery facilities of crude oil, oil products and other commodities from or to railroads, motor carriers, water carriers, and others prior or subsequent to movement by pipeline.
4–4 Expense classification. The primary expense accounts are to be reported under the following classifications:
(a) Operations and maintenance expense. This group of accounts includes all costs directly associated with the operation, repairs and maintenance of property devoted to pipeline operations including scheduling, dispatching, movement, and delivery of crude oil, oil products and other commodities.
(b) General expense. This group of accounts includes general and administrative expense and all other expenses not directly allocable to operations and maintenance expenses.
4–5 Expense distribution. The several classes of expenses shall be directly allocated to applicable service functions to the fullest possible extent. Expenses common to two or more functions and system expenses shall be equitably apportioned to the service functions. The basis for apportionment and the underlying records in support thereof shall be readily available for inspection by the Commission’s examiners.
This account shall include money, checks, sight drafts and sight bills of exchange, money in banks or in other depositories subject to withdrawal on demand, and other similar items. The amount of checks and sight drafts transmitted to payees which are unpaid at the close of the accounting period shall be credited to this account.
Compensating balances (see Definition 33) under an agreement which legally restricts the use of such funds shall not be included in this account. Such balances shall be included in account 10–5 “Special deposits” or account 22 “Sinking and other funds.”
This account shall include cash deposits, either placed in hands of trustees or under the direct control of the reporting company, which are restricted for specific purposes. Examples are those deposits made for the payment of dividends and interest due within one year, the liquidation of other current liabilities, to guarantee fulfillment of current contract obligations, to meet specific operating requirements, or compensating balances (see Definition 33) under an agreement which legally restricts the use of such funds and which constitute support for short-term borrowing arrangements. Sub-accounts may be set up, if necessary to account for special deposits for specific purposes.
Deposits available for general company purposes shall be included in account 10 “Cash.”
(a) This account shall include the cost of securities and other collectible obligations acquired for the purpose of temporarily investing cash, such as United States Treasury certificates, marketable securities, time drafts receivable, demand loans, time deposits with banks and trust companies, and other similar investments of a temporary character. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments.
(b) This account shall be subdivided to reflect the marketable equity securities’ portion and other temporary investments. (See Instruction 1–15).
This account shall include the book cost, not includible elsewhere, of all collectible obligations in the form of notes receivable, contracts receivable, and similar evidences (except interest coupons) of money receivable on demand or within a time not exceeding one year from date of the balance sheet. Notes receivable from affiliates shall be included in account 13, Receivables from Affiliated Companies.
(a) This account shall include amounts receivable due and accrued from affiliated companies subject to settlement within one year from date of the balance sheet. This includes receivables for items such as revenue for services rendered, material furnished, rent, interest and dividends, advances and notes.
(b) An oil pipeline company participating in a cash management program must maintain supporting documentation for all deposits into, borrowings from, interest income from, and interest expense to such program. Cash management programs include all agreements in which funds in excess of the daily needs of the oil pipeline company along with the excess funds of the oil pipeline company’s parent, affiliated and subsidiary companies are concentrated, consolidated, or otherwise made available for use by other entities within the corporate group. The written documentation must include the following information:
(1) For deposits with and withdrawals from the cash management program: The date of the deposit or withdrawal, the amount of the deposit or withdrawal, and the maturity date, if any, of the deposit;
(2) For borrowings from a cash management program: The date of the borrowing, the amount of the borrowing, and the maturity date, if any, of the borrowing;
(3) The security, if any, provided by the cash management program for repayment of deposits into the cash management program and the security required, if any, by the cash management program in support of borrowings from the program; and
(4) The monthly balance of the cash management program.
(c) The oil pipeline company must maintain current and up-to-date copies of the documents authorizing the establishment of the cash management program including the following:
(1) The duties and responsibilities of the administrator and the oil pipeline company in the cash management program;
(2) The restrictions on deposits or borrowings by oil pipeline companies in the cash management program;
(3) The interest rate, including the method used to determine the interest earning rates and interest borrowing rates for deposits into and borrowings from the program; and
(4) The method used to allocate interest income and expenses among oil pipeline companies in the program.
This account shall include amounts receivable due and accrued from other than affiliates which are subject to settlement within one year from date of the balance sheet. This includes items such as revenue for services rendered, material furnished, rent, accounts of officers and employees, miscellaneous accounts with others.
This account shall be credited with amounts provided for losses on notes and accounts receivable which may become uncollectible, and also with collections on accounts previously charged hereto. This account shall be charged with any amounts which have been found to be impractical of collection.
(a) This account shall include the amount of interest due and accrued as of the date of the balance sheet on all interest-bearing obligations held by the carrier. This account shall also include the amount of dividends declared on stocks owned.
(b) Interest and dividends receivable from affiliated companies or on the carrier’s own securities shall not be included in this account.
(a) This account shall include the cost of oil purchased and the value of oil acquired through tariff allowances and operating gains. Amounts paid preceding carriers for transportation, customs duties, or similar charges shall be charged to account 230, Allowance Oil Revenue. Additions to inventory from tariff allowances shall be credited to revenue at current value. Additions resulting from operating gains shall be credited against operating oil losses and shortages.
(b) The cost or value of oil owned by the carrier and used to maintain lines and working tanks in condition for transportation operations shall be included in account 33, Operating Oil Supply.
(a) This account shall include the cost, including sales, use and excise taxes and transportation costs to point of delivery, less purchase and trade discounts, of all unapplied material and supplies, such as line pipe, line pipe fittings, fuel, tools, and other pipeline supplies. The value of items being manufactured by the carrier and the fair value of salvaged material shall also be included herein.
(b) Carriers shall take annual inventories of material and supplies and shall make the adjustments necessary to reconcile the books to the inventory figures. To the extent practicable, adjustments shall be made directly to the same accounts to which such material and supplies were charged during the period. Differences that cannot be directly allocated shall be equitably apportioned among the accounts to which material was charged since the last inventory.
This account shall include the amount of expenses paid in advance of accrual such as insurance, rent, and taxes, the benefits of which are to be realized in subsequent periods. Monthly transfers shall be made to the appropriate expense or other accounts for the expired portion of the prepayments applicable to that month.
This account shall include such items as estimated tax refunds receivable, legally enforceable, balances due on subscriptions to capital stock, temporary guaranty and other deposits, and all other current assets due within one year which are not includible in the other current asset accounts.
(a) This account shall include the portion of deferred income tax assets and liabilities relating to current assets and liabilities, when the balance is a net debit.
(b) A net credit balance shall be included in Account 59, Deferred income tax liabilities.
This account shall include the cost of investments in securities (other than securities held in special funds) and investment advances made to affiliated companies. Separate records shall be maintained to show the securities pledged and the following classes of investments in each affiliated company:
(a) Stocks.
(b) Bonds.
(c) Other secured obligations.
(d) Unsecured notes.
(e) Investment advances.
This account shall include the cost of investments in securities of (other than securities held in special funds) and advances made to other than affiliated companies. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments. Separate records shall be maintained to show the securities pledged and the following classes of investments in each nonaffiliated company:
(a) Stocks.
(b) Bonds.
(c) Other secured obligations.
(d) Unsecured notes.
(e) Investment advances.
(a) This account shall include cash and cost of investments in securities and other assets, trusteed or otherwise restricted, that have been segregated in distinct funds for purposes of redeeming outstanding obligations; purchasing or replacing assets; paying pensions, relief, hospitalization, and other similar items. This account shall also include unrealized holding gains and losses on trading and available-for-sale types of security investments. The cash value of life insurance policies on the lives of employees and officers to the extent that the carrier is the beneficiary of such policies shall also be included in this account. Separate subsidiary records shall be maintained for each distinct fund.
(b) Securities issued or assumed by the accounting company shall be recorded at par or stated value.
(c) This account shall include compensating balances (see Definition 34) under an agreement which legally restricts the use of such funds and which constitute support for long-term borrowing arrangements.
This account shall include the cost of tangible property used in carrier service, or held for such use within a reasonable time under a definite plan for pipeline operations. Separate primary accounts are prescribed for each class of carrier property.
This account shall be credited with amounts charged to operating expenses or other accounts representing the loss in service value of depreciable carrier property. The service value of depreciable property retired shall be charged to this account. It shall also include other entries as may be authorized by the Commission. Detail of this account shall be maintained by primary property accounts. Separate subsidiary records shall be maintained for the amount of accrued cost of removal other than legal obligations for the retirement of property recorded in account 31, Accrued depreciation—Carrier property.
This account shall be credited with amounts charged to operating expenses or other accounts representing the loss in service value of carrier property subject to amortization accounting as authorized by the Commission. Upon the retirement of property subject to amortization this account shall be charged with the amount included herein applicable to the specific property at the time the property is retired. Subsidiary records shall be maintained for each group of property items under a separate amortization authorization.
This account shall include the cost of oil purchased and the value of oil added through tariff allowances and operating gains which is used to maintain lines and tanks in working condition. Additions to operating supply from tariff allowances shall be credited to revenue at current value. Additions resulting from operating gains shall be credited against operating oil losses and shortages.
This account shall include the cost of tangible property not used in carrier pipeline operations. This account shall also include, amounts recorded for asset retirement costs associated with noncarrier property.
This account shall be credited with amounts charged to income, representing the loss in service value of depreciable noncarrier property.
This account shall include the cost of intangible assets such as organizing the carrier, patents, permits, franchises, and goodwill. Organization costs include the legal expense, taxes, fees, stationery and printing, original capital stock expense and costs of economic feasibility studies made prior to initial operation of the carrier. Separate subsidiary records shall be maintained for each class of intangible asset.
This account shall be credited with the amounts charged to operating expenses or income representing the expired cost of intangible property. When the period of benefit of intangible property is fully expired, or assets are retired to which the intangible relates, this account shall be charged with the amount herein applicable to the specific property.
This account shall include such items as accounts receivable, utility deposits, guaranty deposits and other similar assets which are not expected to be realized or returned to the carrier within one year from date of the balance sheet. The estimated net salvage value of retired carrier property held without being dismantled shall be included in this account.
This account shall include items that cannot be disposed of until further information is received and items of a deferred nature, not provided for elsewhere, to be amortized to expense or other accounts in future periods. This includes such items as engineering surveys and studies and debt expense.
This account shall include the amount of deferred taxes determined in accordance with instruction 1–12 and the text of Account 64, Accumulated deferred income tax liabilities, when the balance is a net debit.
This account shall include the amounts paid for derivative instruments, and the change in the fair value of all derivative instrument assets not designated as cash flow or fair value hedges. Account 640, miscellaneous income, shall be credited or debited as appropriate with the corresponding amount of the change in the fair value of the derivative instrument.
(a) This account shall include the amounts paid for derivative instruments, and the change in the fair value of derivative instrument assets, designated by the utility as cash flow or fair value hedges.
(b) When a carrier designates a derivative instrument asset as a cash flow hedge, it will record the change in the fair value of the derivative instrument in this account with a concurrent charge to account 77, accumulated other comprehensive income, with the effective portion of the derivative gain or loss. The ineffective portion of the cash flow hedge shall be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
(c) When a carrier designates a derivative instrument as a fair value hedge, it shall record the change in the fair value of the derivative instrument in this account with a concurrent charge to a subaccount of the asset or liability that carries the item being hedged. The ineffective portion of the fair value hedge shall be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
This account shall include outstanding obligations in the form of notes, and other similar evidences of indebtedness payable on demand or within one year from the date of issue except those payable to affiliated companies.
This account shall not include obligations due within one year which are intended to be refinanced on a long-term basis. Long-term refinancing of short-term obligations means; (1) replacement with long-term obligations or equity securities, or (2) renewal, extension, or replacement with short-term obligations for an uninterrupted period extending beyond one year from the balance sheet date.
The intention to refinance on a long-term basis shall be supported by the ability to refinance. Evidence of this ability includes either; (1) the actual issuance of a long-term obligation or equity securities for the purpose of refinancing the short-term obligation, after the balance sheet date but before the balance sheet is issued, or (2) before the balance sheet is issued, the existence of a financing agreement which is long-term and based on terms readily determinable with no existing violations of its provisions, and with a lender which is financially capable of honoring the agreement.
This account shall include amounts payable due and accrued to affiliated companies (except interest and dividends) subject to settlement within one year from date of the balance sheet, and for which arrangements for long-term refinancing have not been made (See Note following account 50, “Notes Payable”). This includes payables for items such as services and material received, rent, advances and notes.
This account shall include amounts payable due and accrued (except those to affiliated companies) subject to settlement within one year from the date of the balance sheet. This includes payables for items such as joint revenue, material and supplies, services received, rents, claims, taxes collected from employees and others for account of taxing entities, and other similar items.
This account shall include salaries and wages payable due and accrued including vacation pay and unclaimed salaries and wages as of the balance sheet date. Unclaimed salaries and wages outstanding for more than one year may be written off to income unless the amount unclaimed escheats to the state.
This account shall include interest accrued or payable on all obligations.
This account shall include the amount of dividends (other than stock dividends) declared but unpaid as of the date of the balance sheet.
This account shall include all Federal, state, and local taxes (except taxes withheld from employees) accrued and payable, estimated if necessary, as of the balance sheet date. Prepaid taxes shall be shown as current assets in account 18, Prepayments. Subsidiary records shall be maintained to allow analyses of this account by matured and unmatured taxes and by type of tax and taxing entity.
This account shall include the amount of long-term debt which will mature and become payable within one year from date of the balance sheet for which arrangements for long-term refinancing have not been made (See note following account 50, “Notes Payable”).
This account shall include all other current liabilities not provided for elsewhere that are payable within one year from date of balance sheet.
(a) This account shall include the portion of deferred income tax assets and liabilities relating to current assets and liabilities, when the balance is a net credit.
(b) A net debit balance shall be included in Account 19–5, Deferred income tax assets.
This account shall include the total par value of the carrier’s outstanding obligations maturing more than one year from the date of the balance sheet, including obligations due within one year which are expected to be refinanced on a long-term basis (See note following account 52, “Accounts payable”). This account shall be divided to show the face value of (1) debt issued and actually outstanding, and (2) debt “nominally issued” and “nominally outstanding”. These accounts shall be further divided by the following classes of debt: mortgage bonds, collateral trusts, income bonds, miscellaneous obligations and nonnegotiable debt to affiliated companies.
This account shall include the premium received and not yet amortized on the issuance of long-term debt. The amount of premium received on each issue of bonds, mortgages, notes, and other long-term debt shall be amortized over the life of the debt by credit to interest expense.
Issue costs related to long-term debt (debt expense) shall be included in account 44. Other deferred charges, and amortized over the life of the debt by charge to account 660, Miscellaneous income charges.
This account shall include the amount of discount on long-term debt, and the amount of interest expressly provided for and included in the face amount of obligations issued or assumed and not amortized as of the balance sheet date. The amount of discount or interest applicable to each issue of debt obligation shall be amortized over the life of the respective debt by charge to interest expense.
Issue costs related to long-term debt (debt expense) shall be included in account 44, Other deferred charges, and amortized over the life of the debt by charge to account 660, Miscellaneous income charges.
(a) This account shall include such items as deferred revenue from rents or leases that will not be realizable as income within one year, and the liability for amounts contributed by employees or others for pensions, savings, and similar items. This account shall also include the amount accrued for pensions in which the employees have a vested right and which are administered by the carrier.
(a) This account shall be credited (charged) with amounts concurrently charged (credited) to account 671, Provision for deferred taxes and account 696, Provision for deferred taxes—extraordinary items, representing the net tax effect of changes in material temporary differences (see definition 30(e)) during the current accounting period.
(b) This account shall be credited with the amount of investment tax credit utilized in the current year for income tax purposes but deferred for accounting purposes (see instruction 1–12).
(c) This account shall be concurrently debited with amounts credited to account 671, Provision for deferred taxes representing amortization of amounts for investment tax credits deferred in prior accounting periods.
(d) This account shall be maintained in such a manner as to show separately: (1) The balance of deferred income taxes and deferred investment tax credit separately as of the beginning and as of the end of each year entries are made affecting the account balance, (2) the current years net credit or charges applicable to temporary differences and deferred investment tax credits.
The portion of deferred assets and liabilities relating to current assets and liabilities should likewise be classified as current and included in Account 19–5, Deferred Income Tax Assets, or Account 59, Deferred Income Tax Liabilities, as appropriate.
This account shall include a net credit balance only. A net debit balance shall be recorded in Account 45, Accumulated deferred income tax assets.
This account shall include the change in the fair value of all derivative instrument liabilities not designated as cash flow or fair value hedges. Account 660, miscellaneous income charges, shall be debited or credited as appropriate with the corresponding amount of the change in the fair value of the derivative instrument.
(a) This account shall include the change in the fair value of derivative instrument liabilities designated by the carrier as cash flow or fair value hedges.
(b) A carrier shall record the change in the fair value of a derivative instrument liability related to a cash flow hedge in this account, with a concurrent charge to account 77, accumulated other comprehensive income, with the effective portion of the derivative gain or loss. The ineffective portion of the cash flow hedge shall be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
(c) A carrier shall record the change in the fair of a derivative instrument liability related to a fair value hedge in this account, with a concurrent charge to a subaccount of the asset or liability that carries the item being hedged. The ineffective portion of the fair value hedge shall be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
(a) This account shall include liabilities arising from the recognition of asset retirement obligations. The carrier shall credit account 67, Asset retirement obligations, for the liabilities for asset retirement obligations and charge the appropriate carrier property accounts or noncarrier property accounts to record the related asset retirement costs.
(b) This account shall also include the period to period changes for the accretion of the liabilities in account 67, Asset retirement obligations. The carrier shall charge the accretion expense to account 591, Accretion expense, for carrier property, and account 620, Income (net) from noncarrier property, for noncarrier property, as appropriate, and credit account 67, Asset retirement obligations.
(c) This account shall be debited with amounts paid to settle the asset retirement obligations recorded herein.
(d) The utility shall clear from this account any gains or losses resulting from the settlement of asset retirement obligations in accordance with the instructions prescribed in General Instruction 1–19.
(a) This account shall include the par value of par value stock, stated value of no-par stock, and the amount received for no-par stock without stated value, which have been issued to bona fide purchasers and have not been reacquired and cancelled, also shares of stock nominally issued. When other than cash is received for no-par value stock, the fair market value of the consideration shall be entered in this account.
(b) This account shall be divided so as to show separately each class of stock issued, subdivided between (1) issued and outstanding, and (2) nominally issued and nominally outstanding.
(c) When an issue of capital stock or any part thereof is reacquired, either by purchase or donation, and is retired or cancelled, the par value shall be charged to this account. Any excess of reacquisition cost over par value shall be allocated between account 73, Additional Paid-in-Capital and 720, Other Debits to Retained Income. Any excess of par value over reacquisition cost shall be credited to account 73, Additional Paid-in-Capital.
(d) When an issue of capital stock or any part thereof is reacquired, either by purchase or donation, and is not retired or cancelled, nor properly includible in sinking or other funds, the reacquisition cost shall be charged to account 76, Treasury Stock.
(e) When treasury stock is resold, account 76, Treasury Stock, shall be credited with the cost paid for it. Gains shall be credited to account 73, Additional Paid-in-Capital. Losses shall be charged to account 73, Additional Paid-in-Capital to the extent that previous net gains from sales or retirements of the same class of stock are included therein; otherwise, to account 720, Other Debits to Retained Income.
This account shall include the excess of the actual cash value of the consideration received at the time of the original sale over the par or stated value of the stock issued.
This account shall include the full amount of the par value, stated value, or price agreed upon for no-par stock which has been subscribed under a legally binding purchase agreement. The difference between the par value or stated value, plus any premiums or the amount agreed upon for no-par stock, and the down payment or installments received, shall be recorded as a current asset in account 19, Other Current Assets. Appropriate subaccounts shall be kept to record separately the transactions for each class and series of stock involved.
This account shall include gains from purchase and resale of reacquired stock. Credits attributable to reductions in the par or stated value of capital stock may be included in this account only when approved by the Commission. Separate subaccounts shall be maintained for each class and series of stock. Also include herein contributions to capital made by stockholders and others.
This account shall include retained income which has been appropriated and set aside under contractual or legal requirements and for other specific purposes, such as the retirement of bonded indebtedness, contingencies, redemption of preferred capital stock; fire losses; plant replacement and additions; miscellaneous employee benefits; and similar items. Appropriations shall be released when their respective purposes have been served. Separate subaccounts shall be maintained for each specific purpose for which retained income is appropriated.
(a) This account shall include retained income which has not been appropriated or set aside for specific purposes. There shall be no transfers to or from account 73, Additional Paid-in Capital, to this account unless so authorized by the Commission.
(b) The balance of accounts 700 to 750, inclusive, shall be closed to this account at the end of each calendar year.
(a) This account shall include in subdivisions for each class the reacquisition cost of capital stock which has been actually issued or assumed by the carrier, then reacquired, and is neither retired nor cancelled, nor properly includible in sinking or other funds.
(b) This account shall be maintained to reflect separately securities pledged or unpledged.
(c) This account shall be shown on the Balance Sheet as a deduction in arriving at Stockholders’ Equity.
The accounting for the reacquisition of capital stock and resale thereof shall be in accordance with balance sheet account 70, paragraphs (c) through (e).
(a) This account shall include revenues, expenses, gains, and losses that are properly includable in other comprehensive income during the period. Examples of other comprehensive income include foreign currency items, minimum pension liability adjustments, unrealized gains and losses on certain investments in debt and equity securities, and cash flow hedges. Records supporting the entries to this account shall be maintained so that the utility can furnish the amount of other comprehensive income for each item included in this account.
(b) This account shall also be debited or credited, as appropriate, with amounts of accumulated other comprehensive income that have been included in the determination of net income during the period and in accumulated other comprehensive income in prior periods. Separate records for each category of items shall be maintained to identify the amount of the reclassification adjustments from accumulated other comprehensive income to earnings made during the period.
The following table lists the prescribed primary property accounts and indicates those accounts which contain similar items of property for which a single text is provided. The accounts are to be kept separately for crude oil lines and for product lines.
| Account number | Account Title | ||
|---|---|---|---|
| Gathering Lines | Trunk Lines | General | |
| 101 | 151 | 171 | Land. |
| 102 | 152 | Right of Way. | |
| 103 | 153 | Line Pipe. | |
| 104 | 154 | Line Pipe Fittings. | |
| 105 | 155 | Pipeline Construction. | |
| 106 | 156 | 176 | Buildings. |
| 107 | 157 | Boilers. | |
| 108 | 158 | Pumping Equipment. | |
| 109 | 159 | 179 | Machine Tools and Machinery. |
| 110 | 160 | Other Station Equipment. | |
| 111 | 161 | Oil Tanks. | |
| 112 | 162 | Delivery Facilities. | |
| 113 | 163 | 183 | Communication Systems. |
| 114 | 164 | 184 | Office Furniture and Equipment. |
| 115 | 165 | 185 | Vehicles and Other Work Equipment. |
| 116 | 166 | 186 | Other Property. |
| 187 | Construction Work in Progress. | ||
(a) This account shall include the cost of land held in fee and used in pipeline operations. Land not used in carrier service shall be recorded in account 34, Noncarrier Property. Irregular parcels of land without commercial value acquired with rights of way shall not be transferred to account 34 solely to make right of way boundaries regular.
(b) The cost of land and buildings acquired together shall be equitably separated and recorded. When land is acquired with buildings, structures, or other encumbrances that must be removed before the land is usable, demolition cost, less salvage, shall be added to the book cost of the land. Net proceeds from the sale of timber, minerals and improvements which were part of the land cost when purchased by the carrier, shall be credited to this account up to the amount of the purchase price allocated as their cost. Any excess shall be credited to account 640, Miscellaneous Income.
(c) Costs of filing, clearing, grading or leveling land, when such work is not directly associated with construction or a definite plan for construction, shall be charged to this account.
(d) All direct or incidental costs associated with the acquisition of the land and any taxes and public assessments assumed at the time of purchase, shall be included in this account.
(e) Special assessments for public improvements and also costs borne by the carrier for public improvements constructed by it shall be included in this account.
This account shall include the cost of obtaining rights of way used in pipeline operations. Periodic rents paid for the use of a right of way shall be charged to operating rents. Costs of filling, clearing, grading or leveling of a right of way when such work is not directly associated with construction or a definite plan for construction, shall be charged to this account.
This account shall include the cost of all line pipe actually laid in pipe lines devoted to transportation service.
This account shall include the cost of the line pipe fittings, including manifolds, used in pipe lines devoted to transportation service.
(a) This account shall include all the costs of constructing pipe lines except the cost of line pipe and fittings provided for in accounts 103, 153, Line Pipe, and 104, 154, Line Pipe Fittings.
(b) Includible shall be the cost of labor and materials such as casing and vent pipe, pipe coatings of all kinds, river weights, support structures, sand bags, valve boxes, cathodic protection devices, mile posts, right-of-way markers, excavating and backfilling, pipeline pits, and the cost of damages paid for the destruction of crops, timber, and other property during construction. The cost of reopening the trenches for repairs, or installation of casing, coating or cathodic protection, and the necessary backfilling shall be charged to maintenance expense.
This account shall include the cost of all buildings including the foundations, fixtures, and appurtenances thereto. This includes such items as architects’ fees, sidewalks, driveways, fences, permanent water rights, grading and preparing grounds before and after construction, utility lines and other service piping. Cost of restoring grounds after repair work shall be charged to maintenance expense.
This account shall include the cost of boilers, including accessories and attachments such as injectors, water gages, steam gages and fittings, and the cost of special boiler foundations and installations.
This account shall include the cost of engines, motors, pumps, and all other pumping equipment, and the cost of special foundations and installation.
This account shall include the cost of machine tools and machinery, including the cost of their special foundations and installation.
This account shall include the cost of all station equipment not provided for elsewhere, such as electric light, gas, and refrigeration equipment, manifolds, and miscellaneous equipment and fittings. It shall also include the carrier’s investment in tracks if located at and used in connection with a station.
This account shall include the cost of oil tanks, including grades, roofs, fire banks, steam coils, swing pipes, inlet valves, and outlet valves.
This account shall include the cost of facilities for receiving or delivering oil and oil products from or to water carriers, railroads, motor carriers, and others, such as delivery racks, wharves (including buildings thereon), docks, and slips, including piling, pile protection, cribs, cofferdams, walls, and other necessary devices and apparatus for the operation or protection of such property. It shall also include the cost of engines, pumps, and boilers at loading racks and on wharves, the construction of oil-pipe lines between oil tanks and delivery facilities, and the carrier’s investment in tracks if located at and used in connection with delivery facilities.
This account shall include the cost of telegraph, wireless, telephone, and radio equipment.
This account shall include the cost of all office furniture, equipment and fixtures, including such items as safes, desks, chairs, typewriters, accounting machines, cabinets, file cabinets, floor coverings, portable air conditioners, drinking fountains, and other similar items that are not an integral part of a building.
This account shall include the cost of motor and other vehicles, motor and other portable work equipment, garage equipment, and portable tools and machines such as drills, hoists, jacks, power mowers, stocks and dies, laying tongs, vises, air compressors, welding machines, valve reseating machines, pipe-cleaning machines, and concrete mixers, not specifically provided for in other accounts.
This account shall include the cost of property used in pipeline operations not provided for elsewhere.
This account shall include asset retirement costs on plans included in carrier property.
This account shall include the cost of carrier property under construction and the cost of land acquired for such construction as of the date of the balance sheet. It includes interest and taxes during construction, material and supplies delivered to the construction site, and other expenditures that will eventually be part of the cost of the completed property. When construction work is completed, the cost included in this account shall be transferred to the appropriate primary property accounts. Subsidiary records shall be maintained for each construction project. When part of a project under construction is completed and put into service, the costs applicable to that portion shall be transferred to the appropriate property account.
This account shall include revenues on the basis of tariff charges for the gathering or collection of crude oil, oil products and other commodities.
This account shall include revenues on the basis of tariff charges for trunk line transportation of crude oil, oil products or other commodities.
This account shall include revenues on the basis of tariff charges for receiving, delivering, unloading and loading fees at carrier terminal and delivery facilities.
(a) This account shall include the current value of oil acquired through tariff allowances taken into inventory or retained in the line for operating oil supply, and the selling price of such oil sold not previously recorded in inventory or operating oil supply.
(b) Profits and losses on sales of allowance oil from inventory or operating supply shall be included in this account.
This account shall include revenues on the basis of tariff charges for the storage of oil; also demurrage charges incident to failure of consignees to receive shipments promptly.
This account shall include the revenues from renting or subrenting property, the cost of which is included in the accounts for investment in carrier property.
This account shall include revenues incidental to carrier operations and not includible in other revenue accounts.
This account shall include the salaries and wages (including pay for holidays, vacations, sick leave and similar payroll disbursements) of supervisory and other personnel directly engaged in transportation operations and the maintenance and repair of transportation property.
This account shall include the cost of materials applied in the repair and maintenance of transportation property. The salvage value of materials recovered in maintenance work shall be credited to this account. This account shall also include the cost of supplies consumed and expended in operations and in support of the maintenance activity.
This account shall include the cost of operating and maintenance services provided by other than company forces under contract, agreement, and other arrangement. The cost of service performed by affiliated companies shall be segregated within the account.
This account shall include the cost of fuel and power consumed and expended in operations. The cost of normal utilities services shall be included herein when such costs are directly allocable to operations.
(a) This account shall include the cost of settlements with shippers for oil lost or undelivered due to operating causes during the course of transportation.
(b) The value of oil gains from operations shall be credited to this account at current value at time of determination of gain and charged to oil inventory or operating supply.
This account shall include the cost of renting property used in the operations and maintenance of carrier transportation service, such as complete pipeline or segment thereof, office space, land and buildings, and other equipment and facilities.
This account shall include the expenses of aircraft, vehicles, and work equipment used in support of operations and maintenance activities; travel, lodging, meals, memberships, and other expenses of operating and maintenance employees; and other related operating and maintenance expenses that are not defined or classified in other accounts.
This account shall include the salaries and wages (including pay for holidays, vacations, sick leave, and similar payroll disbursements) of executives and general officers, general office personnel, and of other employees whose wages cannot be directly allocated to operations or maintenance.
This account shall include the cost of materials and supplies consumed and expended for administration and general services.
This account shall include the cost of management and general and administrative services provided by other than company forces under contract, agreement or other arrangement. The cost of services performed by affiliated companies shall be segregated within the account.
This account shall include the cost of renting property used in the administration and general operations of carrier transportation service, such as complete pipeline or segment thereof, office space, land and buildings, and other equipment and facilities.
This account shall include charges for the depreciation and amortization of transportation property. Charges for the amortization of fixed term intangibles relating to common carrier operations shall also be included herein.
This account shall include charges for the depreciation of asset retirement costs related to transportation property.
This account shall include the cost to the carrier of annuities, pensions, and benefits for active or retired employees, their beneficiaries or designees. Contributions to health or welfare funds or payment for similar benefits to or on behalf of employees shall be included herein. Premiums, to the extent borne by the carrier, for group life, health, accident and other beneficial insurance for employees shall also be included in this account.
(a) This account shall include the cost of commercial insurance to protect the carrier against losses and damages in its pipeline operations such as injuries to or deaths of employees and other persons, damages to or destruction of carrier property or the property of others, and other business risks and hazards pertaining to transportation operations.
(b) The carrier shall not accrue amounts for the purpose of estimating risk of loss or damage to its property from fire, theft, or similar loss contingencies not covered by commercial insurance.
Insurance or other reimbursement for loss or damage shall be credited to the same account charged with the loss or expense.
(a) This account shall include the amount of expense sustained by the carrier on account of loss or damage to oil or other commodity entrusted to it for transportation or storage resulting from fire, flood, or other casualty.
(b) Expenses on account of damage and destruction to property of others from all causes; and the expense of repairing damages to transportation property caused by casualty shall also be included herein.
(c) This account shall also include expenses incurred on account of injury to or death of employees or other persons including related medical, hospital and funeral expenses.
The cost of oil lost or undelivered through operating causes shall be charged to account 340, Oil Losses and Shortages.
(a) This account shall include accruals for taxes of all kinds, excepting income taxes (see definition 30(a)), relating to carrier property, operations, privileges and licenses.
(b) The detail of this account shall show separately the amounts levied by the Federal government and by each state.
This account shall include the cost of expenses expended for administrative and general services including, the expenses of aircraft, vehicles, and work equipment used for general purposes; travel, lodging, meals, memberships, and other expenses of general employees and officers; utilities services; and all other incidental general expenses not defined or classified in other accounts.
This account shall be charged for accretion expense on the liabilities associated with asset retirement obligations included in account 67, Asset retirement obligations. The carrier shall record in this account the settlement amounts for asset retirement obligations related to carrier property in accordance with the accounting prescribed in General Instruction 1–19.
The carrier shall record in this account gains or losses resulting from the settlement amounts for asset retirement obligations related to carrier property plant. (See General Instruction 1–19).
This account shall include the total revenues included in the operating revenue accounts for the calendar year.
(a) This account shall include all noncarrier revenues and expenses from property carried in account 34, Noncarrier Property.
(b) All expenses related to noncarrier property, such as operation and maintenance expenses, depreciation, taxes (except Federal income taxes) and similar expenses, are includible herein.
(a) This account shall include interest accruing to the carrier on securities of others, loans, notes and advances, deposits, and all other interest bearing assets. Also include the amount of amortized premium or discount related to such assets.
(b) This account shall also include the amount of dividends declared on stocks of others owned by the carrier.
(c) Income shall not be included in this account unless receipt thereof is reasonably assured.
(a) This account shall include income not provided for elsewhere creditable to income accounts for the current year, such as unclaimed wages written off, profit on sales of land and noncarrier, property, profit on sales of investment securities, profit from company bonds reacquired, and decreases in the valuation allowance (contained within account 11) for the marketable equity securities included in current assets.
(b) Gains from extinguishment of debt shall be aggregated and, if material, credited to account 680, Extraordinary Items, upon approval by the Commission.
Included in this account shall be material items unusual in nature or infrequent in occurrence, but not both, accounted for in the current year in accordance with the text of instruction 1–6, upon approval by the Commission.
This account shall include the total expenses included in the operating expense accounts for the calendar year.
This account shall include interest expense on all classes of debt except interest pertaining to construction of property. This account shall also include the amortization of long-term debt premium and discount. Charges for interest on carrier debt obligations previously issued and now held by or for the carrier shall not be recorded in this account.
(a) This account shall include income charges not provided for elsewhere chargeable to income accounts for the current year, such as amortization of debt expense, losses on sale or disposition of land and noncarrier property, losses on sales or reductions in value of investment securities (including increases in the valuation allowance within account 11 for the marketable equity securities included in current assets), bad debts, losses on company bonds reacquired, taxes (other than Federal income taxes) on investment securities, trust management expenses, amortization of intangibles which are not restricted to a fixed term, and the difference between the premium and the added cash surrender value of life insurance on officers and employees when the carrier is beneficiary.
(b) Losses from extinguishment of debt shall be aggregated and, if material, charged to account 680, Extraordinary Items, upon approval by the Commission.
Included in this account shall be material items unusual in nature or infrequent in occurrence, but not both, accounted for in the current year in accordance with the text of instruction 1–6, upon approval by the Commission.
(a) This account shall be debited with the monthly accruals for all income taxes which are estimated to be payable and which are applicable to ordinary income (see instruction 1–12). See the texts of account 695, Income Taxes on Extraordinary Items, account 710, Other Credits to Retained Income, and account 720, Other Debits to Retained Income, for recording other income tax consequences.
(b) Details pertaining to the tax consequences of other unusual and significant items, and also cases where tax consequences are disproportionate to related amounts included in income accounts, shall be submitted to the Commission for consideration and decision as to proper accounting.
(a) This account shall include the net tax effect of changes in material temporary timing differences (see definition 30(e)) during the current accounting period, and the future tax benefits of loss carryforwards recognized in accordance with instruction 1–12(c).
(b) This account shall include credits for the amortization of the investment tax credit if the carrier elected to use the deferred method of accounting for the investment tax credit. (See instruction 1–12(d)).
This account shall include the results of operations of a segment of a business (see definition 32(a)), after giving effect to income tax consequences that has been or will be discontinued in accordance with the text of instruction 1–6, upon approval by the Commission.
This account shall include the gain or loss from the disposal of a segment of a business, after giving effect to income tax consequences, in accordance with the text of instruction 1–6, upon approval by the Commission.
(a) This account shall include extraordinary items accounted for during the current accounting year in accordance with the text of instruction 1–6, upon submission of a letter from the carrier’s independent accountants, approving or otherwise commenting on the item and upon approval by the Commission.
(b) This account shall be maintained in a manner sufficient to identify the nature and gross amount of each debit and credit.
(c) Federal income tax consequences of charges and credits to this account shall be recorded in account 695, Income Taxes on Extraordinary Items, or account 696. Provision for Deferred Taxes—Extraordinary Items, as applicable.
This account shall include the estimated income tax consequences (debit or credit) assignable to the aggregate of items of both taxable income and deductions from taxable income which for accounting purposes are classified extraordinary, and are recorded in account 680, Extraordinary Items (Net). The tax effect of any temporary differences caused by recognizing an item in the account provided for extraordinary items shall be included in account 696, Provision for Deferred Taxes—Extraordinary Items.
This account shall include the deferred tax expense or benefit related to temporary differences applicable to items of revenue or expense included in account 680, Extraordinary Items (Net) (See instruction 1–12).
This account shall include the cumulative effect of changing to a new accounting principle, after giving effect to income tax consequences, in accordance with instruction 1–6, upon approval by the Commission.
This account shall include net income (or deficit) for the calendar year.
This account shall include adjustments after giving income tax effect, in accordance with the text of instruction 1–6, to the balance in the retained income account at the beginning of the calendar year, upon approval by the Commission.
This account shall include other credit adjustments, net of assigned Federal income taxes, not provided for elsewhere in this system but only after such inclusion has been authorized by the Commission.
This account shall include losses from resale of reacquired capital stock, and charges which reduce or write off discount on capital stock issued by the company, but only to the extent that such charges exceed credit balances in account 73, Additional Paid-In Capital, for shares reacquired. This account shall also include other debit adjustments, net of assigned Federal income taxes, not provided for elsewhere in this system of accounts, but only after such inclusion has been authorized by the Commission.
This account shall include appropriations made from retained income during the calendar year. Appropriations charged to this account shall be credited to account 74, Appropriated Retained Income.
This account shall include the amount of dividends declared during the calendar year on all classes of outstanding capital stock. Stock reacquired and owned by the carrier shall not be subject to dividends. Subsidiary records shall be kept to show separately the dividends declared on each type and class of capital stock. When dividends are paid in other than money, complete detail of each transaction shall be maintained.
SUBCHAPTER R—APPROVED FORMS, INTERSTATE COMMERCE ACT
PART 356—PRESERVATION OF RECORDS FOR OIL PIPELINE COMPANIES
§ 356.1 Promulgation.
This part is prescribed and promulgated as the regulations governing the preservation of records by oil pipeline companies subject to the jurisdiction of the Commission, to the extent and in the manner set forth therein. This part is enforceable as of the date the oil pipeline company becomes subject to the jurisdiction of the Commission.
§ 356.2 General instructions.
(a) Scope of this part. (1) The regulations in this part apply to all books of account and other records prepared by or on behalf of the oil pipeline companies.
(2) The regulations in this part must not be construed as excusing compliance with other lawful requirements of any other governmental body, Federal or State, prescribing other record keeping requirements or for preservation of records longer than those prescribed in this part.
(3) To the extent that any Commission regulations may provide for a different retention period, the records should be retained for the longer of the retention periods.
(4) Unless otherwise specified in the schedule in § 356.3, duplicate copies of records may be destroyed at any time. Provided, however, that such duplicate copies must not contain significant information not shown on the originals.
(5) Records other than those listed in the schedule may be destroyed at the option of the oil pipeline company. Provided, however, that records which are used in lieu of those listed must be preserved for the periods prescribed for the records used for substantially similar purposes and that retention of records pertaining to added services, functions, plant, etc., the establishment of which cannot be presently foreseen, must conform to the principles embodied herein.
(6) Notwithstanding the provision of the records retention schedule, the Commission may, upon request of the oil pipeline company, authorize shorter retention periods for any records listed in § 356.3. The oil pipeline companies must show that the longer retention periods are no longer necessary or appropriate to protect the public interest, investors, or consumers. A waiver from any provision of these regulations may be made by the Commission upon its own initiative or upon submission of a written request by the company. Each request for waiver must demonstrate that unusual circumstances warrant a departure from prescribed retention periods, procedures, or techniques, or that compliance with such prescribed requirements would impose an unreasonable burden on the company.
(b) Designation of supervisory official. Each oil pipeline company subject to the provision of this part must designate one or more persons to supervise the oil pipeline company’s program for preservation and authorized destruction of records.
(c) Protection and storage of records. Each oil pipeline company subject to these regulations must provide reasonable protection for records. The records must have protections from fire, floods, and other hazards. Storage spaces, will also prevent unnecessary exposure to deterioration from excessive humidity, dryness, or lack of proper ventilation.
(d) Record storage media. (1) Each oil pipeline company has the flexibility to select its own storage media.
(2) The storage media must have a life expectancy at least equal to the applicable record retention period provided in § 356.3 unless there is a quality transfer from one media to another with no loss of data.
(3) Each oil pipeline company is required to implement internal control procedures that assure the reliability of and ready access to data stored on machine readable media. Internal control procedures must be documented by a responsible supervisory official.
(e) Destruction of records. Oil pipeline companies may use any appropriate method to destroy permitted records.
(f) Premature destruction or loss of records. When records are destroyed or lost before the expiration of the prescribed period of retention, a certified statement listing, as far as may be determined, the records destroyed, and describing the circumstances of accidental or other premature destruction or loss must be filed with the Commission within ninety (90) days from the date of discovery of such destruction.
(g) Retention periods designated “Destroy at option”. “Destroy at option” constitutes authorization for destruction of records at managements’ discretion if it does not conflict with other legal retention requirements or usefulness of such records in satisfying pending regulatory action or directives.
(h) Records of services performed by associated companies. Oil pipeline companies must assure the availability of records of services performed by associated companies for the periods indicated in § 356.3 as necessary to be able to readily furnish detailed information as to the nature of transaction, the involved, and the accounts used to record the transactions.
(i) Index of records. Oil pipeline companies must arrange, file, and index records so they may be readily identified and made available to Commission representatives.
(j) Rate case. The schedule of records in § 356.3 shows the periods of time that designated records must be preserved. However, not withstanding the minimum retention periods provided in this regulation, if an oil pipeline company intends to reflect costs in a current, pending, or future rate case, or if an oil pipeline company has abandoned or retired plant subsequent to the test period of its last rate case, it must retain the appropriate records to support the costs, and adjustments proposed in the next or current rate case.
(k) Pending complaint litigation or governmental proceeding. Notwithstanding the minimum requirements, if an oil pipeline company is involved in pending litigation, complaint proceedings, proceedings remanded by the court, or governmental proceedings, it must retain all relevant records.
(l) Companies going out of business. The records referred to in these regulations may be destroyed after business is discontinued and the company is completely liquidated. The records may not be destroyed until dissolution is final and all transactions are completed. When a company is merged with another company under jurisdiction of the Commission, the successor company must preserve records of the merged company in accordance with these regulations.
(m) Life or mortality study data. Life or mortality study data for depreciation purposes must be retained for 25 years or for 10 years after plant is retired.
§ 356.3 Preservation of records for oil pipeline companies.
Schedule of Records and Periods of Retention
| Item No. and description | Retention period |
|---|---|
| 1. Incorporation and reorganization: | |
| (a) Charter of certificate of incorporation and amendments | Permanently or at termination of the corporation’s existence. |
| (b) Legal documents related to mergers, consolidations, reorganizations, receiverships, and similar actions which affect the identity or organization of the company | Permanently or at termination of the corporation’s existence. |
| 2. Minutes to Directors’, Executive Committees’, Stockholders’, and other corporate meetings | 5 years. |
| 3. Titles, franchises, and authorities: | |
| (a) Certificates of public convenience and necessity issued by regulating bodies | Until expiration or cancellation. |
| (b) Operating authorizations and exemptions to operate issued by regulating bodies | Until expiration or cancellation. |
| (c) Copies of formal orders of regulatory bodies served upon the company | 1 year after expiration or cancellation. |
| (d) Deeds, charters, and other title papers | 3 years after disposition of property. |
| 4. Contracts and agreements: | |
| (a) Contracts and related papers for transactions which are subject to the provisions of the Clayton Antitrust Act (15 U.S.C. 20) | 4 years after expiration, provided there is no pending litigation or governmental inquiry or proceeding involved. |
| (b) Service contracts, such as for operational management, accounting, financial or legal service, and agreements with agents | 3 years after expiration or termination. |
| (c) Contracts and other agreements relating to the construction, acquisition or sale of real property and equipment except as otherwise provided in paragraph (a) of this item | 3 years after expiration or termination. |
| 5. Accountant’s, auditor’s, and inspector’s reports: | |
| (a) Certifications and reports of examinations and audits conducted by public and certified public accountants | 3 years. |
| (b) Reports of examinations and audits conducted by internal auditors, time inspectors, weight inspectors, and others | 3 years. |
| 6. Long-term debt records: | |
| (a) Bond indentures, underwriting, mortgage, and other long-term credit agreements | 6 years after redemption. |
| 7. Ledgers: | |
| (a) General and subsidiary ledgers with indexes thereto | 3 years. |
| (b) Balance sheets and trial balance sheets of general and subsidiary ledgers | 3 years. |
| 8. Journals: | |
| (a) General journals | 3 years. |
| (b) Subsidiary journals and any supporting data, except as otherwise provided for, necessary to explain journal entries | 3 years. |
| (c) Schedules of recurring or standard journal entries with entry identifications | Until superseded. |
| 9. Vouchers: | |
| (a) Voucher registers or equivalent | 5 years. |
| (b) Paid and canceled vouchers, expenditure authorizations, detailed distribution sheets, and other supporting data including original bills and invoices, except as otherwise provided herein | 5 years. |
| 10. Accounts receivable, record, or register of accounts receivable | 3 years after settlement. |
| 11. Records of accounting codes and instructions | 3 years after discontinuance. |
| 12. Property records: | |
| (a) Records which maintain complete information on cost or other value of all real property or equipment | 3 years after disposition of property. |
| (b) Records and additions and betterments made to property and equipment | 3 years after disposition of property. |
| (c) Records pertaining to retirements and replacements of property and equipment | 3 years after disposition of property. |
| (d) Records pertaining to depreciation: | |
| (1) When group method and depreciation rates are prescribed by the Commission | 3 years after disposition of property. |
| (2) Other | 3 years after disposition of property. |
| (e) Records of equipment number changes | 3 years after disposition of property. |
| (f) Records of motor and engine changes | Destroy at option. |
| (g) Files of detailed authorizations for expenditures, work or job orders showing estimated costs of additions and betterments, extensions, replacements, major repairs and dismantlements, approved by proper officials, together with supporting data | 3 years after disposition of property. |
| (h) Periodical inventories of property and equipment | 3 years after prior inventory. |
| 13. Engineering records: | |
| (a) Plans and specifications | 3 years after the disposition of the property. |
| (b) Estimates of work, engineering studies, construction bids, and similar data pertaining to property changes actually made | 15 years. |
| 14. Payroll records: | |
| (a) Registers, abstracts, or summaries showing earnings, deductions, and amounts paid to each employee by pay periods | 3 years. |
| (b) Records showing the detailed distribution of salaries and wages to various accounts | 3 years. |
| 15. Copies of tax returns and supporting schedules filed with taxing authorities, supporting working papers, records of appeals of tax bills, and receipts for payment. See Subsection 9(b) for vouchers evidencing disbursements: | |
| (a) Income tax returns | 3 years after final tax liability is determined. |
| (b) Property tax returns | 3 years after final tax liability is determined. |
| (c) Sales and other use taxes | 3 years final tax liability is determined. |
| (d) Other taxes | 3 years after final tax liability is determined. |
| (e) Agreements between associate companies as to allocation of consolidated income taxes | 3 years after final tax liability is determined. |
| (f) Schedule of allocation of consolidated Federal income taxes among associate companies | 3 years after final tax liability is determined. |
| 16. Information returns and reports to taxing authorities | 3 years, or for the period of any extensions granted for audits. |
| 17. Material ledger, records of material and supplies on hand at all locations | 2 years. |
| 18. Inventories: General Inventories of material and supplies on hand, with record of adjustments between accounts required to bring stores records into agreement with physical inventories | 2 years. |
| 19. Oil and other products stocks and movement pipelines only: | |
| (a) Records and receipts, deliveries, pumpings, stocks, and over and short | 3 years. |
| (b) Run tickets showing quantities by tank measurement of meter reading of oil and other products received into the delivered from company’s lines | 3 years. |
| (c) Statements of oil and oil products consumed as fuel including quantity value, and where consumed | 3 years. |
| (d) Statement of oil and other products lost by line breaks and leaks including quantity, value, and location of breaks and leaks | 3 years. |
| (e) Reports of power furnished by producers: monthly reports of the quantity of oil run in connection with which power was furnished by producers, and records of payment for such power | 3 years. |
| (f) Records of producers’ property identifying ownership and location for producers’ tanks or wells to which carrier’s lines are connected | 3 years after disconnection. |
| (g) Division or other periodical inventory reports of oil and other products on hand | 3 years. |
| (h) Division orders: Directions received by carrier as to the division of interest and to whose account transported oil should be credited | 3 years after discontinuance. |
| (i) Directions received by the carrier for the transfer of division order interests from one interest owner to another | 3 years after discontinuance. |
| (j) Transfer orders for the transfer of ownership of oil or other products in carrier’s custody | 3 years. |
| 20. Official file copies of tariffs, classifications, division sheets, and circulars relative to the transportation of property | 3 years after expiration or cancelation. |
| 21. Authorities and supporting papers for transportation of property for free or at reduced rates | 3 years. |
| 22.Copies of concurrences and powers of attorney | 2 years after expiration or cancelation. |
| 23. Correspondence and working papers in connection with the making of rates and compliance of tariffs, classifications, division sheets, and circulars affecting the transportation of property | 2 years after cancelation of tariff. |
| 24. Reports to Federal Energy Regulatory Commission and other regulatory bodies, annual financial, operating and statistical reports, file copies, and supporting data | 5 years. |
PART 357—ANNUAL SPECIAL OR PERIODIC REPORTS: CARRIERS SUBJECT TO PART I OF THE INTERSTATE COMMERCE ACT
§ 357.1 Common carriers.
All common carriers by pipeline subject to the provisions of Part I of Interstate Commerce Act, as amended, are hereby required hereinafter to file in the office of the Commission on or before the 31st day of March in each year, reports covering the period of 12 months ending with the 31st day of December preceding said date, giving the particulars heretofore called for in the annual reports required by the Commission of said carriers.
§ 357.2 FERC Form No. 6, Annual Report of Oil Pipeline Companies.
(a) Who must file. (1) Each pipeline carrier subject to the provisions of section 20 of the Interstate Commerce Act whose annual jurisdictional operating revenues has been $500,000 or more for each of the three previous calendar years must prepare and file with the Commission copies of FERC Form No. 6, “Annual Report of Oil Pipeline Companies,” pursuant to the General Instructions set out in that form. Newly established entities must use projected data to determine whether FERC Form No. 6 must be filed.
(2) Oil pipeline carriers exempt from filing Form No. 6 whose annual jurisdictional operating revenues have been more than $350,000 but less than $500,000 for each of the three previous calendar years must prepare and file pages 301, “Operating Revenue Accounts (Account 600),” and 700, “Annual Cost of Service Based Analysis Schedule,” of FERC Form No. 6. When submitting pages 301 and 700, each exempt oil pipeline carrier must include page 1 of Form No. 6, the Identification and Attestation schedules.
(3) Oil pipeline carriers exempt from filing Form No. 6 and pages 301 and whose annual jurisdictional operating revenues were $350,000 or less for each of the three previous calendar years must prepare and file page 700, “Annual Cost of Service Based Analysis Schedule,” of FERC Form No. 6. When submitting page 700, each exempt oil pipeline carrier must include page 1 of Form No. 6, the Identification and Attestation schedules.
(b) When to file. (1) The annual report for the year ending December 31, 2004, must be filed on April 25, 2005.
(2) The annual report for each year thereafter must be filed on April 18 of the subsequent year.
(c) What to submit. (1) This report form must be filed as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in the report form, and must be properly completed and verified.
(2) A copy of the report must be retained by the pipeline carrier in its files. The conformed copies may be produced by any legible means of reproduction.
(3) The form must be filed in electronic format only pursuant to § 385.2011 of this chapter, beginning with report year 2002, due on or before March 31, 2003.
§ 357.3 FERC Form No. 73, Oil Pipeline Data for Depreciation Analysis.
(a) Who must file. Any oil pipeline company requesting new or changed depreciation rates pursuant to part 347 of this title if the proposed depreciation rates are based on the remaining physical life of the properties or if directed by the Commission to file service life data during an investigation of its book depreciation rates.
(b) When to submit. Service life data is reported to the Commission by an oil pipeline company, as necessary, concurrently with a filing made pursuant to part 347 of this title or as directed during a depreciation rate investigation.
(c) What to submit. The format and data which must be submitted are prescribed in FERC Form No. 73, Oil Pipeline Data for Depreciation Analysis, available for review on the Commission’s website https://www.ferc.gov.
§ 357.4 FERC Form No. 6–Q, Quarterly report of oil pipeline companies.
(a) Prescription. The quarterly financial report form of oil pipeline companies, designated as FERC Form No. 6–Q, is prescribed for the reporting quarter ending March 31, 2004, and each quarter thereafter.
(b) Filing requirements—(1) Who must file. Each oil pipeline company, subject to the provisions of section 20 of the Interstate Commerce Act, must prepare and file with the Commission FERC Form No. 6–Q.
(2) When to file and what to file. This quarterly financial report form must be filed as follows:
(i) The quarterly financial report for the period January 1 through March 31, 2004, must be filed on or before July 23, 2004.
(ii) The quarterly financial report for the period April 1 through June 30, 2004, must be filed on or before September 22, 2004.
(iii) The quarterly financial report for the period July 1 through September 30, 2004, must be filed on or before December 23, 2004.
(iv) The quarterly financial report for the period January 1 through March 31, 2005, must be filed on or before June 13, 2005.
(v) This report must be filed as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in the quarterly report form, and must be properly completed and verified. Filing on electronic media pursuant to § 385.2011 of this chapter will be required commencing with the reporting quarter ending March 31, 2004, due on or before
(vi) The quarterly financial report for the period April 1 through June 30, 2005, must be filed on or before September 12, 2005.
(vii) Subsequent quarterly financial reports must be filed within 70 days from the end of the reporting quarter.
(viii) The quarterly financial report for the period July 1 through September 30, 2005 must be filed on or before December 13, 2005.
§ 357.5 Cash management programs.
Oil pipeline companies subject to the provisions of the Commission’s Uniform System of Accounts prescribed in part 352 and § 357.2 of this title that participate in cash management programs must file these agreements with the Commission. The documentation establishing the cash management program and entry into the program must be filed within 10 days of the effective date of the rule or entry into the program. Subsequent changes to the cash management agreement must be filed with the Commission within 10 days of the change.
SUBCHAPTER S—STANDARDS OF CONDUCT FOR TRANSMISSION PROVIDERS
PART 358—STANDARDS OF CONDUCT
§ 358.1 Applicability.
(a) This part applies to any interstate natural gas pipeline that transports gas for others pursuant to subparts B or G of part 284 of this chapter and conducts transmission transactions with an affiliate that engages in marketing functions.
(b) This part applies to any public utility that owns, operates, or controls facilities used for the transmission of electric energy in interstate commerce and conducts transmission transactions with an affiliate that engages in marketing functions.
(c) This part does not apply to a public utility transmission provider that is a Commission-approved Independent System Operator (ISO) or Regional Transmission Organization (RTO). If a public utility transmission owner participates in a Commission-approved ISO or RTO and does not operate or control its transmission system and has no access to transmission function information, it may request a waiver from this part.
(d) A transmission provider may file a request for a waiver from all or some of the requirements of this part for good cause.
§ 358.2 General principles.
(a) As more fully described and implemented in subsequent sections of this part, a transmission provider must treat all transmission customers, affiliated and non-affiliated, on a not unduly discriminatory basis, and must not make or grant any undue preference or advantage to any person or subject any person to any undue prejudice or disadvantage with respect to any transportation of natural gas or transmission of electric energy in interstate commerce, or with respect to the wholesale sale of natural gas or of electric energy in interstate commerce.
(b) As more fully described and implemented in subsequent sections of this part, a transmission provider’s transmission function employees must function independently from its marketing function employees, except as permitted in this part or otherwise permitted by Commission order.
(c) As more fully described and implemented in subsequent sections of this part, a transmission provider and its employees, contractors, consultants and agents are prohibited from disclosing, or using a conduit to disclose, non-public transmission function information to the transmission provider’s marketing function employees.
(d) As more fully described and implemented in subsequent sections of this part, a transmission provider must provide equal access to non-public transmission function information disclosed to marketing function employees to all its transmission customers, affiliated and non-affiliated, except as permitted in this part or otherwise permitted by Commission order.
§ 358.3 Definitions.
(a) Affiliate of a specified entity means:
(1) Another person that controls, is controlled by or is under common control with, the specified entity. An affiliate includes a division of the specified entity that operates as a functional unit.
(2) For any exempt wholesale generator (as defined under § 366.1 of this chapter), affiliate shall have the meaning set forth in § 366.1 of this chapter, or any successor provision.
(3) “Control” as used in this definition means the direct or indirect authority, whether acting alone or in conjunction with others, to direct or cause to direct the management policies of an entity. A voting interest of 10 percent or more creates a rebuttable presumption of control.
(b) Internet Web site refers to the Internet location where an interstate natural gas pipeline or a public utility posts the information, by electronic means, required under this part 358.
(c) Marketing functions means:
(1) in the case of public utilities and their affiliates, the sale for resale in interstate commerce, or the submission of offers to sell in interstate commerce, of electric energy or capacity, demand response, virtual transactions, or financial or physical transmission rights, all as subject to an exclusion for bundled retail sales, including sales of electric energy made by providers of last resort (POLRs) acting in their POLR capacity; and
(2) in the case of interstate pipelines and their affiliates, the sale for resale in interstate commerce, or the submission of offers to sell in interstate commerce, natural gas, subject to the following exclusions:
(i) Bundled retail sales,
(ii) Incidental purchases or sales of natural gas to operate interstate natural gas pipeline transmission facilities,
(iii) Sales of natural gas solely from a seller’s own production,
(iv) Sales of natural gas solely from a seller’s own gathering or processing facilities, and
(v) On-system sales by an intrastate natural gas pipeline, by a Hinshaw interstate pipeline exempt from the Natural Gas Act, by a local distribution company, or by a local distribution company operating under section 7(f) of the Natural Gas Act.
(d) Marketing function employee means an employee, contractor, consultant or agent of a transmission provider or of an affiliate of a transmission provider who actively and personally engages on a day-to-day basis in marketing functions.
(e) Open Access Same Time Information System or OASIS refers to the Internet location where a public utility posts the information required by part 37 of this chapter, and where it may also post the information required to be posted on its Internet Web site by this part 358.
(f) Transmission means electric transmission, network or point-to-point service, ancillary services or other methods of electric transmission, or the interconnection with jurisdictional transmission facilities, under part 35 of this chapter; and natural gas transportation, storage, exchange, backhaul, or displacement service provided pursuant to subparts B or G of part 284 of this chapter.
(g) Transmission customer means any eligible customer, shipper or designated agent that can or does execute a transmission service agreement or can or does receive transmission service, including all persons who have pending requests for transmission service or for information regarding transmission.
(h) Transmission functions means the planning, directing, organizing or carrying out of day-to-day transmission operations, including the granting and denying of transmission service requests.
(i) Transmission function employee means an employee, contractor, consultant or agent of a transmission provider who actively and personally engages on a day-to-day basis in transmission functions.
(j) Transmission function information means information relating to transmission functions.
(k) Transmission provider means:
(1) Any public utility that owns, operates or controls facilities used for the transmission of electric energy in interstate commerce; or
(2) Any interstate natural gas pipeline that transports gas for others pursuant to subparts B or G of part 284 of this chapter.
(3) A transmission provider does not include a natural gas storage provider authorized to charge market-based rates.
(l) Transmission service means the provision of any transmission as defined in § 358.3(f).
(m) Waiver means the determination by a transmission provider, if authorized by its tariff, to waive any provisions of its tariff for a given entity.
§ 358.4 Non-discrimination requirements.
(a) A transmission provider must strictly enforce all tariff provisions relating to the sale or purchase of open access transmission service, if the tariff provisions do not permit the use of discretion.
(b) A transmission provider must apply all tariff provisions relating to the sale or purchase of open access transmission service in a fair and impartial manner that treats all transmission customers in a not unduly discriminatory manner, if the tariff provisions permit the use of discretion.
(c) A transmission provider may not, through its tariffs or otherwise, give undue preference to any person in matters relating to the sale or purchase of transmission service (including, but not limited to, issues of price, curtailments, scheduling, priority, ancillary services, or balancing).
(d) A transmission provider must process all similar requests for transmission in the same manner and within the same period of time.
§ 358.5 Independent functioning rule.
(a) General rule. Except as permitted in this part or otherwise permitted by Commission order, a transmission provider’s transmission function employees must function independently of its marketing function employees.
(b) Separation of functions. (1) A transmission provider is prohibited from permitting its marketing function employees to:
(i) Conduct transmission functions; or
(ii) Have access to the system control center or similar facilities used for transmission operations that differs in any way from the access available to other transmission customers.
(2) A transmission provider is prohibited from permitting its transmission function employees to conduct marketing functions.
§ 358.6 No conduit rule.
(a) A transmission provider is prohibited from using anyone as a conduit for the disclosure of non-public transmission function information to its marketing function employees.
(b) An employee, contractor, consultant or agent of a transmission provider, and an employee, contractor, consultant or agent of an affiliate of a transmission provider that is engaged in marketing functions, is prohibited from disclosing non-public transmission function information to any of the transmission provider’s marketing function employees.
§ 358.7 Transparency rule.
(a) Contemporaneous disclosure. (1) If a transmission provider discloses non-public transmission function information, other than information identified in paragraph (a)(2) of this section, in a manner contrary to the requirements of § 358.6, the transmission provider must immediately post the information that was disclosed on its Internet Web site.
(2) If a transmission provider discloses, in a manner contrary to the requirements of § 358.6, non-public transmission customer information, critical energy infrastructure information (CEII) as defined in § 388.113(c)(1) of this chapter or any successor provision, or any other information that the Commission by law has determined is to be subject to limited dissemination, the transmission provider must immediately post notice on its Web site that the information was disclosed.
(b) Exclusion for specific transaction information. A transmission provider’s transmission function employee may discuss with its marketing function employee a specific request for transmission service submitted by the marketing function employee. The transmission provider is not required to contemporaneously disclose information otherwise covered by § 358.6 if the information relates solely to a marketing function employee’s specific request for transmission service.
(c) Voluntary consent provision. A transmission customer may voluntarily consent, in writing, to allow the transmission provider to disclose the transmission customer’s non-public information to the transmission provider’s marketing function employees. If the transmission customer authorizes the transmission provider to disclose its information to marketing function employees, the transmission provider must post notice on its Internet Web site of that consent along with a statement that it did not provide any preferences, either operational or rate-related, in exchange for that voluntary consent.
(d) Posting written procedures on the public Internet. A transmission provider must post on its Internet Web site current written procedures implementing the standards of conduct.
(e) Identification of affiliate information on the public Internet. (1) A transmission provider must post on its Internet Web site the names and addresses of all its affiliates that employ or retain marketing function employees.
(2) A transmission provider must post on its Internet Web site a complete list of the employee-staffed facilities shared by any of the transmission provider’s transmission function employees and marketing function employees. The list must include the types of facilities shared and the addresses of the facilities.
(3) The transmission provider must post information concerning potential merger partners as affiliates that may employ or retain marketing function employees, within seven days after the potential merger is announced.
(f) Identification of employee information on the public Internet. (1) A transmission provider must post on its Internet Web site the job titles and job descriptions of its transmission function employees.
(2) A transmission provider must post a notice on its Internet Web site of any transfer of a transmission function employee to a position as a marketing function employee, or any transfer of a marketing function employee to a position as a transmission function employee. The information posted under this section must remain on its Internet Web site for 90 days. No such job transfer may be used as a means to circumvent any provision of this part. The information to be posted must include:
(i) The name of the transferring employee,
(ii) The respective titles held while performing each function (i.e., as a transmission function employee and as a marketing function employee), and
(iii) The effective date of the transfer.
(g) Timing and general requirements of postings on the public Internet. (1) A transmission provider must update on its Internet Web site the information required by this part 358 within seven business days of any change, and post the date on which the information was updated. A public utility may also post the information required to be posted under part 358 on its OASIS, but is not required to do so.
(2) In the event an emergency, such as an earthquake, flood, fire or hurricane, severely disrupts a transmission provider’s normal business operations, the posting requirements in this part may be suspended by the transmission provider. If the disruption lasts longer than one month, the transmission provider must so notify the Commission and may seek a further exemption from the posting requirements.
(3) All Internet Web site postings required by this part must be sufficiently prominent as to be readily accessible.
(h) Exclusion for and recordation of certain information exchanges. (1) Notwithstanding the requirements of §§ 358.5(a) and 358.6, a transmission provider’s transmission function employees and marketing function employees may exchange certain non-public transmission function information, as delineated in § 358.7(h)(2), in which case the transmission provider must make and retain a contemporaneous record of all such exchanges except in emergency circumstances, in which case a record must be made of the exchange as soon as practicable after the fact. The transmission provider shall make the record available to the Commission upon request. The record may consist of hand-written or typed notes, electronic records such as e-mails and text messages, recorded telephone exchanges, and the like, and must be retained for a period of five years.
(2) The non-public information subject to the exclusion in § 358.7(h)(1) is as follows:
(i) Information pertaining to compliance with Reliability Standards approved by the Commission, and
(ii) Information necessary to maintain or restore operation of the transmission system or generating units, or that may affect the dispatch of generating units.
(i) Posting of waivers. A transmission provider must post on its Internet Web site notice of each waiver of a tariff provision that it grants in favor of an affiliate, unless such waiver has been approved by the Commission. The posting must be made within one business day of the act of a waiver. The transmission provider must also maintain a log of the acts of waiver, and must make it available to the Commission upon request. The records must be kept for a period of five years from the date of each act of waiver.
§ 358.8 Implementation requirements.
(a) Effective date. A transmission provider must be in full compliance with the standards of conduct on the date it commences transmission transactions with an affiliate that engages in marketing functions.
(b) Compliance measures and written procedures. (1) A transmission provider must implement measures to ensure that the requirements of §§ 358.5 and 358.6 are observed by its employees and by the employees of its affiliates.
(2) A transmission provider must distribute the written procedures referred to in § 358.7(d) to all its transmission function employees, marketing function employees, officers, directors, supervisory employees, and any other employees likely to become privy to transmission function information.
(c) Training and compliance personnel. (1) A transmission provider must provide annual training on the standards of conduct to all the employees listed in paragraph (b)(2) of this section. The transmission provider must provide training on the standards of conduct to new employees in the categories listed in paragraph (b)(2) of this section, within the first 30 days of their employment. The transmission provider must require each employee who has taken the training to certify electronically or in writing that s/he has completed the training.
(2) A transmission provider must designate a chief compliance officer who will be responsible for standards of conduct compliance. The transmission provider must post the name of the chief compliance officer and provide his or her contact information on its Internet Web site.
(d) Books and records. A transmission provider must maintain its books of account and records (as prescribed under parts 101, 125, 201 and 225 of this chapter) separately from those of its affiliates that employ or retain marketing function employees, and these must be available for Commission inspections.
SUBCHAPTER T [RESERVED]
SUBCHAPTER U—REGULATIONS UNDER THE PUBLIC UTILITY HOLDING COMPANY ACT OF 2005, FEDERAL POWER ACT AND NATURAL GAS ACT
PART 366—BOOKS AND RECORDS
Subpart A—Definitions and Provisions Under PUHCA 2005, the Federal Power Act and the Natural Gas Act
§ 366.1 Definitions.
For purposes of this part:
Affiliate. The term “affiliate” of a company means any company, 5 percent or more of the outstanding voting securities of which are owned, controlled, or held with power to vote, directly or indirectly, by such company.
Associate company. The term “associate company” of a company means any company in the same holding company system with such company.
Commission. The term “Commission” means the Federal Energy Regulatory Commission.
Company. The term “company” means a corporation, partnership, association, joint stock company, business trust, or any organized group of persons, whether incorporated or not, or a receiver, trustee, or other liquidating agent of any of the foregoing.
Construction. The term “construction” means any construction, extension, improvement, maintenance, or repair of the facilities or any part thereof of a company, which is performed for a charge.
Electric utility company. The term “electric utility company” means any company that owns or operates facilities used for the generation, transmission, or distribution of electric energy for sale. For the purposes of this subchapter, “electric utility company” shall not include persons that engage only in marketing of electric energy.
Exempt wholesale generator. The term “exempt wholesale generator” means any person engaged directly, or indirectly through one or more affiliates as defined in this subchapter, and exclusively in the business of owning or operating, or both owning and operating, all or part of one or more eligible facilities and selling electric energy at wholesale. For purposes of establishing or determining whether an entity qualifies for exempt wholesale generator status, sections 32(a)(2) through (4), and sections 32(b) through (d) of the Public Utility Holding Company Act of 1935 (15 U.S.C. 79z–5a(a)(2)–(4), 79z–5a(b)–(d)) shall apply.
Foreign utility company. The term “foreign utility company” means any company that owns or operates facilities that are not located in any state and that are used for the generation, transmission, or distribution of electric energy for sale or the distribution at retail of natural or manufactured gas for heat, light, or power, if such company:
(1) Derives no part of its income, directly or indirectly, from the generation, transmission, or distribution of electric energy for sale or the distribution at retail of natural or manufactured gas for heat, light, or power, within the United States; and
(2) Neither the company nor any of its subsidiary companies is a public-utility company operating in the United States.
Gas utility company. The term “gas utility company” means any company that owns or operates facilities used for distribution at retail (other than the distribution only in enclosed portable containers or distribution to tenants or employees of the company operating such facilities for their own use and not for resale) of natural or manufactured gas for heat, light, or power. For the purposes of this subchapter, “gas utility company” shall not include entities that engage only in marketing of natural and manufactured gas.
Goods. The term “goods” means any goods, equipment (including machinery), materials, supplies, appliances, or similar property (including coal, oil, or steam, but not including electric energy, natural or manufactured gas, or utility assets) which is sold, leased, or furnished, for a charge.
Holding company—(1) In general. The term “holding company” means—
(i) Any company that directly or indirectly owns, controls, or holds, with power to vote, 10 percent or more of the outstanding voting securities of a public-utility company or of a holding company of any public-utility company; and
(ii) Any person, determined by the Commission, after notice and opportunity for hearing, to exercise directly or indirectly (either alone or pursuant to an arrangement or understanding with one or more persons) such a controlling influence over the management or policies of any public-utility company or holding company as to make it necessary or appropriate for the rate protection of utility customers with respect to rates that such person be subject to the obligations, duties, and liabilities imposed by this subtitle upon holding companies.
(2) Exclusions. The term ”holding company” shall not include—
(i) A bank, savings association, or trust company, or their operating subsidiaries that own, control, or hold, with the power to vote, public utility or public utility holding company securities so long as the securities are—
(A) Held as collateral for a loan;
(B) Held in the ordinary course of business as a fiduciary; or
(C) Acquired solely for purposes of liquidation and in connection with a loan previously contracted for and owned beneficially for a period of not more than two years; or
(ii) A broker or dealer that owns, controls, or holds with the power to vote public utility or public utility holding company securities so long as the securities are—
(A) Not beneficially owned by the broker or dealer and are subject to any voting instructions which may be given by customers or their assigns; or
(B) Acquired in the ordinary course of business as a broker, dealer, or underwriter with the bona fide intention of effecting distribution within 12 months of the specific securities so acquired.
Holding company system. The term “holding company system” means a holding company, together with its subsidiary companies.
Jurisdictional rates. The term “jurisdictional rates” means rates accepted, established or permitted by the Commission for the transmission of electric energy in interstate commerce, the sale of electric energy at wholesale in interstate commerce, the transportation of natural gas in interstate commerce, and the sale in interstate commerce of natural gas for resale for ultimate public consumption for domestic, commercial, industrial, or any other use.
Natural gas company. The term “natural gas company” means a person engaged in the transportation of natural gas in interstate commerce or the sale of such gas in interstate commerce for resale.
Person. The term “person” means an individual or company.
Public utility. The term “public utility” means any person who owns or operates facilities used for transmission of electric energy in interstate commerce or sales of electric energy at wholesale in interstate commerce.
Public-utility company. The term “public-utility company” means an electric utility company or a gas utility company. For the purposes of this subchapter, the owner-lessors and owner participants in lease financing transactions involving utility assets shall not be treated as “public-utility companies.”
Service. The term “service” means any managerial, financial, legal, engineering, purchasing, marketing, auditing, statistical, advertising, publicity, tax, research, or any other service (including supervision or negotiation of construction or of sales), information or data, which is sold or furnished for a charge.
Service company. The term “service company” means any associate company within a holding company system organized specifically for the purpose of providing non-power goods or services or the sale of goods or construction work to any public utility or any natural gas company, or both, in the same holding company system.
State commission. The term “state commission” means any commission, board, agency, or officer, by whatever name designated, of a state, municipality, or other political subdivision of a state that, under the laws of such state, has jurisdiction to regulate public-utility companies.
Subsidiary company. The term “subsidiary company” of a holding company means—
(1) Any company, 10 percent or more of the outstanding voting securities of which are directly or indirectly owned, controlled, or held with power to vote, by such holding company; and
(2) Any person, the management or policies of which the Commission, after notice and opportunity for hearing, determines to be subject to a controlling influence, directly or indirectly, by such holding company (either alone or pursuant to an arrangement or understanding with one or more other persons) so as to make it necessary for the rate protection of utility customers with respect to rates that such person be subject to the obligations, duties, and liabilities imposed by this subtitle upon subsidiary companies of holding companies.
Voting security. The term “voting security” means any security presently entitling the owner or holder thereof to vote in the direction or management of the affairs of a company. For the purposes of this subchapter, the term “voting security” shall not include member interests in electric power cooperatives.
§ 366.2 Commission access to books and records.
(a) In general. Unless otherwise exempted by Commission rule or order, each holding company and each associate company thereof shall maintain, and shall make available to the Commission, such books, accounts, memoranda, and other records as the Commission determines are relevant to costs incurred by a public utility or natural gas company that is an associate company of such holding company and necessary or appropriate for the protection of utility customers with respect to jurisdictional rates. However, for purposes of this subchapter, no provision in the subchapter shall apply to or be deemed to include:
(1) The United States;
(2) A state or political subdivision of a state;
(3) Any foreign governmental authority not operating in the United States;
(4) Any agency, authority, or instrumentality of any entity referred to in paragraphs (a)(1), (2), or (3) of this section; or
(5) Any officer, agent, or employee of any entity referred to in paragraphs (a)(1), (2), (3), or (4) of this section as such in the course of his or her official duty.
(b) Affiliate companies. Unless otherwise exempted by Commission rule or order, each affiliate of a holding company or of any subsidiary company of a holding company shall maintain, and shall make available to the Commission, such books, accounts, memoranda, and other records with respect to any transaction with another affiliate, as the Commission determines are relevant to costs incurred by a public utility or natural gas company that is an associate company of such holding company and necessary or appropriate for the protection of utility customers with respect to jurisdictional rates.
(c) Holding company systems. The Commission may examine the books, accounts, memoranda, and other records of any company in a holding company system, or any affiliate thereof, as the Commission determines are relevant to costs incurred by a public utility or natural gas company within such holding company system and necessary or appropriate for the protection of utility customers with respect to jurisdictional rates.
(d) E-Tag Authors and Balancing Authorities. E-Tag Authors and Balancing Authorities must take appropriate steps to ensure Commission view-only access to complete electronic tags (e-Tags), or any successor to e-Tags, used to schedule the transmission of electric power in wholesale markets, by designating the Commission as an addressee on the e-Tags. E-Tag Authors must include the Commission on the list of entities with view-only rights to the e-Tags. Balancing Authorities located within the United States must validate the inclusion of the Commission on the e-Tag before those e-Tags are electronically delivered to an address specified by the Commission. The complete e-Tag data to be made available under this section shall consist of:
(1) e-Tags for interchange transactions scheduled to flow into, out of or within the United States’ portion of the Eastern or Western Interconnections, or into the Electric Reliability Council of Texas from the United States’ portion of the Eastern or Western Interconnection; or from the Electric Reliability Council of Texas into the United States’ portion of the Eastern or Western Interconnection; and
(2) Information on every aspect of the e-Tag, including all applicable e-Tag IDs, transaction types, market segments, physical segments, profile sets, transmission reservations, and energy schedules. In addition, e-Tag Authors and Balancing Authorities must also make available, upon request to the e-Tag Authors and Balancing Authorities, access to the complete e-Tags, or any successor to e-Tags, used to schedule the transmission of electric power in wholesale markets, to Regional Transmission Organizations, Independent System Operators, and their Market Monitoring Units, on an ongoing basis, subject to appropriate confidentiality restrictions.
(e) Confidentiality. No member, officer, or employee of the Commission shall divulge any fact or information that may come to his or her knowledge during the course of examination of books, accounts, memoranda, or other records as provided in this section, except as may be directed by the Commission or by a court of competent jurisdiction.
§ 366.3 Exemption from Commission access to books and records; waivers of accounting, record-retention, and reporting requirements.
(a) Exempt classes of entities. Any person that is a holding company solely with respect to one or more of the following will be exempt from the requirements of §§ 366.2 and 366.21 and any associated service company will be exempt from the requirements of §§ 366.2, 366.22, and 366.23; such person need not make the filings provided in § 366.4(a) or (b):
(1) Qualifying facilities under the Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 2601 et seq.);
(2) Exempt wholesale generators; or
(3) Foreign utility companies.
(b) Exemptions of additional persons and classes of transactions—(1) Commission authority to exempt additional persons and classes of transactions. The Commission shall exempt a person or class of transactions from the requirements of § 366.2 and the accounting, record-retention, and reporting requirements of §§ 366.21, 366.22, and 366.23 if, upon individual application or upon the motion of the Commission—
(i) The Commission finds that the books, accounts, memoranda, and other records of any person are not relevant to the jurisdictional rates of a public utility or natural gas company; or
(ii) The Commission finds that any class of transactions is not relevant to the jurisdictional rates of a public utility or natural gas company.
(2) Commission exemption of additional persons and classes of transactions. The Commission has determined that the following persons and classes of transactions satisfy the requirements of paragraph (b)(1) of this section, and any person that is a holding company solely with respect to one or more of the following may file to obtain an exemption for that person or class of transactions, as appropriate, from the requirements of §§ 366.2 and 366.21 (applicable to holding companies) and §§ 366.2, 366.22, and 366.23 (applicable to the holding companies’ associated service companies), pursuant to the notification procedure contained in § 366.4(b):
(i) Passive investors, so long as the ownership remains passive, including:
(A) Mutual funds,
(B) Collective investment vehicles whose assets are managed by banks, savings and loan associations and their operating subsidiaries, or brokers/dealers; and
(C) Persons that directly, or indirectly through their subsidiaries or affiliates, buy and sell the securities of public-utility companies in the ordinary course of business as a broker/dealer, underwriter or fiduciary, and not exercising operational control over such companies;
(ii) Commission-jurisdictional utilities that have no captive customers and that are not affiliated with any jurisdictional utility that has captive customers, and that do not own Commission-jurisdictional transmission facilities or provide Commission-jurisdictional transmission services and that are not affiliated with persons that own Commission-jurisdictional transmission facilities or provide Commission-jurisdictional transmission services, and holding companies that own or control only such utilities;
(iii) Transactions where the holding company affirmatively certifies on behalf of itself and its subsidiaries, as applicable, that it will not charge, bill or allocate to the public utility or natural gas company in its holding company system any costs or expenses in connection with goods and services transactions, and will not engage in financing transactions with any such public utility or natural gas company;
(iv) Transactions between or among affiliates that are independent of and do not include a public utility or natural gas company;
(v) Electric power cooperatives;
(vi) Local distribution companies that are not regulated as “natural gas companies” pursuant to sections 1(b) or 1(c) of the Natural Gas Act, (15 U.S.C. 717(b), (c)).
(vii) Natural gas companies that distribute natural or manufactured gas at retail to industrial or electric generation customers and/or distribute de minimis amounts of natural or manufactured gas at retail to farmer or rancher customers located adjacent to the natural gas company’s rights-of-way.
(c) Waivers. Any person that is a holding company solely with respect to one or more of the following may file to obtain a waiver of the accounting, record-retention, and reporting requirements of § 366.21 (applicable to holding companies) and §§ 366.22 and 366.23 (applicable to the holding companies’ associated service companies), pursuant to the notification procedures contained in § 366.4(c):
(1) Single-state holding company systems; for purposes of § 366.3(c)(1), a holding company system will be deemed to be a single-state holding company system if the holding company system derives no more than 13 percent of its public-utility company revenues from outside a single state (for purposes of this waiver, revenues derived from exempt wholesale generators, foreign utility companies and qualifying facilities will not be considered public-utility company revenues);
(2) Holding companies that own generating facilities that total 100 MW or less in size and are used fundamentally for their own load or for sales to affiliated end-users; or
(3) Investors in independent transmission-only companies.
(d) Other requests for exemptions and waivers. Any person seeking an exemption or waiver that is not covered by paragraphs (a), (b)(2) or (c) of this section, shall file a petition for declaratory order pursuant to § 385.207(a) of this chapter justifying the request for exemption or waiver. Any person seeking such an exemption or waiver shall bear the burden of demonstrating that such an exemption or waiver is warranted.
(e) Nothing in paragraphs (a)–(d) of this section shall affect the authority of the Commission under the Federal Power Act (16 U.S.C. 791 et seq.), the Natural Gas Act (15 U.S.C. 717 et seq.), or other applicable law, including the authority of the Commission with respect to rates, charges, classifications, rules, regulations, practices, contracts, facilities, and services under the Federal Power Act and Natural Gas Act and with respect to access to books and records under the Federal Power Act and Natural Gas Act.
§ 366.4 FERC–65, notification of holding company status, FERC–65A, exemption notification, and FERC–65B, waiver notification.
(a) Notification of holding company status. (1) Persons that meet the definition of a holding company as provided by § 366.1 as of February 8, 2006 shall notify the Commission of their status as a holding company no later than June 15, 2006. Holding companies formed after February 8, 2006 shall notify the Commission of their status as a holding company, no later than the later of June 15, 2006 or 30 days after they become holding companies.
(2) The notification required pursuant to § 366.4(a)(1) shall be made by submitting FERC–65 (notification of holding company status), which shall contain the following: The identity of the holding company and of the public utilities and natural gas companies in the holding company system; the identity of service companies, including special-purpose subsidiaries providing non-power goods and services; the identity of all affiliates and subsidiaries; and their corporate relationship to each other. This filing will be for informational purposes and will not be noticed in the
(3) Notwithstanding § 366.4(a)(1) and (2), holding companies that are exempt holding companies pursuant to § 366.3(a) are not required to notify the Commission of their status or to submit FERC–65 (notification of holding company status).
(b) FERC–65A (exemption notification) and petitions for exemption. (1) Persons who, pursuant to § 366.3(b)(2), seek exemption from the requirements of § 366.2 and the accounting, record-retention, and reporting requirements of §§ 366.21, 366.22, and 366.23, may seek such exemption by filing FERC–65A (exemption notification); FERC–65A must be subscribed, consistent with § 385.2005(a) of this chapter, but need not be verified. These filings will be noticed in the
(2) Notwithstanding § 366.4(b)(1), persons that are exempt holding companies pursuant to § 366.3(a) are not required to file FERC–65A (exemption notification).
(3) Persons that do not qualify for exemption pursuant to § 366.3(b)(2) may seek an individual exemption from this subchapter. They may not do so by means of filing FERC–65A and instead must file a petition for declaratory order as required under § 366.3(d). Such petitions will be noticed in the
(c) FERC–65B (waiver notification) and petitions for waiver. (1) Persons who, pursuant to § 366.3(c), seek waiver of the accounting, record-retention, and reporting requirements of §§ 366.21, 366.22, and 366.23, may seek such waiver by filing FERC–65B (waiver notification); FERC–65B must be subscribed, consistent with § 385.2005(a) of this chapter, but need not be verified. FERC–65B will be noticed in the
(2) Persons that do not qualify for waiver pursuant to § 366.3(c) may seek an individual waiver from this subchapter. They may not do so by means of filing FERC–65B and instead must file a petition for declaratory order as required under § 366.3(d). Such petitions will be noticed in the
(d) Procedure for notification of material change in facts. (1) If there is any material change in facts that may affect an exemption or waiver granted pursuant to paragraphs (b) or (c) of this section, the person receiving the exemption or waiver shall within 30 days of the material change in facts:
(i) Submit a new FERC–65A (exemption notification) or FERC–65B (waiver notification) or a petition for declaratory order, pursuant to paragraphs (b) or (c) of this section, as appropriate;
(ii) File a written explanation why the material change in facts does not affect the exemption or waiver; or
(iii) Notify the Commission that it no longer seeks to maintain its exemption or waiver.
(2) If there is a material change in facts that may affect the automatic exemption allowed under § 366.3(a) of this subpart, the person receiving the exemption or waiver shall within 30 days of the material change in facts:
(i) Submit a FERC–65A (exemption notification) or FERC–65B (waiver notification) or a petition for declaratory order, pursuant to paragraphs (b) or (c) of this section, as appropriate;
(ii) File a written explanation why the material change in facts does not affect the exemption; or
(iii) Notify the Commission that it no longer seeks to maintain its exemption.
(e) Revocation of exemption or waiver. (1) If a person that is exempt pursuant to § 366.3(a) fails to conform to the criteria for such exemption, or if a person that has been granted an exemption or waiver pursuant to paragraphs (b) or (c) of this section either fails to conform to the criteria for such exemption or waiver or fails to conform with any material facts or representations presented in its submittals to the Commission, such person may no longer rely upon the exemption or waiver.
(2) The Commission may, on its own motion or on the complaint of any person, revoke the exemption or waiver granted under § 366.3(a) or paragraphs (b) or (c) of this section, if the person fails to conform to any of the criteria under this part for exemption or waiver.
§ 366.5 Allocation of costs for non-power goods and services.
(a) Commission review. In the case of non-power goods or administrative or management services provided by an associate company organized specifically for the purpose of providing such goods or services to any public utility in the same holding company system, at the election of that holding company system or a state commission having jurisdiction over the public utility, the Commission shall review and authorize the allocation of the costs for such goods or services to the extent relevant to that associate company. Such election to have the Commission review and authorize cost allocations shall remain in effect until further Commission order.
(b) Exemptions. Paragraph (a) of this section shall not apply to any holding company system whose public utility operations are confined substantially to a single state. For purposes of this section, a holding company system will be deemed to have its public utility operations confined substantially to a single state if the holding company system derives no more than 13 percent of its public utility revenues from outside a single state. A holding company system or state commission may, pursuant to this subsection, seek a Commission determination that a holding company’s public utility operations are confined substantially to a single state by filing a petition for declaratory order pursuant to § 385.207(a) of this chapter. Any holding company system or state commission seeking such a determination shall bear the burden of demonstrating that such determination is warranted.
(c) Other classes of transactions. Either upon petition for declaratory order or upon its own motion, the Commission may exclude from the scope of Commission review and authorization under paragraph (a) of this section any class of transactions that the Commission finds is not relevant to the jurisdictional rates of a public utility. Any holding company system or state commission seeking to obtain such a determination under this subsection shall file a petition for declaratory order pursuant to § 385.207(a) of this chapter. Any holding company system or state commission seeking such an exemption shall bear the burden of demonstrating that such an exemption is warranted.
(d) Nothing in paragraphs (a)–(c) of this section shall affect the authority of the Commission under the Federal Power Act (16 U.S.C. 791 et seq.), the Natural Gas Act (15 U.S.C. 717 et seq.), or other applicable law, including the authority of the Commission with respect to rates, charges, classifications, rules, regulations, practices, contracts, facilities, and services under the Federal Power Act and Natural Gas Act, and with respect to access to books and records under the Federal Power Act and Natural Gas Act.
(a) General. Unless otherwise provided by Commission rule or order, a person may continue to engage in activities or transactions authorized under the Public Utility Holding Company Act of 1935 prior to the effective date of the Public Utility Holding Company Act of 2005, February 8, 2006, until the later of the date such authorization expires or December 31, 2007, so long as that person continues to comply with the terms of such authorization. If any such activities or transactions are challenged in a formal Commission proceeding, the person claiming prior authorization shall be required to provide at that time the full text of any such authorization (whether by rule, order, or letter) and the application(s) or pleading(s) underlying such authorization (whether by rule, order, or letter).
(b) Financing Authorizations. Holding companies that intend to rely on financing authorization orders or letters issued by the Securities and Exchange Commission must file these orders or letters with the Commission within 30 days after the effective date of the Public Utility Holding Company Act of 2005, February 8, 2006; any reports or other submissions that, pursuant to such financing authorizations, previously were filed with the Securities and Exchange Commission must instead be filed with the Commission, effective February 8, 2006. For the purposes of this section, compliance with the terms of such financing authorizations includes the requirement to notify the Commission of any financing transactions that a holding company engages in pursuant to such financing authorization.
§ 366.7 Procedures for obtaining exempt wholesale generator and foreign utility company status.
(a) Self-certification notice procedure. An exempt wholesale generator or a foreign utility company, or its representative, may file with the Commission a notice of self-certification demonstrating that it satisfies the definition of exempt wholesale generator or foreign utility company (including stating the location of its generation); such notices of self-certification must be subscribed, consistent with § 385.2005(a) of this chapter, but need not be verified. In the case of exempt wholesale generators, the person filing a notice of self-certification under this section must also file a copy of the notice of self-certification with the state regulatory authority of the state in which the facility is located, and that person must also represent to this Commission in its submittal with this Commission that it has filed a copy of the notice of self-certification with the state regulatory authority of the state in which the facility is located. Notice of the filing of a notice of self-certification will be published in the
(b) Optional procedure for Commission determination of exempt wholesale generator status or foreign utility company status. A person may file for a Commission determination of exempt wholesale generator status or foreign utility company status under § 366.1 by filing a petition for declaratory order pursuant to § 385.207(a) of this chapter, justifying the request for such status; however, consistent with section 32(c) of the Public Utility Holding Company Act of 1935 (15 U.S.C. 79z–5a (c)), a Commission determination of exempt wholesale generator status may not become effective until the relevant state commissions have made the determinations provided for therein if such determinations are necessary. (If such determinations are not necessary, the petition for declaratory order should state so.) Persons that file petitions must include a form of notice suitable for publication in the
(c) Procedure for notification of material change in facts. If there is any material change in facts that may affect an exempt wholesale generator’s or a foreign utility company’s status as an exempt wholesale generator or a foreign utility company, the exempt wholesale generator or foreign utility company shall within 30 days of the material change in facts:
(1) Submit a new notice of self-certification or a new petition for declaratory order, pursuant to paragraphs (a) or (b) of this section, as appropriate;
(2) File a written explanation why the material change in facts does not affect its status; or
(3) Notify the Commission that it no longer seeks to maintain its exempt wholesale generator or foreign utility company status.
(d) Revocation of status. (1) If an exempt wholesale generator or a foreign utility company fails to conform to the criteria for such status or fails to conform with any material facts or representations presented in its submittals to the Commission, the notice of self-certification of the status of the facility or Commission order certifying the status of the facility may no longer be relied upon.
(2) The Commission may, on its own motion or on the complaint of any person, revoke the status of a facility or company, if the facility or company fails to conform to any of the criteria under this part for such status.
(e) An exempt wholesale generator shall not be subject to any requirements of this part other than § 366.7, i.e., procedures for obtaining exempt wholesale generator status. A foreign utility company shall not be subject to any requirements of this part other than § 366.7, i.e., procedures for obtaining foreign utility company status.
Subpart B—Accounting and Recordkeeping Under PUHCA 2005, the Federal Power Act and the Natural Gas Act
§ 366.21 Accounts and records of holding companies.
(a) General. Unless otherwise exempted or granted a waiver by Commission rule or order pursuant to §§ 366.3 and 366.4, every holding company shall maintain and make available to the Commission books, accounts, memoranda, and other records of all of its transactions in sufficient detail to permit examination, audit and verification of the financial statements, schedules and reports either required to be filed with the Commission or issued to stockholders, as necessary and appropriate for the protection of utility customers with respect to jurisdictional rates.
(b) Unless otherwise exempted or granted a waiver by Commission rule or order pursuant to §§ 366.3 and 366.4, beginning January 1, 2008, all holding companies must comply with the Commission’s records retention requirements for holding companies and service companies as prescribed in part 368 of this chapter. Until December 31, 2007, holding companies registered under the Public Utility Holding Company Act of 1935 (15 U.S.C. 79a et seq.) may follow either the Commission’s records retention rules for public utilities and licensees or for natural gas companies, as appropriate (parts 125 and 225 of this chapter), or the Securities and Exchange Commission’s record retention rules in 17 CFR part 257.
(c) Nothing in this section shall relieve any company subject thereto from compliance with the requirements as to recordkeeping and record-retention that may be prescribed by any other regulatory agency.
§ 366.22 Accounts and records of service companies.
(a) Record-retention requirements—(1) General. Unless otherwise exempted or granted a waiver by Commission rule or order pursuant to §§ 366.3 and 366.4, beginning January 1, 2008, every service company must maintain and make available to the Commission such books, accounts, memoranda, and other records in such manner and preserve them for such periods as the Commission prescribes in part 368 of this chapter, in sufficient detail to permit examination, audit, and verification, as necessary and appropriate for the protection of utility customers with respect to jurisdictional rates.
(2) Transition period. Until December 31, 2007, service companies in holding company systems registered under the Public Utility Holding Company Act of 1935 (15 U.S.C. 79a et seq.) may follow either the Commission’s records retention requirements in parts 125 and 225 of this chapter or the Securities and Exchange Commission’s records retention rules in 17 CFR part 257.
(3) Nothing in this section shall relieve any service company subject thereto from compliance with requirements as to record-retention that may be prescribed by any other regulatory agency.
(b) Accounting requirements—(1) General. Unless otherwise exempted or granted a waiver by Commission rule or order pursuant to §§ 366.3 and 366.4, beginning January 1, 2008, every centralized service company (See § 367.2 of this chapter) must maintain and make available to the Commission such books, accounts, memoranda, and other records as the Commission prescribes in part 367 of this chapter, in sufficient detail to permit examination, audit, and verification, as necessary and appropriate for the protection of utility customers with respect to jurisdictional rates. Every such service company must maintain and make available such books, accounts, memoranda, and other records in such manner as are prescribed in part 367 of this chapter, and must keep no other records with respect to the same subject matter except:
(i) Records other than accounts;
(ii) Records required by Federal or State law;
(iii) Subaccounts or supporting accounts which are not inconsistent with the accounts required either by the Uniform System of Accounts for Centralized Service Companies in part 367 of this chapter; and
(iv) Any other accounts that may be authorized by the Commission.
(2) Transition period. Until December 31, 2007, service companies in holding company systems registered under the Public Utility Holding Company Act of 1935 (15 U.S.C. 79a et seq.), as described in paragraph (b)(1) of this section, may follow either the Commission’s Uniform System of Accounts in parts 101 and 201 of this chapter or the Securities and Exchange Commission’s Uniform System of Accounts in 17 CFR part 256.
(3) Nothing in this section shall relieve any service company subject thereto from compliance with requirements as to accounting that may be prescribed by any other regulatory agency.
§ 366.23 FERC Form No. 60, Annual reports of centralized service companies, and FERC–61, Narrative description of service company functions.
(a) General—(1) FERC Form No. 60. Unless otherwise exempted or granted a waiver by Commission rule or order pursuant to §§ 366.3 and 366.4, every centralized service company (see § 367.2 of this chapter) in a holding company system, regardless of whether that service company is providing services to a public utility, a natural gas company, or both, must file an annual report, FERC Form No. 60, as provided in § 369.1 of this chapter. Every report must be submitted on the FERC Form No. 60 then in effect and must be prepared in accordance with the instructions incorporated in that form.
(2) FERC–61. Unless otherwise exempted or granted a waiver by Commission rule or order pursuant to §§ 366.3 and 366.4, every service company in a holding company system, including a special-purpose company (e.g., a fuel supply company or a construction company), that does not file a FERC Form No. 60 shall instead file with the Commission by May 1, 2007 and by May 1 each year thereafter, a narrative description, FERC–61, of the service company’s functions during the prior calendar year. In complying with this section, a holding company may make a single filing on behalf of all such service company subsidiaries.
(3) For good cause shown, the Commission may extend the time within which any such report or narrative description required to be filed pursuant to paragraphs (a)(1) or (2) of this section is to be filed or waive the requirements applicable to any such report or narrative description.
(b) Transition period. Service companies in holding company systems exempted from the requirements of the Public Utility Holding Company Act of 1935 (15 U.S.C. 79a et seq.) need not file an annual report, FERC Form No. 60, for calendar years 2005 through 2007, after which they must comply with the provisions of this section.
PART 367—UNIFORM SYSTEM OF ACCOUNTS FOR CENTRALIZED SERVICE COMPANIES SUBJECT TO THE PROVISIONS OF THE PUBLIC UTILITY HOLDING COMPANY ACT OF 2005, FEDERAL POWER ACT AND NATURAL GAS ACT
Subpart A—Definitions
§ 367.1 Definitions.
(a) When used in this system of accounts:
(1) Accounts mean the accounts prescribed by this Uniform System of Accounts.
(2) Actually issued, as applied to securities issued or assumed by the service companies, means those which have been sold to bona fide purchasers for a valuable consideration, those issued as dividends on stock, and those which have been issued in accordance with contractual requirements direct to trustees of sinking funds.
(3) Actually outstanding, as applied to securities issued or assumed by the service company, means those which have been actually issued and are neither retired nor held by or for the service company; provided, however, that securities held by trustees must be considered as actually outstanding.
(4) Amortization means the gradual extinguishment of an amount in an account by distributing such amount over a fixed period, over the life of the asset or liability to which it applies, or over the period during which it is anticipated the benefit will be realized.
(5) Associate company means any company in the same holding company system with such company.
(6) Book cost means the amount at which property is recorded in these accounts without deduction of related provisions for accrued depreciation, amortization, or for other purposes.
(7) Centralized service company means a service company that provides services such as administrative, managerial, financial, accounting, recordkeeping, legal or engineering services, which are sold, furnished, or otherwise provided (typically for a charge) to other companies in the same holding company system. Centralized service companies are different from other service companies that only provide a discrete good or service.
(8) Commission means the Federal Energy Regulatory Commission.
(9) Company, when not otherwise indicated in the context, means a service company.
(10) Construction, when used in the context of a service provided to other companies, means any construction, extension, improvement, maintenance, or repair of the facilities or any part thereof of a company, which is performed for a charge.
(11) Cost means the amount of money actually paid for property or services. When the consideration given is other than cash in a purchase and sale transaction, as distinguished from a transaction involving the issuance of common stock in a merger, the value of such consideration must be determined on a cash basis.
(12) Cost accumulation system means a system for the accumulation of service company costs on a job, project, or functional basis. It includes schedules and worksheets used to account for charges billed to single and groups of associate and non-associate companies. It can be a variety of systems, including but not limited to, a work order system or an activity-based accounting software system.
(13) Cost of removal means the cost of demolishing, dismantling, tearing down or otherwise removing service property, including the cost of transportation and handling incidental thereto. It does not include the cost of removal activities associated with asset retirement obligations that are capitalized as part of the tangible long-lived assets that give rise to the obligation (See General Instructions in § 367.22).
(14) Debt expense means all expenses in connection with the issuance and initial sale of evidences of debt, such as fees for drafting mortgages and trust deeds; fees and taxes for issuing or recording evidences of debt; cost of engraving and printing bonds and certificates of indebtedness; fees paid trustees; specific costs of obtaining governmental authority; fees for legal services; fees and commissions paid underwriters, brokers, and salesmen for marketing such evidences of debt; fees and expenses of listing on exchanges; and other like costs.
(15) Depreciation, as applied to depreciable service company property, means the loss in service value not restored by current maintenance. Among the causes to be used as consideration for causes of loss in service value are wear and tear, decay, action of the elements, inadequacy, obsolescence, changes in the art, changes in demand and requirements of public authorities.
(16) Direct cost means the labor costs and expenses which can be identified through a cost allocation system as being applicable to services performed for a single or group of associate and non-associate companies. Cost incidental to or related to a directly charged item must be classified as direct costs.
(17) Discount, as applied to the securities issued or assumed by the service company, means the excess of the par (stated value of no-par stocks) or face value of the securities plus interest or dividends accrued at the date of the sale over the cash value of the consideration received from their sale.
(18) Electric utility company means any company that owns or operates facilities used for the generation, transmission, or distribution of electric energy for sale. For the purposes of this subchapter, “electric utility company” shall not include entities that engage only in marketing of electric energy.
(19) Gas utility company means any company that owns or operates facilities used for distribution at retail (other than the distribution only in enclosed portable containers or distribution to tenants or employees of the company operating such facilities for their own use and not for resale) of natural or manufactured gas for heat, light, or power. For the purposes of this subchapter, “gas utility company” shall not include entities that engage only in marketing of natural and manufactured gas.
(20) Goods means any goods, equipment (including machinery), materials, supplies, appliances, or similar property (including coal, oil, or steam, but not including electric energy, natural or manufactured gas, or utility assets) which is sold, leased, or furnished, for a charge.
(21) Holding company.
(i) In general. The term “holding company” means—
(A) Any company that directly or indirectly owns, controls, or holds, with power to vote, 10 percent or more of the outstanding voting securities of a public-utility company or of a holding company of any public-utility company; and
(B) Any person, determined by the Commission, after notice and opportunity for hearing, to exercise directly or indirectly (either alone or pursuant to an arrangement or understanding with one or more persons) such a controlling influence over the management or policies of any public-utility company or holding company as to make it necessary or appropriate for the rate protection of utility customers with respect to rates that such person be subject to the obligations, duties, and liabilities imposed by this subchapter upon holding companies.
(ii) Exclusions. The term “holding company” does not include—
(A) A bank, savings association, or trust company, or their operating subsidiaries that own, control, or hold, with the power to vote, public utility or public utility holding company securities so long as the securities are—
(1) Held as collateral for a loan;
(2) Held in the ordinary course of business as a fiduciary; or
(3) Acquired solely for purposes of liquidation and in connection with a loan previously contracted for and owned beneficially for a period of not more than two years; or
(B) A broker or dealer that owns, controls, or holds with the power to vote public utility or public utility holding company securities so long as the securities are—
(1) Not beneficially owned by the broker or dealer and are subject to any voting instructions which may be given by customers or their assigns; or
(2) Acquired in the ordinary course of business as a broker, dealer, or underwriter with the bona fide intention of effecting distribution within 12 months of the specific securities so acquired.
(22) Holding company system means a holding company, together with its subsidiary companies.
(23) Indirect cost means the costs of a general overhead nature such as general services, housekeeping costs, and other support cost which cannot be separately identified to a single or group of associate and non-associate companies and, therefore, must be allocated. Costs incidental to or related to indirect items should also be classified as an indirect cost.
(24) Investment advances means advances, represented by notes or by book accounts only, with respect to which it is mutually agreed or intended between the creditor and debtor that they must be settled by the issuance of securities or must not be subject to current settlement.
(25) Lease, capital means a lease of property used by the service company, which meets one or more of the criteria stated in General Instructions in § 367.18.
(26) Lease, operating means a lease of property used by a service company, which does not meet any of the criteria stated in General Instructions in § 367.18.
(27) Minor items of property means the associated parts or items of which retirement units are composed.
(28) Natural gas company means a person engaged in the transportation of natural gas in interstate commerce or the sale of such gas in interstate commerce for resale.
(29) Net salvage value means the salvage value of property retired less the cost of removal.
(30) Nominally issued, as applied to securities issued or assumed by the service company, means those which have been signed, certified, or otherwise executed, and placed with the proper officer for sale and delivery, or pledged, or otherwise placed in some special fund of the service company, but which have not been sold, or issued direct to trustees of sinking funds in accordance with contractual requirements.
(31) Nominally outstanding, as applied to securities issued or assumed by the service company, means those which, after being actually issued, have been reacquired by or for the service company under circumstances which require them to be considered as held alive and not retired, provided, however, that securities held by trustees must be considered as actually outstanding.
(32) Non-associate company means a person, partnership, organization, government body or company which is not a member of the holding company system.
(33) Non-utility company means a company that is not a utility company.
(34) Person means an individual or company.
(35) Premium, as applied to securities issued or assumed by the service company, means the excess of the cash value of the consideration received from their sale over the sum of their par (stated value of no-par stocks) or face value and interest or dividends accrued at the date of sale.
(36) Public utility means any person who owns or operates facilities used for transmission of electric energy in interstate commerce or sales of electric energy at wholesale in interstate commerce.
(37) Public-utility company means an electric utility company or gas utility company.
(38) Regulatory assets and liabilities are the assets and liabilities that result from rate actions for regulatory agencies. Regulatory assets and liabilities arise from specific revenues, expenses, gains, or losses that would have been included in net income determination in one period under the general requirements of the Uniform System of Accounts but for it being probable:
(i) That such items will be included in a different period(s) for purposes of developing rates the service company is authorized to charge for its services; or
(ii) In the case of regulatory liabilities, that refunds to customers, not provided for in other accounts, will be required.
(39) Replacing or replacement, when not otherwise indicated in the context, means the construction or installation of service property in place of property retired, together with the removal of the property retired.
(40) Research, development, and demonstration (RD&D) means expenditures incurred by a service company, for the service company or on behalf of others, either directly or through another person or organization (such as research institute, industry association, foundation, university, engineering company or similar contractor) in pursuing research, development, and demonstration activities including experiment, design, installation, construction, or operation. This definition includes expenditures for the implementation or development of new and/or existing concepts until technically feasible and commercially feasible operations are verified. When conducted on behalf of an associate or non-associate utility company such research, development, and demonstration costs should be reasonably related to the existing or future business of such company. The term includes, but is not limited to: All the costs incidental to the design, development or implementation of an experimental facility, a plant process, a product, a formula, an invention, a system or similar items, and the improvement of already existing items of a like nature; amounts expended in connection with the proposed development and/or proposed delivery of alternate sources of electricity or substitute or synthetic gas supplies (alternate fuel sources, for example, an experimental coal gasification plant or an experimental plant synthetically producing gas from liquid hydrocarbons); and the costs of obtaining its own patent, such as attorney’s fees expended in making and perfecting a patent application. The term includes preliminary investigations and detailed planning of specific projects for securing for customers’ non-conventional electric power or pipeline gas supplies that rely on technology that has not been verified previously to be feasible. The term does not include expenditures for efficiency surveys; studies of management, management techniques and organization; consumer surveys, advertising, promotions, or items of a like nature.
(41) Retained earnings means the accumulated net income of the service company less distribution to stockholders and transfers to other capital accounts.
(42) Retirement units means those items of property which, when retired, with or without replacement, are accounted for by crediting the book cost of the retirement units to the property account in which it is included.
(43) Salvage value means the amount received for property retired, less any expenses incurred in connection with the sale or in preparing the property for sale; or, if retained, the amount at which the material recoverable is chargeable to materials and supplies, or other appropriate account.
(44) Service means any managerial, financial, legal, engineering, purchasing, marketing, auditing, statistical, advertising, publicity, tax, research, or any other service (including supervision or negotiation of construction or of sales), information or data, which is sold or furnished for a charge.
(45) Service company means any associate company within a holding company system organized specifically for the purpose of providing non-power goods or services or the sale of goods or construction work to any public utility or any natural gas company, or both, in the same holding company system.
(46) Service cost means the total of direct and indirect costs incurred to provide a service to an associate or non-associate company which are properly charged to expense by the service company.
(47) Service life means the time between the date property is placed in service, or property is leased to others, and the date of its retirement. If depreciation is accounted for on a production basis rather than on a time basis, then service life should be measured in terms of the appropriate unit of production.
(48) Service value means the difference between the cost and net salvage value of service property.
(49) State commission means any commission, board, agency, or officer, by whatever name designated, of a State, municipality, or other political subdivision of a State that, under the laws of such State, has jurisdiction to regulate public-utility companies.
(50) Uniform System of Accounts (USofA) means the Uniform System of Accounts for Centralized Service Companies prescribed in this part, as amended from time to time.
(51) Utility company means a public-utility company or natural gas company whose rates are regulated by the Commission, state commission or other similar regulatory body.
(b) [Reserved]
Subpart B—General Instructions
§ 367.2 Companies for which this system of accounts is prescribed.
(a) Unless otherwise exempted or granted a waiver by Commission rule or order pursuant to §§ 366.3 and 366.4 of this chapter, this Uniform System of Accounts applies to any centralized service company operating, or organized specifically to operate, within a holding company system for the purpose of providing non-power services to any public utility or any natural gas company, or both, in the same holding company system.
(b) This Uniform System of Accounts is not applicable to:
(1) Service companies that are specifically organized as a special-purpose company such as a fuel supply company or a construction company.
(2) Electric or gas utility companies.
(3) Companies primarily engaged:
(i) In the production of goods, including exploration and development of fuel resources,
(ii) In the provision of water, telephone, or similar services, the sale of which is normally subject to public rate regulation,
(iii) In the provision of transportation, whether or not regulated, or
(iv) In the ownership of property, including leased property and fuel reserves, for the use of associate companies.
(4) A service company that provides services exclusively to a local gas distribution company.
(5) Holding companies.
(c) To the extent that the term service company is used in this Uniform System of Accounts, it applies only to centralized service companies.
§ 367.3 Records.
(a) Each service company must keep its books of account, and all other books, records, and memoranda that support the entries in the books of account, so as to be able to furnish full information on any item included in any account. Each entry must be supported by sufficient detailed information that will permit ready identification, analysis, and verification of all facts relevant and related to the records.
(b) The books and records referred to in this part include not only accounting records in a limited technical sense, but all other records, such as minutes books, stock books, reports, correspondence, and memoranda, that may be useful in developing the history of or facts regarding any transaction.
(c) No service company may destroy any books or records unless the destruction is permitted by the rules and regulations of the Commission.
(d) In addition to prescribed accounts, clearing accounts, temporary or experimental accounts, and subaccounts of any accounts may be kept, provided the integrity of the prescribed accounts is not impaired.
(e) The arrangement or sequence of the accounts prescribed in this part must not be controlling as to the arrangement or sequence in report forms that may be prescribed by the Commission.
§ 367.4 Numbering system.
(a) The account numbering plan used in this part consists of a system of three-digit whole numbers as follows:
(1) 100–199, Assets and other debits.
(2) 200–299, Liabilities and other credits.
(3) 300–399, Property accounts.
(4) 400–432 and 434–435, Income accounts.
(5) 433, 436 and 439, Retained earnings accounts.
(6) 457–458, Revenue accounts.
(7) 500–599, Electric operating expenses.
(8) 800–894, Gas operating expenses.
(9) 900–949, Customer accounts, customer service and informational, sales, and general and administrative expenses.
(b) The numbers prefixed to account titles are to be considered as parts of the titles. Each service company, however, may adopt for its own purposes a different system of account numbers (See also General Instructions in § 367.3(d)) provided that the numbers prescribed in this part must appear in the descriptive headings of the ledger accounts and in the various sources of original entry; however, if a service company uses a different system of account numbers and it is not practicable to show the prescribed account numbers in the various sources of original entry, the reference to the prescribed account numbers may be omitted from the various sources of original entry. Each service company using different account numbers for its own purposes must keep readily available a list of the account numbers that it uses and a reconciliation of those account numbers with the account numbers provided in this part. It is intended that the service company’s records must be kept so as to permit ready analysis by prescribed accounts (by direct reference to sources of original entry to the extent practicable) and to permit preparation of financial and operating statements directly from the records at the end of each accounting period according to the prescribed accounts.
§ 367.5 Accounting period.
Each service company must keep its books on a monthly basis so that for each month all transactions applicable to the account, as nearly as may be ascertained, must be entered in the books of the service company. Amounts applicable or assignable to a single or group of associate and non-associate companies must be segregated monthly. Each service company must close its books at the end of each calendar year unless otherwise authorized by the Commission.
§ 367.6 Submittal of questions.
To maintain uniformity of accounting, service companies must submit questions of doubtful interpretation to the Commission for consideration and decision.
§ 367.7 Item list.
Lists of items appearing in the texts of the accounts or elsewhere in this part are for the purpose of indicating clearly the application of the prescribed accounting. The lists are intended to be representative, but not exhaustive. The appearance of an item in a list warrants the inclusion of the item in the account mentioned only when the text of the account also indicates inclusion inasmuch as the same item frequently appears in more than one list. The proper entry in each instance must be determined by the texts of the accounts.
§ 367.8 Extraordinary items.
Extraordinary items are to be recognized according to the rules which are considered generally accepted accounting principles. These items are related to the effects of events and transactions that have occurred during the current period and that are of an unusual nature and infrequent occurrence. Each item recognized as extraordinary must be disclosed in the notes to financial statements (See Accounts 434 and 435 in §§ 367.4340 and 367.4350).
§ 367.9 Prior period items.
(a) Items of profit and loss related to the following must be accounted for as prior period adjustments and excluded from the determination of net income for the current year:
(1) Correction of an error in the financial statements of a prior year.
(2) Adjustments that result from realization of income tax benefits of pre-acquisition operating loss carry forwards of purchased subsidiaries.
(b) All other items of profit and loss recognized during the year must be included in the determination of net income for that year.
§ 367.10 Unaudited items.
Whenever a financial statement is required by the Commission, if it is known that a transaction has occurred that affects the accounts but the amount involved in the transaction and its effect upon the accounts cannot be determined with absolute accuracy, the amount must be estimated and the estimated amount included in the proper accounts. The service company is not required to anticipate minor items that would not appreciably affect the accounts.
§ 367.11 Distribution of pay and expenses of employees.
The charges to property, operating expense and other accounts for services and expenses of employees engaged in activities chargeable to various accounts, such as construction, maintenance, and operations, must be based upon the actual time engaged in the respective classes of work, or an appropriate allocation method.
§ 367.12 Payroll distribution.
Underlying accounting data must be maintained so that the distribution of the cost of labor charged direct to the various accounts will be readily available. The underlying data must permit a reasonably accurate distribution to be made of the cost of labor charged initially to clearing accounts so that the total labor cost may be classified among construction, cost of removal, or operating functions.
§ 367.13 Accounting to be on accrual basis.
(a) The service company is required to keep its accounts on the accrual basis. This requires the inclusion in its accounts of all known transactions of appreciable amount that affect the accounts. If bills covering the transactions have not been received or rendered, the amounts must be estimated and appropriate adjustments made when the bills are received. When the amount is ascertained, the necessary adjustments must be made through the accounts in which the estimate was recorded. If it is determined during the interval that a material adjustment will be required, the estimate must be adjusted through the current accounts. The service company is not required to anticipate minor items which would not appreciably affect these accounts.
(b) When payments are made in advance for items such as insurance, rents, taxes or interest, the amount applicable to future periods must be charged to account 165, Prepayments (§ 367.1650), and spread over the periods to which they are applicable by credits to account 165 (§ 367.1650), and charges to the accounts appropriate for the expenditure.
§ 367.14 Transactions with associate companies.
Each service company must keep its accounts and records so as to be able to furnish accurately and expeditiously statements of all transactions with associate companies. The statements may be required to show the general nature of the transactions, the amounts involved in the transactions and the amounts included in each account prescribed in this part with respect to such transactions. Transactions with associate companies must be recorded in the appropriate accounts for transactions of the same nature. Nothing contained in this part, however, must be construed as restraining the service company from subdividing accounts for the purpose of recording separately transactions with associate companies.
§ 367.15 Contingent assets and liabilities.
Contingent assets represent a possible source of value to the service company contingent upon the fulfillment of conditions regarded as uncertain. Contingent liabilities include items that, under certain conditions, may become obligations of the service company but that are neither direct nor assumed liabilities at the date of the balance sheet. The service company must be prepared to give a complete statement of significant contingent assets and liabilities (including cumulative dividends on preference stock) in its annual report and at such other times as may be requested by the Commission.
§ 367.16 Long-term debt: Premium, discount and expense, and gain or loss on reacquisition.
(a) A separate premium, discount and expense account must be maintained for each class and series of long-term debt (including receivers’ certificates) issued or assumed by the service company. The premium must be recorded in account 225, Unamortized premium on long-term debt (§ 367.2250), the discount must be recorded in account 226, Unamortized discount on long-term debt—Debit (§ 367.2260), and the expense of issuance must be recorded in account 181, Unamortized debt expense (§ 367.1810). The premium, discount and expense must be amortized over the life of the respective issues under a plan that will distribute the amounts equitably over the life of the securities. The amortization must be on a monthly basis, and the amounts relating to discounts and expenses must be charged to account 428, Amortization of debt discount and expense (§ 367.4280). The amounts relating to premiums must be credited to account 429, Amortization of premium on debt—Credit (§ 367.4290).
(b) When long-term debt is reacquired the difference between the amount paid upon reacquisition of any long-term debt and the face value, adjusted for unamortized discount, expenses or premium, as the case may be, applicable to the debt redeemed must be recognized currently in income and recorded in account 421, Miscellaneous income or loss (§ 367.4210), or account 426.5, Other deductions (§ 367.4265).
§ 367.17 Comprehensive inter-period income tax allocation.
(a) Where there are timing differences between the periods in which transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income, the income tax effects of such transactions are to be recognized in the periods in which the differences between book accounting income and taxable income arise and in the periods in which the differences reverse using the deferred tax method. In general, comprehensive inter-period tax allocation should be followed whenever transactions enter into the determination of pretax accounting income for the period even though some transactions may affect the determination of taxes payable in a different period, as further qualified in this section.
(b) Once comprehensive inter-period tax allocation has been initiated, either in whole or in part, it must be practiced on a consistent basis and must not be changed or discontinued without prior Commission approval.
(c) Tax effects deferred currently will be recorded as deferred debits or deferred credits in accounts 190, Accumulated deferred income taxes (§ 367.1900), 282, Accumulated deferred income taxes—Other property (§ 367.2820), and 283, Accumulated deferred income taxes—Other (§ 367.2830), as appropriate. The resulting amounts recorded in these accounts must be disposed of as prescribed in this system of accounts or as otherwise authorized by the Commission.
§ 367.18 Criteria for classifying leases.
(a) If, at its inception, a lease meets one or more of the following criteria, the lease must be classified as a capital lease. Otherwise, it must be classified as an operating lease.
(1) The lease transfers ownership of the property to the lessee by the end of the lease term.
(2) The lease contains a bargain purchase option.
(3) The lease term is equal to 75 percent or more of the estimated economic life of the leased property. However, if the beginning of the lease term falls within the last 25 percent of the total estimated economic life of the leased property, including earlier years of use, this criterion must not be used for purposes of classifying the lease.
(4) The present value at the beginning of the lease term of the minimum lease payments, excluding that portion of the payments representing executory costs such as insurance, maintenance, and taxes to be paid by the lessor, including any related profit, equals or exceeds 90 percent of the excess of the fair value of the leased property to the lessor at the inception of the lease over any related investment tax credit retained by the lessor and expected to be realized by the lessor. However, if the beginning of the lease term falls within the last 25 percent of the total estimated economic life of the leased property, including earlier years of use, this criterion must not be used for purposes of classifying the lease. The lessee must compute the present value of the minimum lease payments using its incremental borrowing rate, unless:
(i) It is practicable for the company to learn the implicit rate computed by the lessor, and
(ii) The implicit rate computed by the lessor is less than the lessee’s incremental borrowing rate.
(iii) If both of those conditions are met, the lessee must use the implicit rate.
(b) If, at any time, the lessee and lessor agree to change the provisions of the lease, other than by renewing the lease or extending its term, in a manner that would have resulted in a different classification of the lease under the criteria in paragraph (a) of this section had the changed terms been in effect at the inception of the lease, the revised agreement must be considered as a new agreement over its term, and the criteria in paragraph (a) of this section must be applied for purposes of classifying the new lease. Likewise, any action that extends the lease beyond the expiration of the existing lease term, such as the exercise of a lease renewal option other than those already included in the lease term, must be considered as a new agreement and must be classified according to the criteria in paragraph (a) of this section. Changes in estimates (for example, changes in estimates of the economic life or of the residual value of the leased property) or changes in circumstances (for example, default by the lessee) must not give rise to a new classification of a lease for accounting purposes.
§ 367.19 Accounting for leases.
(a) All leases must be classified as either capital or operating leases.
(b) The service company must record a capital lease as an asset in account 101.1, Property under capital leases (§ 367.1011) and an obligation in account 227, Obligations under capital leases—Non-current (§ 367.2270), or account 243, Obligations under capital leases—Current (§ 367.2430), at an amount equal to the present value at the beginning of the lease term of minimum lease payments during the lease term, excluding that portion of the payments representing executory costs such as insurance, maintenance, and taxes to be paid by the lessor, together with any related profit. However, if the determined amount exceeds the fair value of the leased property at the inception of the lease, the amount recorded as the asset and obligation must be the fair value.
(c) The service company, as a lessee, must recognize an asset retirement obligation (See General Instructions in § 367.22) arising from the property under a capital lease unless the obligation is recorded as an asset and liability under a capital lease. The service company must record the asset retirement cost by debiting account 101.1, Property under capital leases (§ 367.1011), and crediting the liability for the asset retirement obligation in account 230, Asset retirement obligations (§ 367.2300). Asset retirement costs recorded in account 101.1 (§ 367.1011) must be amortized by charging rent expense (see Operating Expense Instructions in § 367.82) or account 421, Miscellaneous income or loss (§ 367.4210), as appropriate, and crediting a separate subaccount of the account in which the asset retirement costs are recorded. Charges for the periodic accretion of the liability in account 230, Asset retirement obligations (§ 367.2300), must be recorded by a charge to account 411.10, Accretion expense (§ 367.4118), for service company property, and account 421, Miscellaneous income or loss (§ 367.4210), for non-service company property and a credit to account 230, Asset retirement obligations (§ 367.2300).
(d) Rental payments on all leases must be charged to rent expense, fuel expense, construction work in progress, or other appropriate accounts as they become payable.
(e) For a capital lease, for each period during the lease term, the amounts recorded for the asset and obligation must be reduced by an amount equal to the portion of each lease payment that would have been allocated to the reduction of the obligation, if the payment had been treated as a payment on an installment obligation (liability) and allocated between interest expense and a reduction of the obligation so as to produce a constant periodic rate of interest on the remaining balance.
§ 367.20 Depreciation accounting.
(a) Method. Service companies must use a method of depreciation that allocates in a systematic and rational manner the service value of depreciable property over the service life of the property.
(b) Service lives. Estimated useful service lives of depreciable property must be supported by objective evidence and analysis, including where appropriate engineering, economic, or other depreciation studies.
(c) Rate. Service companies must use percentage rates of depreciation that are based on a method of depreciation that allocates the service value of depreciable property over the service life of the property. Where composite depreciation rates are used, they must be based on the weighted average estimated useful service lives of the depreciable property comprising the composite group.
§ 367.22 Accounting for asset retirement obligations.
(a) An asset retirement obligation represents a liability for the legal obligation associated with the retirement of a tangible, long-lived asset that a service company is required to settle as a result of an existing or enacted law, statute, ordinance, or written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel. An asset retirement cost represents the amount capitalized when the liability is recognized for the long-lived asset that gives rise to the legal obligation. The amount recognized for the liability and an associated asset retirement cost must be stated at the fair value of the asset retirement obligation in the period in which the obligation is incurred.
(b) The service company must initially record a liability for an asset retirement obligation in account 230, Asset retirement obligations (§ 367.2300), and charge the associated asset retirement costs to service company property (including account 101.1 in § 367.1011) related to the property that gives rise to the legal obligation. The asset retirement cost must be depreciated over the useful life of the related asset that gives rise to the obligations. For periods subsequent to the initial recording of the asset retirement obligation, a service company must recognize the period to period changes of the asset retirement obligation that result from the passage of time due to the accretion of the liability and any subsequent measurement changes to the initial liability for the legal obligation recorded in account 230, Asset retirement obligations (§ 367.2300), as follows:
(1) The service company must record the accretion of the liability by debiting account 411.10, Accretion expense (§ 367.4118); and
(2) The service company must recognize any subsequent measurement changes of the liability initially recorded in account 230, Asset retirement obligations (§ 367.2300), for each specific asset retirement obligation as an adjustment of that liability in account 230 with the corresponding adjustment to service company property. The service company must on a timely basis monitor any measurement changes of the asset retirement obligations.
(c) Gains or losses resulting from the settlement of asset retirement obligations associated with service company property resulting from the difference between the amount of the liability for the asset retirement obligation included in account 230, Asset retirement obligations (§ 367.2300), and the actual amount paid to settle the obligation shall be accounted for as follows:
(1) Gains shall be credited to account 421, Miscellaneous income or loss (§ 367.4210), and;
(2) Losses shall be charged to account 426.5, Other deductions (§ 367.4265).
(d) Separate subsidiary records must be maintained for each asset retirement obligation showing the initial liability and associated asset retirement cost, any incremental amounts of the liability incurred in subsequent reporting periods for additional layers of the original liability and related asset retirement cost, the accretion of the liability, the subsequent measurement changes to the asset retirement obligation, the depreciation and amortization of the asset retirement costs and related accumulated depreciation, and the settlement date and actual amount paid to settle the obligation. For purposes of analysis, a service company must maintain supporting documentation so as to be able to furnish accurately and expeditiously with respect to each asset retirement obligation the full details of the identity and nature of the legal obligation, the year incurred, the identity of the plant giving rise to the obligation, the full particulars relating to each component and supporting computations related to the measurement of the asset retirement obligation.
§ 367.23 Transactions with non-associate companies.
When a service or construction is performed for non-associate companies at an amount other than cost, the amount of revenues in excess or deficiency of the cost on servicing the non-associate companies must be charged to account 458.4, Excess or deficiency on servicing non-associate utility companies (§ 367.4584). A deficiency incurred in a project deemed beneficial to the associate companies may be charged to associate companies subject to disallowance by a State Commission or Federal Commission having jurisdiction over the rates or services of the associate companies. To the extent not charged, or if disallowed, the deficiency will be charged to account 458.4 (§ 367.4584). In computing charges to associate companies for any calendar year, any net credit in this account must be deducted from amounts reimbursable by associate companies as compensation for use of capital invested in the service company.
§ 367.24 Construction and service contracts for other companies.
(a) Expenditures made in the performance of construction or service contracts, under which the service company undertakes projects to construct physical property for associate or non-associate companies must be recorded in Account 412, Cost and expenses of construction or other services (§ 367.4120). The service company must keep records pursuant to its cost allocation system indicating the cost of each contract or project, the amount of service costs allocated to the contracts, and the additional classification of expenditures relating to projects that will meet the accounting requirements of the company for which the work is performed.
(b) Account 412 (§ 367.4120) will include:
(1) The cost of materials, construction payrolls, outside services, and other expenses which are directly attributable to the performance of service or construction contracts for other companies.
(2) The cost of goods procured directly attributable to the performance of service or construction contracts for other companies.
(3) The related salaries, expense of officers and employees, pay of employees on the service company’s regular staff specifically assigned to construction work, and other expenses of maintaining the service company’s organization and equipment.
(4) The support services performed by the service company in connection with the procurement of goods for associate companies.
§ 367.25 Determination of service cost.
A service must be deemed at cost and fair allocation of costs requires an accurate accounting for the elements that makes up the aggregate expense of conducting the business of the service company. In the accounts prescribed in this part, the total amounts included in the expense accounts during any period plus the amount that appropriately may be added as compensation for the use of capital constitute cost during that period.
§ 367.26 Departmental classification.
Salaries and wages and all other costs must be classified by departmental or other functional category in accordance with the departmental organization of the service company to provide a readily available basis for analysis.
§ 367.27 Billing procedures.
Charges for services to associate public-utility companies must be made monthly with sufficient information and in sufficient detail to permit such company, where applicable, to identify and classify the charge in terms of the system of accounts prescribed by the regulatory authorities to which it is subject. The information provided to associate public-utility companies must provide a summary of the accounts by service provided and showing the charges, classified as direct cost, indirect cost, and compensation for use of capital.
§ 367.28 Methods of allocation.
Indirect costs and compensation for use of capital must be allocated to projects in accordance with the service company’s applicable and currently effective methods of allocation. Both direct and allocated indirect costs on projects must be assigned among those companies in the same manner. The cost accumulation system must identify the methods of allocation and the accounts to be charged. Companies must be notified in writing of any change in the methods of allocation.
§ 367.29 Compensation for use of capital.
A servicing transaction is deemed to be performed at no more than cost if the price of the service does not exceed a fair and equitable allocation of expenses plus reasonable compensation for necessary capital procured through the issuance of capital stock. Interest on borrowed capital and compensation for the use of capital must only represent a reasonable return on the amount of capital reasonably necessary for the performance of services or construction work for, or the sale of goods to, associate companies. The compensation may be estimated and must be computed monthly. The amount of compensation must be stated separately in each billing to the associate companies. An annual statement to support the amount of compensation for use of capital billed for the previous 12 months and how it was calculated must be supplied to each associate company at the end of the calendar year.
§ 367.30 Cost accumulation system for associate companies.
Service companies must maintain a detailed classification of service costs, that permits costs to be identified with the functional processes of the associate companies served. To permit the classification, each service company must maintain a cost accumulation system, as described in Definitions § 367.1(a)(12), for accumulating reimbursable costs and charges to the associate companies served, and maintain time records for all service company employees in order to support the accounting allocation of all expenses assignable to the types of services performed and chargeable to the associate companies served. Service company employee records must permit a ready identification of the hours worked, account numbers charged, and other code designations that facilitate proper classification.
Subpart C—Service Company Property Instructions
§ 367.50 Service company property to be recorded at cost.
(a) All amounts included in the accounts for service company property must be stated at the cost incurred by the service company, except for property acquired by lease which qualifies as capital lease property under General Instructions in § 367.18, Criteria for classifying leases, and is recorded in Account 101.1, Property under capital leases (§ 367.1011).
(b) When the consideration given for property is other than cash, the value of the consideration must be determined on a cash basis (See, however, Definitions § 367.1(a)(11)). In the entry recording the transaction, the actual consideration must be described with sufficient particularity to identify it. The service company must be prepared to furnish the Commission the particulars of its determination of the cash value of the consideration, if other than cash.
(c) When property is purchased under a plan involving deferred payments, no charge must be made to the service company property accounts for interest, insurance, or other expenditures occasioned solely by such form of payment.
(d) The service company property accounts must not include the cost or other value of service company property contributed to the company. Contributions in the form of money or its equivalent toward the construction of property must be credited to accounts charged with the cost of such construction. Property constructed from contributions of cash or its equivalent must be shown as a reduction to gross property constructed when assembling cost data for posting to property ledgers of accounts. The accumulated gross costs of property must be recorded as a debit in the plant ledger of accounts along with the related amount of contributions concurrently recorded as a credit.
§ 367.51 Components of construction.
(a) For service companies, the cost of construction properly included in the service company property accounts must include, where applicable, the direct and overhead costs as listed and defined as follows:
(1) Contract work includes amounts paid for work performed under contract by other companies, firms, or individuals, costs incident to the award of such contracts, and the inspection of the work.
(2) Labor includes the pay and expenses of employees of the service company engaged in construction work, and related workmen’s compensation insurance, payroll taxes and similar items of expense. It does not include the pay and expenses of employees that are distributed to construction through clearing accounts nor the pay and expenses included in other items in this section.
(3)(i) Materials and supplies includes the purchase price at the point of free delivery plus customs duties, excise taxes, the cost of inspection, loading and transportation, the related stores expenses, and the cost of fabricated materials from the service company’s shop. In determining the cost of materials and supplies used for construction, proper allowance must be made for unused materials and supplies, for materials recovered from temporary structures used in performing the work involved, and for discounts allowed and realized in the purchase of materials and supplies.
(ii) The cost of individual items of equipment of small value (for example, $500 or less) or of short life, including small portable tools and implements, must not be charged to service company property accounts unless the correctness of the accounting is verified by current inventories. The cost must be charged to the appropriate operating expense or clearing accounts, according to the use of the items, or, if the items are consumed directly in construction work, the cost must be included as part of the cost of the construction.
(4) Transportation includes the cost of transporting employees, materials and supplies, tools, purchased equipment, and other work equipment (when not under own power) to and from points of construction. It includes amounts paid to others as well as the cost of operating the service company’s own transportation equipment. (See paragraph (a)(5) of this section.)
(5) Special machine service includes the cost of labor (optional), materials and supplies, depreciation, and other expenses incurred in the maintenance, operation and use of special machines, such as steam shovels, pile drivers, derricks, ditchers, scrapers, material unloaders, and other labor saving machines; also expenditures for rental, maintenance and operation of machines of others. It does not include the cost of small tools and other individual items of small value or short life which are included in the cost of materials and supplies. (See paragraph (a)(3) of this section.) When a particular construction job requires the use for an extended period of time of special machines, transportation or other equipment, the associated net book cost, less the appraised or salvage value at time of release from the job, must be included in the cost of construction.
(6) Shop service includes the proportion of the expense of the service company’s shop department assignable to construction work except that the cost of fabricated materials from the service company’s shop must be included in materials and supplies.
(7) Protection includes the cost of protecting the service company’s property from fire or other casualties and the cost of preventing damages to others, or to the property of others, including payments for discovery or extinguishment of fires, cost of apprehending and prosecuting incendiaries, related witness fees, amounts paid to municipalities and others for fire protection, and other analogous items of expenditures in connection with construction work.
(8) Injuries and damages includes expenditures or losses in connection with construction work on account of injuries to persons and damages to the property of others; also the cost of investigation of, and defense against, actions for the injuries and damages. Insurance recovered or recoverable on account of compensation paid for injuries to persons incident to construction must be credited to the account or accounts to which such compensation is charged. Insurance recovered or recoverable on account of property damages incident to construction must be credited to the account or accounts charged with the cost of the damages.
(9) Privileges and permits includes payments for and expenses incurred in securing temporary privileges, permits or rights in connection with construction work, such as for the use of private or public property, streets, or highways, but it does not include rents.
(10) Rents include amounts paid for the use of construction quarters and office space occupied by construction forces and amounts properly includible in construction costs for the facilities jointly used.
(11) Engineering and supervision includes the portion of the pay and expenses of engineers, surveyors, draftsmen, inspectors, superintendents and their assistants applicable to construction work.
(12) General administration capitalized includes the portion of the pay and expenses of the general officers and administrative and general expenses applicable to construction work.
(13) Engineering services includes amounts paid to other companies, firms, or individuals engaged by the service company to plan, design, prepare estimates, supervise, inspect, or give general advice and assistance in connection with construction work.
(14) Insurance includes premiums paid or amounts provided or reserved as self-insurance for the protection against loss and damages in connection with construction, by fire or other casualty injuries to or death of persons other than employees, damages to property of others, defalcation of employees and agents, and the nonperformance of contractual obligations of others. It does not include workmen’s compensation or similar insurance on employees included as labor in paragraph (a)(2) of this section.
(15) Law expenditures includes the general law expenditures incurred in connection with construction and the directly related court and legal costs, other than law expenses included in protection in paragraph (a)(7) of this section, and in injuries and damages in paragraph (a)(8) of this section.
(16) Taxes include taxes on physical property (including land) during the period of construction and other taxes properly includible in construction costs before the facilities become available for service.
(17) Interest cost on funds used during construction which are allowed to be capitalized following generally accepted accounting principles.
(18) Earnings and expenses during construction. The earnings and expenses during construction must constitute a component of construction costs.
(19) Training costs. When it is necessary that employees be trained to operate or maintain property that is being constructed and the property is not conventional in nature, or is new to the company’s operations, these costs may be capitalized as a component of construction cost. Once property is placed in service, the capitalization of training costs must cease and subsequent training costs must be expensed. (See Operating Expense Instructions in § 367.83.)
(20) Studies include the costs of studies such as safety or environmental studies mandated by regulatory bodies relative to property under construction. Studies relative to facilities in service must be charged to account 183, Preliminary survey and investigation charges (§ 367.1830).
(21) Asset retirement costs. The costs recognized as a result of asset retirement obligations incurred during the construction and testing of service company property must constitute a component of construction costs.
(b) [Reserved]
§ 367.52 Overhead construction costs.
(a) All overhead construction costs, such as engineering, supervision, general office salaries and expenses, construction engineering and supervision by others than the service company, law expenses, insurance, injuries and damages, relief and pensions, taxes and interest, must be charged to particular jobs or units on the basis of the amounts of the reasonably applicable overheads.
(b) As far as practicable, the determination of payroll charges includible in construction overheads must be based on the related time card distributions. Where this procedure is impractical, special studies must be made periodically of the time of supervisory employees devoted to construction activities to the end that only the overhead costs that have a definite relation to construction must be capitalized.
(c) The records supporting the entries for overhead construction costs must be kept so as to show the total amount of each overhead for each year, the nature and amount of each overhead expenditure charged to each construction project and to each property account, and the bases of distribution of such costs.
§ 367.53 Service company property purchased or sold.
(a) When service company property is acquired by purchase, merger, consolidation, liquidation, or otherwise, after the effective date of this system of accounts, the costs of acquisition, including related incidental expenses, must be charged to the appropriate service company property accounts and account 107, Construction work in progress (§ 367.1070), as appropriate.
(b) If property acquired is in a physical condition so that it is necessary to rehabilitate it substantially in order to bring the property up to the standards of the service company, the cost of the work, except replacements, must be accounted for as a part of the purchase price of the property.
(c) Unless otherwise authorized by the Commission, all service company property acquired from an affiliate company must be recorded at its book value. Additionally, if property is acquired that is in excess of $10 million and has been previously devoted to public service at a price above book value, the service company must file with the Commission the proposed journal entries associated with the acquisition within six months from the date of acquisition of the property.
(d) When service company property is sold, conveyed, or transferred to another by sale, merger, consolidation, or otherwise, the book cost of the property sold or transferred to another must be credited to the appropriate service company property accounts. The amounts (estimated, if not known) carried with respect the accounts for accumulated provision for depreciation and amortization must be charged to those accounts. The difference, if any, between the net amount of debits and credits and the consideration received for the property (less commissions and other expenses of making the sale) must be included in account 421.1, Gain on disposition of property (§ 367.4211), or account 421.2, Loss on disposition of property (§ 367.4212).
(e) In connection with the acquisition of service company property previously devoted to service company operations or acquired from an associate company, the service company must procure, if possible, all existing records relating to the property acquired or related certified copies, and must preserve the records in conformity with regulations or practices governing the preservation of records of its own construction.
§ 367.54 Expenditures on leased property.
(a) The cost of substantial initial improvements (including repairs, rearrangements, additions, and betterments) made to prepare service company property leased to be used for a period of more than one year, and the cost of subsequent substantial additions, replacements, or betterments to the property, must be charged to the service company property account appropriate for the class of property leased. If the service life of the improvements is terminable by action of the lease, the cost, less net salvage, of the improvements must be spread over the life of the lease by charges to account 404, Amortization of limited-term service property (§ 367.4040). However, if the service life is not terminated by action of the lease but by depreciation proper, the cost of the improvements, less net salvage, must be accounted for as depreciable property. The provisions of this paragraph are applicable to property leased under either capital leases or operating leases.
(b) If improvements made to property leased for a period of more than one year are of relatively minor cost, or if the lease is for a period of not more than one year, the cost of the improvements must be charged to the account in which the rent is included, either directly or by amortization.
§ 367.55 Land and land rights.
(a) The accounts for land and land rights must include the cost of land owned in fee by the service company and rights. Interests, and privileges held by the service company in land owned by others, such as leaseholds, easements, water and water power rights, diversion rights, submersion rights, rights-of-way, and other like interests in land. Do not include in the accounts for land and land rights and rights-of-way costs incurred in connection with first clearing and grading of land and rights-of-way and the damage costs associated with the construction and installation of property. The costs must be included in the appropriate property accounts directly benefited.
(b) Where special assessments for public improvements provide for deferred payments, the full amount of the assessments must be charged to the appropriate land account and the unpaid balance must be carried in an appropriate liability account. Interest on unpaid balances must be charged to the appropriate interest account. If any part of the cost of public improvements is included in the general tax levy, the related amount must be charged to the appropriate tax account.
(c) The net profit from the sale of timber, cord wood, sand, gravel, other resources or other property acquired with the rights-of-way or other lands must be credited to the appropriate property account to which it is related. Where land is held for a considerable period of time and timber and other natural resources on the land at the time of purchase increases in value, the net profit (after giving effect to the cost of the natural resources) from the sales of timber or its products or other natural resources must be credited to the appropriate operating income account when the land has been recorded in account 101, Service company property (§ 367.1010), otherwise to account 421, Miscellaneous income or loss (§ 367.4210).
(d) Separate entries must be made for the acquisition, transfer, or retirement of each parcel of land, and each land right (except rights of way for distribution lines), or water right, having a life of more than one year. A record must be maintained showing the nature of ownership, full legal description, area, map reference, purpose for which used, city, county, and tax district on which situated, from whom purchased or to whom sold, payment given or received, other costs, contract date and number, date of recording of deed, and book and page of record. Entries transferring or retiring land or land rights must refer to the original entry recording its acquisition.
(e) Any difference between the amount received from the sale of land or land rights, less agents’ commissions and other costs incident to the sale, and the book cost of such land or rights, must be included in account 421.1, Gain on disposition of property (§ 367.4211), or account 421.2, Loss on disposition of property (§ 367.4212), when the property has been recorded in account 101, Service company property (§ 367.1010). Appropriate adjustments of the accounts must be made with respect to any structures or improvements located on the land sold.
(f) The cost of buildings and other improvements (other than public improvements) must not be included in the land accounts. If, at the time of acquisition of an interest in land the interest extends to buildings or other improvements (other than public improvements) that are then devoted to operations, the land and improvements must be separately appraised and the cost allocated to land and buildings or improvements on the basis of the appraisals. If the improvements are removed or wrecked without being used in operations, the cost of removing or wrecking must be charged and the salvage credited to the account in which the cost of the land is recorded.
(g) Provisions must be made for amortizing amounts carried in the accounts for limited-term interests in land so as to apportion equitably the cost of each interest over the life thereof. (See account 111, Accumulated provision for amortization of service company property in § 367.1110, and account 404, Amortization of limited-term property in § 367.4040.)
(h) The items of cost to be included in the accounts for land and land rights are as follows:
(1) Bulkheads, buried, not requiring maintenance or replacement.
(2) Cost, first, of acquisition including mortgages and other liens assumed (but not the related subsequent interest).
(3) Condemnation proceedings, including court and counsel costs.
(4) Consents and abutting damages, payment for.
(5) Conveyancers’ and notaries’ fees.
(6) Fees, commissions, and salaries to brokers, agents and others in connection with the acquisition of the land or land rights.
(7) Leases, cost of voiding upon purchase to secure possession of land.
(8) Removing, relocating, or reconstructing, property of others, such as buildings, highways, railroads, bridges, cemeteries, churches, telephone and power lines, in order to acquire quiet possession.
(9) Retaining walls unless identified with structures.
(10) Special assessments levied by public authorities for public improvements on the basis of benefits for new roads, new bridges, new sewers, new curbing, new pavements, and other public improvements, but not taxes levied to provide for the maintenance of such improvements.
(11) Surveys in connection with the acquisition, but not amounts paid for topographical surveys and maps where the costs are attributable to structures or plant equipment erected or to be erected or installed on the land.
(12) Taxes assumed, accrued to date of transfer of title.
(13) Title, examining, clearing, insuring and registering in connection with the acquisition and defending against claims relating to the period prior to the acquisition.
(14) Appraisals prior to closing title.
(15) Cost of dealing with distributees or legatees residing outside of the state or county, such as recording power of attorney, recording will or exemplification of will, recording satisfaction of state tax.
(16) Filing satisfaction of mortgage.
(17) Documentary stamps.
(18) Photographs of property at acquisition.
(19) Fees and expenses incurred in the acquisition of water rights and grants.
(20) Cost of fill to extend bulkhead line over land under water, where riparian rights are held, which is not occasioned by the erection of a structure.
(21) Sidewalks and curbs constructed by the service company on public property.
(22) Labor and expenses in connection with securing rights of way, where performed by company employees and company agents.
§ 367.56 Structures and improvements.
(a) The accounts for structures and improvements must include the cost of all buildings and facilities to house, support, or safeguard property or persons, including all fixtures permanently attached to and made a part of buildings and that cannot be removed from the buildings and facilities without cutting into the walls, ceilings, or floors, or without in some way impairing the buildings, and improvements of a permanent character on, or to, land. Also include those costs incurred in connection with the first clearing and grading of land and rights-of-way and the damage costs associated with construction and installation of property.
(b) The cost of specially-provided foundations not intended to outlast the machinery or apparatus for which provided, and associated costs, such as angle irons, castings, and other items installed at the base of an item of equipment, must be charged to the same account as the cost of the machinery, apparatus, or equipment.
(c) Where the structure of a dam also forms the foundation of the service company building, the foundation must be considered a part of the dam.
(d) The cost of disposing of materials excavated in connection with construction of structures must be considered as a part of the cost of that work, except as follows:
(1) When the material is used for filling, the cost of loading, hauling, and dumping must be equitably apportioned between the work in connection with which the removal occurs and the work in connection with which the material is used.
(2) When the material is sold, the net amount realized from the sales must be credited to the work in connection with which the removal occurs. If the amount realized from the sale of excavated materials exceeds the removal costs and the costs in connection with the sale, the excess must be credited to the land account in which the site is carried.
(e) Lighting or other fixtures temporarily attached to buildings for purposes of display or demonstration must not be included in the cost of the building but in the appropriate equipment account.
(f) This account must include the following items:
(1) Architects” plans and specifications including supervision.
(2) Ash pits (when located within the building).
(3) Athletic field structures and improvements.
(4) Boilers, furnaces, piping, wiring, fixtures, and machinery for heating, lighting, signaling, ventilating, and air-conditioning systems, plumbing, vacuum cleaning systems, incinerator and smoke pipe, flues and similar items.
(5) Bulkheads, including dredging, riprap fill, piling, decking, concrete, fenders, and similar items when exposed and subject to maintenance and replacement.
(6) Chimneys.
(7) Coal bins and bunkers.
(8) Commissions and fees to brokers, agents, architects, and others.
(9) Conduit (not to be removed) with its contents.
(10) Damages to abutting property during construction.
(11) Docks.
(12) Door checks and door stops.
(13) Drainage and sewerage systems.
(14) Elevators, cranes, hoists, and the machinery for operating them.
(15) Excavation, including shoring, bracing, bridging, refill and disposal of excess excavated material, cofferdams around foundation, pumping water from cofferdams during construction, and test borings.
(16) Fences and fence curbs (not including protective fences isolating items of equipment, which must be charged to the appropriate equipment account).
(17) Fire protection systems when forming a part of a structure.
(18) Flagpole.
(19) Floor covering (permanently attached).
(20) Foundations and piers for machinery, constructed as a permanent part of a building or other item listed in this paragraph (f).
(21) Grading and clearing when directly occasioned by the building of a structure.
(22) Intrasite communication system, poles, pole fixtures, wires, and cables.
(23) Landscaping, lawns, shrubbery and similar items.
(24) Leases, voiding upon purchase to secure possession of structures.
(25) Leased property, expenditures on.
(26) Lighting fixtures and outside lighting system.
(27) Mail chutes when part of a building.
(28) Marquee, permanently attached to building.
(29) Painting, first cost.
(30) Permanent paving, concrete, brick, flagstone, asphalt, within the property lines.
(31) Partitions, including movable.
(32) Permits and privileges.
(33) Platforms, railings, and gratings when constructed as a part of a structure.
(34) Power boards for services to a building.
(35) Refrigerating systems for general use.
(36) Retaining walls except when identified with land.
(37) Roadways, railroads, bridges, and trestles intrasite except railroads provided for in equipment accounts.
(38) Roofs.
(39) Scales, connected to and forming a part of a structure.
(40) Screens.
(41) Sewer systems, for general use.
(42) Sidewalks, culverts, curbs and streets constructed by the service company on its property.
(43) Sprinkling systems.
(44) Sump pumps and pits.
(45) Stacks—brick, steel, or concrete, when set on foundation forming part of general foundation and steelwork of a building.
(46) Steel inspection during construction.
(47) Storage facilities constituting a part of a building.
(48) Storm doors and windows.
(49) Subways, areaways, and tunnels, directly connected to and forming part of a structure.
(50) Tanks, constructed as part of a building or as a distinct structural unit.
(51) Temporary heating during construction (net cost).
(52) Temporary water connection during construction (net cost).
(53) Temporary shanties and other facilities used during construction (net cost).
(54) Topographical maps.
(55) Tunnels, intake and discharge, when constructed as part of a structure, including sluice gates, and those constructed to house mains.
(56) Vaults constructed as part of a building.
(57) Watchmen’s sheds and clock systems (net cost when used during construction only).
(58) Water basins or reservoirs.
(59) Water front improvements.
(60) Water meters and supply system for a building or for general company purposes.
(61) Water supply piping, hydrants and wells.
(62) Wharves.
(63) Window shades and ventilators.
(64) Yard drainage system.
(65) Yard lighting system.
(66) Yard surfacing, gravel, concrete, or oil. (First cost only.)
(g) Structures and Improvements accounts must be credited with the cost of structures created to house, support, or safeguard equipment, the use of which has terminated with the removal of the equipment with which they are associated even though they have not been physically removed.
§ 367.57 Equipment.
(a) The cost of equipment chargeable to the service company property accounts, unless otherwise indicated in the text of an equipment account, includes the related net purchase price, sales taxes, investigation and inspection expenses necessary to such purchase, expenses of transportation when borne by the service company, labor employed, materials and supplies consumed, and expenses incurred by the service company in unloading and placing the equipment in readiness to operate. Also include those costs incurred in connection with the first clearing and grading of land and rights-of-way and the damage costs associated with construction and installation of property.
(b) Exclude from equipment accounts hand and other portable tools, that are likely to be lost or stolen or that have relatively small value (for example, $500 or less) or short life, unless the correctness of the related accounting as service company property is verified by current inventories. Special tools acquired and included in the purchase price of equipment must be included in the appropriate property account. Portable drills and similar tool equipment when used in connection with the operation and maintenance of a particular plant or department, such as production, transmission, distribution, or similar items, or in stores, must be charged to the property account appropriate for their use.
(c) The equipment accounts must include angle irons and similar items that are installed at the base of an item of equipment, but piers and foundations that are designed to be as permanent as the buildings that house the equipment, or that are constructed as a part of the building and that cannot be removed without cutting into the walls, ceilings or floors or without in some way impairing the building, must be included in the building accounts.
(d) The cost of efficiency or other tests made subsequent to the date equipment becomes available for service must be charged to the appropriate expense accounts, except that tests to determine whether equipment meets the specifications and requirements as to efficiency, performance, and similar items, guaranteed by manufacturers, made after operations have commenced and within the period specified in the agreement or contract of purchase may be charged to the appropriate service company property account.
§ 367.58 Property record system required for service company property.
(a) Each service company must keep its cost allocation system so as to show the nature of each addition to or retirement of service company property, the related total cost, the source or sources of costs, and the property account or accounts to which charged or credited. Records covering jobs of short duration may be cleared monthly.
(b) Each service company must maintain records in which, for each property account, the amounts of the annual additions and retirements are classified so as to show the number and cost of the various record units or retirement units.
§ 367.59 Additions and retirements of property.
(a) For the purpose of avoiding undue refinement in accounting for additions to and retirements and replacements of service company property, all property will be considered as consisting of retirement units and minor items of property. Each company must maintain a written property units listing for use in accounting for additions and retirements of property and apply the listing consistently.
(b) The addition and retirement of retirement units must be accounted for as follows:
(1) When a retirement unit is added, the related cost must be added to the appropriate service company property account.
(2) When a retirement unit is retired, with or without replacement, the related book cost must be credited to the property account in which it is included, determined in the manner provided in paragraph (d) of this section. If the retirement unit is of a depreciable class, the book cost of the unit retired and credited to service company property must be charged to the accumulated provision for depreciation applicable to the property. The cost of removal and the salvage must be charged or credited, as appropriate, to the depreciation account.
(c) The addition and retirement of minor items of property must be accounted for as follows:
(1) When a minor item of property that did not previously exist is added to service company property, the related cost must be accounted for in the same manner as for the addition of a retirement unit, as provided in paragraph (b)(1) of this section, if a substantial addition results, otherwise the charge must be to the appropriate maintenance expense account.
(2) When a minor item of property is retired and not replaced, the related book cost must be credited to the property account in which it is included; and, in the event the minor item is a part of depreciable property, the account for accumulated provision for depreciation must be charged with the book cost and cost of removal and credited with the salvage. If, however, the book cost of the minor item retired and not replaced has been or will be accounted for by its inclusion in the retirement unit of which it is a part when the unit is retired, no separate credit to the property account is required when the minor item is retired.
(3) When a minor item of depreciable property is replaced independently of the retirement unit of which it is a part, the cost of replacement must be charged to the maintenance account appropriate for the item. However, if the replacement effects a substantial betterment (the primary aim of which is to make the property affected more useful, more efficient, of greater durability, or of greater capacity), the excess cost of the replacement over the estimated cost at current prices of replacing without betterment must be charged to the appropriate property account.
(d) The book cost of service company property retired must be the amount at which the property is included in the property accounts, including all components of construction costs. The book cost must be determined from the service company’s records and, if this cannot be done, it must be estimated. Service companies must furnish the particulars of the estimates to the Commission, if requested. When it is impracticable to determine the book cost of each unit, due to the relatively large number or related small cost, an appropriate average book cost of the units, with due allowance for any differences in size and character, must be used as the book cost of the units retired.
(e) The book cost of land retired must be credited to the appropriate land account. If the land is sold, the difference between the book cost (less any accumulated provision for related depreciation or amortization that has been authorized and provided) and the sale price of the land (less commissions and other expenses of making the sale) must be recorded in accounts 421.1, Gain on disposition of property (§ 367.4211) or 421.2, Loss on disposition of property (§ 367.4212), as appropriate.
(f) The book cost less net salvage of depreciable service company property retired must be charged in its entirety to account 108, Accumulated provision for depreciation of service company property (§ 367.1080).
(g) The accounting for the retirement of amounts included in account 303, Miscellaneous intangible property (§ 367.3030), and the items of limited-term interest in land included in the accounts for land and land rights, must be as provided for in the text of account 111, Accumulated provision for amortization of service company property (§ 367.1110), account 404, Amortization of limited-term property (§ 367.4040), and account 405, Amortization of other property (§ 367.4050).
Subpart D—Operating Expense Instructions
§ 367.80 Supervision and engineering.
(a) The supervision and engineering includible in the operating expense accounts must consist of the pay and expenses of superintendents, engineers, clerks, other employees and consultants engaged in supervising and directing the operation and maintenance of each service company function. Wherever allocations are necessary in order to arrive at the amount to be included in any account, the method and basis of allocation must be reflected by underlying records.
(b) This account must include the following labor items:
(1) Special tests to determine efficiency of equipment operation.
(2) Preparing or reviewing budgets, estimates, and drawings relating to operation or maintenance for departmental approval.
(3) Preparing instructions for operations and maintenance activities.
(4) Reviewing and analyzing operating results.
(5) Establishing organizational setup of departments and executing related changes.
(6) Formulating and reviewing routines of departments and executing related changes.
(7) General training and instruction of employees by supervisors whose pay is chargeable to the training and instruction. Specific instruction and training in a particular type of work is chargeable to the appropriate functional expense account (See Service Company Property in § 367.51(a)(19)).
(8) Secretarial work for supervisory personnel, but not general clerical and stenographic work chargeable to other accounts.
(c) This account must include the following expense items:
(1) Consultants’ fees and expenses.
(2) Meals, traveling and incidental expenses.
§ 367.81 Maintenance.
(a) The cost of maintenance chargeable to the various operating expense and clearing accounts includes labor, materials, overheads and other expenses incurred in maintenance work. A list of work operations applicable generally to service company property is included in paragraph (d) of this section. Other work operations applicable to specific classes of property are listed in functional maintenance expense accounts.
(b) Materials recovered in connection with the maintenance of property must be credited to the same account to which the maintenance cost was charged.
(c) Maintenance of property leased from others must be treated as provided in operating expense instruction in § 367.82.
(d) This account must include the following items:
(1) Direct field supervision of maintenance.
(2) Inspecting, testing, and reporting on condition of property specifically to determine the need for repairs, replacements, rearrangements and changes and inspecting and testing the adequacy of repairs which have been made.
(3) Work performed specifically for the purpose of preventing failure, restoring serviceability or maintaining life of property.
(4) Rearranging and changing the location of property.
(5) Repairing for reuse materials recovered from property.
(6) Testing for locating and clearing trouble.
(7) Net cost of installing, maintaining, and removing temporary facilities to prevent interruptions in service.
(8) Replacing or adding minor items of plant which do not constitute a retirement unit. (See Service Company Property Instruction in § 367.59.)
§ 367.82 Rents.
(a) The rent expense accounts provided under the several functional groups of expense accounts must include all rents, including taxes paid by the lessee on leased property, for property used in the operations of the service company, except:
(1) Minor amounts paid for occasional or infrequent use of any property or equipment and all amounts paid for use of equipment that, if owned, would be includible in property accounts 391 to 398 (§§ 367.3910 to 367.3980), inclusive, that must be treated as an expense item and included in the appropriate functional account, and
(2) Rents that are chargeable to clearing accounts, and distributed from the clearing accounts to the appropriate account. If rents cover property used for more than one function, such as production and transmission, or by more than one department, the rents must be apportioned to the appropriate rent expense or clearing accounts of each department on an actual, or, if necessary, an estimated basis.
(b) When a portion of property or equipment rented from others for use in connection with service company operations is subleased, the revenue derived from the subleasing must be credited to the rent revenue account in operating revenues. However, if the rent was charged to a clearing account, amounts received from subleasing the property must be credited to the clearing account.
(c) The cost, when incurred by the lessee, of operating and maintaining leased property, must be charged to the accounts appropriate for the expense if the property were owned.
(d) The cost incurred by the lessee of additions and replacements to property leased from others must be accounted for as provided in Service Company Property Instruction in § 367.54.
§ 367.83 Training costs.
When it is necessary that employees be trained to specifically operate or maintain facilities that are being constructed, the related costs must be accounted for as a current operating and maintenance expense. These expenses must be charged to the appropriate functional accounts currently as they are incurred. However, when the training costs involved relate to facilities that are not conventional in nature, or are new to the service company’s operations, these costs may be capitalized until the time that the facilities are ready for functional use.
Subpart E—Special Instructions
§ 367.100 Accounts 131–174, Current and accrued assets.
Current and accrued assets are cash, those assets which are readily convertible into cash or are held for current use in operations or construction, current claims against others, payment of which is reasonably assured, and amounts accruing to the service company that are subject to current settlement, except those items for which accounts other than those designated as current and accrued assets are provided. There must not be included in the group of accounts designated as current and accrued assets any item, the amount or collectibility of which is not reasonably assured, unless an adequate provision for the related possible loss has been made. Items of current character but of doubtful value may be written down and for record purposes carried in these accounts at nominal value.
§ 367.101 Accounts 231–243, Current and accrued liabilities.
Current and accrued liabilities are those obligations which have either matured or which become due within one year from the date of issuance or assumption, except for: bonds, receivers’ certificates and similar obligations which must be classified as long-term debt until date of maturity; accrued taxes, such as income taxes, which must be classified as accrued liabilities even though payable more than one year from date; compensation awards, which must be classified as current liabilities regardless of date due; and minor amounts payable in installments which may be classified as current liabilities. If a liability is due more than one year from date of issuance or assumption by the service company, it shall be credited to a long-term debt account appropriate for the transaction, except, however, the current liabilities previously mentioned.
§ 367.102 Accounts 408.1 and 408.2, Taxes other than income taxes.
(a) These accounts must include the amounts of ad valorem, gross revenue or gross receipts taxes, state unemployment insurance, franchise taxes, Federal excise taxes, social security taxes, and all other taxes assessed by Federal, state, county, municipal, or other local governmental authorities, except income taxes.
(b) These accounts shall be charged in each accounting period with the amounts of taxes which are applicable to each account, with concurrent credits to account 236, Taxes accrued (§ 367.2360), or account 165, Prepayments (§ 367.1650), as appropriate. When it is not possible to determine the exact amounts of taxes, the amounts shall be estimated and adjustments made in current accruals as the actual tax levies become known.
(c) Special assessments for street and similar improvements must be included in the appropriate service company property account.
(d) Taxes specifically applicable to construction must be included in the cost of construction.
(e) Gasoline and other sales taxes must be charged as far as practicable to the same account as the materials on which the tax is levied.
(f) Social security and other forms of so-called payroll taxes must be distributed to utility and non-utility functions on a basis related to payroll. Amounts applicable to construction must be charged to the appropriate plant account.
(g) Interest on tax refunds or deficiencies must not be included in these accounts but in accounts 419, Interest and dividend income (§ 367.4190), or 431, Other interest expense (§ 367.4310), as appropriate.
§ 367.103 Accounts 409.1, 409.2, and 409.3, Income taxes.
(a) These accounts must include the amounts of local, state and Federal income taxes on income properly accruable during the period covered by the income statement to meet the actual liability for such taxes. Concurrent credits for the tax accruals must be made to account 236, Taxes accrued (§ 367.2360), and as the exact amounts of taxes become known, the current tax accruals must be adjusted by charges or credits to these accounts, so that these accounts include the actual taxes payable by the service company.
(b) The accruals for income taxes shall be apportioned to Operating Income, Other Income and Deductions, and Extraordinary Items so that, as nearly as practicable, each tax will be included in the appropriate account based on the income which gave rise to the tax.
(c) Taxes assumed by the service company on interest must be charged to account 431, Other interest expense (§ 367.4310).
(d) Interest on tax refunds or deficiencies must not be included in these accounts but in account 419, Interest and dividend income (§ 367.4190), or account 431, Other interest expense (§ 367.4310), as appropriate.
§ 367.104 Accounts 410.1, 410.2, 411.1, and 411.2, Provision for deferred income taxes.
(a) Accounts 410.1 (§ 367.4101) and 410.2 (§ 367.4102) must be debited, and Accumulated Deferred Income Taxes must be credited, with amounts equal to any current deferrals of taxes on income or any allocations of deferred taxes originating in prior periods, as provided by the texts of accounts 190 (§ 367.1900), 282 (§ 367.2820), and 283 (§ 367.2830). There must not be netted against entries required to be made to these accounts any credit amounts appropriately includible in accounts 411.1 (§ 367.4111) or 411.2 (§ 367.4112).
(b) Accounts 411.1 (§ 367.4111) and 411.2 (§ 367.4112) must be credited, and Accumulated Deferred Income Taxes must be debited, with amounts equal to any allocations of deferred taxes originating in prior periods or any current deferrals of taxes on income, as provided by the texts of accounts 190 (§ 367.1900), 282 (§ 367.2820), and 283 (§ 367.2830). There must not be netted against entries required to be made to these accounts any debit amounts appropriately includible in account 410.1 (§ 367.4101) or 410.2 (§ 367.4102).
§ 367.105 Accounts 411.4, and 411.5, Investment tax credit adjustments.
(a) Account 411.4 (§ 367.4114) must be debited with the amounts of investment tax credits related to service company property that are credited to account 255, Accumulated deferred investment tax credits (§ 367.2550), by companies which do not apply the entire amount of the benefits of the investment credit as a reduction of the overall income tax expense in the year in which such credit is realized (See account 255 in § 367.2550).
(b) Account 411.4 (§ 367.4114) must be credited with the amounts debited to account 255 (§ 367.2550) for proportionate amounts of tax credit deferrals allocated over the average useful life of service company property to which the tax credits relate or such lesser period of time as may be adopted and consistently followed by the company.
(c) Account 411.5 (§ 367.4115) must also be debited and credited as directed in paragraphs (a) and (b), for investment tax credits related to other income and deductions.
§ 367.106 Accounts 426.1, 426.2, 426.3, 426.4, and 426.5, Miscellaneous expense accounts.
These accounts must include miscellaneous expense items which are nonoperating in nature but which are properly deductible before determining total income before interest charges.
Subpart F—Balance Sheet Chart of Accounts
§ 367.1010 Account 101, Service company property.
(a) This account must include the cost of service company property, included in accounts 301 (§ 367.3010), 303 (§ 367.3030) and 389 to 399.1 (§§ 376.3890 to 367.3991), owned and used by the service company in its operations, and having an expectation of life in service of more than one year from date of installation.
(b) The cost of additions to, and betterments of, property leased from others, that are includible in this account, must be recorded in subaccounts separate and distinct from those relating to owned property. (See Service Company Property Instruction in § 367.54.)
§ 367.1011 Account 101.1, Property under capital leases.
(a) This account must include the amount recorded under capital leases for property leased from others and used by the service company in its operations.
(b) The property included in this account must be classified separately according to detailed accounts 301 (§ 367.3010), 303 (§ 367.3030) and 389 to 399.1 (§§ 367.3890 to 367.3991) prescribed for service company property.
(c) Records must be maintained with respect to each capital lease reflecting:
(1) Name of lessor,
(2) Basic details of lease,
(3) Terminal date,
(4) Original cost or fair market value of property leased,
(5) Future minimum lease payments,
(6) Executory costs,
(7) Present value of minimum lease payments,
(8) The amount representing interest and the interest rate used, and
(9) Expenses paid.
§ 367.1060 Account 106, Completed construction not classified.
At the end of the year or such other date as a balance sheet may be required by the Commission, this account must include the total of the balances of construction projects for service company property which has been completed and placed in service but have not been classified for transfer to the detailed service company property accounts.
§ 367.1070 Account 107, Construction work in progress.
(a) This account must include the total of the balances of construction projects for service company property in process of construction.
(b) Construction projects must be cleared from this account as soon as practicable after completion of the job. Further, if a project is designed to consist of two or more units that may be placed in service at different dates, any expenditures that are common to and that will be used in the operation of the project as a whole must be included in service company property upon the completion and the readiness for service of the first unit. Any expenditures that are identified exclusively with units of property not yet in service must be included in this account.
(c) Expenditures on research, development, and demonstration projects for construction of facilities are to be included in a separate subaccount in this account. Records must be maintained to show separately each project along with complete detail of the nature and purpose of the research, development, and demonstration project together with the related costs.
§ 367.1080 Account 108, Accumulated provision for depreciation of service company property.
(a) This account must be credited with the following:
(1) Amounts charged to account 403, Depreciation expense (§ 367.4030), or to clearing accounts for current depreciation expense for service company property.
(2) Amounts charged to account 416, Costs and expenses of merchandising, jobbing, and contract work (§ 367.4160), or to clearing accounts for current depreciation expense.
(3) Amounts of depreciation applicable to properties acquired. (See Service Company Property Instruction in § 367.53.)
(4) Amounts of depreciation applicable to service company property donated to the service company.
(b) The service company must maintain separate subaccounts for depreciation applicable to service company property.
(c) At the time of retirement of depreciable service company property, this account must be charged with the book cost of the property retired and the cost of removal, and must be credited with the salvage value and any other amounts recovered, such as insurance.
(d) The subsidiary records for this account must reflect the current credits and debits to this account in sufficient detail to show the following separately:
(1) The amount of accrual for depreciation,
(2) The book cost of property retired,
(3) Cost of removal,
(4) Salvage, and
(5) Other items, including recoveries from insurance.
(e) The service company is restricted in its use of the accumulated provision for depreciation to the purposes identified in paragraphs (a) through (d) of this section. It must not transfer any portion of this account to retained earnings or make any other use of the depreciation without authorization by the Commission.
§ 367.1110 Account 111, Accumulated provision for amortization of service company property.
(a) This account must be credited with the following:
(1) Amounts charged to account 404, Amortization of limited-term property (§ 367.4040), for the current amortization of limited-term service company property investments.
(2) Amounts charged to account 405, Amortization of other property (§ 367.4050).
(3) Amounts charged to account 425, Miscellaneous amortization (§ 367.4250), for the amortization of intangible or other property, that does not have a definite or terminable life and is not subject to charges for depreciation expense, with Commission approval.
(b) The service company must maintain subaccounts of this account for the amortization applicable to service company property and property leased to others.
(c) When any property to which this account applies is sold, relinquished, or otherwise retired from service, this account must be charged with the amount previously credited in respect to the property. The book cost of the retired property less the amount chargeable to this account and less the net proceeds realized at retirement must be included in account 421.1, Gain on disposition of property (§ 367.4211), or account 421.2, Loss on disposition of property (§ 367.4212), as appropriate.
(d) For general ledger and balance sheet purposes, this account must be regarded and treated as a single composite provision for amortization. The subsidiary records must reflect the current credits and debits to this account in sufficient detail to show the following separately:
(1) The amount of accrual for amortization,
(2) The book cost of property retired,
(3) Cost of removal,
(4) Salvage, and
(5) Other items, including recoveries from insurance.
(e) The service company is restricted in its use of the accumulated provision for amortization to the purposes provided in paragraphs (a) through (d) of this section. It must not transfer any portion of this account to retained earnings or make any other use of the amortization without authorization by the Commission.
Other Property and Investments
§ 367.1230 Account 123, Investment in associate companies.
(a) This account must include the book cost of investments in securities issued or assumed by associate companies and investment advances to the companies, including related accrued interest when the interest is not subject to current settlement, provided that the investment does not relate to a subsidiary company. (If the investment relates to a subsidiary company, it must be included in account 123.1, Investment in subsidiary companies (§ 367.1231).) Include in this account the offsetting entry to the recording of amortization of discount or premium on interest bearing investments. (See account 419, Interest and dividend income (§ 367.4190).)
(b) This account must be maintained in a manner so as to show the investment in securities of, and advances to, each associate company together with full particulars regarding any of the investments that are pledged.
(c) Securities and advances of associate companies owned and pledged must be included in this account, but the securities, if held in special deposits or in special funds, must be included in the appropriate deposit or fund account. A complete record of securities pledged must be maintained.
(d) Securities of associate companies held as temporary cash investments are includible in account 136, Temporary cash investments (§ 367.1360).
(e) Balances in open accounts with associate companies that are subject to current settlement are includible in account 146, Accounts receivable from associate companies (§ 367.1460).
(f) The service company must write down the cost of any security in recognition of a decline in the related value. Securities must be written off or written down to a nominal value if there is no reasonable prospect of substantial value. Fluctuations in market value must not be recorded but a permanent impairment in the value of securities must be recognized in the accounts. When securities are written off or written down, the amount of the adjustment must be charged to account 426.5, Other deductions (§ 367.4265), or to an appropriate account for accumulated provisions for loss in value established as a separate subdivision of this account.
§ 367.1240 Account 124, Other investments.
(a) This account must include the book cost of investments in securities issued or assumed by non-associate companies, investment advances to these companies, and any investments not accounted for elsewhere. This account must also include unrealized holding gains and losses on trading and available-for-sale types of security investments. Include also the offsetting entry to the recording of amortization of discount or premium on interest bearing investments. (See account 419, Interest and dividend income (§ 367.4190).)
(b) The records must be maintained in a manner so as to show the amount of each investment and the investment advances to each person.
§ 367.1280 Account 128, Other special funds.
(a) This account must include the amount of cash and book cost of investments that have been segregated in special funds for insurance, employee pensions, savings, relief, hospital, and other purposes not provided for elsewhere. This account must also include unrealized holding gains and losses on trading and available-for-sale types of security investments. A separate account with appropriate title, must be kept for each fund.
(b) Amounts deposited with a trustee under the terms of an irrevocable trust agreement for pensions or other employee benefits must not be included in this account.
Current and Accrued Assets
§ 367.1310 Account 131, Cash.
This account must include the amount of current cash funds except working funds.
§ 367.1340 Account 134, Other special deposits.
(a) This account must include deposits with fiscal agents or others for special purposes other than the payment of interest and dividends. The special deposits may include, among other things, cash deposited with federal, state, or municipal authorities as a guaranty for the fulfillment of obligations; cash deposited with trustees to be held until mortgaged property sold, destroyed, or otherwise disposed of is replaced; cash realized from the sale of the accounting service company’s securities and deposited with trustees to be held until invested in property of the service company. Entries to this account must specify the purpose for which the deposit is made.
(b) Assets available for general corporate purposes must not be included in this account. Further, deposits for more than one year, that are not offset by current liabilities, must be charged to account 128, Other special funds (§ 367.1280).
§ 367.1350 Account 135, Working funds.
This account must include cash advanced to officers, agents, employees, and others as petty cash or working funds.
§ 367.1360 Account 136, Temporary cash investments.
(a) This account must include the book cost of investments, such as demand and time loans, bankers’ acceptances, United States Treasury certificates, marketable securities, and other similar investments, acquired for the purpose of temporarily investing cash.
(b) This account must be maintained so as to show separately temporary cash investments in securities of associate companies and of others. Records must be kept of any pledged investments.
§ 367.1410 Account 141, Notes receivable.
(a) This account must include the book cost, not includible elsewhere, of all collectible obligations in the form of notes receivable and similar evidences (except interest coupons) of money due on demand or within one year from the date of issue, except, however, notes receivable from associate companies. (See account 136, Temporary cash investments (§ 367.1360), and account 145, Notes receivable from associate companies (§ 367.1450).)
(b) The face amount of notes receivable discounted, sold, or transferred without releasing the service company from liability as a related endorser, must be credited to a separate subaccount of this account and appropriate disclosure must be made in financial statements of any contingent liability arising from the transactions.
§ 367.1420 Account 142, Customer accounts receivable.
(a) This account must include amounts due from customers for service, and for merchandising, jobbing and contract work. This account must not include amounts due from associate companies.
(b) This account must be maintained so as to permit ready segregation of the amounts due for merchandising, jobbing and contract work.
§ 367.1430 Account 143, Other accounts receivable.
(a) This account must include amounts due the service company upon open accounts, other than amounts due from associate companies and from customers for services and merchandising, jobbing and contract work.
(b) This account must be maintained so as to show separately amounts due on subscriptions to capital stock and from officers and employees, but the account must not include amounts advanced to officers or others as working funds. (See account 135, Working funds (§ 367.1350).)
§ 367.1440 Account 144, Accumulated provision for uncollectible accounts—Credit.
(a) This account must be credited with amounts provided for losses on accounts receivable that may become uncollectible, and also with collections on related previously charged accounts. Concurrent charges must be made to account 904, Uncollectible accounts (§ 367.9040), for amounts applicable to service company operations, and to corresponding accounts for other operations. Records must be maintained so as to show the write-offs of account receivable for each service company department.
(b) This account must be subdivided to show the provision applicable to the following classes of accounts receivable:
(1) Service company customers.
(2) Merchandising, jobbing and contract work.
(3) Officers and employees.
(4) Others.
(c) Accretions to this account must not be made in excess of a reasonable provision against losses of the related character.
(d) If provisions for uncollectible notes receivable or for uncollectible receivables from associate companies are necessary, separate related subaccounts must be established under the account in which the receivable is carried.
§ 367.1450 Account 145, Notes receivable from associate companies.
(a) This account must include notes and drafts upon which associate companies are liable, and that mature and are expected to be paid in full not later than one year from the date of issue, together with any related interest, and debit balances subject to current settlement in open accounts with associate companies. Items that do not bear a specified due date but that have been carried for more than twelve months and items that are not paid within twelve months from due date must be transferred to account 123, Investment in associate companies (§ 367.1230).
(b) On the balance sheet, accounts receivable from an associate company may be set off against accounts payable to the same company.
(c) The face amount of notes receivable discounted, sold or transferred without releasing the service company from liability as endorser thereon, must be credited to a separate subaccount of this account and appropriate disclosure must be made in financial statements of any contingent liability arising from such transactions.
§ 367.1460 Account 146, Accounts receivable from associate companies.
(a) This account must include notes and drafts upon which associate companies are liable, and that mature and are expected to be paid in full not later than one year from the date of issue, together with any related interest thereon, and debit balances subject to current settlement in open accounts with associate companies. Items that do not bear a specified due date but that have been carried for more than twelve months and items that are not paid within twelve months from due date must be transferred to account 123, Investment in associate companies (§ 367.1230).
(b) On the balance sheet, accounts receivable from an associate company may be set off against accounts payable to the same company.
(c) The face amount of notes receivable discounted, sold or transferred without releasing the service company from liability as the related endorser, must be credited to a separate subaccount of this account and appropriate disclosure must be made in financial statements of any contingent liability arising from the transactions.
§ 367.1520 Account 152, Fuel stock expenses undistributed.
The service company must utilize this account, where appropriate, to include the cost of service company labor and of office supplies used and operating expenses incurred with respect to the review, analysis and management of fuel supply contracts or agreements, the accumulation of fuel information and its interpretation, the logistics and handling of fuel, and other related support functions, as a service to the company engaged in the procurement and transportation of fuel. This account must be maintained to show the expenses attributable to each company through its cost allocation system. All expenses of a service company’s fuel department or functions must be cleared through this account.
§ 367.1540 Account 154, Materials and operating supplies.
(a) This account must include the cost of materials purchased primarily for use in the service company business for construction, operation and maintenance purposes. It must include the book cost of materials recovered in connection with construction, maintenance or the retirement of service company property, the materials being credited to construction, maintenance or accumulated depreciation provision, respectively. This account must include the following items:
(1) Reusable materials consisting of large individual items must be included in this account at original cost, estimated if not known. The cost of repairing the items must be charged to the maintenance account appropriate for the previous use.
(2) Reusable materials consisting of relatively small items, the identity of which (from the date of original installation to the related final abandonment or sale) cannot be ascertained without undue refinement in accounting, must be included in this account at current prices new for the items. The cost of repairing the items must be charged to the appropriate expense account as indicated by previous use.
(3) Scrap and non-usable materials included in this account must be carried at the estimated net amount realizable. The difference between the amounts realized for scrap and non-usable materials sold and the net amount at which the materials were carried in this account, as far as practicable, must be adjusted to the accounts credited when the materials were charged to this account.
(b) Materials and supplies issued must be credited in this account and charged to the appropriate construction, operating expense, or other account on the basis of a unit price determined by the use of cumulative average, first-in-first-out, or any other method of inventory accounting that conforms with accepted accounting standards consistently applied.
(c) This account must include the following items:
(1) Invoice price of materials less cash or other discounts.
(2) Freight, switching or other transportation charges when practicable to include as part of the cost of particular materials to which they relate.
(3) Customs duties and excise taxes.
(4) Costs of inspection and special tests prior to acceptance.
(5) Insurance and other directly assignable charges.
(d) Where expenses applicable to materials purchased cannot be directly assigned to particular purchases, they may be charged to a stores expense clearing account (account 163, Stores expense undistributed (§ 367.1630)), and distributed from there to the appropriate account.
(e) When materials and supplies are purchased for immediate use, they need not be carried through this account, but may be charged directly to the appropriate service company property or expense account.
§ 367.1630 Account 163, Stores expense undistributed.
(a) This account must include the cost of supervision, labor and expenses incurred in the operation of general storerooms, including purchasing, storage, handling and distribution of materials and supplies.
(b) This account must be cleared by adding to the cost of materials and supplies issued a suitable loading charge that will distribute the expense equitably over stores issues. The balance in the account at the close of the calendar year must not exceed the amount of stores expenses reasonably attributable to the inventory of materials and supplies exclusive of fuel, as any amount applicable to fuel costs should be included in account 152, Fuel stock expenses undistributed (§ 367.1520).
(c) This account must include the following labor items:
(1) Inspecting and testing materials and supplies when not assignable to specific items.
(2) Unloading from shipping facility and putting in storage.
(3) Supervision of purchasing and stores department to extent assignable to materials handled through stores.
(4) Getting materials from stock and in readiness to go out.
(5) Inventorying stock received or stock on hand by stores employees but not including inventories by general department employees as part of internal or general audits.
(6) Purchasing department activities in checking material needs, investigating sources of supply, analyzing prices, preparing and placing orders, and related activities to extent applicable to materials handled through stores. (Optional. Purchasing department expenses may be included in administrative and general expenses.)
(7) Maintaining stores equipment.
(8) Cleaning and tidying storerooms and stores offices.
(9) Keeping stock records, including recording and posting of material receipts and issues and maintaining inventory record of stock.
(10) Collecting and handling scrap materials in stores.
(d) This account must include the following supplies and expenses items:
(1) Adjustments of inventories of materials and supplies, but not including large differences that can readily be assigned to important classes of materials and equitably distributed among the accounts to which the classes of materials have been charged since the previous inventory.
(2) Cash and other discounts not practically assignable to specific materials.
(3) Freight, express, and similar items, when not assignable to specific items.
(4) Heat, light and power for storerooms and store offices.
(5) Brooms, brushes, sweeping compounds and other supplies used in cleaning and tidying storerooms and stores offices.
(6) Injuries and damages.
(7) Insurance on materials and supplies and on stores equipment.
(8) Losses due to breakage, leakage, evaporation, fire or other causes, less credits for amounts received from insurance, transportation companies or others in compensation of the losses.
(9) Postage, printing, stationery and office supplies.
(10) Rent of storage space and facilities.
(11) Communication service.
(12) Excise and other similar taxes not assignable to specific materials.
(13) Transportation expense on inward movement of stores and on transfer between storerooms, but not including charges on materials recovered from retirements that must be accounted for as part of cost of removal.
(e) A physical inventory of each class of materials and supplies must be made at least every two years.
§ 367.1650 Account 165, Prepayments.
This account must include amounts representing prepayments of insurance, rents, taxes, interest and miscellaneous items, and must be kept or supported in a manner so as to disclose the amount of each class of prepayment.
§ 367.1710 Account 171, Interest and dividends receivable.
(a) This account must include the amount of interest on bonds, mortgages, notes, commercial paper, loans, open accounts, deposits, and other similar items, the payment of which is reasonably assured, and the amount of dividends declared or guaranteed on stocks owned.
(b) Interest that is not subject to current settlement must not be included in this account, but in the account in which is carried the principal on which the interest is accrued.
(c) Interest and dividends receivable from associate companies must be included in account 146, Accounts receivable from associate companies (§ 367.1460).
§ 367.1720 Account 172, Rents receivable.
(a) This account must include rents receivable or accrued on property rented or leased by the service company to others.
(b) Rents receivable from associate companies must be included in account 146, Accounts receivable from associate companies (§ 367.1460).
§ 367.1730 Account 173, Accrued revenues.
At the option of the service company, the estimated amount accrued for service rendered, but not billed at the end of any accounting period, may be included in this account. In case accruals are made for unbilled revenues, they must be made likewise for unbilled expenses, such as for the purchase of energy.
§ 367.1740 Account 174, Miscellaneous current and accrued assets.
This account must include the book cost of all other current and accrued assets, appropriately designated and supported so as to show the nature of each asset included in the account.
§ 367.1750 Account 175, Derivative instrument assets.
This account must include the amounts paid for derivative instruments, and the change in the fair value of all derivative instrument assets not designated as cash flow or fair value hedges. Account 421, Miscellaneous income or loss (§ 367.4210), must be credited or debited, as appropriate, with the corresponding amount of the change in the fair value of the derivative instrument.
§ 367.1760 Account 176, Derivative instrument assets—Hedges.
(a) This account must include the amounts paid for derivative instruments, and the change in the fair value of derivative instrument assets designated by the service company as cash flow or fair value hedges.
(b) When a service company designates a derivative instrument asset as a cash flow hedge it will record the change in the fair value of the derivative instrument in this account with a concurrent charge to account 219, Accumulated other comprehensive income (§ 367.2190), with the effective portion of the gain or loss. The ineffective portion of the cash flow hedge must be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
(c) When a service company designates a derivative instrument as a fair value hedge it must record the change in the fair value of the derivative instrument in this account with a concurrent charge to a subaccount of the asset or liability that carries the item being hedged. The ineffective portion of the fair value hedge must be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
Deferred Debits
§ 367.1810 Account 181, Unamortized debt expense.
This account must include expenses related to the issuance or assumption of debt securities. Amounts recorded in this account must be amortized over the life of each respective issue under a plan that will distribute the amount equitably over the life of the security. The amortization must be on a monthly basis, and the related amounts must be charged to account 428, Amortization of debt discount and expense (§ 367.4280). Any unamortized amounts outstanding at the time that the related debt is prematurely reacquired must be accounted for as indicated in General Instructions in § 367.16.
§ 367.1823 Account 182.3, Other regulatory assets.
(a) This account must include the amounts of regulatory-created assets, not includible in other accounts, resulting from the ratemaking actions of regulatory agencies. (See Definitions § 367.1(a)(38).)
(b) The amounts included in this account are to be established by those charges which would have been included in net income, or accumulated other comprehensive income, determinations in the current period under the general requirements of the Uniform System of Accounts but for it being probable that such items will be included in a different period(s) for purposes of developing rates that the utility is authorized to charge for its utility services. When specific identification of the particular source of a regulatory asset cannot be made, such as in plant phase-ins, rate moderation plans, or rate levelization plans, account 407.4, Regulatory credits (§ 367.4074), must be credited. The amounts recorded in this account are generally to be charged, concurrently with the recovery of the amounts in rates, to the same account that would have been charged if included in income when incurred, except all regulatory assets established through the use of account 407.4 (§ 367.4074) must be charged to account 407.3, Regulatory debits (§ 367.4073), concurrent with the recovery in rates.
(c) If rate recovery of all or part of an amount included in this account is disallowed, the disallowed amount must be charged to Account 426.5, Other deductions (§ 367.4265), or Account 435, Extraordinary deductions (§ 367.4350), in the year of the disallowance.
(d) The records supporting the entries to this account must be kept so that the service company can furnish full information as to the nature and amount of each regulatory asset included in this account, including justification for inclusion of such amounts in this account.
§ 367.1830 Account 183, Preliminary survey and investigation charges.
(a) This account must be charged with all expenditures for preliminary surveys, plans, investigations, and other similar items, made for the purpose of determining the feasibility of service company projects under contemplation. If construction results, this account must be credited and the appropriate service company property account charged. If the work is abandoned, the charge must be made to account 426.5, Other deductions (§ 367.4265), or to the appropriate operating expense account.
(b) The records supporting the entries to this account must be kept so that the service company can furnish complete information as to the nature and the purpose of the survey, plans, or investigations and the nature and amounts of the several charges.
(c) The amount of preliminary survey and investigation charges transferred to service company property must not exceed the expenditures that may reasonably be determined to contribute directly and immediately and without duplication to service company property.
§ 367.1840 Account 184, Clearing accounts.
This account must include undistributed balances in clearing accounts at the date of the balance sheet. Balances in clearing accounts must be substantially cleared not later than the end of the calendar year unless the items held relate to a future period.
§ 367.1850 Account 185, Temporary facilities.
This account must include amounts shown by project for property installed for temporary use for a period of less than one year. Each project must be charged with the cost of temporary facilities and credited with payments received from customers and net salvage realized on removal of the temporary facilities. Any net credit or debit resulting must be cleared to the construction or service project to which the facilities relate.
§ 367.1860 Account 186, Miscellaneous deferred debits.
(a) This account must include all debits not provided for elsewhere, such as miscellaneous work in progress, and unusual or extraordinary expenses, not included in other accounts, that are in the process of amortization and items the proper final disposition of which is uncertain.
(b) The records supporting the entries to this account must be kept so that the service company can furnish full information as to each deferred debit included in this account.
§ 367.1880 Account 188, Research, development, or demonstration expenditures.
(a) This account must be charged with the cost of all expenditures coming within the meaning of research, development and demonstration (RD&D) of this Uniform System of Accounts (See Definitions § 367.1(a)(40)), except those expenditures properly chargeable to account 107, Construction work in progress (§ 367.1070).
(b) Costs that are minor or of a general or recurring nature must be transferred from this account to the appropriate operating expense function or, if the costs are common to the overall operations or cannot be feasibly allocated to the various operating accounts, then the costs must be recorded in account 930.2, Miscellaneous general expenses (§ 367.9302).
(c) In certain instances, a service company may incur large and significant research, development, and demonstration expenditures that are nonrecurring and that would distort the annual research, development, and demonstration charges for the period. In such a case, the portion of such amounts that causes the distortion may be amortized to the appropriate operating expense account over a period not to exceed five years, unless otherwise authorized by the Commission.
(d) The entries in this account must be maintained so as to show separately each project along with complete detail of the nature and purpose of the research, development, and demonstration project together with the related costs.
§ 367.1890 Account 189, Unamortized loss on reacquired debt.
This account must include the losses on long-term debt reacquired or redeemed. The amounts in this account must be amortized in accordance with General Instruction § 367.16.
§ 367.1900 Account 190, Accumulated deferred income taxes.
(a) This account must be debited and account 411.1, Provision for deferred income taxes—Credit, operating income (§ 367.4111), or account 411.2, Provision for deferred income taxes—Credit, other income and deductions (§ 367.4112), as appropriate, must be credited with an amount equal to that by which income taxes payable for the year are higher because of the inclusion of certain items in income for tax purposes, which items for general accounting purposes will not be fully reflected in the service company’s determination of annual net income until subsequent years.
(b) This account must be credited and account 410.1, Provision for deferred income taxes, operating income (§ 367.4101), or account 410.2, Provision for deferred income taxes, other income and deductions (§ 367.4102), as appropriate, must be debited with an amount equal to that by which income taxes payable for the year are lower because of prior payment of taxes as provided by paragraph (a) of this section, because of difference in timing for tax purposes of particular items of income or income deductions from that recognized by the utility for general accounting purposes. The credit to this account and debit to account 410.1 (§ 367.4101), or 410.2 (§ 367.4102) must, in general, represent the effect on taxes payable in the current year of the smaller amount of book income recognized for tax purposes as compared to the amount recognized in the service company’s current accounts with respect to the item or class of items for which deferred tax accounting by the service company was authorized by the Commission.
(c) The service company is restricted in its use of this account to the purpose provided in paragraphs (a) and (b) of this section. The service company must not make use of the balance in this account or any related portion except as provided in the text of this account, without prior approval of the Commission. Any remaining deferred tax account balance with respect to an amount for any prior year’s tax deferral, the amortization of which or other recognition in the service company’s income accounts has been completed, or other disposition made, must be debited to account 410.1, Provision for deferred income taxes, operating income (§ 367.4101), or account 410.2, Provision for deferred income taxes, other income and deductions (§ 367.4102), as appropriate, or otherwise disposed of as the Commission may authorize or direct. (See General Instructions in § 367.17.)
Proprietary Capital
§ 367.2010 Account 201, Common stock issued.
This account must include the par or stated value of all common capital stock issued and outstanding.
§ 367.2040 Account 204, Preferred stock issued.
This account must include the par or stated value of all preferred stock issued and outstanding.
§ 367.2110 Account 211, Miscellaneous paid-in capital.
This account must include the balance of all other credits for paid-in capital that is not properly included in proprietary capital accounts. This account may include all commissions and expenses incurred in connection with the issuance of capital stock.
§ 367.2150 Account 215, Appropriated retained earnings.
This account must include the amount of retained earnings that has been appropriated or set aside for special purposes. Separate subaccounts must be maintained under titles that will designate the purpose for which each appropriation was made.
§ 367.2160 Account 216, Unappropriated retained earnings.
This account must include the balances, either debit or credit, of unappropriated retained earnings arising from earnings of the service company. This account must not include any amounts representing the undistributed earnings of subsidiary companies.
§ 367.2161 Account 216.1, Unappropriated undistributed subsidiary earnings.
This account must include the balances, either debit or credit, of undistributed retained earnings of subsidiary companies since their acquisition. When dividends are received from subsidiary companies relating to amounts included in this account, this account must be debited and account 216, Unappropriated retained earnings (§ 367.2160), credited.
§ 367.2190 Account 219, Accumulated other comprehensive income.
(a) This account must include revenues, expenses, gains, and losses that are properly includable in other comprehensive income during the period. Examples of other comprehensive income include, but are not limited to, minimum pension liability adjustments, and unrealized gains and losses on certain investments in debt and equity securities. Records supporting the entries to this account must be maintained so that the service company can furnish the amount of other comprehensive income for each item included in this account.
(b) This account also must be debited or credited, as appropriate, with amounts of accumulated other comprehensive income that have been included in the determination of net income during the period and in accumulated other comprehensive income in prior periods. Separate records for each category of items must be maintained to identify the amount of the reclassification adjustments from accumulated other comprehensive income to earnings made during the period.
Long-Term Debt
§ 367.2230 Account 223, Advances from associate companies.
(a) This account must include the face value of notes payable to associate companies and the amount of open book accounts representing advances from associate companies. It does not include notes and open accounts representing indebtedness subject to current settlement that are includible in account 233, Notes payable to associate companies (§ 367.2330), or account 234, Accounts payable to associate companies (§ 367.2340).
(b) The records supporting the entries to this account must be kept so that the service company can furnish complete information concerning each note and open account.
§ 367.2240 Account 224, Other long-term debt.
(a) This account must include, until maturity, all long-term debt not otherwise provided for. This covers items such as receivers’ certificates, real estate mortgages executed or assumed, assessments for public improvements, notes and unsecured certificates of indebtedness not owned by associate companies, receipts outstanding for long-term debt, and other obligations maturing more than one year from date of issue or assumption.
(b) Separate accounts must be maintained for each class of obligation, and records must be maintained to show for each class all details as to date of obligation, date of maturity, interest dates and rates, security for the obligation, and other similar items.
(a) This account must include the excess of the cash value of consideration received over the face value upon the issuance or assumption of long-term debt securities.
(b) Amounts recorded in this account must be amortized over the life of each respective issue under a plan that will distribute the amount equitably over the life of the security. The amortization must be on a monthly basis, with the related amounts credited to account 429, Amortization of premium on debt—Credit (§ 367.4290) (see General Instructions in § 367.16).
§ 367.2260 Account 226, Unamortized discount on long-term debt—Debit.
(a) This account must include the excess of the face value of long-term debt securities over the related cash value of consideration received, related to the issue or assumption of all types and classes of debt.
(b) Amounts recorded in this account must be amortized over the life of the respective issues under a plan that will distribute the amount equitably over the life of the securities. The amortization must be on a monthly basis, with the related amounts charged to account 428, Amortization of debt discount and expense (§ 367.4280). (see General Instructions in § 367.16.)
Other Noncurrent Liabilities
§ 367.2270 Account 227, Obligations under capital lease—Non-current.
This account must include the portion not due within one year, of the obligations recorded for the amounts applicable to leased property recorded as assets in account 101.1, Property under capital leases (§ 367.1011).
§ 367.2282 Account 228.2, Accumulated provision for injuries and damages.
(a) This account must be credited with amounts charged to account 925, Injuries and damages (§ 367.9250), or other appropriate accounts, to meet the probable liability, not covered by insurance, for deaths or injuries to employees and others and for damages to property neither owned nor held under lease by the service company.
(b) When liability for any injury or damage is admitted by the service company, either voluntarily or because of the decision of a court or other lawful authority, such as workmen’s compensation board, the admitted liability must be charged to this account and credited to the appropriate current liability account. Details of these charges must be maintained according to the year the casualty occurred which gave rise to the loss.
(c) Recoveries or reimbursements for losses charged to this account must be credited to this account; the cost of repairs to property of others if provided for in this account must be charged to this account.
§ 367.2283 Account 228.3, Accumulated provision for pensions and benefits.
(a) This account must include provisions made by the service company and amounts contributed by employees for pensions, accident and death benefits, savings, relief, hospital and other provident purposes, where the funds are included in the assets of the service company either in general or in segregated fund accounts.
(b) Amounts paid by the service company for the purposes for which this liability is established must be charged to this account.
(c) A separate account must be kept for each kind of provision included in this account.
(d) If employee pension or benefit plan funds are not included among the assets of the service company but are held by outside trustees, payments into such funds, or accruals therefore, must be included in this account.
§ 367.2300 Account 230, Asset retirement obligations.
(a) This account must include the amount of liabilities for the recognition of asset retirement obligations related to service company property. This account must be credited for the amount of the liabilities for asset retirement obligations with amounts charged to the appropriate property account to record the related asset retirement costs.
(b) The service company must charge the accretion expense to account 411.10, Accretion expense (§ 367.4118), and credit account 230, Asset retirement obligations (§ 367.2300).
(c) This account must be debited with amounts paid to settle the asset retirement obligations recorded in this account.
(d) The service company must clear from this account any gains or losses resulting from the settlement of asset retirement obligations in accordance with the instructions prescribed in the General Instructions in § 367.22.
Current and Accrued Liabilities
§ 367.2310 Account 231, Notes payable.
This account must include the face value of all notes, drafts, acceptances, or other similar evidences of indebtedness, payable on demand or within a time not exceeding one year from date of issue, to other than associate companies.
§ 367.2320 Account 232, Accounts payable.
This account must include all amounts payable by the service company within one year that are not provided for in other accounts.
§ 367.2330 Account 233, Notes payable to associate companies.
(a) This account must include amounts owing to associate companies on notes, drafts, acceptances, or other similar evidences of indebtedness, and open accounts payable on demand or not more than one year from date of issue or creation.
(b) Exclude from this account notes and accounts that are includible in account 223, Advances from associate companies (§ 367.2230).
§ 367.2340 Account 234, Accounts payable to associate companies.
This account must include all amounts payable to associate companies by the service company within one year, which are not provided for in other accounts.
§ 367.2360 Account 236, Taxes accrued.
(a) This account must be credited with the amount of taxes accrued during the accounting period, corresponding debits being made to the appropriate accounts for tax charges. The credits may be based upon estimates, but from time to time during the year as the facts become known, the amount of the periodic credits must be adjusted so as to include as nearly as can be determined in each year the related applicable taxes. Any amount representing a prepayment of taxes applicable to the period subsequent to the date of the balance sheet, must be shown under account 165, Prepayments (§ 367.1650).
(b) If accruals for taxes are found to be insufficient or excessive, corrections must be made through current tax accruals.
(c) Accruals for taxes must be based upon the net amounts payable after credit for any discounts, and must not include any amounts for interest on tax deficiencies or refunds. Interest received on refunds must be credited to account 419, Interest and dividend income (§ 367.4190), and interest paid on deficiencies must be charged to account 431, Other interest expense (§ 367.4310).
(d) The records supporting the entries to this account must be kept so as to show for each class of taxes, the amount accrued, the basis for the accrual, the accounts to which charged, and the amount of tax paid.
§ 367.2370 Account 237, Interest accrued.
This account must include the amount of interest accrued but not matured on all liabilities of the service company not including, however, interest that is added to the principal of the debt on which it is incurred. Supporting records must be maintained so as to show the amount of interest accrued on each obligation.
§ 367.2380 Account 238, Dividends declared.
This account must include the amount of dividends that have been declared but not paid. Dividends must be credited to this account when they become a liability.
§ 367.2410 Account 241, Tax collections payable.
(a) This account must include the amount of taxes collected by the service company through payroll deductions or otherwise pending transmittal of the taxes to the proper taxing authority.
(b) Do not include liability for taxes assessed directly against the service company that is accounted for as part of the service company’s own tax expense.
§ 367.2420 Account 242, Miscellaneous current and accrued liabilities.
This account must include the amount of all other current and accrued liabilities not provided for elsewhere, appropriately designated and supported so as to show the nature of each liability.
§ 367.2430 Account 243, Obligations under capital leases—Current.
This account must include the portion, due within one year, of the obligations recorded for the amounts applicable to leased property recorded as assets in account 101.1, Property under capital leases (§ 367.1011).
§ 367.2440 Account 244, Derivative instrument liabilities.
This account must include the change in the fair value of all derivative instrument liabilities not designated as cash flow or fair value hedges. Account 426.5, Other deductions (§ 367.4265), must be debited or credited as appropriate with the corresponding amount of the change in the fair value of the derivative instrument.
§ 367.2450 Account 245, Derivative instrument liabilities—Hedges
(a) This account must include the change in the fair value of derivative instrument liabilities designated by the service company as cash flow or fair value hedges.
(b) A service company must record the change in the fair value of a derivative instrument liability related to a cash flow hedge in this account, with a concurrent charge to account 219, Accumulated other comprehensive income (§ 367.2190), with the effective portion of the derivative’s gain or loss. The ineffective portion of the cash flow hedge must be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
(c) A service company must record the change in the fair value of a derivative instrument liability related to a fair value hedge in this account, with a concurrent charge to a subaccount of the asset or liability that carries the item being hedged. The ineffective portion of the fair value hedge must be charged to the same income or expense account that will be used when the hedged item enters into the determination of net income.
Deferred Credits
§ 367.2530 Account, 253, Other deferred credits.
This account must include advance billings and receipts and other deferred credit items, not provided for elsewhere, including amounts which cannot be entirely cleared or disposed of until additional information has been received.
§ 367.2540 Account 254, Other regulatory liabilities.
(a) This account must include the amounts of regulatory liabilities, not includible in other accounts, imposed on the service company by the ratemaking actions of regulatory agencies. (See Definitions § 367.1(a)(38).)
(b) The amounts included in this account are to be established by those credits which would have been included in net income, or accumulated other comprehensive income, determinations in the current period under the general requirements of the USofA but for it being probable that: Such items will be included in a different period(s) for purposes of developing the rates that the service company is authorized to charge for its services; or refunds to customers, not provided for in other accounts, will be required. When specific identification of the particular source of the regulatory liability cannot be made or when the liability arises from revenues collected pursuant to tariffs on file at a regulatory agency, account 407.3, Regulatory debits (§ 367.4073), must be debited. The amounts recorded in this account generally are to be credited to the same account that would have been credited if included in income when earned except: All regulatory liabilities established through the use of account 407.3 (§ 367.4073) must be credited to account 407.4, Regulatory credits (§ 367.4074); and in the case of refunds, a cash account or other appropriate account should be credited when the obligation is satisfied.
(c) If it is later determined that the amounts recorded in this account will not be returned to customers through rates or refunds, such amounts must be credited to Account 421, Miscellaneous income or loss (§ 367.4210), or Account 434, Extraordinary income (§ 367.4340), as appropriate, in the year such determination is made.
(d) The records supporting the entries to this account must be so kept that the service company can furnish full information as to the nature and amount of each regulatory liability included in this account, including justification for inclusion of such amounts in this account.
§ 367.2550 Account 255, Accumulated deferred investment tax credits.
This account must be credited with all investment tax credits deferred by companies that have elected to follow deferral accounting, partial or full, rather than recognizing in the income statement the total benefits of the tax credit as realized. After this election, a company may not transfer amounts from this account, except as authorized in this account and in accounts 411.4, Investment tax credit adjustments, service company property (§ 367.4114) or 411.5, Investment tax credit adjustments, other income and deductions (§ 367.4115), or with approval of the Commission.
§ 367.2820 Account 282, Accumulated deferred income taxes—Other property.
(a) This account must include the tax deferrals resulting from adoption of the principle of comprehensive inter-period income tax allocation described in the General Instructions in § 367.17 that are related to all property other than accelerated amortization property.
(b) This account must be credited and accounts 410.1, Provision for deferred income taxes, operating income (§ 367.4101), or 410.2, Provision for deferred income taxes, Other income and deductions (§ 367.4102), as appropriate, must be debited with tax effects related to property described in paragraph (a) of this section where taxable income is lower than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
(c) This account must be debited, and accounts 411.1, Provision for deferred income taxes—Credit, operating income (§ 367.4111), or 411.2, Provision for deferred income taxes—Credit, other income and deductions (§ 367.4112), as appropriate, must be credited with tax effects related to property described in paragraph (a) of this section where taxable income is higher than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
(d) The service company is restricted in its use of this account to the purposes described in paragraphs (a) through (c) of this section. It must not transfer the balance in this account or any related portion to retained earnings or make any other use of the balance except as provided in paragraph (a) through (c) of this section without prior approval of the Commission. Upon the disposition by sale, exchange, transfer, abandonment or premature retirement of property on which there is a related balance, this account must be charged with an amount equal to the related income tax expense, if any, arising from the disposition and accounts 411.1, Income taxes deferred in prior years—Credit, operating income (§ 367.4111), or 411.2, Income taxes deferred in prior years—Credit, other income and deductions (§ 367.4112), must be credited. When property is disposed of by transfer to a wholly-owned subsidiary, the related balance in this account also must be transferred. When the disposition relates to retirement of an item or items under a group method of depreciation where there is no tax effect in the year of retirement, no entries are required in this account if it can be determined that the related balance must be retained to offset future group item tax deficiencies.
§ 367.2830 Account 283, Accumulated deferred income taxes—Other.
(a) This account must include all credit tax deferrals resulting from the adoption of the principles of comprehensive inter-period income tax allocation described in the General Instructions in § 367.17 other than those deferrals that are includible in account 282, Accumulated deferred income taxes—Other property (§ 367.2820).
(b) This account must be credited, and accounts 410.1 Provision for deferred income taxes, operating income (§ 367.4101), or 410.2 Provision for deferred income taxes, other income and deductions (§ 367.4102), as appropriate, must be debited with tax effects related to items described in paragraph (a) of this section where taxable income is lower than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
(c) This account must be debited, and accounts 411.1, Provision for deferred income taxes-Credit, operating income (§ 367.4111), or 411.2, Provision for deferred income taxes-Credit, other income and deductions (§ 367.4112), as appropriate, must be credited with tax effects related to items described in paragraph (a) of this account where taxable income is higher than pretax accounting income due to differences between the periods in which revenue and expense transactions affect taxable income and the periods in which they enter into the determination of pretax accounting income.
(d) Records with respect to entries to this account, as described in paragraphs (a) through (c) of this section, and the account balance, must be maintained so as to show the factors of calculation with respect to each annual amount of the item or class of items.
(e) The service company is restricted in its use of this account to the purposes described in paragraphs (a) through (c) of this section. It must not transfer the balance in the account or any portion of the account to retained earnings or to any other account or make any use of the account except as provided in the text of this account, without prior approval of the Commission. Upon the disposition by sale, exchange, transfer, abandonment or premature retirement of items on which there is a related balance herein, this account must be charged with an amount equal to the related income tax effect, if any, arising from the disposition and accounts 411.1, Provision for deferred income taxes-Credit, operating income (§ 367.4111), or 411.2, Provision for deferred income taxes—Credit, other income and deductions (§ 367.4112), as appropriate, must be credited.
(f) When property is disposed of by transfer to a wholly-owned subsidiary, the related balance in this account also must be transferred. When the disposition relates to retirement of an item or items under a group method of depreciation where there is no tax effect in the year of retirement, no entries are required in this account if it can be determined that the related balance must be retained to offset future group item tax deficiencies.
Subpart G—Service Company Property Chart of Accounts
§ 367.3010 Account 301, Organization.
(a) This account must include all fees paid to federal or state governments for the privilege of incorporation and expenditures incident to organizing the corporation, partnership, or other enterprise and putting it into readiness to do business.
(b) This account must include the following items:
(1) Cost of obtaining certificates authorizing the service company to engage in its business.
(2) Fees and expenses for incorporation.
(3) Fees and expenses for mergers or consolidations.
(4) Office expenses incident to organizing the service company.
(5) Stock and minute books and corporate seal.
(c) This account must not include any discounts upon securities issued or assumed; nor may it include any costs incident to negotiating loans, selling bonds or other evidences of debt or expenses in connection with the authorization, issuance or sale of capital stock.
(d) Exclude from this account and include in the appropriate expense account, the cost of preparing and filing papers in connection with the extension of the term of incorporation unless the first organization costs have been written off. When charges are made to this account for expenses incurred in mergers, consolidations, or reorganizations, amounts previously included in this account or in similar accounts in the books of the companies concerned must be excluded from this account.
§ 367.3030 Account 303, Miscellaneous intangible property.
(a) This account must include the cost of patent rights, licenses, privileges, and other intangible property necessary or valuable in the conduct of service company operations and not specifically chargeable to any other account.
(b) When any item included in this account is retired or expires, the related book cost must be credited to this account and charged to account 426.5, Other deductions (§ 367.4265), or account 111, Accumulated provision for amortization of property (§ 367.1110).
(c) This account must be maintained in a manner so that the service company can furnish full information with respect to the amounts included in this account.
§ 367.3060 Account 306, Leasehold improvements.
This account must include all costs incurred by the service company in improvements of, remodeling of, or installation of additional facilities in rented offices or buildings to suit tenant’s needs, placed in service prior to January 1, 2008.
§ 367.3890 Account 389, Land and land rights.
This account must include the cost of land and land rights used for service company purposes, the cost of which is not properly includible in other land and land rights accounts (See Service Company Property Instructions in § 367.55).
§ 367.3900 Account 390, Structures and improvements.
This account must include the cost in place of structures and improvements used for service company purposes, the cost of which is not properly includible in other structures and improvements accounts (See Service Company Property Instructions in § 367.56).
§ 367.3910 Account 391, Office furniture and equipment.
(a) This account must include the cost of office furniture and equipment owned by the service company and devoted to service company operations, and not permanently attached to buildings, except the cost of the furniture and equipment that the service company elects to assign to other property accounts on a functional basis.
(b) This account must include the following items:
(1) Bookcases and shelves.
(2) Desks, chairs, and desk equipment.
(3) Drafting-room equipment.
(4) Filing, storage, and other cabinets.
(5) Floor covering.
(6) Library and library equipment.
(7) Mechanical office equipment, such as accounting machines, typewriters, and other similar items.
(8) Safes.
(9) Tables.
§ 367.3920 Account 392, Transportation equipment.
(a) This account must include the cost of transportation vehicles used for service company purposes.
(b) This account must include the following items:
(1) Airplanes.
(2) Automobiles.
(3) Bicycles.
(4) Electrical vehicles.
(5) Motor trucks.
(6) Motorcycles.
(7) Repair cars or trucks.
(8) Tractors and trailers.
(9) Other transportation vehicles.
§ 367.3930 Account 393, Stores equipment.
(a) This account must include the cost of equipment used for the receiving, shipping, handling, and storage of materials and supplies.
(b) This account must include the following items:
(1) Chain falls.
(2) Counters.
(3) Cranes (portable).
(4) Elevating and stacking equipment (portable).
(5) Hoists.
(6) Lockers.
(7) Scales.
(8) Shelving.
(9) Storage bins.
(10) Trucks, hand and power driven.
(11) Wheelbarrows.
§ 367.3940 Account 394, Tools, shop and garage equipment.
(a) This account must include the cost of tools, implements, and equipment used in construction, repair work, general shops and garages and not specifically provided for or includible in other accounts.
(b) This account must include the following items:
(1) Air compressors.
(2) Anvils.
(3) Automobile repair shop equipment.
(4) Battery charging equipment.
(5) Belts, shafts and countershafts.
(6) Boilers.
(7) Cable pulling equipment.
(8) Concrete mixers.
(9) Drill presses.
(10) Derricks.
(11) Electric equipment.
(12) Engines.
(13) Forges.
(14) Furnaces.
(15) Foundations and settings specially constructed for equipment in this account and not expected to outlast the equipment for which provided.
(16) Gas producers.
(17) Gasoline pumps, oil pumps and storage tanks.
(18) Greasing tools and equipment.
(19) Hoists.
(20) Ladders.
(21) Lathes.
(22) Machine tools.
(23) Motor-driven tools.
(24) Motors.
(25) Pipe threading and cutting tools.
(26) Pneumatic tools.
(27) Pumps.
(28) Riveters.
(29) Smithing equipment.
(30) Tool racks.
(31) Vises.
(32) Welding apparatus.
(33) Work benches.
§ 367.3950 Account 395, Laboratory equipment.
(a) This account must include the cost installed of laboratory equipment used for general laboratory purposes.
(b) This account must include the following items:
(1) Ammeters.
(2) Balances and scales.
(3) Barometers.
(4) Calorimeters-bomb, flow, recording types, and other similar items.
(5) Current batteries.
(6) Electric furnaces.
(7) Frequency changers.
(8) Galvanometers.
(9) Gas burning equipment.
(10) Gauges.
(11) Glassware, beakers, burettes, and other similar items.
(12) Humidity testing apparatus.
(13) Inductometers.
(14) Laboratory hoods.
(15) Laboratory standard millivolt meters.
(16) Laboratory standard volt meters.
(17) Laboratory tables and cabinets.
(18) Meter-testing equipment.
(19) Millivolt meters.
(20) Motor generator sets.
(21) Muffles.
(22) Oil analysis apparatus.
(23) Panels.
(24) Phantom loads.
(25) Piping.
(26) Portable graphic ammeters, voltmeters, and wattmeters.
(27) Portable loading devices.
(28) Potential batteries.
(29) Potentiometers.
(30) Rotating standards.
(31) Specific gravity apparatus.
(32) Standard bottles for meter prover testing.
(33) Standard cell, reactance, resistor, and shunt.
(34) Stills.
(35) Sulphur and ammonia apparatus.
(36) Switchboards.
(37) Synchronous timers.
(38) Tar analysis apparatus.
(39) Testing panels.
(40) Testing resistors.
(41) Thermometers—indicating and recording.
(42) Transformers.
(43) Voltmeters.
(44) Other testing, laboratory, or research equipment not provided for elsewhere.
(45) Other items of equipment for testing gas, fuel, flue gas, water, residuals, and other similar items.
§ 367.3960 Account 396, Power operated equipment.
(a) This account must include the cost of power operated equipment used in construction or repair work exclusive of equipment includible in other accounts. Include, also, the tools and accessories acquired for use with the equipment and the vehicle on which the equipment is mounted.
(b) This account must include the following items:
(1) Air compressors, including driving unit and vehicle.
(2) Back filling machines.
(3) Boring machines.
(4) Bulldozers.
(5) Cranes and hoists.
(6) Diggers.
(7) Engines.
(8) Pile drivers.
(9) Pipe cleaning machines.
(10) Pipe coating or wrapping machines.
(11) Tractors—Crawler type.
(12) Trenchers.
(13) Other power operated equipment.
(c) It is intended that this account include only the large units that are generally self-propelled or mounted on movable equipment.
§ 367.3970 Account 397, Communication equipment.
(a) This account must include the cost installed of telephone, telegraph, and wireless equipment for general use in connection with service company operations.
(b) This account must include the following items:
(1) Amplifiers.
(2) Antennae.
(3) Booths.
(4) Cables.
(5) Carrier terminal equipment.
(6) Conductors.
(7) Distributing boards.
(8) Extension cords.
(9) Gongs.
(10) Hand sets, manual and dial.
(11) Insulators.
(12) Intercommunicating sets.
(13) Loading coils.
(14) Microwave equipment.
(15) Operators’ desks.
(16) Paraboloids.
(17) Poles and fixtures used wholly for telephone or telegraph wire.
(18) Power supply equipment.
(19) Radio transmitting and receiving sets.
(20) Reflectors.
(21) Repeaters.
(22) Remote control equipment and lines.
(23) Sending keys.
(24) Storage batteries.
(25) Switchboards.
(26) Telautograph circuit connections.
(27) Telegraph receiving sets.
(28) Telephone and telegraph circuits.
(29) Testing instruments.
(30) Towers.
(31) Underground conduit used wholly for telephone or telegraph wires and cable wires.
§ 367.3980 Account 398, Miscellaneous equipment.
(a) This account must include the cost of equipment, apparatus, and other similar items, used in the service company’s operations that are not included in any other account of this system of accounts.
(b) This account must include the following items:
(1) Hospital and infirmary equipment.
(2) Kitchen equipment.
(3) Employees’ recreation equipment.
(4) Radios.
(5) Restaurant equipment.
(6) Soda fountains.
(7) Operators’ cottage furnishings.
(8) Other miscellaneous equipment.
§ 367.3990 Account 399, Other tangible property.
This account must include the cost of tangible service company property not provided for elsewhere.
§ 367.3991 Account 399.1, Asset retirement costs for service company property.
This account must include asset retirement costs on service company property.
Subpart H—Income Statement Chart of Accounts
Service Company Operating Income
§ 367.4000 Account 400, Operating revenues.
There must be shown under this caption the total amount included in the service company operating revenue accounts 457 through 459 (§§ 367.4570 through 367.4590).
§ 367.4010 Account 401, Operation expense.
There must be shown under this caption the total amount included in the service company operation expense accounts 500 through 589 (§§ 367.5000 through 367.5890), 800 through 881 (§§ 367.8000 through 367.8810) and 901 through 931 (§§ 367.9010 through 367.9310).
§ 367.4020 Account 402, Maintenance expense.
There must be shown under this caption the total amount included in the service company maintenance expense accounts 500 through 598 (§§ 367.5000 through 367.5890), 800 through 894 (§§ 367.8000 through 367.8810), and 935 (§ 367.9350).
§ 367.4030 Account 403, Depreciation expense.
(a) This account must include the amount of depreciation for all service company property, the cost of which is included in accounts 390 through 399.1 (§§ 367.3900 through 367.3991). Provide subaccounts by each class of service company property owned or leased except the depreciation expense that is charged to clearing accounts or to account 416, Costs and expenses of merchandising, jobbing and contract work (§ 367.4160).
(b) The service company must keep the records of property and property retirements that will reflect the service life of property that has been retired and aid in estimating probable service life by mortality, turnover, or other appropriate methods; and also the records that will reflect the percentage of salvage and costs of removal for property retired from each account, or related subaccount, for depreciable property.
(c) Depreciation expenses applicable to transportation equipment, shop equipment, tools, work equipment, power operated equipment and other general equipment may be charged to clearing accounts as necessary in order to obtain a proper distribution of expenses between construction and operation.
§ 367.4031 Account 403.1, Depreciation expense for asset retirement costs.
This account must include the depreciation expense for asset retirement costs included in service company property.
§ 367.4040 Account 404, Amortization of limited-term property.
This account must include amortization charges applicable to amounts included in the service company property accounts for limited-term franchises, licenses, patent rights, limited-term interests in land, and expenditures on leased property where the service life of the improvements is terminable by action of the lease. The charges to this account must be sufficient to distribute the book cost of each investment as evenly as may be over the period of its benefit (See account 111, Accumulated provision for amortization of service company property (§ 367.1110)).
§ 367.4050 Account 405, Amortization of other property.
(a) When authorized by the Commission, this account must include charges for amortization of intangible or other property that does not have a definite or terminable life and that is not subject to charges for depreciation expense.
(b) This account must be supported in sufficient detail to show the amortization applicable to each investment being amortized, together with the book cost of the investment and the period over which it is being written off.
§ 367.4073 Account 407.3, Regulatory debits.
This account shall be debited, when appropriate, with amounts credited to Account 254, Other Regulatory Liabilities, to record regulatory liabilities imposed on the service company by the ratemaking actions of regulatory agencies. This account shall also be debited, when appropriate, with the amounts credited to Account 182.3, Other Regulatory Assets, concurrent with the recovery of such amounts in rates.
§ 367.4074 Account 407.4, Regulatory credits.
This account shall be credited, when appropriate, with amounts debited to Account 182.3, Other Regulatory Assets, to establish regulatory assets. This account shall also be credited, when appropriate, with the amounts debited to Account 254, Other Regulatory Liabilities, concurrent with the return of such amounts to customers through rates.
§ 367.4081 Account 408.1, Taxes other than income taxes, operating income.
This account must include those taxes, other than income taxes, that relate to service company operating income. This account must be maintained so as to allow ready identification of the various classes of taxes.
§ 367.4082 Account 408.2, Taxes other than income taxes, other income and deductions.
This account must include those taxes, other than income taxes, that relate to other income and deductions.
§ 367.4091 Account 409.1, Income taxes, operating income.
This account must include the amount of those local, state and Federal income taxes that relate to service company operating income.
§ 367.4092 Account 409.2, Income taxes, other income and deductions.
This account must include the amount of those local, state and Federal income taxes (both positive and negative), that relate to other income and deductions.
§ 367.4093 Account 409.3, Income taxes, extraordinary items.
This account must include the amount of those local, state and Federal income taxes (both positive and negative), that relate to extraordinary items.
§ 367.4101 Account 410.1, Provision for deferred income taxes, operating income.
This account must include the amounts of those deferrals of taxes and allocations of deferred taxes that relate to service company operating income.
§ 367.4102 Account 410.2, Provision for deferred income taxes, other income and deductions.
This account must include the amounts of those deferrals of taxes and allocations of deferred taxes that relate to other income and deductions.
§ 367.4111 Account 411.1, Provision for deferred income taxes—Credit, operating income.
This account must include the amounts of those allocations of deferred taxes and deferrals of taxes, credit, that relate to service company operating income.
§ 367.4112 Account 411.2, Provision for deferred income taxes—Credit, other income and deductions.
This account must include the amounts of those allocations of deferred taxes and deferrals of taxes, credit, that relate to other income and deductions.
§ 367.4114 Account 411.4, Investment tax credit adjustments, service company property.
This account must include the amount of those investment tax credit adjustments that relate to service company property.
§ 367.4115 Account 411.5, Investment tax credit adjustments, other.
This account must include the amount of those investment tax credit adjustments not properly included in other accounts.
§ 367.4116 Account 411.6, Gains from disposition of service company plant.
(a) The service company must record in this account gains resulting from the settlement of asset retirement obligations related to service company plant in accordance with the accounting prescribed in General Instructions in § 367.22.
(b) Income taxes relating to losses, recorded in this account must be recorded in Account 409.1, Income Taxes, operating income (§ 367.4091).
§ 367.4117 Account 411.7, Losses from disposition of service company plant.
(a) The service company must record in this account losses resulting from the settlement of asset retirement obligations related to service company plant in accordance with the accounting prescribed in General Instructions in § 367.22.
(b) Income taxes relating to losses, recorded in this account must be recorded in Account 409.1, Income Taxes, operating income (§ 367.4091).
§ 367.4118 Account 411.10, Accretion expense.
This account must be charged for accretion expense on the liabilities associated with asset retirement obligations included in account 230, Asset retirement obligations (§ 367.2300), related to service company property.
§ 367.4120 Account 412, Cost and expenses of construction or other services.
This account must include expenditures related to the performance of construction or service contracts, under which the service company undertakes projects to construct physical property for associate or non-associate companies (see General Instructions § 367.24, Construction and service contracts for other companies) and the cost of services performed for others not provided for elsewhere.
§ 367.4160 Account 416, Costs and expenses of merchandising, jobbing and contract work.
(a) This account must include the following labor items for services provided:
(1) Canvassing and demonstrating appliances in homes and other places for the purpose of selling appliances.
(2) Demonstrating and selling activities in sales rooms.
(3) Installing appliances on customer premises where the work is done only for purchasers of appliances from the associated company.
(4) Installing wiring, piping, or other property work, on a jobbing or contract basis.
(5) Preparing advertising materials for appliance sales purposes.
(6) Receiving and handling customer orders for merchandise or for jobbing services.
(7) Cleaning and tidying sales rooms.
(8) Maintaining display counters and other equipment used in merchandising.
(9) Arranging merchandise in sales rooms and decorating display windows.
(10) Reconditioning repossessed appliances.
(11) Bookkeeping and other clerical work in connection with merchandise and jobbing activities.
(12) Supervising merchandise and jobbing operations.
(b) This account must include the following materials and expenses items:
(1) Advertising in newspapers, periodicals, radio, television, and other similar items.
(2) Cost of merchandise sold and of materials used in jobbing work.
(3) Stores expenses on merchandise and jobbing stocks.
(4) Fees and expenses of advertising and commercial artists’ agencies.
(5) Printing booklets, dodgers, and other advertising data.
(6) Premiums given as inducement to buy appliances.
(7) Light, heat and power.
(8) Depreciation on equipment used primarily for merchandise and jobbing operations.
(9) Rent of sales rooms or of equipment.
(10) Transportation expense in delivery and pick-up of appliances by the associated company’s facilities.
(11) Stationery and office supplies and expenses.
(12) Losses from uncollectible merchandise and jobbing accounts.
(c) Records in support of this account shall be so kept as to permit ready summarization of costs and expenses by such major items as are feasible.
(d) Related taxes must be recorded in account 408.2, Taxes other than income taxes, other income and deductions (§ 367.4082), or account 409.2, Income taxes, other income and deductions (§ 367.4092), as appropriate.
§ 367.4180 Account 418, Non-operating rental income.
(a) The expenses shall include all elements of costs incurred in the ownership and rental of property and the accounts shall be maintained so as to permit ready summarization of operation, maintenance, rents, depreciation, and amortization.
(b) Related taxes shall be recorded in Account 408.2, Taxes other than income taxes, other income and deductions (§ 367.4082) or Account 409.2, Income taxes, other income and deductions (§ 367.4092), as appropriate.
§ 367.4181 Account 418.1, Equity in earnings of subsidiary companies.
This account must include the service company’s equity in the earnings or losses of subsidiary companies for the year.
§ 367.4190 Account 419, Interest and dividend income.
(a) This account must include interest revenues on securities, loans, notes, advances, special deposits, tax refunds and all other interest-bearing assets, and dividends on stocks of other companies, whether the securities on which the interest and dividends are received are carried as investments or included in sinking or other special fund accounts.
(b) This account may include the pro rata amount necessary to extinguish (during the interval between the date of acquisition and the date of maturity) the difference between the cost to the service company and the face value of interest-bearing securities. The amounts credited or charged must be concurrently included in the accounts in which the securities are carried.
(c) Where significant in amount, expenses, excluding operating taxes and income taxes, applicable to security investments and to interest and dividend revenues on the account must be charged in this account.
(d) Related taxes must be recorded in account 408.2, Taxes other than income taxes, other income and deductions (§ 367.4082), or account 409.2, Income taxes, other income and deductions (§ 367.4092).
(e) Interest accrued, the payment of which is not reasonably assured, dividends receivable that have not been declared or guaranteed, and interest or dividends upon reacquired securities issued or assumed by the service company must not be credited to this account.
§ 367.4191 Account 419.1, Allowance for other funds used during construction.
This account must include concurrent credits for allowance for other funds used during construction.
§ 367.4210 Account 421, Miscellaneous income or loss.
This account must include all revenue and expense items except taxes properly includible in the income account and not provided for elsewhere. Related taxes must be recorded in account 408.2, Taxes other than income taxes, other income and deductions (§ 367.4082), or account 409.2, Income taxes, other income and deductions (§ 367.4092).
§ 367.4211 Account 421.1, Gain on disposition of property.
This account must be credited with the gain on the sale, conveyance, exchange, or transfer of service or other property to another. Income taxes on gains recorded in this account must be recorded in account 409.2, Income taxes, other income and deductions (§ 367.4092).
§ 367.4212 Account 421.2, Loss on disposition of property.
This account must be charged with the loss on the sale, conveyance, exchange or transfer of service or other property to another. The reduction in income taxes relating to losses recorded in this account must be recorded in account 409.2, Income taxes, other income and deductions (§ 367.4092).
§ 367.4250 Account 425, Miscellaneous amortization.
(a) This account must include amortization charges not includible in other accounts which are properly deductible in determining the income of the service company before interest charges. Charges included in this account, if significant in amount, must be in accordance with an orderly and systematic amortization program.
(b) This account must include the following items:
(1) Amortization of intangibles included in service company property.
(2) Other miscellaneous amortization charges authorized to be included in this account by the Commission.
§ 367.4261 Account 426.1, Donations.
This account must include all payments or donations for charitable, social or community welfare purposes.
§ 367.4262 Account 426.2, Life insurance.
This account must include all payments for life insurance of officers and employees where the service company is beneficiary (net premiums less increase in cash surrender value of policies).
§ 367.4263 Account 426.3, Penalties.
This account must include payments by the service company for penalties or fines for violation of any regulatory statutes by the service company or its officials.
(a) This account must include expenditures for the purpose of influencing public opinion with respect to the election or appointment of public officials, referenda, legislation, or ordinances (either with respect to the possible adoption of new referenda, legislation or ordinances or repeal or modification of existing referenda, legislation or ordinances) or approval, modification, or revocation of franchises; or for the purpose of influencing the decisions of public officials.
(b) This account must not include expenditures that are directly related to appearances before regulatory or other governmental bodies in connection with an associate utility company’s existing or proposed operations.
§ 367.4265 Account 426.5, Other deductions.
This account must include other miscellaneous expenses that are not properly included in service company operations.
§ 367.4270 Account 427, Interest on long-term debt.
(a) This account must include the amount of interest on outstanding long-term debt issued or assumed by the service company, the liability for which is included in account 224, Other long-term debt (§ 367.2240).
(b) This account must be kept or supported so as to show the interest accruals on each class and series of long-term debt.
(c) This account must not include interest on nominally issued or nominally outstanding long-term debt, including securities assumed.
§ 367.4280 Account 428, Amortization of debt discount and expense.
(a) This account must include the amortization of unamortized debt discount and expense on outstanding long-term debt. Amounts charged to this account must be credited concurrently to accounts 181, Unamortized debt expense (§ 367.1810), and 226, Unamortized discount on long-term debt—Debit (§ 367.2260).
(b) This account must be kept or supported so as to show the debt discount and expense on each class and series of long-term debt.
(a) This account must include the amortization of unamortized net premium on outstanding long-term debt. Amounts credited to this account must be charged concurrently to account 225, Unamortized premium on long-term debt (§ 367.2250).
(b) This account must be kept or supported so as to show the premium on each class and series of long-term debt.
(c) This account must include the following items:
(1) Loss relating to investments in securities written-off or written-down.
(2) Loss on sale of investments.
(3) Loss on reacquisition, resale or retirement of service company’s debt securities.
(4) Preliminary survey and investigation expenses related to abandoned projects, when not written-off to the appropriate operating expense account.
§ 367.4300 Account 430, Interest on debt to associate companies.
This account must include interest accrued on amounts included in account 223, Advances from associate companies (§ 367.2230), and account 233, Notes payable to associate companies (§ 367.2330). The records supporting the entries to this account must be kept so as to show to who the interest is to be paid, the period covered by the accrual, the rate of interest and the principal amount of the advances or other obligations on which the interest is accrued. Separate subaccounts must be maintained for each related debt account.
§ 367.4310 Account 431, Other interest expense.
This account must include all interest charges not provided for elsewhere.
§ 367.4320 Account 432, Allowance for borrowed funds used during construction—Credit.
This account must include concurrent credits for allowance for borrowed funds used during construction.
Subpart I—Retained Earnings Accounts
§ 367.4330 Account 433, Balance transferred from income.
This account must include the net credit or debit transferred from income for the year.
§ 367.4340 Account 434, Extraordinary income.
This account must be credited with gains of unusual nature and infrequent occurrence that would significantly distort the current year’s income computed before extraordinary items, if reported other than as extraordinary items. Income tax relating to the amounts recorded in this account must be recorded in account 409.3, Income taxes, extraordinary items (§ 367.4093) (See General Instructions in § 367.8).
§ 367.4350 Account 435, Extraordinary deductions.
This account must be debited with losses of unusual nature and infrequent occurrence that would significantly distort the current year’s income computed before extraordinary items, if reported other than as extraordinary items. Income tax relating to the amounts recorded in this account must be recorded in account 409.3, Income taxes, extraordinary items (§ 367.4093) (See General Instructions in § 367.8).
§ 367.4360 Account 436, Appropriations of retained earnings.
This account must include appropriations of retained earnings as follows:
(a) Appropriations required under terms of mortgages, orders of courts, contracts, or other agreements.
(b) Appropriations required by action of regulatory authorities.
(c) Other appropriations made at option of the service company for specific purposes.
§ 367.4370 Account 437, Dividends declared—preferred stock.
(a) This account must include amounts declared payable out of retained earnings as dividends on actually outstanding preferred or prior lien capital stock issued by the service company.
(b) Dividends must be segregated for each class and series of preferred stock as to those payable in cash, stock, and other forms. If not payable in cash, the medium of payment must be described with sufficient detail to identify it.
§ 367.4380 Account 438, Dividends declared—common stock.
(a) This account must include amounts declared payable out of retained earnings as dividends on actually outstanding common capital stock issued by the service company.
(b) Dividends must be segregated for each class of common stock as to those payable in cash, stock and other forms. If not payable in cash, the medium of payment must be described with sufficient detail to identify it.
§ 367.4390 Account 439, Adjustments to retained earnings.
(a) This account must, with prior Commission approval, include significant non-recurring transactions accounted for as prior period adjustments, as follows:
(1) Correction of an error in the financial statements of a prior year.
(2) Adjustments that result from realization of income tax benefits of reacquisition operating loss carry forwards of purchased subsidiaries. All other items of profit and loss recognized during a year must be included in the determination of net income for that year.
(b) Adjustments, charges, or credits due to losses on reacquisition, resale or retirement of the company’s own capital stock must be included in this account.
Subpart J—Operating Revenue Chart of Accounts
§ 367.4570 Account 457, Services rendered to associate companies.
This account must include amounts billed to associate companies for services rendered at cost (See accounts 457.1 through 457.3 in §§ 367.4571 through 367.4573). Overbillings or underbillings arising from adjustments of estimated costs to actual costs must be cleared through this account and concurrent adjustments made to other accounts involved.
§ 367.4571 Account 457.1, Direct costs charged to associate companies.
This account must include those direct costs that can be identified through a cost allocation system as being applicable to services performed for associate companies. This account must not include any compensation for use of equity capital or inter-company interest on indebtedness.
§ 367.4572 Account 457.2, Indirect costs charged to associate companies.
This account must include recovery of those indirect costs that cannot be separately identified to a single or group of associate companies and therefore must be allocated. Only journal or memorandum entries should be prepared monthly, by departments, for all such cost accumulated and billed to customers. Amounts billed to associate companies must be included in this account. This account must not include any compensation for use of equity capital or inter-company interest on indebtedness.
§ 367.4573 Account 457.3, Compensation for use of capital-associate companies.
This account must include only the portion of compensation for use of equity capital and inter-company interest on indebtedness before income taxes that is properly allocable to services rendered to each associate company.
§ 367.4580 Account 458, Services rendered to non-associate companies.
This account must include amounts billed for services rendered to non-associate companies (See accounts 458.1 through 458.4 (§§ 367.4581 through 367.4584)).
§ 367.4581 Account 458.1, Direct costs charged to non-associate companies.
This account must include those direct costs that can be identified through a cost allocation system as being applicable to services performed for non-associate companies. This account must not include any compensation for use of equity capital or interest on indebtedness.
§ 367.4582 Account 458.2, Indirect costs charged to non-associate companies.
This account must include recovery of those indirect costs of services performed for non-associate companies that cannot be specifically assigned and therefore must be allocated. This account must not include any compensation for use of equity capital or inter-company interest on indebtedness.
§ 367.4583 Account 458.3, Compensation for use of capital—Non-associate companies.
This account must include only the portion of compensation for use of equity capital and inter-company interest on indebtedness before income taxes that is properly allocable to services rendered to non-associate utility companies. A statement to support the basis for the compensation and how it was calculated must be attached to a separate journal entry, ledger system, or memorandum file.
§ 367.4584 Account 458.4, Excess or deficiency on servicing non-associate utility companies.
This account must include the amount by which the aggregate price received for services rendered to non-associate utility companies differs from the sum of the total direct and indirect costs and compensation for use of capital which are properly allocable to such services (See accounts 458.1 through 458.3 (§§ 367.4581 through 367.4583) and General Instructions in § 367.23).
Subpart K—Operation and Maintenance Expense Chart of Accounts
§ 367.5000 Accounts 500–598, Electric operation and maintenance accounts.
Service companies must use accounts 500 through 598 in part 101 of this chapter.
§ 367.8000 Accounts 800–894, Gas operation and maintenance accounts.
Service companies must use accounts 800 through 894 in part 201 of this chapter.
§ 367.9010 Account 901, Supervision.
This account must include the cost of labor and expenses incurred in the general direction and supervision of customer accounting and collecting activities. Direct supervision of a specific activity must be charged to account 902, Meter reading expenses (§ 367.9020), or account 903, Customer records and collection expenses (§ 367.9030), as appropriate (See Operating Expense Instructions in § 367.80).
§ 367.9020 Account 902, Meter reading expenses.
(a) This account must include the cost of labor, materials used and expenses incurred in reading customer meters, and determining consumption when performed by employees engaged in reading meters.
(b) This account must include the following labor items:
(1) Addressing forms for obtaining meter readings by mail.
(2) Changing and collecting meter charts used for billing purposes.
(3) Inspecting time clocks, checking seals, and other similar items, when performed by meter readers and the work represents a minor activity incidental to regular meter reading routine.
(4) Reading meters, including demand meters, and obtaining load information for billing purposes. Exclude and charge to account 586, Meter expenses (§ 367.5000), account 878, Meter and house regulator expenses (§ 367.8000), or to account 903, Customer records and collection expenses (§ 367.9030), as applicable, the cost of obtaining meter readings, first and final, if incidental to the operation of removing or resetting, sealing, or locking, and disconnecting or reconnecting meters.
(5) Computing consumption from meter reader’s book or from reports by mail when done by employees engaged in reading meters.
(6) Collecting from prepayment meters when incidental to meter reading.
(7) Maintaining record of customers” keys.
(8) Computing estimated or average consumption when performed by employees engaged in reading meters.
(c) This account must include the following materials and expenses items:
(1) Badges, lamps, and uniforms.
(2) Demand charts, meter books and binders and forms for recording readings, but not the cost of preparation.
(3) Postage and supplies used in obtaining meter readings by mail.
(4) Transportation, meals, and incidental expenses.
§ 367.9030 Account 903, Customer records and collection expenses.
(a) This account must include the cost of labor, materials used and expenses incurred in work on customer applications, contracts, orders, credit investigations, billing and accounting, collections and complaints.
(b) This account must include the following labor items:
(1) Receiving, preparing, recording and handling routine orders for service, disconnections, transfers or meter tests initiated by the customer, excluding the cost of carrying out the orders, that is chargeable to the account appropriate for the work called for by the orders.
(2) Investigations of customers” credit and keeping of records pertaining to the investigations, including records of uncollectible accounts written off.
(3) Receiving, refunding or applying customer deposits and maintaining customer deposit, line extension, and other miscellaneous records.
(4) Checking consumption shown by meter readers” reports where incidental to preparation of billing data.
(5) Preparing address plates and addressing bills and delinquent notices.
(6) Preparing billing data.
(7) Operating billing and bookkeeping machines.
(8) Verifying billing records with contracts or rate schedules.
(9) Preparing bills for delivery, and mailing or delivering bills.
(10) Collecting revenues, including collection from prepayment meters unless incidental to meter-reading operations.
(11) Balancing collections, preparing collections for deposit, and preparing cash reports.
(12) Posting collections and other credits or charges to customer accounts and extending unpaid balances.
(13) Balancing customer accounts and controls.
(14) Preparing, mailing, or delivering delinquent notices and preparing reports of delinquent accounts.
(15) Final meter reading of delinquent accounts when done by collectors incidental to regular activities.
(16) Disconnecting and reconnecting service because of nonpayment of bills.
(17) Receiving, recording, and handling of inquiries, complaints, and requests for investigations from customers, including preparation of necessary orders, but excluding the cost of carrying out such orders, which is chargeable to the account appropriate for the work called for by the orders.
(18) Statistical and tabulating work on customer accounts and revenues, but not including special analyses for sales department, rate department, or other general purposes, unless incidental to regular customer accounting routines.
(19) Preparing and periodically rewriting meter reading sheets.
(20) Determining consumption and computing estimated or average consumption when performed by employees other than those engaged in reading meters.
(c) This account must include the following materials and expenses items:
(1) Address plates and supplies.
(2) Cash overages and shortages.
(3) Commissions or fees to others for collecting.
(4) Payments to credit organizations for investigations and reports.
(5) Postage.
(6) Transportation expenses (Major only), including transportation of customer bills and meter books under centralized billing procedure.
(7) Transportation, meals, and incidental expenses.
(8) Bank charges, exchange, and other fees for cashing and depositing customers’ checks.
(9) Forms for recording orders for services removals, and other similar forms.
(10) Rent of mechanical equipment.
(d) The cost of work on meter history and meter location records is chargeable to account 586, Meter expenses (§ 367.5000) or account 878, Meter and house regulator expenses (§ 367.8000).
§ 367.9040 Account 904, Uncollectible accounts.
This account must be charged with amounts sufficient to provide for losses from uncollectible service company revenues. Concurrent credits must be made to account 144, Accumulated provision for uncollectible accounts—Credit (§ 367.1440). Losses from uncollectible accounts also must be charged to account 144 (§ 367.1440).
§ 367.9050 Account 905, Miscellaneous customer accounts expenses.
(a) This account must include the cost of labor, materials used and expenses incurred not provided for in other accounts.
(b) This account must include the following labor items:
(1) General clerical and stenographic work.
(2) Miscellaneous labor.
(c) This account must include the following materials and expenses items:
(1) Communication service.
(2) Miscellaneous office supplies and expenses and stationery and printing other than those specifically provided for in accounts 902 and 903 (§§ 367.9020 and 367.9030).
§ 367.9070 Account 907, Supervision.
This account must include the cost of labor and expenses incurred in the general direction and supervision of customer service activities, the object of which is to encourage safe, efficient and economical use of the associate utility company’s service. Direct supervision of a specific activity within customer service and informational expense classification must be charged to the account wherein the costs of such activity are included (See Operating Expense Instructions in § 367.80).
§ 367.9080 Account 908, Customer assistance expenses.
(a) This account must include the cost of labor, materials used and expenses incurred in providing instructions or assistance to customers, the object of which is to encourage safe, efficient and economical use of the associate utility company’s service.
(b) This account must include the following labor items:
(1) Direct supervision of department.
(2) Processing customer inquiries relating to the proper use of electric equipment, the replacement of such equipment and information related to the equipment.
(3) Advice directed to customers as to how they may achieve the most efficient and safest use of electric equipment.
(4) Demonstrations, exhibits, lectures, and other programs designed to instruct customers in the safe, economical or efficient use of electric service, and/or oriented toward conservation of energy.
(5) Engineering and technical advice to customers, the object of which is to promote safe, efficient and economical use of the associate utility company’s service.
(c) This account must include the following materials and expenses items:
(1) Supplies and expenses pertaining to demonstrations, exhibits, lectures, and other programs.
(2) Loss in value on equipment and appliances used for customer assistance programs.
(3) Office supplies and expenses.
(4) Transportation, meals, and incidental expenses.
(d) Do not include in this account expenses that are provided for elsewhere, such as accounts 416, Costs and expenses of merchandising, jobbing and contract work (§ 367.4160), 587, Customer installations expenses (§ 367.5870), 879, Customer installations expenses (§ 367.8790), and 912, Demonstrating and selling expenses (§ 367.9120).
§ 367.9090 Account 909, Informational and instructional advertising expenses.
(a) This account must include the cost of labor, materials used and expenses incurred in activities which primarily convey information as to what the associate utility company urges or suggests customers should do in utilizing service to protect health and safety, to encourage environmental protection, to utilize their equipment safely and economically, or to conserve energy.
(b) This account must include the following labor items:
(1) Direct supervision of informational activities.
(2) Preparing informational materials for newspapers, periodicals, billboards, and other similar forms of advertisement, and preparing and conducting informational motion pictures, radio and television programs.
(3) Preparing informational booklets, bulletins, and other similar forms of advertisement, used in direct mailings.
(4) Preparing informational window and other displays.
(5) Employing agencies, selecting media and conducting negotiations in connection with the placement and subject matter of information programs.
(c) This account must include the following materials and expenses items:
(1) Use of newspapers, periodicals, billboards, radio, and other similar forms of advertisement, for informational purposes.
(2) Postage on direct mailings to customers exclusive of postage related to billings.
(3) Printing of informational booklets, dodgers, bulletins, and other similar items.
(4) Supplies and expenses in preparing informational materials for the associate utility company.
(5) Office supplies and expenses.
(d) Exclude from this account and charge to account 930.2, Miscellaneous general expenses, the cost of publication of stockholder reports, dividend notices, bond redemption notices, financial statements, and other notices of a general corporate character. Also exclude all expenses of a promotional, institutional, goodwill or political nature, that are included in accounts 913, Advertising expenses (§ 367.9130), 930.1, General advertising expenses (§ 367.9301), and 426.4, Expenditures for certain civic, political, and related expenses (§ 367.4264).
(e) Entries relating to informational advertising included in this account must contain or refer to supporting documents that identify the specific advertising message. If references are used, copies of the advertising message must be readily available.
§ 367.9100 Account 910, Miscellaneous customer service and informational expenses.
(a) This account must include the cost of labor, materials used and expenses incurred in connection with customer service and informational activities that are not includible in other customer information expense accounts.
(b) This account must include the following labor items:
(1) General clerical and stenographic work not assigned to specific customer service and informational programs.
(2) Miscellaneous labor.
(c) This account must include the following materials and expenses items:
(1) Communication service.
(2) Printing, postage and office supplies expenses.
§ 367.9110 Account 911, Supervision.
This account must include the cost of labor and expenses incurred in the general direction and supervision of sales activities, except merchandising. Direct supervision of a specific activity, such as demonstrating, selling, or advertising, must be charged to the account wherein the costs of such activity are included (See Operating Expense Instructions in § 367.80).
§ 367.9120 Account 912, Demonstrating and selling expenses.
(a) This account must include the cost of labor, materials used and expenses incurred in promotional, demonstrating, and selling activities, except by merchandising, the object of which is to promote or retain the business of present and prospective customers of the service company and the companies within the holding company system that is not recorded in Accounts 416, Costs and expenses of merchandising, jobbing and contract work (§ 367.4160), or 930.1, General advertising expenses for associated companies (§ 367.9301).
(b) This account must include the following labor items:
(1) Demonstrating uses of services provided by companies within the holding company system.
(2) Conducting cooking schools, preparing recipes, and related home service activities.
(3) Exhibitions, displays, lectures, and other programs to promote the services provided by the service company or the companies within the holding company system.
(4) Experimental and development work in connection with new and improved appliances and equipment, prior to general public acceptance.
(5) Solicitation of new customers or of additional business from old customers, including commissions paid employees.
(6) Engineering and technical advice to present or prospective customers in connection with promoting or retaining the use of services.
(7) Special customer canvasses when their primary purpose is the retention of business or the promotion of new business.
(c) This account must include the following materials and expenses items:
(1) Supplies and expenses pertaining to demonstration and experimental and development activities.
(2) Booth and temporary space rental.
(3) Loss in value on equipment and appliances used for demonstration purposes.
(4) Transportation, meals, and incidental expenses.
§ 367.9130 Account 913, Advertising expenses.
(a) This account must include the cost of labor, materials used and expenses incurred in advertising designed to promote or retain the use of services provided by the service company or the companies within the holding company system, except advertising the sale of merchandise.
(b) This account must include the following labor items:
(1) Direct supervision of department.
(2) Preparing advertising material for newspapers, periodicals, billboards, and other similar forms of advertisement, and preparing and conducting motion pictures, radio and television programs.
(3) Preparing booklets, bulletins, and other similar forms of advertisement, used in direct mail advertising.
(4) Preparing window and other displays.
(5) Clerical and stenographic work.
(6) Investigating advertising agencies and media and conducting negotiations in connection with the placement and subject matter of sales advertising.
(c) This account must include the following materials and expenses items:
(1) Advertising in newspapers, periodicals, billboards, radio, and other similar forms of advertisement, for sales promotion purposes, but not including institutional or goodwill advertising included in account 930.1, General advertising expenses (§ 367.9301).
(2) Materials and services given as prizes or otherwise in connection with civic lighting contests, canning, or cooking contests, bazaars, and other similar materials and services, in order to publicize and promote the use of utility services.
(3) Fees and expenses of advertising agencies and commercial artists.
(4) Novelties for general distribution.
(5) Postage on direct mail advertising.
(6) Premiums distributed generally, such as recipe books, and other similar items, when not offered as inducement to purchase appliances.
(7) Printing booklets, dodgers, bulletins, and other similar forms of advertisement.
(8) Supplies and expenses in preparing advertising material.
(9) Office supplies and expenses.
(d) The cost of advertisements which set forth the value or advantages of offered services without reference to specific appliances or the promotion of appliances must be considered sales promotion advertising and charged to this account. However, advertisements that are limited to specific makes of appliances sold by any company and prices, terms, and other similar items, without referring to the value or advantages of offered services, must be considered as merchandise advertising and the cost must be charged to account 416, Costs and expenses of merchandising, jobbing and contract work (§ 367.4160).
(e) Advertisements that substantially mention or refer to the value or advantages of offered services, together with specific reference to makes of appliances sold by any company and the price, terms, and other similar items, and designed for the joint purpose of increasing the use of offered services and the sales of appliances, must be considered as a combination advertisement and the costs must be distributed between this account and account 416 (§ 367.4160) on the basis of space, time, or other proportional factors.
(f) Exclude from this account and charge to account 930.2, Miscellaneous general expenses (§ 367.9302), the cost of publication of stockholder reports, dividend notices, bond redemption notices, financial statements, and other notices of a general corporate character. Exclude also all institutional or goodwill advertising (See account 930.1, General advertising expenses (§ 367.9301)).
§ 367.9160 Account 916, Miscellaneous sales expenses.
(a) This account must include the cost of labor, materials used and expenses incurred in connection with sales activities, except merchandising, which are not includible in other sales expense accounts.
(b) This account must include the following labor items:
(1) General clerical and stenographic work not assigned to specific functions.
(2) Special analysis of customer accounts and other statistical work for sales purposes not a part of the regular customer accounting and billing routine.
(3) Miscellaneous labor.
(c) This account must include the following materials and expenses items:
(1) Communication service.
(2) Printing, postage, and office supplies and expenses applicable to sales activities, except those chargeable to account 913, Advertising expenses (§ 367.9130).
§ 367.9200 Account 920, Administrative and general salaries.
(a) This account must include salaries, wages, bonuses and other consideration for services, with the exception of director’s fees paid directly to officers and employees of the service company.
(b) This account must be supported by time records and appropriately referenced to detailed records subdividing salaries and wages by departments or other functional organization units.
§ 367.9210 Account 921, Office supplies and expenses.
(a) This account must include office supplies and expenses incurred in connection with the general administration of service company operations assignable to specific administrative or general departments and not specifically provided for in other accounts. This includes the expenses of the various administrative and general departments, the salaries and wages of which are included in account 920, Administrative and general salaries (§ 367.9200).
(b) This account may be subdivided in accordance with a classification appropriate to the departmental or other functional organization of the service company. The following items must be included in this account:
(1) Automobile service, including charges through clearing account.
(2) Bank messenger and service charges.
(3) Books, periodicals, bulletins and subscriptions to newspapers, newsletters, tax service, and other similar items.
(4) Building service expenses for customer accounts, sales, and administrative and general purposes.
(5) Communication service expenses to include telephone, telegraph, wire transfer, micro-wave, and other similar items.
(6) Cost of individual items of office equipment used by general departments which are of small value or short life.
(7) Membership fees and dues in trade, technical, and professional associations paid by a utility for employees. (Company memberships must be included in account 930.2 in § 367.9302.)
(8) Office supplies and expenses.
(9) Payment of court costs, witness fees, and other expenses of legal department.
(10) Postage, printing and stationery.
(11) Meals, traveling, entertainment and incidental expenses.
(c) Records must be so maintained to permit ready analysis by item showing the nature of the expense and identity of the person furnishing the service.
§ 367.9230 Account 923, Outside services employed.
(a) This account must include the fees and expenses of professional consultants and others for general services with the exception of fees and expenses for outside services of account 928, Regulatory commission expenses (§ 367.9280), and account 930.1, General advertising expenses (§ 367.9301). Separate subaccounts must be provided for auditing, legal, engineering, management consulting fees and any other fees for professional or outside services.
(b) Records must be maintained so as to permit ready analysis showing the nature of service, identity of the person furnishing the service, affiliation to the service company, and, if allocated to more than one company, the specific method of allocation.
§ 367.9240 Account 924, Property insurance.
(a) This account must include the cost of insurance or reserve accruals to protect the service company against losses and damages to owned or leased property used in service company operations. It also must include the cost of labor and related supplies and expenses incurred in property insurance activities.
(b) Recoveries from insurance companies or others for property damages must be credited to the account charged with the cost of the damage. If the damaged property has been retired, the credit must be to the appropriate account for accumulated provision for depreciation.
(c) Records must be kept so as to show the amount of coverage for each class of insurance carried, the property covered, and the applicable premiums. Any dividends distributed by mutual insurance companies must be credited to the accounts to which the insurance premiums were charged. The following items must be included in this account:
(1) Premiums payable to insurance companies for fire, storm, burglary, boiler explosion, lightning, fidelity, riot, and similar insurance.
(2) Special costs incurred in procuring insurance.
(3) Insurance inspection service.
(4) Insurance counsel, brokerage fees, and expenses.
(d) The cost of insurance or reserve accruals capitalized must be charged to construction either directly or by transfer to construction projects from this account.
(e) The cost of insurance or reserve accruals for the following classes of property must be charged as indicated.
(1) Materials and supplies and stores equipment, to account 163, Stores expense undistributed (§ 367.1630), or appropriate materials account.
(2) Transportation and other general equipment to appropriate clearing accounts that may be maintained.
(3) Merchandise and jobbing property, to account 416, Costs and expenses of merchandising, jobbing and contract work (§ 367.4160).
(f) The cost of labor and related supplies and expenses of administrative and general employees who are only incidentally engaged in property insurance work may be included in accounts 920 and 921 (§§ 367.9200 and 367.9210), as appropriate.
§ 367.9250 Account 925, Injuries and damages.
(a) This account must include the cost of insurance or reserve accruals to protect the service company against injuries and damages claims of employees or others, losses of such character not covered by insurance, and expenses incurred in settlement of injuries and damages claims. It also must include the cost of labor and related supplies and expenses incurred in injuries and damages activities.
(b) Reimbursements from insurance companies or others for expenses charged to this account because of injuries and damages and insurance dividends or refunds must be credited to this account. The following items must be included in this account:
(1) Premiums payable to insurance companies for protection against claims from injuries and damages by employees or others, such as public liability, property damages, casualty, employee liability, and other similar items.
(2) Losses not covered by insurance or reserve accruals on account of injuries or deaths to employees or others and damages to the property of others.
(3) Fees and expenses of claim investigators.
(4) Payment of awards to claimants for court costs and attorneys’ services.
(5) Medical and hospital service and expenses for employees as the result of occupational injuries, or resulting from claims of others.
(6) Compensation payments under workmen’s compensation laws.
(7) Compensation paid while incapacitated as the result of occupational injuries (See paragraph (c) of this section).
(8) Cost of safety, accident prevention and similar educational activities.
(c) Payments to or on behalf of employees for accident or death benefits, hospital expenses, medical supplies or for salaries while incapacitated for service or on leave of absence beyond periods normally allowed, when not the result of occupational injuries, must be charged to account 926, Employee pensions and benefits (§ 367.9260) (See also paragraph (e) of account 926 (§ 367.9260)).
(d) The cost of injuries and damages or reserve accruals capitalized must be charged to construction directly or by transfer to construction projects from this account.
(e) Exclude the time and expenses of employees (except those engaged in injuries and damages activities) spent in attendance at safety and accident prevention educational meetings, if occurring during the regular work period.
(f) The cost of labor and related supplies and expenses of administrative and general employees who are only incidentally engaged in injuries and damages activities may be included in accounts 920 and 921 (§§ 367.9200 and 367.9210), as appropriate.
§ 367.9260 Account 926, Employee pensions and benefits.
(a) This account must include pensions paid to, or on behalf of, retired employees, or accruals to provide for pensions, or payments for the purchase of annuities for this purpose, when the service company has definitely, by contract, committed itself to a pension plan under which the pension funds are irrevocably devoted to pension purposes, and payments for employee accident, sickness, hospital, and death benefits, or insurance related to this account. Include, also, expenses incurred in medical, educational or recreational activities for the benefit of employees, and administrative expenses in connection with employee pensions and benefits.
(b) The service company must maintain a complete record of accruals or payments for pensions and be prepared to furnish full information to the Commission of the plan under which it has created or proposes to create a pension fund and a copy of the declaration of trust or resolution under which the pension plan is established.
(c) Records in support of this account must be kept so that the total pensions expense, the total benefits expense, the administrative expenses included in this account, and the amounts of pensions and benefits expenses transferred to construction or other accounts will be readily available. The following items must be included in this account:
(1) Payment of pensions under a non-accrual or non-funded basis.
(2) Accruals for or payments to pension funds or to insurance companies for pension purposes.
(3) Group and life insurance premiums (credit dividends received).
(4) Payments for medical and hospital services and expenses of employees when not the result of occupational injuries.
(5) Payments for accident, sickness, hospital, and death benefits or insurance.
(6) Payments to employees incapacitated for service or on leave of absence beyond periods normally allowed, when not the result of occupational injuries, or in excess of statutory awards.
(7) Expenses in connection with educational and recreational activities for the benefit of employees.
(d) The cost of labor and related supplies and expenses of administrative and general employees who are only incidentally engaged in employee pension and benefit activities may be included in accounts 920 and 921 (§§ 367.9200 and 367.9210), as appropriate.
(e) Salaries paid to employees during periods of non-occupational sickness may be charged to the appropriate labor account rather than to employee benefits.
§ 367.9280 Account 928, Regulatory commission expenses.
(a) This account must include all expenses, properly included in service company operating expenses, incurred by the service company in connection with formal cases before regulatory commissions, or other regulatory bodies, on its own behalf or on behalf of associate companies, including payments made to a regulatory commission for fees assessed to the service company for pay and expenses of such commission, its officers, agents and employees, and for filings or reports made under regulations of regulatory commissions. The service company must be prepared to show the cost of each formal case. The following items must be included in this account:
(1) Salaries, fees, retainers, and expenses of counsel, solicitors, attorneys, accountants, engineers, clerks, attendants, witnesses, and others engaged in the prosecution of, or defense against petitions or complaints presented to regulatory bodies.
(2) Office supplies and expenses, payments to public service or other regulatory commissions, stationery and printing, traveling expenses, and other expenses incurred directly in connection with formal cases before regulatory commissions.
(b) Exclude from this account and include in other appropriate operating expense accounts, expenses incurred in the improvement of service, additional inspection, or rendering reports, which are made necessary by the rules and regulations, or orders, of regulatory bodies.
§ 367.9301 Account 930.1, General advertising expenses for associated companies.
(a) This account must include the cost of labor, materials used, and expenses incurred in advertising and related activities, the cost of which by their content and purpose are not provided for elsewhere.
(b) This account must include the following labor items:
(1) Supervision.
(2) Preparing advertising material for newspapers, periodicals, billboards, and other similar items, and preparing or conducting motion pictures, radio and television programs.
(3) Preparing booklets, bulletins, and other similar forms of advertisement, used in direct mail advertising.
(4) Preparing window and other displays.
(5) Clerical and stenographic work.
(6) Investigating and employing advertising agencies, selecting media and conducting negotiations in connection with the placement and subject matter of advertising.
(c) This account must include the following materials and expenses items:
(1) Advertising in newspapers, periodicals, billboards, radio, and other similar forms of advertisement.
(2) Advertising matter such as posters, bulletins, booklets, and related items.
(3) Fees and expenses of advertising agencies and commercial artists.
(4) Postage and direct mail advertising.
(5) Printing of booklets, dodgers, bulletins, and other related items.
(6) Supplies and expenses in preparing advertising materials.
(7) Office supplies and expenses.
(d) Properly includible in this account is the cost of advertising activities on a local or national basis of a good will or institutional nature, which is primarily designed to improve the image of the associate utility company or the industry, including advertisements which inform the public concerning matters affecting the associate utility company’s operations, such as, the cost of providing service, the associate utility company’s efforts to improve the quality of service, the company’s efforts to improve and protect the environment, and other similar forms of advertisement. Entries relating to advertising included in this account must contain or refer to supporting documents which identify the specific advertising message. If references are used, copies of the advertising message must be readily available.
(e) Exclude from this account and include in account 426.4, Expenditures for certain civic, political and related activities (§ 367.4264), expenses for advertising activities that are designed to solicit public support or the support of public officials in matters of a political nature.
§ 367.9302 Account 930.2, Miscellaneous general expenses.
(a) This account must include the cost of expenses incurred in connection with the general management of the service company not provided for elsewhere.
(b) This account must include labor items including miscellaneous labor not elsewhere provided for.
(c) This account must include the following expenses items:
(1) Industry association dues for company memberships.
(2) Contributions for conventions and meetings of the industry.
(3) Research, development, and demonstration expenses not charged to other operation and maintenance expense accounts on a functional basis.
(4) Communication service not chargeable to other accounts.
(5) Trustee, registrar, and transfer agent fees and expenses.
(6) Stockholders meeting expenses.
(7) Dividend and other financial notices.
(8) Printing and mailing dividend checks.
(9) Directors’ fees and expenses.
(10) Publishing and distributing annual reports to stockholders.
(11) Public notices of financial, operating and other data required by regulatory statutes, not including, however, notices required in connection with security issues or acquisitions of property.
(d) Records must be maintained so as to permit ready analysis by item showing the nature of the expense and identity of the person furnishing the service.
§ 367.9310 Account 931, Rents.
This account must include rents, including taxes, paid for the property of others used, occupied or operated in connection with service company functions. Provide subaccounts for major groupings such as office space, warehouses, other structure, office furniture, fixtures, computers, data processing equipment, microwave and telecommunication equipment, airplanes, automobiles, and other similar groupings of property. The cost, when incurred by the lessee, of operating and maintaining leased property, must be charged to the accounts appropriate for the expense as if the property were owned.
§ 367.9350 Account 935, Maintenance of structures and equipment.
This account must include materials used and expenses incurred in the maintenance of property owned, the cost of which is included in accounts 390 through 399 (§§ 367.3900 through 367.3990), and of property leased from others. Provide subaccounts by major classes of structures and equipment, owned and leased.
PART 368—PRESERVATION OF RECORDS OF HOLDING COMPANIES AND SERVICE COMPANIES
§ 368.1 Promulgation.
This part is prescribed and promulgated as the regulations governing the preservation of records by any holding company and by any service company within a holding company system subject to the jurisdiction of the Commission under the Public Utility Holding Company Act of 2005 (42 U.S.C. §§ 16451 et seq.).
§ 368.2 General instructions.
(a) Scope of this part. (1) The regulations in this part apply to all books of account and other records prepared, maintained or held by any agent or employee on behalf of the company. The specification in the schedule in § 368.3 of a record related to a type of transaction includes all documents and correspondence, not redundant or duplicative of other records retained, needed to explain or verify the transaction.
(2) Company means a service company or a holding company as defined in § 367.1 of this chapter. Public utilities, licensees, and natural gas companies must continue to use parts 125 and 225 of this chapter.
(3) Any company subject to this regulation, that, as agent, operator, lessor or otherwise, maintains or has possession of any records relating to the operation, property or obligations of a public utility, licensee, or natural gas company, as defined in the Federal Power Act (16 U.S.C. §§ 824 et seq.), the Natural Gas Act (15 U.S.C. §§ 717 et seq.), or the laws of any state within which the public utility, licensee, or natural gas company operates, must comply with the laws or regulations as to record retention and destruction which would apply to the records if they were records of the public utility, licensee, or natural gas company as codified in parts 125 and 225 of this chapter.
(4) The regulations in this part should not be construed as excusing compliance with other lawful requirements of any other governmental body, Federal or State, prescribing other record keeping requirements or for preservation of records longer than those prescribed in this part.
(5) To the extent that any Commission regulations may provide for a different record retention period, the records must be retained for the longer of the retention periods.
(6) Records, other than those listed in the schedule, may be destroyed at the option of the company. However, records that are used in lieu of those listed must be preserved for the periods prescribed for the records used for substantially similar purposes. Additionally, retention of records pertaining to added services, functions, plant, and other similar service, the establishment of which cannot be presently foreseen, must conform to the principles embodied in this section.
(7) Notwithstanding the provisions of the records retention schedule in this section, the Commission may, upon the request of the company, authorize a shorter period of retention for any record listed in the schedule upon a showing by the company that preservation of the record for a longer period is not necessary or appropriate, in the public interest or for the protection of investors or consumers.
(b) Designation of supervisory official. Each company subject to these record retention regulations must designate one or more officials to supervise the preservation or authorized destruction of its records.
(c) Protection and storage of records. The company must provide reasonable protection from damage by fire, flood, and other hazards for records required by these record retention regulations to be preserved and, in the selection of storage space, safeguard such records from unnecessary exposure to deterioration from excessive humidity, dryness, or lack of proper ventilation.
(d) Index of records. At each site or location where company records are kept or stored, the records must be arranged, filed, and currently indexed so that records may be readily identified and made available for inspection by authorized representatives of any regulatory agency concerned, including the Commission.
(e) Record storage media. Each company has the flexibility to select its own storage media subject to the following conditions.
(1) The storage media must have a life expectancy at least equal to the applicable record retention period provided in § 368.3 of this chapter unless there is a quality transfer from one media to another with no loss of data.
(2) Each company is required to implement internal control procedures that assure the reliability of, and ready access to, data stored on machine readable media. Internal control procedures must be documented by a responsible supervisory official.
(3) Each transfer of data from one media to another must be verified for accuracy and documented. Software and hardware required to produce readable records must be retained for the same period the media format is used.
(f) Destruction of records. At the expiration of the retention period, the company may use any appropriate method to destroy records. Precautions should be taken, however, to macerate or otherwise destroy the legibility of records, the content of which is forbidden by law to be divulged to unauthorized persons.
(g) Premature destruction or loss of records. When records are destroyed or lost before the expiration of the prescribed period of retention, a certified statement listing, as far as may be determined, the records destroyed and describing the circumstances of accidental or other premature destruction or loss must be filed with the Commission within 90 days from the date of discovery of the destruction.
(h) Schedule of records and periods of retention. The schedule of records retention periods constitutes a part of these records retention regulations. The schedule prescribes the periods of time that designated records must be preserved. Plant records related to public utilities and licensees and natural gas companies must be retained in accordance with §§ 125.3 and 225.3 of this chapter.
(i) Retention periods designated “Destroy at option.” “Destroy at option” constitutes authorization for destruction of records at managements’ discretion if the destruction does not conflict with other legal retention requirements or usefulness of the records in satisfying pending regulatory actions or directives. “Destroy at option after audit” requires retention until the company has received an opinion from its independent accountants with respect to the financial statements including the transactions to which the records relate.
(j) Records of services performed by associate companies. Holding companies and service companies must assure the availability of records of services performed by and for public utilities and licensees and natural gas companies with supporting cost information for the periods indicated in §§ 125.3 and 225.3 of this chapter as necessary to be able to readily furnish detailed information as to the nature of the transaction, the amounts involved, and the accounts used to record the transactions.
(k) Rate case. Notwithstanding the minimum retention periods provided in these regulations, the company must retain the appropriate records to support the costs and adjustments proposed in any rate case.
(l) Pending complaint litigation or governmental proceedings. Notwithstanding the minimum requirements, if a company is involved in pending litigation, complaint procedures, proceedings remanded by the court, or governmental proceedings, it must retain all relevant records.
(m) Life or mortality study data. Life or mortality study data for depreciation purposes must be retained for 25 years or for 10 years after property is retired, whichever is longer.
§ 368.3 Schedule of records and periods of retention.
Schedule of Records and Periods of Retention
| Item No. and description | Retention period |
|---|---|
| 1. Reports to stockholders: Annual reports or statements to stockholders | 5 years. |
| 2. Organizational documents: | |
| (a) Minute books of stockholders, directors’ and directors’ committee meetings | 5 years or termination of the corporation’s existence, whichever occurs first. |
| (b) Title, franchises, and licenses: Copies of formal orders of regulatory commissions served upon the company | 6 years after final non-appealable order. |
| (1) Certificates of incorporation, or equivalent agreements and amendments thereto | Life of corporation. |
| (2) Deeds, leases and other title papers (including abstracts of title and supporting data), and contracts and agreements related to the acquisition or disposition of property or investments | 6 years after property or investment is disposed of unless delivered to transferee. |
| 3. Contracts and agreements: Contracts, including amendments and agreements (except contracts provided for elsewhere): | |
| (a) Service contracts, such as for management, consulting, accounting, legal, financial or engineering services | All contracts, related memoranda, and revisions should be retained for 4 years after expiration or until the conclusion of any contract disputes pertaining to such contracts, whichever is later. |
| (b) Memoranda essential to clarify or explain provisions of contracts and agreements | For same period as contract to which they relate. |
| (c) Card or book records of contracts, leases, and agreements made, showing dates of expirations and of renewals, memoranda of receipts, and payments under such contracts | For the same periods as contracts to which they relate. |
| (d) Contracts and other agreements relating to services performed in connection with construction of property (including contracts for the construction of property by others for the company and for supervision and engineering relating to construction work) | All contracts, related memoranda, and revisions should be retained for 4 years after expiration or until the conclusion of any contract disputes or governmental proceedings pertaining to such contracts, whichever is later. |
| 4. Accountants’ and auditors’ reports: | |
| (a) Reports of examinations and audits by accountants and auditors not in the regular employ of the company (such as reports of public accounting firms and commission accountants) | 5 years after the date of the report. |
| (b) Internal audit reports and working papers | 5 years after the date of the report. |
| 5. Automatic data processing records (retain original source data used as input for data processing and data processing report printouts for the applicable periods prescribed elsewhere in the schedule): Software program documentation and revisions thereto | Retain as long as it represents an active viable program or for periods prescribed for related output data, whichever is shorter. |
| 6. General and subsidiary ledgers: | |
| (a) Ledgers: | |
| (1) General ledgers | 10 years. |
| (2) Ledgers subsidiary or auxiliary to general ledgers except ledgers provided for elsewhere | 10 years. |
| (b) Indexes: | |
| (1) Indexes to general ledgers | 10 years. |
| (2) Indexes to subsidiary ledgers except ledgers provided for elsewhere | 10 years. |
| (c) Trial balance sheets of general and subsidiary ledgers | 2 years |
| 7. Journals: General and subsidiary | 10 years. |
| 8. Journal vouchers and journal entries including supporting detail: | |
| (a) Journal vouchers and journal entries | 10 years. |
| (b) Analyses, summarization, distributions, and other computations which support journal vouchers and journal entries: | |
| (1) Charging property accounts | 25 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies. |
| (2) Charging all other accounts | 6 years. |
| 9. Cash books: General and subsidiary or auxiliary books | 5 years after close of fiscal year. |
| 10. Voucher registers: Voucher registers or similar records when used as a source document | 5 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies. |
| 11. Vouchers: | |
| (a) Paid and canceled vouchers (one copy-analysis sheets showing detailed distribution of charges on individual vouchers and other supporting papers | 5 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies. |
| (b) Original bills and invoices for materials, services, etc., paid by vouchers | 5 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies. |
| (c) Paid checks and receipts for payments of specific vouchers | 5 years. |
| (d) Authorization for the payment of specific vouchers | 5 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies. |
| (e) Lists of unaudited bills (accounts payable), list of vouchers transmitted, and memoranda regarding changes in audited bills | Destroy at option. |
| (f) Voucher indexes | Destroy at option. |
| (g) Purchases and stores records related to disbursement vouchers | 5 years. |
| 12. Insurance records: | |
| (a) Records of insurance policies in force, showing coverage, premiums paid, and expiration dates | Destroy at option after expiration of such policies. |
| (b) Records of amounts recovered from insurance companies in connection with losses and of claims against insurance companies, including reports of losses, and supporting papers | 6 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies. |
| (c) Records of self-insurance against: | |
| (1) losses from fire and casualty, | 6 years after date of last accounting entry with respect thereto. |
| (2) damage to property of others, and | 6 years after date of last accounting entry with respect thereto. |
| (3) personal injuries | 6 years after date of last accounting entry with respect thereto. |
| (d) Inspectors’ reports and reports of condition of property | Destroy when superseded. |
| 13. Maintenance project and work orders: | |
| (a) Authorizations for expenditures for maintenance work to be covered by project or work orders, including memoranda showing the estimates of costs to be incurred | 5 years. |
| (b) Project or work order sheets to which are posted in detail the entries for labor, material, and other charges in connection with maintenance, and other work pertaining to company operations | 5 years. |
| (c) Summaries of expenditures on maintenance and job orders and clearances to operating other accounts (exclusive of property accounts) | 5 years. |
| 14. Property records, excluding documents included in Item 2(a)(2): | |
| (a) Ledgers of property accounts including land and other detailed ledgers showing the cost of property by classes | 25 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies. |
| (b) Continuing property inventory ledger, book or card records showing description, location, quantities, cost, etc., of physical units (or items) of property owned | 25 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies. |
| (c) Operating equipment records | 3 years after disposition, termination of lease, or write-off of property or investment. |
| (d) Office furniture and equipment records | 3 years after disposition, termination of lease or write-off of property or investment. |
| (e) Automobiles, other vehicles and related garage equipment records | 3 years after disposition, termination of lease or write-off of property or investment. |
| (f) Aircraft and airport equipment records | 3 years after disposition, termination of lease or write-off of property or investment. |
| (g) Other property records not defined elsewhere | 3 years after disposition, termination of lease or write-off of property or investment. |
| 15. Construction work in progress ledgers, project or work orders, and supplemental records: | |
| (a) Construction work in progress ledgers | 5 years after clearance to property account, provided continuing inventory records are maintained; otherwise 5 years after property is retired. |
| (b) Project or work orders sheets to which are posted in summary form or in detail the entries for labor, materials, and other charges for property additions and the entries closing the project or work orders to property records at completion | 5 years after clearance to property account, provided continuing inventory records are maintained; otherwise 5 years after property is retired. |
| (c) Authorizations for expenditures for additions to property, including memoranda showing the detailed estimates of cost, and the bases therefore (including original and revised or subsequent authorizations) | 5 years after clearance to property account. |
| (d) Requisitions and registers of authorizations for property expenditures | 5 years after clearance to property account. |
| (e) Completion or performance reports showing comparison between authorized estimates and actual expenditures for property additions | 5 years after clearance to property account. |
| (f) Analysis or cost reports showing quantities of materials used, unit costs, number of man-hours etc., in connection with completed construction project | 5 years after clearance to property account. |
| (g) Records and reports pertaining to progress of construction work, the order in which jobs are to be completed, and similar records which do not form a basis of entries to the accounts | Destroy at option. |
| 16. Retirement work in progress ledgers, project or work orders, and supplemental records: | |
| (a) Project or work order sheets to which are posted the entries for removal costs, materials recovered, and credits to property accounts for cost of property retirement | 5 years after the property is retired. |
| (b) Authorizations for retirement of property, including memoranda showing the basis for determination to be retired and estimates of salvage and removal costs | 5 years after the property is retired. |
| (c) Registers of retirement work | 5 years. |
| 17. Summary sheets, distribution sheets, reports, statements, and papers directly supporting debits and credits to property accounts not covered by construction or retirement project or work orders and their supporting records | 5 years. |
| 18. Appraisals and valuations: | |
| (a) Appraisals and valuations made by the company of its properties or investments or of the properties or investments of any associated companies. (Includes all records essential thereto.) | 3 years after appraisal. |
| (b) Determinations of amounts by which properties or investments of the company or any of its associated companies will be either written up or written down as a result of: | |
| (1) Mergers or acquisitions | 10 years after completion of transaction or as ordered by the Commission. |
| (2) Asset impairments | 10 years after recognition of asset impairment. |
| (3) Other bases | 10 years after the asset was written up or down. |
| 19. Production maps, geological maps, reproductions, including aerial photographs, showing the location of all facilities the subject matter of which falls within the project or work orders of the company | 6 years after completion of project or work order. |
| 20. Engineering records, drawings, supporting data to include diagrams, profiles, photographs, field-survey notes, plot plans, detail drawings, and records of engineering studies that are part of or performed by the company within the project or work order system | 6 years after completion of project or work order. |
| 21. Records of building space occupied by various departments of the company | 6 years. |
| 22. Contracts relating to property: | |
| (a) Contracts relating to acquisition or sale of property | 6 years after property is retired or sold |
| (b) Contracts and other agreements relating to services performed in connection with construction of property (including contracts for the construction of property by others for the company and for supervision and engineering relating to construction work) | 6 years after property is retired or sold. |
| 23. Records pertaining to reclassification of property accounts to conform to prescribed systems of accounts including supporting papers showing the bases for such reclassifications | 6 years. |
| 24. Records of accumulated provisions for depreciation and depletion of property and amortization of intangible property and supporting computation of expense: | |
| (a) Detailed records or analysis sheets segregating the accumulated depreciation according to the classification of property | 3 years after retirement or disposition of property |
| (b) Records reflecting the service life of property and the percentage of salvage and cost of removal for property retired from each account for depreciable company property | 3 years after retirement or disposition of property |
| 25. Investment records: | |
| (a) Records of investment in associate companies | 3 years after disposition of investment. |
| (b) Records of other investments, including temporary investments of cash | 3 years after disposition of investment. |
| 26. Procurement: | |
| (a) Agreements entered into for the acquisition of goods or the performance of services. Includes all forms of agreements such as but not limited to: Letters of intent, exchange of correspondence, master agreements, term contracts, rental agreements, and the various types of purchase orders: | |
| (1) For goods or services relating to property construction | 6 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies. |
| (2) For other goods or services | 6 years. |
| (b) Supporting documents including accepted and unaccepted bids or proposals (summaries of unaccepted bids or proposals may be kept in lieu of originals) evidencing all relevant elements of the procurement | 6 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies. |
| 27. Material ledgers: Ledger sheets of materials and supplies received, issued, and on hand | 6 years after the date the records/ledgers were created. |
| 28. Materials and supplies received and issued: Records showing the detailed distribution of materials and supplies issued during accounting periods | 6 years. See §§ 125.2(g) and 225.2(g) of this chapter for public utilities and licensees and natural gas companies). |
| 29. Miscellaneous billing data: Billing department’s copies of contracts with customers (other than contracts in general files) | 5 years. |
| 30. Revenue summaries: Summaries of monthly revenues according to classes of service. Including summaries of forfeited discounts and penalties | 5 years. |
| 31. Tax records: | |
| (a) Copies of tax returns and supporting schedules filed with taxing authorities, supporting working papers, records of appeals of tax bills, and receipts for payment. See Item 11 for vouchers evidencing disbursements: | |
| (1) Income tax returns | 2 years after final tax liability is determined. |
| (2) Agreements between and schedule of allocation by associate companies of consolidated Federal income taxes | 2 years after final tax liability is determined. |
| (b) Other taxes, including State or local property or income taxes | |
| (1) Property tax returns | 2 years after final tax liability is determined. |
| (2) Sales and other use taxes | 2 years. |
| (3) Other Taxes | 2 years after final tax liability is determined. |
| (c) Filings with taxing authorities to qualify employee benefit plans | 5 years after discontinuance of plan. |
| (d) Information returns and reports to taxing authorities | 3 years after final tax liability is determined. |
| 32. Statements of funds and deposits: | |
| (a) Summaries and periodic statements of cash balances on hand and with depositories for company or associate | Destroy at option after completion of audit by independent accountants. |
| (b) Requisitions and receipts for funds furnished associates and others | Destroy at option after funds have been returned or accounted for. |
| (c) Statements of periodic deposits with external fund administrators or trustees | Retain records for the most recent 3 years. |
| (d) Statements of periodic withdrawals from external fund | Retain records for the most recent 3 years. |
| 33. Records of deposits with banks and others: | |
| (a) Statements from depositories showing the details of funds received, disbursed, transferred, and balances on deposit, bank reconcilement papers and statements of interest credits | Destroy at option after completion of audit by independent accountants. |
| (b) Check stubs, registers, or other records of checks issued | 6 years. |
| 34. Payroll records: | |
| (a) Payroll sheets or registers of payments of salaries and wages, pensions and annuities paid by company or by contractors of its account | 6 years. |
| (b) Records showing the distribution of salaries and wages paid for each payroll period and summaries or recapitulations of such distribution | 6 years. |
| 35. Financial, operating and statistical annual reports regularly prepared in the course of business for internal administrative or operating purposes | 5 years. |
| 36. Budgets and other forecasts (prepared for internal administrative or operating purposes) of estimated future income, receipts and expenditures in connection with financing, construction and operations, including acquisitions and disposals of properties or investments | 3 years. |
| 37. Periodic or special reports filed by the company on its own behalf with the Commission or with any other Federal or State rate-regulatory agency, including exhibits or amendments to such reports: | |
| (a) Reports to Federal and State regulatory commissions including annual financial, operating and statistical reports | 5 years. |
| (b) Monthly and quarterly reports of operating revenues, expenses, and statistics | 5 years. |
| 38. Advertising: Copies of advertisements by or for the company on behalf of itself or any associate company in newspapers, magazines, and other publications, including costs and other records relevant thereto (excluding advertising of appliances, employment opportunities, routine notices, and invitations for bids all of which may be destroyed at option) | 2 years. |
PART 369—STATEMENTS AND REPORTS (SCHEDULES)
§ 369.1 FERC Form No. 60, Annual report of centralized service company.
(a) Prescription. The form of annual report for centralized service companies, designated as FERC Form No. 60, is prescribed for the reporting year 2008 and each subsequent year.
(b) Filing requirements—(1) Who must file. Unless the holding company system is exempted or granted a waiver by Commission rule or order pursuant to §§ 366.3 and 366.4, every centralized service company (See § 367.2 of this chapter) in a holding company system must prepare and file electronically with the Commission the FERC Form No. 60 then in effect pursuant to the General Instructions set out in the form.
(2) When to file and what to file. (i) The annual report for the year ending December 31, 2008 must be filed by May 1, 2009. The annual report for each year thereafter must be filed by May 1 of the following years.
(ii) The annual report in effect must be filed with the Commission as prescribed in § 385.2011 of this chapter and as indicated in the General Instructions set out in the form, and must be properly completed and verified. Filing on electronic media pursuant to § 385.2011 of this chapter is required.
SUBCHAPTER W—REVISED GENERAL RULES
PART 375—THE COMMISSION
Subpart A—General Provisions
§ 375.101 The Commission.
(a) Establishment. The Federal Energy Regulatory Commission is an independent regulatory commission within the Department of Energy established by section 401 of the DOE Act.
(b) Offices. The principal office of the Commission is at 888 First Street, NE., Washington, DC 20426. Regional offices are maintained at Atlanta, GA, Chicago, IL, Portland, OR, New York, NY, and San Francisco, CA.
(c) Hours. Unless the Chairman otherwise directs, the offices of the Commission are open each day, except Saturdays, Sundays, and Holidays, from 8:30 a.m. to 5:00 p.m.
(d) Sessions. The Commission may meet and exercise its powers at any place in the United States. The time and place of meetings of the Commission are announced in advance as provided in § 375.204.
(e) Quorum. A quorum for the transaction of business consists of at least three members present.
(f) Action by Commissioners or representatives. The Commission may, by one or more of its members or by such agents as it may designate, conduct any hearing, or other inquiry necessary or appropriate to its functions, except that nothing in this paragraph supersedes the provisions of section 556, of Title 5, United States Code relating to Administrative Law Judges.
§ 375.102 Custody and authentication of Commission records.
(a) Custody of official records. The Senior Agency Official for Records shall have legal custody of all records of the Commission. The individual Commission office that maintains a record shall have physical custody of that record.
(b) Authentication of action. All orders and other actions of the Commission shall be authenticated by the Secretary or the Secretary’s designee, with the exception of actions taken pursuant to delegations of authority under 18 CFR part 375, subpart C, which will be authenticated by the issuing official. Issuances posted on the Commission’s electronic filing system on the Commission’s website are authenticated.
§ 375.103 Official seal.
The Commission hereby prescribes as its official seal, judicial notice of which shall be taken pursuant to section 401(e) of the DOE Act, the imprint illustrated below and described as follows:
A circle, the outside border of which shall consist of two concentric circles enclosing the words “Department of Energy” and “Federal Energy Regulatory Commission.” Within the inner circle shall appear a stylized eagle with head facing to its right. Its body shall be in the shape of a tapered shield, widest at the top, consisting of nine vertical stripes. The top of the shield contains five equally-spaced light color stars representing the five members of the Commission appointed by the President under Title IV of the DOE Act. Identical stylized wings appear on either side of the shield, each incorporating twenty stylized feathers protruding from a solid color wing-like shape. Below the eagle shall appear five squares, arranged in a horizontal line. Each of these squares shall contain a circle representing an area of the Commission’s responsibility. The first square at the left of the line shall include a stylized representation of a pipeline; the second square shall represent a hydroelectric power facility; the third, and center square, shall represent a natural gas flame; the fourth square shall represent a drilling rig; the fifth square shall represent a stylized lightning bolt.
§ 375.104 Transfer of proceedings from other agencies to the Commission.
(a) Transfer of pending proceedings. Pursuant to the authorization provided in section 705(b)(2), and the provisions of section 705(b)(1) of the DOE Act, all proceedings and applications pending at the time such Act took effect, before any department, agency, commission, or component thereof, the functions of which have been transferred to the Commission by the Act, have been transferred in accordance with the joint regulations issued by the Commission and the Secretary of Energy on October 1, 1977. Those joint regulations appear as an appendix to this section.
(b) Substitution of Commission for other agencies in court proceedings. Pursuant to section 705(e) of the DOE Act, the Commission authorizes the Solicitor of the Commission to file the appropriate pleadings to substitute the Commission for the Interstate Commerce Commission or the Federal Power Commission as necessary in any pending court litigation, responsibility for which is transferred to the Commission.
(a) Scope.This part establishes the transfer of proceedings pending with regard to those functions of various agencies which have been consolidated in the Department of Energy and identifies those proceedings which are transferred into the jurisdiction of the Secretary and those which are transferred into the jurisdiction of the Federal Energy Regulatory Commission.
(b) Proceedings transferred to the Secretary. The following proceedings are transferred to the Secretary:
(1) All Notices of Proposed Rulemaking, pending and outstanding, which have been proposed by the Department of Energy;
(2) All Notices of Inquiry which have been issued by the Department of Energy;
(3) All Requests for Interpretations which have been filed pursuant to 10 CFR part 205, subpart F, and on which no interpretation has been issued, with the Office of General Counsel of the Department of Energy;
(4) All Applications for Exception Relief which have been filed pursuant to 10 CFR part 205, subpart D, and on which no final decision and order has been issued, with the Office of Exceptions and Appeals of the Department of Energy;
(5) All petitions for special redress, relief or other extraordinary assistance which have been filed pursuant to 10 CFR part 205, subpart R, and on which no order has been issued, with the Office of Private Grievances and Redress of the Department of Energy;
(6) All appeals from Remedial Orders, Exception Decisions and Orders, Interpretations issued by the Office of General Counsel, and other agency orders which have been filed pursuant to 10 CFR part 205, subpart H, and on which no order has been issued prior to October 1, 1977, with the Office of Exceptions and Appeals of the Department of Energy;
(7) All applications for modification or rescission of any DOE order or interpretation which have been filed pursuant to 10 CFR part 205, subpart J, and on which no order has been issued prior to October 1, 1977, with the Office of Exceptions and Appeals of the Federal Energy Administration;
For a document relating to procedures for natural gas import and export proceedings see 42 FR 61856, Dec. 7, 1977.
(8) All applications for temporary stays and stays which have been filed pursuant to 10 CFR part 205, subpart I, and on which no order has been issued, with the Office of Exceptions and Appeals of the Department of Energy;
(9) All applications which have been filed with the Office of Regulatory Programs of the Department of Energy and on which no final order has been issued;
(10) All investigations which have been instituted and have not been resolved by the Office of Compliance of the Department of Energy;
(11) All Notices of Probable Violation which have been issued prior to October 1, 1977, by the Office of Compliance of Department of Energy;
(12) All Notices of Proposed Disallowance which have been issued prior to October 1, 1977, by the Office of Compliance of Department of Energy;
(13) All Prohibition Orders which have been issued pursuant to 10 CFR part 303 and as to which no Notice of Effectiveness has been issued;
(14) From the Department of the Interior:
(i) The tentative power rate adjustments for the Central Valley Project, California, proposed on September 12, 1977 (42 FR 46619, September 16, 1977).
(15) From the Interstate Commerce Commission:
(i) Ex Parte No. 308 (Sub-No. 1)—Investigation of Common Carrier Pipelines.
(16) From the Federal Power Commission:
(i) Cases:
(A) Northwest Pipeline Corporation, Docket No. CP75–340.
(B) Midwestern Gas Transmission Co., Docket No. CP77–458, et al.
(C) St. Lawrence Gas Company, Docket No. G–17500.
(D) U.S.D.I. Bonneville Power Administration, Docket No. E–9563.
(E) U.S.D.I. Southwestern Power Administration, Docket No. E–7201.
(F) U.S.D.I. Southeastern Power Administration, Docket No. E–6957.
(G) Tenneco InterAmerica, Inc., Docket No. CP77–561.
(ii) Applications:
(A) Maine Public Service Co., Docket No. E–6751, (ERA Docket No. IE–78–1).
(B) Northern States Power Co., Docket No. E–9589, (ERA Docket No. IE–78–2).
(C) Arizona Public Service Co., Docket No. IT–5331, (ERA Docket No. IE–78–3).
(D) Niagara Mohawk Power Corp., Docket No. E–7022, (ERA Docket No. IE–77–6).
(E) Maine Public Service Co., Docket No. IT–6027, (ERA Docket No. PP–12).
(F) Boise Cascade, Docket No. E–7765, (ERA Docket No. PP–52).
(G) Bonneville Power Administration, Docket No. IT–5959, (ERA Docket No. PP–10).
(H) EPR—Oregon (Geothermal Steam Leases).
(I) EPR—Utah (Geothermal Steam Leases).
(J) EPR—Idaho (Geothermal Steam Leases).
(K) EPR—Oregon (Geothermal Steam Leases).
(L) EPR—Idaho (Geothermal Steam Leases).
(iii) Rulemakings:
(A) Implementation of sections 382(b) and 382(c) of the Energy Policy and Conservation Act of 1971. Docket No. RM77–3.
(B) Naw Form Nos:
151, Docket No. RM76–19.
153, Docket No. RM76–27.
154, Docket No. RM36–33.
156, Docket No. RM76–32.
157, Docket No. RM76–21.
158, Docket No. RM76–31.
159, Docket No. RM76–23.
160, Docket No. RM76–20.
161, Docket No. RM76–26.
162, Docket No. RM76–34.
155, Docket No. RM76–28.
163, Docket No. RM76–30.
164, Docket No. RM76–25.
(C) Procedures for the Filing of Federal Rate Schedules Docket No. RM77–9.
(iv) Project withdrawals and power site revocations:
(A) Project 1021, 1226, 1606, and 1772—(Wyoming)—U.S. Forest Service (Applicant).
(B) Project Nos. 1021, 1226, 1606, and 1772—(Wyoming)—U.S. Forest Service (Applicant).
(C) Project Nos. 220 and 691—(Wyoming)—Cliff Gold Mining Co. (Applicant for P–691) The Colowyo Gold Mining Co. (Applicant for P–220).
(D) Project No. 1203—(Wyoming)—F. D. Foster (Applicant).
(E) Project No. 1241—(Wyoming)—F. B. Hommel (Applicant).
(F) Project No. 847—(Oregon)—H. L. Vorse (Applicant).
(G) Project No. 907—(Colorado)—S. B. Collins (Applicant).
(H) Project No. 941—(Colorado)—Marian Mining Company (Applicant).
(I) Project Nos. 347 and 418—(Colorado)—Jones Brothers (Applicant for P–347) Frank Gay et al. (Applicant for P–418).
(J) Project Nos. 373, 521, 937, 1024, 1415, 1546, 1547, and 1025—( )—U.S. Forest (Applicant).
(K) Project No. 163—(Colorado)—James F. Meyser and Edward E. Drach (Applicants).
(L) Project Nos. 385, 445, 506, 519, 1220, 1296, 1418, 1519, 1576, 1615, 1616, 1618, 1678, 1682, and 1750—(Colorado)—U.S. Forest Service (Applicant).
(M) DA–117—(Alaska)—Bureau of Land Management (Applicant).
(N) Project No. 114—(Alaska)—Elizabeth H. Graff et al. (Applicant).
(O) DA–222—(Washington)—Bureau of Land Management (Applicant).
(P) DA–562—(Oregon)—U.S. Geological Survey (Applicant).
(Q) DA–601—(Idaho)—Bureau of Land Management (Applicant).
(R) DA–509—(Colorado)—Fed. Highway Admin. (Applicant).
(S) DA–616—(Idaho)—U.S. Forest Service (Applicant).
(T) DA–1—(South Carolina)—U.S. Forest Service (Applicant).
(U) DA–1116—(California)—U.S. Geological Survey (Applicant).
(V) DA–154—(Arizona)—U.S. Geological Survey (Applicant).
(W) DA–1098—(California)—Merced Irrigation District (Applicant).
(c) Proceedings transferred to the Commission. There are hereby transferred to the jurisdiction of the Federal Energy Regulatory Commission the following proceedings:
(1) From the Interstate Commerce Commission:
(i) Ex Parte No. 308—Valuation of Common Carrier Pipelines.
(ii) I&S 9164—Trans Alaska Pipeline System—Rate Filings (including I&S 9164 (Sub-No. 1), NOR 36611, NOR 36611 (Sub-No. 1). NOR 36611 (Sub-No. 2), NOR 36611 (Sub-No. 3), NOR 36611 (Sub-No. 4)).
(iii) I&S 9089—General Increase, December 1975, Williams Pipeline Company.
(iv) I&S 9128—Anhydrous Ammonia, Gulf Central Pipeline Company.
(v) NOR 35533 (Sub-No. 3)—Petroleum Products, Southwest & Midwest Williams Pipeline.
(vi) NOR 35794—Northville Dock Pipeline Corp. et al.
(vii) NOR 35895—Inexco Oil Company v. Belle Fourche Pipeline Co. et al.
(viii) NOR 36217—Department of Defense v. Interstate Storage & Pipeline Corp.
(ix) NOR 36423—Petroleum Products Southwest to Midwest Points.
(x) NOR 36520—Williams Pipeline Company—Petroleum Products Midwest.
(xi) NOR 36553—Kerr-McGee Refining Corporation v. Texoma Pipeline Co.
(xii) Suspension Docket 67124—Williams Pipeline Co.—General Increase.
(xiii) Valuation Docket 1423—Williams Pipeline Company (1971–1974 inclusive).
(2) To remain with the Commission until forwarding to the Secretary:
(i) El Paso Eastern Co., et al., Docket No. CP 77–330, et al.
(ii) Tenneco Atlantic Pipeline Co., et al., Docket No. CP 77–100, et al.
(iii) Distrigas of Massachusetts Corp., et al., Docket No. CP 70–196, et al.
(iv) Distrigas of Massachusetts Corp., et al., Docket No. CP 77–216, et al.
(v) Eascogas LNG, Inc., et al., Docket No. CP 73–47, et al.
(vi) Pacific Indonesia LNG Co., et al., Docket No. CP74–160, et al., (except as provided in paragraph (c)(3) of this section).
(3) The Amendment to Application of Western LNG Terminal Associates, filed on November 11, 1977, in Pacific Indonesia LNG Co., et al., FPC Docket No. CP74–160, et al., ERA Docket No. 77–001–LNG, is transferred to the jurisdiction of the Commission until timely filing of all briefs on and opposing exceptions to the Initial Decision of the presiding Administrative Law Judge on that Amendment, at which time the Commission shall forward a copy of the record of that proceeding to the Secretary of Energy for decision on those matters within his jurisdiction. (If the Commission waives the preparation of an initial decision, the Commission will forward a copy of the record after completion of the hearing, or after the timely filing of any briefs submitted to the Commission, whichever occurs later.)
(d) Residual clause. All proceedings (other than proceedings described in paragraphs (b) and (c) of this section) pending with regard to any function of the Department of Energy, the Department of Energy, Department of the Interior, the Department of Commerce, the Department of Housing and Urban Development, the Department of Navy, and the Naval Reactor and Military Applications Programs which is transferred to the Department of Energy (DOE) by the DOE Organization Act, will be conducted by the Secretary. All proceedings (other than proceedings described in paragraphs (b) and (c) of this section) before the Federal Power Commission or Interstate Commerce Commission will be conducted by the Federal Energy Regulatory Commission.
§ 375.105 Filings.
(a) Filings in pending proceedings. All filings in proceedings referred to in § 375.104 shall be made with the Secretary.
(b) Filings in connection with functions transferred to the Commission. All persons required to file periodic or other reports with any agency or commission whose functions are transferred under such Act to the Commission shall file such reports which relate to those transferred functions with the Secretary. The Commission hereby continues in effect all previously-approved forms for making periodic or other reports.
(c) Where to make filings. All filings of documents with the Commission shall be made with the Secretary. The address for filings to be made with the Secretary is: Secretary, Federal Energy Regulatory Commission, 888 First St., NE., Washington, DC 20426. Where a document to be filed with the Secretary is hand-delivered, it shall be submitted to Room 1A, 888 First St., NE., Washington, DC 20426. Documents received after regular business hours are deemed to have been filed on the next regular business day.
Subpart B—Procedures Under the Government in the Sunshine Act
§ 375.201 Purpose.
The purpose of this subpart is to set forth the Commission procedures for conduct of its official business in accordance with the provisions of 5 U.S.C. 552b. The Commission may waive the provisions set forth in this subpart to the extent authorized by law.
§ 375.202 Definitions and limitations on definitions.
(a) Definitions. For purposes of this subpart:
(1) Meeting means the deliberations of at least a quorum of the Commission where such deliberations determine or result in the joint conduct of official Commission business, except that such term does not include deliberations to determine whether to conduct a closed meeting.
(2) Portion of a meeting means the consideration during a meeting of a particular topic or item separately identified in the notice of Commission meeting described in § 375.204.
(3) Open when used in the context of a Commission meeting or a portion thereof, means the public may attend and observe the deliberations of the Commission during such meeting or portion of a meeting consistent with the provisions of § 375.203.
(4) Closed when used in the context of a Commission meeting or a portion thereof, means that the public may not attend or observe the deliberations of the Commission during such meeting or portion of such meeting.
(b) Limitations on other definitions in this chapter. For purposes of this subpart:
(1) Transcripts, minutes and electronic recordings of Commission meetings (whether or not prepared at the direction of the Commission) are not part of the “formal record” as defined in § 388.101(c) of this chapter; and
(2) Transcripts, minutes and electronic recordings of Commission meetings (whether or not prepared at the direction of the Commission) are not part of the “public record” of the Commission as defined in § 388.105(b)) of this chapter.
§ 375.203 Open meetings.
(a) General rule. Except as provided in § 375.206, meetings of the Commission will be open meetings.
(b) Public participation in open meetings. (1) Members of the public are invited to listen and observe at open meetings.
(i) “Observe” does not include participation or disruptive conduct, and persons engaging in such conduct will be removed from the meeting.
(ii) The right of the public to observe open meetings does not alter those rules which relate to the filing of motions, pleadings, or other documents. Unless such pleadings conform to the other procedural requirements, pleadings based upon comments or discussions at open meetings, as a general rule, will not become part of the official record, will receive no consideration, and no further action by the Commission will be taken thereon.
(2) To the extent their use does not interfere with the conduct of open meetings, electronic audio and visual recording equipment may be used by a seated observer at an open meeting.
(c) Physical arrangements. The Secretary shall be responsible for seeing that ample space, sufficient visibility, and adequate acoustics are provided for public observation of open meetings.
§ 375.204 Notice of meetings.
(a) Public announcements of meetings—(1) General rule. Except to the extent that information described in § 375.205(a) (involving closed meetings) is exempt from disclosure, the Secretary shall announce at least one week before each Commission meeting, the time, place, and subject matter of the meeting, whether it is an open meeting or closed meeting, and the name and telephone number of the official designated by the Commission to respond to requests for information about the meeting.
(2) Abbreviated notice. If the Commission determines by a majority of its members by a recorded vote that Commission business requires that a Commission meeting be called with less than one week’s notice as prescribed in paragraph (a)(1) of this section, the Secretary shall make public announcements of the time, place, and subject matter of such meeting and whether open or closed to the public, at the earliest practicable time.
(3) Change in the time or place. If there is a change in time or place of a meeting following the public announcement prescribed in paragraph (a)(1) or (2) of this section the Secretary shall publicly announce such change at the earliest practicable time.
(4) Change in the subject matter or the determination to open or close a meeting. The subject matter of a meeting, or the determination of the Commission to open or close a meeting or a portion of a meeting, may be changed following the public announcement prescribed in paragraph (a) (1) or (2) of this section only if:
(i) The Commission determines by a recorded vote by a majority of the membership that Commission business so requires and that no earlier announcement of the change is possible; and
(ii) The Secretary publicly announces such change and the vote of each member upon such change at the earliest practicable time.
(b) Stricken items. Notwithstanding the provisions of paragraph (a) of this section, individual items that have been announced for consideration at Commission meetings may be deleted without vote or notice.
(c) Definitions. For the purpose of this section, earliest practicable time, means as soon as practicable, which should in few, if any, instances be later than the commencement of the meeting or portion of the meeting in question.
(d) Informing public of meeting announcements. (1) The Secretary shall use reasonable means to assure that the public is fully informed of the public announcements required by this section. For example, such announcements may be posted on the Commission’s public notice boards, published in official Commission publications, or sent to the persons on a mailing list maintained for those who want to receive such material.
(2) Immediately following each public announcement required by this section, notice of the time, place, and subject matter of a meeting, whether the meeting is open or closed, any change in a preceding announcement, and the name and telephone number of the official designated by the Commission to respond to requests for information about the meeting shall also be submitted by the Secretary for publication in the
(e) Issuance of list of Commission actions. Following each Commission meeting, the Secretary shall issue a list of Commission actions taken which shall become effective as of the date of issuance of the related order (or date designated therein) or other document, which the Secretary shall issue in due course, in the manner prescribed by the Commission.
§ 375.205 Closed meetings.
(a) Meetings will be closed to public observation where the Commission properly determines, according to the procedures set forth in § 375.206, that such meeting or portion of the meeting or disclosure of information to be considered at the meeting is likely to:
(1) Disclose matters that are (i) specifically authorized under criteria established by an Executive order to be kept secret in the interests of national defense or foreign policy and are (ii) in fact properly classified pursuant to such Executive order;
(2) Relate solely to the internal personnel rules and practices of the Commission;
(3) Disclose matters specifically exempted from disclosure by statute (other than 5 U.S.C. 552): Provided, That such statute:
(i) Requires that the matters be withheld from the public in such a manner as to leave no discretion on the issue, or
(ii) Establishes particular criteria for withholding or refers to particular types of matters to be withheld;
(4) Disclose the trade secrets and commercial or financial information obtained from a person and privileged or confidential, which may include geological or geophysical information and data, including maps, concerning wells;
(5) Involve accusing any person of a crime, or formally censuring any person;
(6) Disclose information of a personal nature where disclosure would constitute a clearly unwarranted invasion of personal privacy, including personnel and medical files and similar files;
(7) Disclose investigatory records compiled for law enforcement purposes, or information which if written would be contained in such records, but only to the extent that the production of such records or information would:
(i) Interfere with enforcement proceedings;
(ii) Deprive a person of a right to a fair trial or an impartial adjudication;
(iii) Constitute an unwarranted invasion of personal privacy;
(iv) Disclose the identity of a confidential source and, in the case of a record compiled by a criminal law enforcement authority in the course of a criminal investigation, or by an agency conducting a lawful national security intelligence investigation, confidential information furnished only by the confidential source;
(v) Disclose investigative techniques and procedures, or;
(vi) Endanger the life or physical safety of law enforcement personnel.
(8) Disclose information contained in or related to examination, operating, or condition reports prepared by, on behalf of, or for the use of an agency responsible for the regulation or supervision of financial institutions;
(9) Disclose information the premature disclosure of which would be:
(i) In the case of an agency which regulates currencies, securities, commodities, or financial institutions, likely to:
(A) Lead to significant financial speculation in currencies, securities, or commodities, or
(B) Significantly endanger the stability of any financial institution; or
(ii) Likely to frustrate significantly implementation of a proposed Commission action, except that paragraph (a)(9)(i) of this section shall not apply where the Commission has already disclosed to the public the content or nature of such proposed action, or where the Commission is required by law to make such disclosure on its own initiative prior to taking final agency action on such proposal; or
(10) Specifically concern the Commission’s issuance of a subpoena, or the Commission’s participation in a civil action or proceeding, an action in a foreign court or international tribunal, or an arbitration, or the initiation, conduct, or disposition by the Commission of a particular case:
(i) Of formal Commission adjudication pursuant to the procedures in 5 U.S.C. 554; or
(ii) Otherwise involving a determination on the record after opportunity for a hearing.
(b) Commission meetings shall not be closed pursuant to paragraph (a) of this section when the Commission finds that the public interest requires that they be open.
§ 375.206 Procedures to close meetings.
(a) General rule. A meeting or a portion of a meeting may be closed only when the Commission votes by a majority of the membership to close the meeting. A separate vote shall be taken with respect to each Commission meeting or portion of a meeting which is proposed to be closed to the public or with respect to any information which is proposed to be withheld. A single vote may be taken with respect to a series of meetings, a portion or portions of which are proposed to be closed to the public, or with respect to any information concerning such series of meetings, so long as each meeting in such series involves the same particular matters and is scheduled to be held no more than thirty days after the initial meeting in such series. The vote of each Commission member participating in such vote shall be recorded and no proxies shall be allowed.
(b) Request for closed meeting. Whenever any person whose interests may be directly affected by a meeting or a portion of a meeting requests that the Commission close such portion to the public for any of the reasons referred to in paragraph (a) (5), (6), or (7) of § 375.205, the Commission, upon request of any one of its members, shall vote by recorded vote whether to close such meeting.
(c) Release of vote. Within one day of any vote taken pursuant to paragraph (a) or (b) of this section, the Secretary of the Commission shall make publicly available a written copy of such vote reflecting the vote of each member. If a portion of a meeting is to be closed to the public, the Secretary shall, within one day of the vote taken pursuant to paragraph (a) or (b) of this section, make publicly available a full written explanation of the Commission’s action closing the portion together with a list of all persons expected to attend the meeting and their affiliation. The information required by this paragraph shall be disclosed except to the extent that it is exempt from disclosure under the provisions of § 375.205(a).
(d) Certification. Prior to a determination that a meeting should be closed pursuant to paragraph (a) or (b) of this section, the General Counsel of the Commission shall publicly certify that, in his opinion, the meeting may be closed to the public and shall state each relevant exemptive provision. A copy of such certification, together with a statement from the presiding officer of the meeting setting forth the time and place of the meeting, and the persons present, shall be retained by the Secretary of the Commission as part of the transcript, recording, or minutes required by paragraph (e) of this section.
(e) Transcripts, recordings, minutes. (1) The Secretary shall maintain a complete transcript or electronic recording adequate to record fully the proceedings of each meeting, or portion of a meeting, closed to the public, except that in the case of a meeting, or portion of a meeting, closed to the public pursuant to § 375.205(a)(8), (9)(i), or (10), the Secretary shall maintain either a transcript or recording, or a set of minutes. Any such minutes shall fully and clearly describe all matters discussed and shall provide a full and accurate summary of any actions taken, and the reasons therefor, including a description of each of the views expressed on any item and the record of any rollcall vote (reflecting the vote of each member on the question). All agenda documents considered in connection with any Commission action shall be identified in such minutes.
(2) The Secretary shall maintain a complete verbatim copy of the transcript, a complete copy of the minutes, or a complete electronic recording of each meeting, or portion of a meeting, closed to the public, for a period of at least two years after such meeting, or until one year after the conclusion of any Commission proceeding with respect to which the meeting or portion was held, whichever occurs later.
(f) Public availability of transcripts, records, minutes. (1) Within a reasonable time after the adjournment of a meeting closed to the public, the Commission shall make available to the public, in the Division of Public Information of the Commission, Washington, DC, the transcript, electronic recording, or minutes of the discussion of any item on the agenda, or of any item of the testimony of any witness received at the meeting, except for such item or items of such discussion or testimony as the Director of Public Information determines may be withheld under § 375.204. Copies of such transcript, or minutes, or a transcription of such recording shall be furnished to any person at the actual cost of duplication or transcription.
(2) The determination of the Director of the Division of Public Information to withhold information pursuant to paragraph (f)(1) of this section may be appealed to the General Counsel or the General Counsel’s designee, in accordance with § 388.107 of this chapter.
Subpart C—Delegations
§ 375.301 Purpose and subdelegations.
(a) The purpose of this subpart is to set forth the authorities that the Commission has delegated to staff officials. Any action by a staff official under the authority of this subpart may be appealed to the Commission in accordance with § 385.1902 of this chapter.
(b) Where the Commission, in delegating functions to specified Commission officials, permits an official to further delegate those functions to a designee of such official, designee shall mean the deputy of such official, the head of a division, or a comparable official as designated by the official to whom the direct delegation is made.
(c) For purposes of Subpart C, uncontested and in uncontested cases mean that no motion to intervene, or notice of intervention, in opposition to the pending matter made under § 385.214 (intervention) has been received by the Commission.
§ 375.302 Delegations to the Secretary.
The Commission authorizes the Secretary, or the Secretary’s designee to:
(a) Sign official general correspondence on behalf of the Commission, except as otherwise provided in this section.
(b) Prescribe, for good cause, a different time than that required by the Commission’s Rules of Practice and Procedure or Commission order for filing by public utilities, licensees, natural gas companies, and other persons of answers to complaints, petitions, motions, and other documents.
(c) Schedule hearings and issue notices thereof.
(d) Accept for filing notices of intervention and petitions to intervene by commissions and agencies of the States and the Federal government.
(e) Pass upon motions to intervene before a presiding administrative law judge is designated. If a presiding administrative law judge has been designated, the provisions of § 385.504(b)(12) of this chapter are controlling.
(f) Deny motions for extensions of time (other than motions made while a proceeding is pending before a presiding officer as defined in § 385.102(e)), except that such motions may be granted in accordance with § 385.2008 of this chapter.
(g) Reject any documents filed later than the time prescribed by an order or rule of the Commission, except that such documents may be accepted in accordance with § 385.2008 of this chapter.
(h) Reject any documents filed that do not meet the requirements of the Commission’s rules which govern matters of form, except that such documents may be accepted in accordance with § 385.2001 of this chapter for good cause shown.
(i) Waive requirements of the Commission’s rules which govern matters of form, when consistent with the public interest in a particular case.
(j) Pass upon, in contested proceedings, questions of extending time for electric public utilities, licensees, natural gas companies, and other persons to file required reports, data, and information and to do other acts required to be done at or within a specific time by any rule, regulation, license, permit, certificate, or order of the Commission.
(k) Accept service of process on behalf of the Commission.
(l) Accept for filing bonds or agreements and undertakings submitted in rate suspension proceedings.
(m) Issue notices or orders instituting procedures to be followed concerning contested audit issues under part 41 or 158 of this chapter either when the utility:
(1) Initially notifies the Commission that it requests disposition of a contested issue pursuant to § 41.7 or 158.7 of this chapter; or
(2) Requests disposition of a contested issue pursuant to the shortened procedures provided in § 41.3 or 158.3 of this chapter.
(n) Publish notice of land withdrawals under section 24 of the Federal Power Act.
(o) Issue notices of applications filed under the Federal Power Act and the Natural Gas Act, fixing the time for filing comments, protests or petitions to intervene and schedule hearings on such applications when appropriate or required by law.
(p) Accept for filing amendments to agreements and contracts or rate schedules submitted in compliance with Commission orders accepting offers of rate settlements if such filings are in satisfactory compliance with such orders.
(q) Grant authorizations, pursuant to the provisions of § 35.1(a) of this chapter for a designated representative to post and file rate schedules of public utilities which are parties to the same rate schedule.
(r) Redesignate proceedings, licenses, certificates, rate schedules, and other authorizations and filing to reflect changes in the names of persons and municipalities subject to or invoking Commission jurisdiction under the Federal Power Act or the Natural Gas Act, where no substantive changes in ownership, corporate structure or domicile, or jurisdictional operation are involved.
(s) Change the appropriate hydroelectric project license article upon application by the licensee to reflect the specified reasonable rate of return as provided in § 2.15 of this chapter.
(t) Reject without prejudice all requests for rehearing and requests for modification of a proposed order issued in a proceeding under section 210 or section 211 of the Federal Power Act, 16 U.S.C. 824i, 824j.
(u) Reject without prejudice all motions for clarification that are combined with requests for rehearing and/or requests for modification of a proposed order issued in a proceeding under section 210 or section 211 of the Federal Power Act, 16 U.S.C. 824i, 824j.
(v) Toll the time for action on requests for rehearing, and toll the time for action on protested self-certifications and self-recertifications of qualifying facilities.
(w) Issue notices in compliance with section 206(b) of the Federal Power Act.
(x) Issue instructions for electronic registration pursuant to, grant applications for waivers of the requirements of, and make determinations regarding exemptions from 18 CFR part 390.
(y) Direct the staff of the Dispute Resolution Service (DRS) to contact the parties in a complaint proceeding and establish a date by which DRS must report to the Commission whether a dispute resolution process to address the complaint will be pursued by the parties.
(z) Issue instructions pertaining to allowable electronic file and document formats, the filing of complex documents, whether paper copies are required, and procedural guidelines for submissions via the Internet, on electronic media or via other electronic means.
(aa) Issue a notice that the Commission will not further review on its own motion a Notice of Penalty filed under Section 215(e) of the Federal Power Act.
§ 375.303 Delegations to the Director of the Office of Electric Reliability.
The Commission authorizes the Director or the Director’s designee to:
(a) Program-Specific Delegated Authority: Take the following actions with respect to the following programs:
(1) Section 206 of the Public Utility Regulatory Policy Act of 1978 and corresponding Section 202(g) of the Federal Power Act.
(i) Accept for filing all uncontested contingency plans regarding shortages of electric energy or capacity, circumstances which may result in such shortages, and accommodations of any such shortages or circumstances, if said contingency plans comply with all applicable statutory requirements, and with all applicable Commission rules, regulations and orders for which waivers have not been granted, or if waivers have been granted by the Commission, if the filings comply with the terms of the waivers;
(ii) Reject a contingency plan regarding shortages of electric energy or capacity, unless accompanied by a request for waiver in conformity with § 385.2001 of this chapter, if it fails patently to comply with applicable statutory requirements and with all applicable Commission rules, regulations and orders;
(iii) Sign and issue deficiency letters;
(iv) Act on any request or petition for waiver, consistent with Commission policy.
(2) Section 215 of the Federal Power Act.
(i) Approve uncontested applications.
(ii) Reject an application, unless accompanied by a request for waiver in conformity with § 385.2001 of this chapter, if it fails patently to comply with applicable statutory requirements or with all applicable Commission rules, regulations or orders;
(iii) Act on any request or petition for waiver, consistent with Commission policy;
(iv) Sign and issue deficiency letters; and
(v) Direct the Electric Reliability Organization, Regional Entities, or users, owners, and operators of the Bulk-Power System within the United States (not including Alaska and Hawaii) to provide such information as is necessary to implement Section 215 of the Federal Power Act (16 U.S.C. 824o) pursuant to §§ 39.2(d) and 39.11 and Part 40 of this chapter.
(vi) Issue an order extending the period of time for consideration of a Notice of Penalty filed under Section 215(e) of the Federal Power Act for the purpose of directing the Electric Reliability Organization or the applicable Regional Entity to provide such information as is necessary to implement Section 215(e)(2) of the Federal Power Act (16 U.S.C. 824o(e)(2)) pursuant to § 39.2 and Part 40 of this chapter.
(b) Non-Program-Specific Delegated Authority:
(1) Take appropriate action on:
(i) Any notice of intervention or motion to intervene filed in an uncontested proceeding processed by the Office of Electric Reliability; and
(ii) Applications for extensions of time to file required filings, reports, data and information and to perform other acts required at or within a specific time by any rule, regulation, license, permit, certificate, or order by the Commission.
(2) Take appropriate action on requests or petitions for waivers of filing requirements for the appropriate statements and reports processed by the Office of Electric Reliability pursuant to §§ 141.51 and 141.300 of this chapter; and
(3) Undertake the following actions:
(i) Issue reports for public information purposes. Any report issued without Commission approval must:
(A) Be of a noncontroversial nature, and
(B) Contain the statement, “This report does not necessarily reflect the views of the Commission,” in bold face type on the cover;
(ii) Upon request or otherwise, issue staff position papers to further the Electric Reliability Organization and Regional Entity reliability standard development process. Any such staff position paper issued without Commission approval must contain the statement, “This position paper does not necessarily reflect the views of the Commission,” in bold face type on the cover;
(iii) Issue and sign requests for additional information regarding applications, filings, reports and data processed by the Office of Electric Reliability.
(iv) Accept for filing, data and reports required by Commission regulations, rules or orders, or presiding officers’ initial decisions upon which the Commission has taken no further action, if such filings are in compliance with such regulations, rules, orders or decisions and, when appropriate, notify the filing party of such acceptance.
§ 375.304 Delegations to the Chief Administrative Law Judge.
(a) The Commission authorizes the Chief Administrative Law Judge and the Administrative Law Judge designated by the Chief Administrative Law Judge to exercise the power granted to a Presiding Officer by part 385, particularly § 385.504 of this chapter.
(b) The Commission authorizes the Chief Administrative Law Judge to
(1) For those proceedings pending under subpart E of part 385 of this chapter:
(i) Consolidate for hearing two or more proceedings on any or all issues,
(ii) Sever two or more proceedings or issues in a proceeding,
(iii) Designate and substitute presiding officers, and
(iv) Extend any close or record date ordered by the Commission in a proceeding for good cause, and
(v) Set or extend procedural time standards, including but not limited to hearing, briefing and initial decision dates, including dates set by the Commission, unless the Commission states otherwise in its hearing order.
(2) For proceedings under subparts I and J of part 385 of this chapter, designate presiding officers who will have all the authorities and duties vested in presiding officers by those rules and other applicable rules in conducting proceedings pursuant to sections 503(c) and 504(b)(1) of the Department of Energy Organization Act, 42 U.S.C. 7193(c) and 7194(b)(1) (1982).
(3) Deny or grant, in whole or in part, petitions for waivers of fees prescribed in §§ 381.303 and 381.304 of this chapter in accordance with § 381.106 of this chapter.
(c) The Commission authorizes the Chief Administrative Law Judge, and the Administrative Law Judge designated by the Chief Administrative Law Judge to serve as a settlement judge for a proceeding, to certify to the Commission uncontested offers of settlement.
§ 375.305 Delegations to the Solicitor.
The Commission authorizes the Solicitor, or the Solicitor’s designee to:
(a) File with the appropriate court of the United States a certified list of the materials comprising the record of any proceeding which involves the Commission;
(b) Retain appropriate materials; and
(c) Deliver such materials to the court as required.
§ 375.307 Delegations to the Director of the Office of Energy Market Regulation.
The Commission authorizes the Director or the Director’s designee to:
(a) Program-Specific Delegated Authority: Take the following actions with respect to the following programs:
(1) Sections 205 and 206 of the Federal Power Act. (i) Accept for filing all uncontested tariffs or rate schedules and uncontested tariff or rate schedule changes submitted by public utilities, including changes that would result in rate increases, if they comply with all applicable statutory requirements, and with all applicable Commission rules, regulations and orders for which waivers have not been granted, or if waivers have been granted by the Commission, if the filings comply with the terms of the waivers;
(ii) Reject a tariff or rate schedule filing, unless accompanied by a request for waiver in conformity with § 385.2001 of this chapter, if it fails patently to comply with applicable statutory requirements and with all applicable Commission rules, regulations and orders;
(iii) Take appropriate action on requests or petitions for waivers of notice as provided in section 205(d) of the Federal Power Act, provided the requests conform to the requirements of § 385.2001 of this chapter;
(iv) Refer to the Chief Administrative Law Judge (Chief ALJ) for action by the Chief ALJ, with the Chief ALJ’s concurrence, uncontested motions that would result in lower interim settlement rates, pending Commission action on settlement agreements;
(v) Sign and issue deficiency letters; and
(vi) Act on requests for authorization for a designated representative to post and file rate schedules of public utilities which are parties to the same rate schedules.
(2) Other sections of the Federal Power Act. (i) Pass upon any uncontested application for authorization to issue securities or to assume obligations and liabilities filed by public utilities and licensees pursuant to Part 34 of this chapter;
(ii) Take appropriate action on uncontested applications for the sale or lease or other disposition of facilities, merger or consolidation of facilities, purchase or acquisition or taking of securities of a public utility, or purchase or lease or acquisition of an existing generation facility under section 203 of the Federal Power Act;
(iii) Take appropriate action on uncontested applications for interlocking positions under section 305(b) of the Federal Power Act; and
(iv) Sign and issue deficiency letters for filings under Federal Power Act sections 203, 204, 215, and 305(b).
(v) Take appropriate action on uncontested Electric Reliability Organization budget, business plan, and special assessment filings made pursuant to § 39.4 of this chapter.
(vi) Take appropriate action on uncontested filings proposing Electric Reliability Organization or Regional Entity organization rules or rule changes made pursuant to § 39.10 of this chapter.
(vii) Take appropriate action on uncontested delegation agreement filings by the Electric Reliability Organization or Regional Entity made pursuant to section 39.8 of this chapter.
(3) Public Utility Holding Company Act of 2005. Take appropriate action on:
(i) Uncontested FERC–65A (exemption notification) filings;
(ii) Uncontested FERC–65B (waiver notification) filings; and
(iii) Uncontested applications under section 1275(b) of the Energy Policy Act of 2005 and/or the Federal Power Act to allocate service company costs to members of a holding company system.
(4) Federal Power Marketing Administration Filings. Approve uncontested rates and rate schedules filed by the Secretary of Energy or his designee, for power developed at projects owned and operated by the federal government and for services provided by federal power marketing agencies.
(5) Section 210(m) of the Public Utility Regulatory Policies Act of 1978. (i) Approve uncontested applications;
(ii) Reject an application, unless accompanied by a request for waiver in conformity with § 385.2001 of this chapter, if it fails patently to comply with applicable statutory requirements or with all applicable Commission rules, regulations and orders;
(iii) Act on any request or petition for waiver, consistent with Commission policy; and
(iv) Sign and issue deficiency letters.
(6) Other sections of the Public Utility Regulatory Policies Act of 1978. Take appropriate action on:
(i) Filings related to uncontested nonexempt qualifying small power production facilities;
(ii) Uncontested applications for certification of qualifying status for small power production and cogeneration facilities under § 292.207 of this chapter;
(iii) Requests or petitions for waivers of the requirements of subpart C of Part 292 of this chapter governing cogeneration and small power production facilities made by any state regulatory authority or nonregulated electric utility pursuant to § 292.402 of this chapter;
(iv) Requests or petitions for waivers of the Commission’s regulations under the Federal Power Act related to nonexempt qualifying small power production facilities and related authorizations consistent with Massachusetts Refusetech, Inc., 31 FERC ¶ 61,048 (1985), and the orders cited therein without limitation as to whether qualifying status is by Commission certification or notice of qualifying status, provided that, in the case of a notice of qualifying status, any waiver is granted on condition that the filing party has correctly noticed the facility as a qualifying facility; and
(v) Requests or petitions for waivers of the technical requirements applicable to qualifying small power production facilities and qualifying cogeneration facilities.
(7) Sections 4 and 5 of the Natural Gas Act. (i) Accept for filing all uncontested tariffs or rate schedules and uncontested tariff or rate schedule changes, except major pipeline rate increases under section 4(e) of the Natural Gas Act and under subpart D of Part 154 of this chapter, if they comply with all applicable statutory requirements, and with all applicable Commission rules, regulations and orders for which waivers have not been granted, or if waivers have been granted by the Commission, if the filings comply with the terms of the waivers;
(ii) Accept for filing all uncontested tariff or rate schedules changes made in compliance with Commission orders;
(iii) Reject a tariff or rate schedule filing, unless accompanied by a request for waiver in conformity with § 385.2001 of this chapter, if it patently fails to comply with applicable statutory requirements and with all applicable Commission rules, regulations and orders;
(iv) Take appropriate action on requests or petitions for waiver of notice as provided in section 4(d) of the Natural Gas Act, provided the request conforms to the requirements of § 385.2001 of this chapter; and
(v) Refer to the Chief Administrative Law Judge (Chief ALJ) for action by the Chief ALJ, with the Chief ALJ’s concurrence, uncontested motions that would result in lower interim settlement rates, pending Commission action on settlement agreements.
(8) Section 7 of the Natural Gas Act. Take appropriate action on the following types of uncontested applications for authorizations and uncontested amendments to applications and authorizations filed pursuant to section 7 of the Natural Gas Act and impose appropriate conditions:
(i) Applications by a pipeline for the deletion of delivery points but not facilities;
(ii) Applications to abandon pipeline services, but not facilities, involving a specific customer or customers, if such customer or customers have agreed to the abandonment;
(iii) Applications for temporary or permanent certificates (and for amendments thereto) for services, but not facilities, in connection with the transportation;
(iv) Blanket certificate applications by interstate pipelines and local distribution companies served by interstate pipelines filed pursuant to §§ 284.221 and 284.224 of this chapter;
(v) Applications for temporary certificates involving transportation service or sales, but not facilities, pursuant to § 157.17 of this chapter;
(vi) Dismiss any protest to prior notice filings involving existing service, made pursuant to § 157.205 of this chapter, that does not raise a substantive issue and fails to provide any specific detailed reason or rationale for the objection;
(vii) Applications pertaining to approval of changes in customer names where there is no change in rate schedule, rate, or other incident of service;
(viii) Applications for approval of customer rate schedule shifts;
(ix) Applications filed under section 1(c) of the Natural Gas Act and Part 152 of this chapter, for declaration of exemption from the provisions of the Natural Gas Act and certificates held by the applicant;
(x) Applications and amendments requesting authorizations filed pursuant to section 7(c) of the Natural Gas Act for new or additional service through existing facilities to right-of-way grantors either directly or through distributors, where partial consideration for the granting of the rights-of-way was the receipt of gas service pursuant to section 7(c) of the Natural Gas Act;
(xi) An uncontested request from the holder of an authorization, granted pursuant to the Director’s delegated authority, to vacate all or part of such authorization; and
(xii) Sign and issue deficiency letters.
(9) Natural Gas Policy Act of 1978. (i) Notify jurisdictional agencies within 45 days after the date on which the Commission receives notice of a determination pursuant to § 270.502(b) of this chapter that the notice is incomplete under § 270.204 of this chapter;
(ii) Issue preliminary findings under § 270.502(a)(1) of this chapter;
(iii) Accept any uncontested item that has been filed under § 284.123 of this chapter consistent with Commission regulations and policy;
(iv) Reject an application filed pursuant to § 284.123 of this chapter, unless accompanied by a request for waiver in conformity with § 385.2001 of this chapter, if it fails patently to comply with applicable statutory requirements or Commission rules, regulations and orders; and
(v) Take appropriate action on petitions to permit after an initial 60-day period one additional 60-day period of exemption pursuant to § 284.264(b) of this chapter where the application for extension arrives at the Commission no later than 45 days after the commencement of the initial period of exemption and where only services are involved.
(10) Regulation of Oil Pipelines Under the Interstate Commerce Act. (i) Accept any uncontested item that has been filed consistent with Commission regulations and policy;
(ii) Reject any filing, unless accompanied by a request for waiver in conformity with § 385.2001 of this chapter, that patently fails to comply with applicable statutory requirements and with all applicable Commission rules, regulations and orders; and
(iii) Prescribe for carriers the classes of property for which depreciation charges may be properly included under operating expenses, review the fully documented depreciation studies filed by the carriers, and authorize or revise the depreciation rates reflected in the depreciation study with respect to each of the designated classes of property.
(b) General, Non-Program-Specific Delegated Authority. (1) Take appropriate action on:
(i) Any notice of intervention or motion to intervene, filed in an uncontested proceeding processed by the Office of Energy Market Regulation;
(ii) Applications for extensions of time to file required filings, reports, data and information and to perform other acts required at or within a specific time by any rule, regulation, license, permit, certificate, or order by the Commission; and
(iii) Filings for administrative revisions to electronic filed tariffs.
(2) Take appropriate action on requests or petitions for waivers of:
(i) Filing requirements for the appropriate statements and reports processed by the Office of Energy Market Regulation under Parts 46, 141, 260 and 357 of this chapter, §§ 284.13 and 284.126 of this chapter, and other relevant Commission orders; and
(ii) Fees prescribed in §§ 381.403 and 381.505 of this chapter in accordance with § 381.106(b) of this chapter.
(3) Undertake the following actions:
(i) Issue reports for public information purposes. Any report issued without Commission approval must:
(A) Be of a noncontroversial nature, and
(B) Contain the statement, “This report does not necessarily reflect the views of the Commission,” in bold face type on the cover;
(ii) Issue and sign requests for additional information regarding applications, filings, reports and data processed by the Office of Energy Market Regulation; and
(iii) Accept for filing, data and reports required by Commission regulations, rules or orders, or presiding officers’ initial decisions upon which the Commission has taken no further action, if such filings are in compliance with such regulations, rules, orders or decisions and, when appropriate, notify the filing party of such acceptance.
§ 375.308 Delegations to the Director of the Office of Energy Projects.
The Commission authorizes the Director or the Director’s designee to:
(a) Take appropriate action on uncontested applications and on applications for which the only motion or notice of intervention in opposition is filed by a competing preliminary permit or exemption applicant that does not propose and substantiate materially different plans to develop, conserve, and utilize the water resources of the region for the following:
(1) Licenses (including original, new, and transmission line licenses) under part I of the Federal Power Act;
(2) Exemptions from all or part of the licensing requirements of part I of the Federal Power Act; and
(3) Preliminary permits for proposed projects.
(b) Take appropriate action on uncontested applications for:
(1) Amendments (including changes in the use or disposal of water power project lands or waters or in the boundaries of water power projects) to licenses (including original, new, and transmission line licenses) under part I of the Federal Power Act, exemptions from all or part of the requirements of part I of the Federal Power Act, and preliminary permits; and
(2) Surrenders of licenses (including original and new), exemptions, and preliminary permits.
(c) Take appropriate action on the following:
(1) Determinations or vacations with respect to lands of the United States reserved from entry, location, or other disposal under section 24 of the Federal Power Act;
(2) Transfer of a license under section 8 of the Federal Power Act;
(3) Applications for the surrender of transmission line licenses pursuant to part 6 of this chapter;
(4) Motions filed by licensees, permittees, exemptees, applicants, and others requesting an extension of time to file required submittals, reports, data, and information and to do other acts required to be done at or within a specific time period by any rule, regulation, license, exemption, permit, notice, letter, or order of the Commission in accordance with § 385.2008 of this chapter;
(5) Declarations of intent and petitions for declaratory orders concerning the Commission’s jurisdiction over a hydropower project under the Federal Power Act;
(6) New or revised exhibits, studies, plans, reports, maps, drawings, or specifications, or other such filings made voluntarily or in response to a term or condition in a preliminary permit, license, or exemption issued for a hydropower project, or in response to the requirements of an order of the Commission or presiding officer’s initial decision concerning a hydropower project;
(7) Requests by applicants to withdraw, pursuant to § 385.216 of this chapter, any pleadings under part I of the Federal Power Act and any pleadings related to exemptions from all or part of part I of the Federal Power Act;
(8) Requests by licensees for exemption from:
(i) The requirement of filing FERC Form No. 80, Licensed Projects Recreation, under § 8.11 of this chapter; and
(ii) The fees prescribed in § 381.302(a) of this chapter in accordance with § 381.302(c) of this chapter and the fees in § 381.601 of this chapter, in accordance with § 381.106 of this chapter;
(9) Requests for waivers incidental to the exercise of delegated authority provided the request conforms to the requirements of § 385.2001 of this chapter;
(10) Proposals for the development of water resources projects submitted by other agencies of the Federal government for Commission review or comment. The Director shall direct comments, when necessary, to the sponsoring agency on matters including, but not limited to, the need for, and appropriate size of, any hydroelectric power installation proposed by any other agency of the Federal government;
(11) The reasonableness of disputed agency cost statements pursuant to § 4.303(e) of this chapter.
(d) Issue an order pursuant to section 5 of the Federal Power Act to cancel a preliminary permit if the permittee fails to comply with the specific terms and conditions of the permit; provided:
(1) The Director gives notice to the permittee of probable cancellation no less than 30 days prior to the issuance of the cancellation order, and
(2) The permittee does not oppose the issuance of the cancellation order.
(e) Issue an order to revoke an exemption of a small conduit hydroelectric facility from the licensing provisions of part I of the Federal Power Act granted pursuant to § 4.93 of this chapter, or an exemption of a small hydroelectric power project from the licensing provisions of part I of the Federal Power Act granted pursuant to § 4.105 of this chapter if the exemption holder fails to begin or complete actual construction of the exempted facility or project within the time specified in the order granting the exemption or in Commission regulations at § 4.94(c) or § 4.106(c) of this chapter, provided:
(1) The Director gives notice to the exemption holder by certified mail of probable revocation no less than 30 days prior to the issuance of the revocation order, and
(2) The holder of the exemption does not oppose the issuance of the revocation order.
(f) Issue an order pursuant to section 13 of the Federal Power Act to terminate a license granted under part I of the Federal Power Act if the licensee fails to commence actual construction of the project works within the time prescribed in the license, provided:
(1) The Director gives notice by certified mail to the licensee of probable termination no less than 30 days prior to the issuance of the termination order, and
(2) The licensee does not oppose the issuance of the termination order.
(g) Require licensees and applicants for water power projects to make repairs to project works, take any related actions for the purpose of maintaining the safety and adequacy of such works, make or modify emergency action plans, have inspections by independent consultants, and perform other actions necessary to comply with part 12 of this chapter or otherwise protect human life, health, property, or the environment.
(h) For any unlicensed or unexempted hydropower project, take the following actions:
(1) Conduct investigations to ascertain the Commission’s jurisdiction,
(2) Make preliminary jurisdictional determinations, and
(3) If a project has been preliminarily determined to require a license, issue notification of the Commission’s jurisdiction; require the filing of a license application; and require that actions necessary to comply with part 12 of this chapter or otherwise protect human life, health, property, or the environment are taken.
(i) Take appropriate action on uncontested settlements among non-Federal parties involving headwater benefits.
(j) Dismiss applications for licenses and approve the withdrawal of applications for hydropower project licenses, in instances where no petition for or notice of intervention contending that licensing is required under part I of the Federal Power Act has been filed and the Director determines that licensing is not required by such Part I.
(k) Reject or dismiss an application filed under Part I of the Federal Power Act or an application for an exemption from some or all of the requirements of Part I of the Federal Power Act if:
(1) An application is patently deficient under § 4.32(e)(2)(i);
(2) A revised application
(i) Does not conform to the requirements of §§ 4.32(a), 4.32(b), or 4.38, under § 4.32(d)(1) or
(ii) If revisions to an application are not timely submitted under § 4.32(e)(1)(iii); or
(3) The applicant fails to provide timely additional information, documents, or copies of submitted materials under § 4.32(g).
(l) Redesignate proceedings, licenses, and other authorizations and filings to reflect changes in the names of persons and municipalities subject to or invoking Commission jurisdiction under the Federal Power Act, where no substantive changes in ownership, corporate structure or domicile, or jurisdictional operation are involved.
(m) Determine payments for headwater benefits from the operation of Federal reservoir projects.
(n) Determine whether to allow a credit against annual charges for the use of government dams or other structures billed to licensees each year for contractual payments for the construction, operation, and maintenance of a Federal dam.
(o) Prepare and issue comments on general water policy and planning issues for the use of the Director of the Water Resources Council or the Assistant Secretaries of the Department of Energy.
(p) Prepare and transmit letters concerning power site lands to the Bureau of Land Management and the U.S. Geological Survey; respond to routine requests for information and any non-docketed correspondence; prepare and transmit letters requesting comments or additional information on applications for hydropower project licenses, preliminary permits, exemptions, amendments of licenses, permits, or exemptions, and other similar matters from Federal, state, and local agencies, from applicants, and from other appropriate persons; and prepare and transmit letters regarding whether transmission lines are works of a hydropower project and are required to be licensed.
(q) Reject an application or other filing under Section 405 of the Public Utility Regulatory Policies Act of 1978, unless accompanied by a request for waiver in conformity with § 385.2001 of this chapter, if it fails patently to comply with applicable statutory requirements or Commission rules, regulations, and orders.
(r) Pass upon petitions filed under §§ 292.210 and 292.211 of this chapter.
(s) Make any preliminary determination of inconsistency between a fish and wildlife agency’s fish and wildlife recommendation and applicable law, and conduct through staff whatever consultation with the agency that is necessary or appropriate in order to attempt to resolve any inconsistency, under section 10(j) of the Federal Power Act, and to take such related actions as are required under that section.
(t) Waive the pre-filing consultation requirements in §§ 4.38 and 16.8 of this title whenever the Director, in his discretion, determines that an emergency so requires, or that the potential benefit of expeditiously considering a proposed improvement in safety, environmental protection, efficiency, or capacity outweighs the potential benefit of requiring completion of the consultation process prior to the filing of an application.
(u) Approve, on a case-specific basis, and issue such orders as may be necessary in connection with the use of alternative procedures, under § 4.34(i) of this chapter, for the development of an application for an original, new or subsequent license, exemption, or license amendment subject to the pre-filing consultation process, and assist in the pre-filing consultation and related processes.
(v) Take appropriate action on the following types of uncontested applications for authorizations and uncontested amendments to applications and authorizations and impose appropriate conditions:
(1) Applications or amendments requesting authorization for the construction or acquisition and operation of facilities that have a construction or acquisition cost less than the limits specified in column 2 of table I in § 157.208(d) of this chapter;
(2) Applications by a pipeline for the abandonment of pipeline facilities;
(3) Applications for temporary certificates for facilities pursuant to § 157.17 of this chapter;
(4) Petitions to amend certificates to conform to actual construction;
(5) Applications for temporary certificates for facilities pursuant to § 157.17 of this chapter;
(6) Dismiss any protest to prior notice filings made pursuant to § 157.205 of this chapter and involving pipeline facilities that does not raise a substantive issue and fails to provide any specific detailed reason or rationale for the objection;
(7) Applications for temporary or permanent certificates (and for amendments thereto) for the transportation, exchange or storage of natural gas, provided that the cost of construction of the applicant’s related facility is less than the limits specified in column 2 of table 1 in § 157.208(d) of this chapter; and
(8) Applications for blanket certificates of public convenience and necessity pursuant to subpart F of part 157 of this chapter, including waiver of project cost limitations in §§ 157.208 and 157.215 of this chapter, and the convening of informal conferences during the 30-day reconciliation period pursuant to the procedures in § 157.205(f).
(w) Take appropriate action on the following:
(1) Any notice of intervention or petition to intervene, filed in an uncontested application for pipeline facilities;
(2) An uncontested request from one holding an authorization, granted pursuant to the Director’s delegated authority, to vacate all or part of such authorization;
(3) Petitions to permit after an initial 60-day period one additional 60-day period of exemption pursuant to § 284.264(b) of this chapter where the application or extension arrives at the Commission later than 45 days after the commencement of the initial period of exemption when the emergency requires installation of facilities;
(4) Applications for extensions of time to file required reports, data, and information and to perform other acts required at or within a specific time by any rule, regulation, license, permit, certificate, or order by the Commission; and
(5) Requests for waiver of the landowner notification requirements in § 157.203(d) of this chapter.
(x) Undertake the following actions:
(1) Compute, for each calendar year, the project limits specified in table I of § 157.208 and table II of § 157.215(a) of this chapter, adjusted for inflation, and publish such limits as soon as possible thereafter in the
(2) Issue reports for public information purposes. Any report issued without Commission approval must:
(i) Be of a noncontroversial nature, and
(ii) Contain the statement, “This report does not necessarily reflect the view of the Commission,” in bold face type on the cover;
(3) Issue and sign deficiency letters regarding natural gas applications;
(4) Accept for filing, data and reports required by Commission orders, or presiding officers’ initial decisions upon which the Commission has taken no further action, if such filings are in compliance with such orders or decisions and, when appropriate, notify the filing party of such acceptance;
(5) Reject requests which patently fail to comply with the provisions of 157.205(b) of this chapter;
(6) Take appropriate action on requests or petitions for waivers of any action incidental to the exercise of delegated authority, including waiver of notice as provided in section 4(d) of the Natural Gas Act, provided the request conforms to the requirements of § 385.2001 of this chapter; and
(7) Take whatever steps are necessary to ensure the protection of all environmental resources during the construction or operation of natural gas facilities, including authority to design and implement additional or alternative measures and stop work authority.
(y) Take appropriate action on the following:
(1) Any action incidental to the exercise of delegated authority, including waiver of notice as provided in section 4(d) of the Natural Gas Act, provided the request conforms to the requirements of § 385.2001 of this chapter; and
(2) Requests or petitions for waivers of filing requirements for statements and reports under §§ 260.8 and 260.9 of this chapter.
(z) Approve, on a case-specific basis, and make such decisions and issue guidance as may be necessary in connection with the use of the pre-filing procedures in § 157.21, “ Pre-filing procedures and review process for LNG terminal facilities and other natural gas facilities prior to filing of applications.”
(aa) Take the following actions to implement part 5 of this chapter on or after October 23, 2003:
(1) Act on requests for approval to use the application procedures of parts 4 or 16, pursuant to § 5.3 of this chapter;
(2) Approve a potential license applicant’s proposed study plan with appropriate modifications pursuant to § 5.13 of this chapter;
(3) Resolve formal study disputes pursuant to § 5.14 of this chapter; and
(4) Resolve disagreements brought pursuant to § 5.15 of this chapter.
(bb) Establish a schedule for each Federal agency or officer, or State agency or officer acting pursuant to delegated Federal authority, to issue or deny Federal authorizations required for natural gas projects subject to section 3 or 7 of the Natural Gas Act.
§ 375.309 Delegations to the General Counsel.
The Commission authorizes the General Counsel or the General Counsel’s designee to:
(a) Designate officers empowered to administer oaths and affirmations, subpoena witnesses, compel their attendance and testimony, take evidence, compel the filing of special reports and interrogatories, gather information, and require the production of any books, papers, correspondence, memoranda, contracts, agreements, or other records, in the course of formal investigations conducted by the Office of the General Counsel to the extent the Commission’s order of investigation expressly provides for the exercise of such investigative powers.
(b) Grant or deny requests of persons pursuant to § 1b.12 of this chapter to procure copies of the transcripts of their testimony taken during non-public investigations conducted by the Office of the General Counsel.
(c) Terminate any informal non-public investigation conducted by the Office of the General Counsel.
(d) Terminate the authority of officers to administer oaths and affirmations, subpoena witnesses, compel their attendance and testimony, take evidence, compel the filing of special reports and interrogatories, gather information, and require the production of any books, papers, correspondence, memoranda, contracts, agreements or other records in the course of formal investigations conducted by the Office of the General Counsel.
(e) Designate presiding officers for proceedings under § 385.1110, who will have all the authorities and duties vested in presiding officers by that section and other applicable rules in conducting proceedings pursuant to section 502(c) of the Natural Gas Policy Act of 1978, 15 U.S.C. 3301–3432 (1982).
(f) Deny or grant, in whole or in part, petitions for waivers of fees prescribed in § 381.305 of this chapter in accordance with § 381.106 of this chapter.
(g) Grant uncontested applications for exempt wholesale generator status that do not involve unusual or interpretation issues; to act on uncontested motions to withdraw such applications; and to act on uncontested amendments to applications for EWG status that do not present unusual or interpretation issues.
(h) Deny or grant, in whole or in part, an appeal of a determination by the CEII Coordinator.
(i) Deny or grant, in whole or in part, an appeal of a Freedom of Information Act determination by the Director of the Office of External Affairs.
§ 375.310 Delegations during emergency conditions.
For delegations of Commission authority during emergency conditions, see subpart B of part 376 of this chapter.
§ 375.311 Delegations to the Director of the Office of Enforcement.
The Commission authorizes the Director or the Director’s designee to:
(a) Request information for purposes of a preliminary investigation under Part 1b of this chapter, or for purposes of conducting market surveillance from an entity whose activities may affect energy markets, and from state or federal agencies that monitor or regulate such entities, whether or not subject to the Commission’s jurisdiction.
(b) Designate, and terminate the authority of, officers empowered to administer oaths and affirmations, subpoena witnesses, compel their attendance and testimony, take evidence, compel the filing of special reports and responses to interrogatories, gather information, and require the production of any books, papers, correspondence, memoranda, contracts, agreements, or other records, in the course of formal investigations conducted by the Office of Enforcement, to the extent the Commission’s order of investigation expressly provides for the exercise of such investigative powers.
(c) Grant or deny requests of persons pursuant to § 1b.12 of this chapter to procure copies of the transcripts of their testimony taken during non-public investigations conducted by the Office of Enforcement.
(d) Terminate any informal non-public investigation conducted by the Office of Enforcement.
(e) Issue reports for public information purposes. Any report issued without Commission approval must
(1) Be of a non-controversial nature, and
(2) Contain the statement, “This report does not necessarily reflect the view of the Commission,” in bold-face type on the cover.
(f) Deny or grant, in whole or in part, requests for waiver of the requirements for particular forms, including Electric Quarterly Reports required under § 35.10b of this chapter.
(g) Take appropriate action on applications for extensions of time to file required reports, data and information, and to perform other acts required at or within a specific time by any rule, regulation, license, permit, certificate, or by order of the Commission.
(h) Undertake the following action with respect to data and reports submitted pursuant to Commission opinions or orders:
(1) Accept for filing data and reports that are in compliance and, when appropriate, notify the filing party of such acceptance;
(2) Reject for filing any data and reports which are not in compliance or not required and, when appropriate, notify the filing party of such rejection, or
(3) Issue deficiency letters regarding such data or reports.
(i) Sign all correspondence on behalf of the Commission with state regulatory commissions and agencies in connection with auditing matters.
(j) Pass upon actual legitimate original cost and depreciation thereon and the net investment in jurisdictional companies and revisions thereof, and sign audit reports involving jurisdictional companies,
(1) If the company agrees with the audit report, or
(2) If the company does not agree with the audit report, provided that any notification of the opportunity for a hearing required under Section 301(a) of the Federal Power Act or Section 8(a) of the Natural Gas Act accompanies the audit report.
(k) Act upon requests by state and federal agencies to review staff audit working papers in connection with audits if the company agrees to the release of the audit working papers, and provided that:
(1) The papers are examined at the Commission; and
(2) The requester
(i) Only makes general notes concerning the contents of the audit working papers,
(ii) Does not make copies of the audit working papers, and
(iii) Does not remove the audit working papers from the area designated by the Director.
(l) With regard to billing errors noted as a result of the Commission staff’s examination of automatic adjustment tariffs approved by the Commission, approve corrective measures, including recomputation of billings and refunds, to the extent the company agrees.
(m) Sign all correspondence with respect to financial accounting and reporting matters on behalf of the Commission.
(n) Pass upon actual legitimate original cost and depreciation thereon and the net investment in jurisdictional companies and revisions thereof.
(o) Issue interpretations of the Uniform Systems of Accounts for public utilities and licensees, centralized service companies, natural gas companies and oil pipeline companies.
(p) Pass upon any proposed accounting matters submitted by or on behalf of jurisdictional companies that require Commission approval under the Uniform Systems of Accounts, except that if the proposed accounting matters involve unusually large transactions or unique or controversial features, the Director of the Office of Enforcement must present the matters to the Commission for consideration.
(q) Pass upon applications to increase the size or combine property units of jurisdictional companies.
(r) Deny or grant, in whole or in part, motions for extension of time to file, or requests for waiver of the requirements of the following forms, data collections, and reports: Annual Reports (Form Nos. 1, 1–F, 2, 2–A, and 6); Quarterly Reports (Form Nos. 3–Q and 6–Q); Annual Report of Centralized Service Companies (Form No. 60); Narrative Description of Service Company Functions (FERC–61); and Electric Quarterly Reports, as well as, where required, the electronic filing of such information (§ 385.2011 of this chapter, Procedures for filing on electronic media, paragraphs (a)(6), (c), and (e)).
(s) Provide notification if a submitted Annual Report (Form Nos. 1, 1–F, 2, 2–A, and 6), Quarterly Report (Form Nos. 3–Q and 6–Q), Annual Report of Centralized Service Companies (Form No. 60), Narrative Description of Service Company Functions (FERC–61), or Electric Quarterly Report fails to comply with applicable statutory requirements, and with all applicable Commission rules, regulations, and orders for which a waiver has not been granted, or, when appropriate, notify a party that a submission is acceptable.
(t) Deny or grant, in whole or in part, requests for waiver of the requirements of parts 352, 356, 367 and 368 of this chapter, except that, if the matters involve unusually large transactions or unique or controversial features, the Director of the Office of Enforcement must present the matters to the Commission for consideration.
§ 375.312 Delegations to the Office of the Executive Director.
The Commission authorizes the Executive Director or the Executive Director’s designee to:
(a) Prescribe the updated fees for part 381 of this chapter in accordance with § 381.104 of this chapter.
(b) Prescribe the updated fees for part 381 of this chapter in accordance with § 388.109(b)(2) of this chapter.
(c) Deny or grant, in whole or in part, petitions for waiver of fees prescribed in § 381.302 of this chapter in accordance with § 381.106(b) of this chapter.
(d) Deny or grant, in whole or in part, petitions for exemption from fees prescribed in part 381 of this chapter in accordance with § 381.108 of this chapter.
(e) Determine the annual charges for administrative costs, for use of United States lands, and for use of government dams or other structures.
(f) Grant or deny waiver of penalty charges for late payment of annual charges.
(g) Give credit for overpayment of annual charges.
(h) Deny or grant, in whole or in part, petitions for exemption from annual charges under § 11.6 of this chapter for state and municipal licensees.
(i) Grant or deny petitions for waiver of annual charges for oil pipelines.
§ 375.313 Delegations to the Critical Energy/Electric Infrastructure Information (CEII) Coordinator.
The Commission authorizes the Coordinator or the Coordinator’s designee to:
(a) Receive and review all requests for CEII as defined in § 388.113(c) of this chapter.
(b) Make determinations as to whether particular information fits within the definition of CEII found at § 388.113(c) of this chapter, including designating information, as appropriate.
(c) Make determinations that information designated as CEII should no longer be so designated when the unauthorized disclosure of the information could no longer be used to impair the security or reliability of the bulk-power system or distribution facilities or any other form of energy infrastructure.
(d) Make determinations as to whether a particular requester’s need for and ability and willingness to protect CEII warrants limited disclosure of the information to the requester.
(e) Establish reasonable conditions on the release of CEII.
(f) Release CEII to requesters who satisfy the requirements in paragraph (d) of this section and agree in writing to abide by any conditions set forth by the Coordinator pursuant to paragraph (e) of this section.
§ 375.315 Delegations to the Director of the Office of Energy Policy and Innovation.
The Commission authorizes the Director or the Director’s designee to:
(a) Take appropriate action on:
(1) Any notice of intervention or motion to intervene, filed in an uncontested proceeding processed by the Office of Energy Policy and Innovation;
(2) Applications or motions for extensions of time to file required filings, reports, data and information and to perform other acts required at or within a specific time by any rule, regulation, license, permit, certificate, or order by the Commission, including applications or motions for extensions of time to file the Annual Report of Natural Gas Transactions (FERC Form No. 552) and the Report of Transmission Investment Activity (FERC–730); and
(3) Requests or petitions for waiver of the requirements of the Annual Report of Natural Gas Transactions (FERC Form No. 552) and the Report of Transmission Investment Activity (FERC–730).
(4) Notification to a party if a submitted Annual Report of Natural Gas Transactions (FERC Form No. 552) or Report of Transmission Investment Activity (FERC–730) fails to comply with applicable statutory requirements, and with all applicable Commission rules, regulations, and orders for which a waiver has not been granted, or, when appropriate notify a party that a submission is acceptable.
(b) Undertake the following actions:
(1) Issue reports for public information purposes. Any report issued without Commission approval must:
(i) Be of a noncontroversial nature, and
(ii) Contain the statement, “This report does not necessarily reflect the views of the Commission,” in bold face type on the cover;
(2) Issue and sign requests for additional information regarding applications, filings, reports and data processed by the Office of Energy Policy and Innovation; and
(3) Accept for filing, data and reports required by Commission regulations, rules, or orders, or presiding officers’ initial decisions upon which the Commission has taken no further action, if such filings are in compliance with such regulations, rules, orders or decisions and, when appropriate, notify the filing party of such acceptance.
PART 376—ORGANIZATION, MISSION, AND FUNCTIONS; OPERATIONS DURING EMERGENCY CONDITIONS
Subpart A—Organization, Mission, and Functions
§ 376.101 Purpose.
This subpart sets forth the organization, mission and functions of the Commission, and its offices and divisions.
§ 376.102 Organization.
The Commission is established as an independent regulatory Commission within the DOE by the DOE Act. The Commission is composed of five members appointed by the President, by and with the advice and consent of the Senate. One of the members is designated by the President as the Chairman. To carry out its mission and functions, the Chairman has organized the Commission into a number of major offices, some of which are further organized into divisions and lower units. The organization of the Commission staff structure may be obtained from the Division of Public Information.
§ 376.103 Mission.
The Commission is responsible for developing, managing, and directing energy regulatory programs and activities assigned to it by statute, executive orders, or by the Secretary, DOE. The Chairman serves as the chief executive officer of the Commission and is responsible for the conduct of all Commission executive and administrative functions. In carrying out its mission, the Commission and its employees are not subject to the supervision or direction of any other official of DOE.
§ 376.104 Functions.
The functions of the Commission include:
(a) All functions vested in the Commission under the DOE Act;
(b) All functions delegated to the Commission by the Secretary of Energy in accordance with the DOE Act; and
(c) All functions vested in the Commission by statute.
§ 376.105 Chairman.
(a) Administrative head of agency. The Chairman is the administrative head of the Commission.
(b) Administrative responsibilities. The Chairman is responsible on behalf of the Commission for the executive and administrative operation of the Commission, including functions of the Commission with respect to—
(1) The appointment and employment of Administrative Law Judges in accordance with the provisions of Title 5, United States Code.
(2) The selection, appointment, and fixing of the compensation of such personnel as he deems necessary.
(3) The supervision of personnel employed by or assigned to the Commission, except that each Commissioner may select and supervise personnel for his personal staff.
(4) The distribution of business among personnel and among administrative units of the Commission.
(5) The procurement of services of experts and consultants in accordance with section 3109 of Title 5, United States Code.
Subpart B—Commission Operation During Emergency Conditions
§ 376.201 Emergency condition defined.
For purposes of this subpart, emergency conditions:
(a) Shall commence:
(1) At the time of an armed attack upon the United States, or its territories or possessions;
(2) At the time the Commission is officially notified of the likelihood or imminence of such an attack; or
(3) At a time specified by the authority of the President; or
(4) At such time that the Commission’s Continuity of Operations Plan is activated; and
(b) Shall continue until the Commission is officially notified of the end of such conditions.
§ 376.202 Authority to move Commission offices.
The Commission may provide for removal of its headquarters to any location in the United States for the duration of emergency conditions. Consistent with directives of the Chairman, the Commission officer or employee in charge of a regional office of the Commission may move such office to a new location in the United States for the duration of emergency conditions.
§ 376.203 Mailing address of Commission during emergency conditions.
The Chairman may direct that during the continuance of emergency conditions, communications, filings, reports, or other submittals to the Commission shall be addressed to the Federal Energy Regulatory Commission, Official Mail and Messenger Service, United States Postal Service to such or other address as the Commission may designate.
(a) Delegation of authority to one or two Commissioners. During emergency conditions, the Commission shall function as usual, if a quorum of the Commission is available and capable of acting. If by reason of such conditions a quorum of the Commission is not available and capable of acting, all functions of the Commission are delegated to the Commissioner or Commissioners who are available and capable of acting.
(b) Delegation of authority to Commission staff. (1) When, by reason of emergency conditions, there is no Commissioner available and capable of acting, the functions of the Commission are delegated to the first five members of the Commission staff on the list set forth in paragraph (b)(2) of this section who are available and capable of acting.
(2) The list referred to in paragraph (b)(1) of this section is:
(i) General Counsel;
(ii) Executive Director;
(iii) Director of the Office of Energy Market Regulation;
(iv) Director of the Office of Energy Projects;
(v) Director of the Office of Electric Reliability;
(vi) Director of the Office of Enforcement;
(vii) Deputy General Counsels, in order of seniority;
(viii) Deputy Directors, Office of Energy Market Regulation, in order of seniority;
(ix) Deputy Directors, Office of Energy Projects, in order of seniority;
(x) Deputy Directors, Office of Electric Reliability, in order of seniority;
(xi) Deputy Directors, Office of Enforcement, in order of seniority;
(xii) Associate General Counsels and Solicitor, in order of seniority;
(xiii) In order of seniority, Assistant Directors and Division heads, Office of Energy Market Regulation; Assistant Directors and Division heads, Office of Energy Projects; Assistant Directors and Division heads, Office of Electric Reliability; Deputy Associate General Counsels; Assistant Directors and Division heads, Office of Enforcement;
(xiv) In order of seniority, Regional Engineers and Branch Chiefs of the Office of Energy Projects’ regional offices; and Deputy Division Directors and Group Managers of the Office of Electric Reliability’s regional offices.
(3) For purposes of paragraph (b)(2)(vii)–(xiv) of this section, order of seniority shall be based on the highest grade and longest period of service in that grade and, furthermore, for purposes of paragraph (b)(2)(xiii)–(xiv) of this section, order of seniority shall be without regard to the particular Office or Division or Branch or Group to which the member of staff is assigned.
(c) Devolution of authority to Commission staff during emergencies affecting the National Capital Region. (1) To the extent not otherwise provided by this section, during emergency conditions when the Chairman is not available and capable of acting, when no Commissioner is available and capable of acting, and when no person listed in paragraph (b)(2)(i) through (xiii) of this section who is located in the National Capital Region is available and capable of acting, the functions of the Commission are delegated, in order of seniority (as described in paragraph (b)(3) of this section), to Regional Engineers and Branch Chiefs of the Office of Energy Projects’ regional offices and Deputy Division Directors and Group Managers of the Office of Electric Reliability’s regional offices.
(2) Such delegation shall continue until such time as the Chairman is available and capable of acting, one or more Commissioners are available and capable of acting, or persons listed in paragraph (b)(2)(i) through (xiii) of this section who are located in the National Capital Region are available and capable of acting.
(d) Reconsideration of staff action taken under delegations. Action taken pursuant to the delegations provided for in this section shall be subject to reconsideration by the Commission, acting with a quorum, within thirty days after the date upon which public notice is given that a quorum of the Commission has been reconstituted and is functioning.
When, by reason of emergency conditions, the Chairman is not available and capable of acting, his functions are delegated to the Commissioner available and capable of acting and who is designated by the President. Until such time as the President designates, or if no such Commissioner is designated, such functions are delegated to the Commissioner designated by the Chairman as Acting Chairman, but if such Acting Chairman is not available and capable of acting such functions are delegated to the Commissioner who is available and capable of acting and who has the longest tenure as a member of the Commission. If there is no Commissioner available and capable of acting, such functions are delegated to the person on the Commission staff who is available and capable of acting and who is highest on the list set forth in § 376.204(b)(2).
§ 376.206 Delegation of functions of certain Commission staff members.
When, by reason of emergency conditions, the Secretary, Director of any Office or Division, or officer in charge of a regional office, is not available and capable of carrying out his or her functions, such functions are delegated to staff members designated by the Chairman to perform such functions. If no staff member so designated is available and capable of carrying out their functions, such functions are delegated to the next subordinate employee in the Office or Division of the highest grade and longest period of service in that grade. If no subordinate employee of the Office or Division is available and capable of carrying out their functions, such functions are delegated to the Commission employee of the highest grade and longest period of service in that grade who is available and capable of carrying out their functions.
§ 376.207 Personnel and fiscal functions.
Subject to modifications or revocation by authority of the Executive Director, during the continuation of emergency conditions authority to effect temporary appointments of such additional officers and employees, to classify and allocate positions to their proper grades, to issue travel orders, and to effect emergency purchases of supplies, equipment and services shall be exercised by the respective Directors of Offices and officials in charge of regional offices, their deputies, or staff in line of succession, as may be required for the discharge of the lawful duties of such organization.
§ 376.208 Effect upon existing Commission requirements.
All outstanding Commission orders, rules and regulations shall remain in force and effect during the continuance of emergency conditions, except to the extent modified in accordance with authority exercised under this subpart.
§ 376.209 Continuity of Operations Plan and suspension of Commission operations.
(a)(1)(i) Activation of COOP and suspension of Commission operations. The Commission’s Continuity of Operations Plan may be activated by the Chairman (or the Chairman’s delegate pursuant to § 376.205, as appropriate). In circumstances in which the Commission’s Continuity of Operations Plan is activated, Commission headquarters operations may be temporarily disrupted in whole or in part or communications with Commission headquarters may be temporarily unavailable, either of which may prevent the public or the Commission from meeting regulatory or statutory requirements. After the Commission’s Continuity of Operations Plan is activated, Commission operations other than emergency functions may be suspended in whole or in part by the Chairman (or the Chairman’s delegate, as appropriate). The provisions of this section are effective upon activation of the Continuity of Operations Plan and the subsequent suspension of Commission operations, in whole or in part, and shall remain in effect up to 30 days, or such shorter time than 30 days as the Chairman (or the Chairman’s delegate, as appropriate) determines to be appropriate, or such longer time than 30 days as the Commission (or the Commission’s delegate pursuant to section 376.204 of this Part, as appropriate) determines to be appropriate. Resumption of Commission operations following activation of the Continuity of Operations Plan and any subsequent suspension of Commission operations, in whole or in part, may occur either simultaneously for all activities, or over time for just some activities, and in such manner and at such time, as the Chairman (or the Chairman’s delegate, as appropriate) or the Commission (or the Commission’s delegate, as appropriate) determines to be appropriate.
(ii) Notification of COOP activation and, following such activation, notification of suspension of Commission operations. During periods when the Commission’s Continuity of Operations Plan is activated and, following such activation, when Commission operations are subsequently suspended in whole or in part, the Chairman (or the Chairman’s delegate pursuant to § 376.205, as appropriate) will notify the public that the Continuity of Operations Plan has been activated and that Commission operations have been suspended in whole or in part by sending a press release announcing that fact to major wire services, industry press, and appropriate metropolitan area radio stations The Commission’s Web site (http://www.ferc.gov) or the Commission’s alternative Web site (http://www.fercalt.gov), as appropriate, will be activated and a notice that the Continuity of Operations Plan has been activated and that Commission operations have been suspended in whole or in part will be prominently displayed thereon. The Web site or alternative Web site, as appropriate, will act as a resource for the press, industry, and general public. An additional press release will be sent to appropriate media outlets and a notice will be prominently displayed on the Commission’s Web site or alternative Web site, as appropriate, when the Continuity of Operations Plan is deactivated and the Commission’s headquarters are reopened or reconstituted and Commission operations resume.
(2) Activities continued during COOP. Notwithstanding other provisions of this section, during periods when the Commission’s Continuity of Operations Plan is activated and, following such activation, when Commission operations are subsequently suspended in whole or in part, the Commission will continue to conduct emergency functions. As part of its emergency functions, the Commission will act on requests to ensure continued construction of essential natural gas facilities with sensitive construction timelines, on Commencement of Service requests, and on completion of dam safety work, in a manner consistent with the maintenance of environmental protections. Also as part of its emergency functions, the Commission will ensure that its personnel are available to respond to plant accidents or reportable incidents at LNG facilities, and to address dam safety, public safety, and security incidents at jurisdictional hydropower projects and to address other matters involving the safety of human life or protection of property. Alternate channels of communication will include measures to ensure that these activities can go forward unhindered.
(b) Standards of conduct for transmission service providers. During periods when the Commission’s Continuity of Operations Plan is activated and, following such activation, when Commission operations are suspended in whole or in relevant part, a Transmission Provider affected by the same emergency affecting the Commission may, for up to 30 days, or such other time as the Chairman (or the Chairman’s delegate pursuant to § 376.205, as appropriate) may direct, delay compliance with the requirement to report to the Commission each emergency that resulted in any deviation from the standards of conduct within 24 hours of such deviation. If the emergency prevents such Transmission Provider from posting information on its OASIS or Internet Web site, the Transmission Provider may, for up to 30 days, or such shorter time as the Chairman (or the Chairman’s delegate, as appropriate) may direct or such longer time as the Commission (or the Commission’s delegate pursuant to § 376.204, as appropriate) may direct, also delay compliance with the requirements of § 358.4(a)(2) of this chapter to post this information on its OASIS or Internet Web site, as applicable.
(c) Tolling of time periods for Commission action. Unless otherwise directed, for those pending matters where the date that the Commission must act falls during the period when the Continuity of Operations Plan is activated and, following such activation, when Commission operations are suspended in whole or in relevant part and also during the 14 days thereafter, the Commission tolls, for purposes of further consideration, the time period in which the Commission must act. Such matters include:
(1) 60-day period to act on requests for Exempt Wholesale Generator or Foreign Utility Company status;
(2) 90-day period for acting on requests for certification of qualifying facility status;
(3) 60-day period for acting on interlocking directorate applications;
(4) 60-day period for acting on Public Utility Holding Company Act exemptions and waivers;
(5) 180-period for acting on applications under section 203 of the Federal Power Act;
(6) 150-day period for acting on intrastate pipeline applications for approval of proposed rates;
(7) Period ending 60 days prior to the Electric Reliability Organization’s (ERO) fiscal year for acting on the ERO’s budget;
(8) 60-day period for acting on notifications that a Reliability Standard may conflict with a function, rule, order, tariff, rate schedule or agreement;
(9) 60-day period for acting on applications for review of a penalty imposed by the ERO for violation of a Reliability Standard;
(10) 45-day protest period for protesting Prior Notice Filings, and the 30-day period for resolving and filing to withdraw such Protests;
(11) 30-day period for acting on requests for rehearing;
(12) Time periods for action by a presiding officer or the Motions Commissioner, as well as by the Commission, on motions to permit interlocutory appeals, interlocutory appeals and certified questions; and
(13) 90-day period for acting on applications requesting relief from, or reinstatement of, an electric utility’s mandatory purchase obligation pursuant to section 210(m) of the Public Utility Regulatory Policies Act of 1978.
(d) Suspension of certain requirements. Unless otherwise directed, during periods when the Commission’s Continuity of Operations Plan is activated and, following such activation, when Commission operations are suspended in whole or in relevant part, the requirements to file by a certain date are suspended when communications with Commission headquarters are unavailable such that filings, submissions, and notifications cannot be received by the Commission. Unless otherwise directed by the Chairman (or the Chairman’s delegate pursuant to § 376.205, as appropriate), those filings, submissions, and notifications, the filing of which was suspended, will be due the first day that communications with Commission headquarters are available such that filings, submissions, and notifications can be received by the Commission. Such filings, submissions, and notifications include:
(1) Filings to comply with orders or notices, including orders or notices issued by the Commission, a presiding officer, and a Commission decisional employee (including the directors of the Commission’s various offices and their delegates);
(2) Filings required to be made by a date certain either under the Commission’s regulations, or under orders and notices issued by the Commission, a presiding officer, and a Commission decisional employee (including the directors of the Commission’s various offices and their delegates); such filings include, e.g., briefs, motions, and answers to motions;
(3) Motions to intervene and notices of intervention, or protests;
(4) Comments responding to notices of inquiry, proposed rulemakings or technical conferences;
(5) Responses to data requests and deficiency letters issued either by the Commission or by a decisional employee pursuant to delegated authority;
(6) Self-reports of violations;
(7) Responses to staff audit reports;
(8) Contacts with the Commission’s Enforcement Hotline;
(9) Accounting filings required by the Commission’s Uniform Systems of Accounts;
(10) Forms required to be filed by a date certain;
(11) Notices of intent to file new applications and applications for new licenses pursuant to section 15 of the Federal Power Act;
(12) Requests for rehearing of orders and letter orders issued either by the Commission or by a decisional employee pursuant to delegated authority; and
(13) The Electric Reliability Organization’s advising the Commission of the Electric Reliability Organization’s intent to issue Level 1 Advisories, Level 2 Recommendations, and Level 3 Essential Actions, and the Electric Reliability Organization’s reporting to the Commission on actions taken in response to Level 2 Recommendations and Level 3 Essential Actions.
(e) Acceptance and suspension of rate and other filings. Unless otherwise directed, if the date by which the Commission is required to act on rate and other filings made pursuant to section 4 of the Natural Gas Act, section 205 of the Federal Power Act, and section 6(3) of the Interstate Commerce Act falls during a period when the Continuity of Operations Plan is activated and, following such activation, when Commission operations are suspended in whole or in relevant part and also during the 14 days thereafter, such filings shall be deemed to be accepted for filing and suspended and made effective on the requested effective date, subject to refund and further order of the Commission. The acceptance for filing and suspension of these filings is without prejudice to any further action the Commission may take with respect to these filings.
(f) Electric Reliability Organization penalties. Unless otherwise directed, if the date a penalty imposed by the Electric Reliability Organization under section 215 of the Federal Power Act would take effect falls during a period when the Continuity of Operations Plan is activated and, following such activation, when Commission operations are suspended in whole or in relevant part and also during the 14 days thereafter, review of such penalty by the Commission shall be deemed to be initiated and the penalty shall be stayed pending further action of the Commission.
(g) Consistency of State action with Reliability Standard. Unless otherwise directed, if the date by which a Commission determination under section 215 of the Federal Power Act as to whether a State action is inconsistent with a Reliability Standard is required to be made falls during a period when the Continuity of Operations Plan is activated and, following such activation, when Commission operations are suspended in whole or in relevant part and also during the 14 days thereafter, the effectiveness of the State action will be deemed to be stayed pending further action by the Commission.
(h) Suspension of evidentiary hearings and related conferences and meetings. During periods when the Continuity of Operations Plan is activated and, following such activation, when Commission operations are suspended in whole or in relevant part, all evidentiary hearings, prehearing conferences, settlement conferences, and other meetings before presiding officers are suspended, and any requirement that a presiding officer act on motions (including motions to permit interlocutory appeals and to certify questions) is also suspended. Service of data requests and other discovery, and responses thereto, by and to the Commission’s Trial Staff is similarly suspended. Upon resumption of Commission operations in whole or in relevant part, such hearings, conferences and other meetings will be rescheduled, action on motions also will be rescheduled, and service of data requests and other discovery, and responses thereto, by and to the Commission’s Trial Staff, will similarly be rescheduled, by the presiding officer or the Commission, as appropriate.
(i) Enforcement Actions under the Public Utility Regulatory Policies Act of 1978. Unless otherwise directed, if the date by which the Commission is required to act on a petition for enforcement action under section 210(h)(2) of the Public Utility Regulatory Policies Act of 1978 falls during a period when the Continuity of Operations Plan is activated and, following such activation, when Commission operations are suspended in whole or in relevant part, and also during the 14 days thereafter, the Commission will not initiate such an enforcement action under section 210(h)(2) of the Public Utility Regulatory Policies Act of 1978 and the petitioner may itself bring its own enforcement action in the appropriate court.
(j) Chairman’s and Commission’s authority to modify deadlines and timeframes. During periods when the Continuity of Operations Plan is activated and, following such activation, when Commission operations are suspended in whole or in part and also during the 14 days thereafter, the Chairman (or the Chairman’s delegate pursuant to § 376.205, as appropriate), may shorten, and the Commission (or the Commission’s delegate pursuant to § 376.204, as appropriate) may extend, with respect to the matters addressed in this section, as appropriate:
(1) The time periods and dates for filings with the Commission, a decisional employee, or a presiding officer;
(2) The time periods and dates for reports, submissions and notifications to the Commission, a decisional employee, or a presiding officer; and
(3) The time periods and dates for actions by the Commission, a decisional employee, or a presiding officer.
PART 380—REGULATIONS IMPLEMENTING THE NATIONAL ENVIRONMENTAL POLICY ACT
§ 380.1 Purpose.
The regulations in this part implement the Federal Energy Regulatory Commission’s procedures under the National Environmental Policy Act of 1969 (NEPA). These regulations supplement the regulations of the Council on Environmental Quality, 40 CFR parts 1500 through 1508. The Commission will comply with the regulations of the Council on Environmental Quality except where those regulations are inconsistent with the statutory requirements of the Commission.
§ 380.2 Definitions and terminology.
For purposes of this part—
(a) Categorical exclusion means a category of actions described in § 380.4, which do not individually or cumulatively have a significant effect on the human environment and which the Commission has found to have no such effect and for which, therefore, neither an environmental assessment nor an environmental impact statement is required. The Commission may decide to prepare environmental assessments for the reasons stated in § 380.4(b).
(b) Commission means the Federal Energy Regulatory Commission.
(c) Council means the Council on Environmental Quality.
(d) Environmental assessment means a concise public document for which the Commission is responsible that serves to:
(1) Briefly provide sufficient evidence and analysis for determining whether to prepare an environmental impact statement or a finding of no significant impact.
(2) Aid the Commission’s compliance with NEPA when no environmental impact statement is necessary.
(3) Facilitate preparation of a statement when one is necessary. Environmental assessments must include brief discussions of the need for the proposal, of alternatives as required by section 102(2)(E) of NEPA, of the environmental impacts of the proposed action and alternatives, and a listing of agencies and persons consulted.
(e) Environmental impact statement (EIS) means a detailed written statement as required by section 102(2)(C) of NEPA. DEIS means a draft EIS and FEIS means a final EIS.
(f) Environmental report or ER means that part of an application submitted to the Commission by an applicant for authorization of a proposed action which includes information concerning the environment, the applicant’s analysis of the environmental impact of the action, or alternatives to the action required by this or other applicable statutes or regulations.
(g) Finding of no significant impact (FONSI) means a document by the Commission briefly presenting the reason why an action, not otherwise excluded by § 380.4, will not have a significant effect on the human environment and for which an environmental impact statement therefore will not be prepared. It must include the environmental assessment or a summary of it and must note other environmental documents related to it. If the assessment is included, the FONSI need not repeat any of the discussion in the assessment but may incorporate it by reference.
§ 380.3 Environmental information to be supplied by an applicant.
(a) An applicant must submit information as follows:
(1) For any proposed action identified in §§ 380.5 and 380.6, an environmental report with the proposal as prescribed in paragraph (c) of this section.
(2) For any proposal not identified in paragraph (a)(1) of this section, any environmental information that the Commission may determine is necessary for compliance with these regulations, the regulations of the Council, NEPA and other Federal laws such as the Endangered Species Act, the National Historic Preservation Act or the Coastal Zone Management Act.
(b) An applicant must also:
(1) Provide all necessary or relevant information to the Commission;
(2) Conduct any studies that the Commission staff considers necessary or relevant to determine the impact of the proposal on the human environment and natural resources;
(3) Consult with appropriate Federal, regional, State, and local agencies during the planning stages of the proposed action to ensure that all potential environmental impacts are identified. (The specific requirements for consultation on hydropower projects are contained in § 4.38 and § 16.8 of this chapter and in section 4(a) of the Electric Consumers Protection Act, Pub. L. No. 99–495, 100 Stat. 1243, 1246 (1986));
(4) Submit applications for all Federal and State approvals as early as possible in the planning process; and
(5) Notify the Commission staff of all other Federal actions required for completion of the proposed action so that the staff may coordinate with other interested Federal agencies.
(c) Content of an applicant’s environmental report for specific proposals—(1) Hydropower projects. The information required for specific project applications under part 4 or 16 of this chapter.
(2) Natural gas projects. (i) For any application filed under the Natural Gas Act for any proposed action identified in §§ 380.5 or 380.6, except for prior notice filings under § 157.208, as described in § 380.5(b), the information identified in § 380.12 and Appendix A of this part.
(ii) For prior notice filings under § 157.208, the report described by § 157.208(c)(11) of this chapter.
(3) Electric transmission project. For pre-filing requests and applications filed under section 216 of the Federal Power Act identified in §§ 380.5(b)(14) and 380.6(a)(5).
§ 380.4 Projects or actions categorically excluded.
(a) General rule. Except as stated in paragraph (b) of this section, neither an environmental assessment nor an environmental impact statement will be prepared for the following projects or actions:
(1) Procedural, ministerial, or internal administrative and management actions, programs, or decisions, including procurement, contracting, personnel actions, correction or clarification of filings or orders, and acceptance, rejection and dismissal of filings;
(2)(i) Reports or recommendations on legislation not initiated by the Commission, and
(ii) Proposals for legislation and promulgation of rules that are clarifying, corrective, or procedural, or that do not substantially change the effect of legislation or regulations being amended;
(3) Compliance and review actions, including investigations (jurisdictional or otherwise), conferences, hearings, notices of probable violation, show cause orders, and adjustments under section 502(c) of the Natural Gas Policy Act of 1978 (NGPA);
(4) Review of grants or denials by the Department of Energy (DOE) of any adjustment request, and review of contested remedial orders issued by DOE;
(5) Information gathering, analysis, and dissemination;
(6) Conceptual or feasibility studies;
(7) Actions concerning the reservation and classification of United States lands as water power sites and other actions under section 24 of the Federal Power Act;
(8) Transfers of water power project licenses and transfers of exemptions under Part I of the Federal Power Act and Part 9 of this chapter;
(9) Issuance of preliminary permits for water power projects under Part I of the Federal Power Act and Part 4 of this chapter;
(10) Withdrawals of applications for certificates under the Natural Gas Act, or for water power project preliminary permits, exemptions, or licenses under Part I of the Federal Power Act and Part 4 of this chapter;
(11) Actions concerning annual charges or headwater benefits, charges for water power projects under Parts 11 and 13 of this chapter and establishment of fees to be paid by an applicant for a license or exemption required to meet the terms and conditions of section 30(c) of the Federal Power Act;
(12) Approval for water power projects under Part I of the Federal Power Act, of “as built” or revised drawings or exhibits that propose no changes to project works or operations or that reflect changes that have previously been approved or required by the Commission;
(13) Surrender and amendment of preliminary permits, and surrender of water power licenses and exemptions where no project works exist or ground disturbing activity has occurred and amendments to water power licenses and exemptions that do not require ground disturbing activity or changes to project works or operation;
(14) Exemptions for small conduit hydroelectric facilities as defined in § 4.30(b)(30) of this chapter under Part I of the Federal Power Act and Part 4 of this chapter;
(15) Electric rate filings submitted by public utilities under sections 205 and 206 of the Federal Power Act, the establishment of just and reasonable rates, and confirmation, approval, and disapproval of rate filings submitted by Federal power marketing agencies under the Pacific Northwest Electric Power Planning and Conservation Act, the Department of Energy Organization Act, and DOE Delegation Order No. 0204–108.
(16) Approval of actions under sections 4(b), 203, 204, 301, 304, and 305 of the Federal Power Act relating to issuance and purchase of securities, acquisition or disposition of property, merger, interlocking directorates, jurisdictional determinations and accounting orders;
(17) Approval of electrical interconnections and wheeling under sections 202(b), 210, 211, and 212 of the Federal Power Act, that would not entail:
(i) Construction of a new substation or expansion of the boundaries of an existing substation;
(ii) Construction of any transmission line that operates at more than 115 kilovolts (KV) and occupies more than ten miles of an existing right-of-way; or
(iii) Construction of any transmission line more than one mile long if located on a new right-of-way;
(18) Approval of changes in land rights for water power projects under Part I of the Federal Power Act and Part 4 of this chapter, if no construction or change in land use is either proposed or known by the Commission to be contemplated for the land affected;
(19) Approval of proposals under Part I of the Federal Power Act and Part 4 of this chapter to authorize use of water power project lands or waters for gas or electric utility distribution lines, radial (sub-transmission) lines, communications lines and cables, storm drains, sewer lines not discharging into project waters, water mains, piers, landings, boat docks, or similar structures and facilities, landscaping or embankments, bulkheads, retaining walls, or similar shoreline erosion control structures;
(20) Action on applications for exemption under section 1(c) of the Natural Gas Act;
(21) Approvals of blanket certificate applications and prior notice filings under § 157.204 and §§ 157.209 through 157.218 of this chapter;
(22) Approvals of blanket certificate applications under §§ 284.221 through 284.224 of this chapter;
(23) Producers’ applications for the sale of gas filed under §§ 157.23 through 157.29 of this chapter;
(24) Approval under section 7 of the Natural Gas Act of taps, meters, and regulating facilities located completely within an existing natural gas pipeline right-of-way or compressor station if company records show the land use of the vicinity has not changed since the original facilities were installed, and no significant nonjurisdictional facilities would be constructed in association with construction of the interconnection facilities;
(25) Review of natural gas rate filings, including any curtailment plans other than those specified in § 380.5(b)(5), and establishment of rates for transportation and sale of natural gas under sections 4 and 5 of the Natural Gas Act and sections 311 and 401 through 404 of the Natural Gas Policy Act of 1978;
(26) Review of approval of oil pipeline rate filings under Parts 340 and 341 of this chapter;
(27) Sale, exchange, and transportation of natural gas under sections 4, 5 and 7 of the Natural Gas Act that require no construction of facilities;
(28) Abandonment in place of a minor natural gas pipeline (short segments of buried pipe of 6-inch inside diameter or less), or abandonment by removal of minor surface facilities such as metering stations, valves, and taps under section 7 of the Natural Gas Act so long as appropriate erosion control and site restoration takes place;
(29) Abandonment of service under any gas supply contract pursuant to section 7 of the Natural Gas Act;
(30) Approval of filing made in compliance with the requirements of a certificate for a natural gas project under section 7 of the Natural Gas Act or a preliminary permit, exemption, license, or license amendment order for a water power project under Part I of the Federal Power Act;
(31) Abandonment of facilities by sale that involves only minor or no ground disturbance to disconnect the facilities from the system;
(32) Conversion of facilities from use under the NGPA to use under the NGA;
(33) Construction or abandonment of facilities constructed entirely in Federal offshore waters that has been approved by the Minerals Management Service and the Corps of Engineers, as necessary;
(34) Abandonment or construction of facilities on an existing offshore platform;
(35) Abandonment, construction or replacement of a facility (other than compression) solely within an existing building within a natural gas facility (other than LNG facilities), if it does not increase the noise or air emissions from the facility, as a whole; and
(36) Conversion of compression to standby use if the compressor is not moved, or abandonment of compression if the compressor station remains in operation.
(b) Exceptions to categorical exclusions. (1) In accordance with 40 CFR 1508.4, the Commission and its staff will independently evaluate environmental information supplied in an application and in comments by the public. Where circumstances indicate that an action may be a major Federal action significantly affecting the quality of the human environment, the Commission:
(i) May require an environmental report or other additional environmental information, and
(ii) Will prepare an environmental assessment or an environmental impact statement.
(2) Such circumstances may exist when the action may have an effect on one of the following:
(i) Indian lands;
(ii) Wilderness areas;
(iii) Wild and scenic rivers;
(iv) Wetlands;
(v) Units of the National Park System, National Refuges, or National Fish Hatcheries;
(vi) Anadromous fish or endangered species; or
(vii) Where the environmental effects are uncertain.
§ 380.5 Actions that require an environmental assessment.
(a) An environmental assessment will normally be prepared first for the actions identified in this section. Depending on the outcome of the environmental assessment, the Commission may or may not prepare an environmental impact statement. However, depending on the location or scope of the proposed action, or the resources affected, the Commission may in specific circumstances proceed directly to prepare an environmental impact statement.
(b) The projects subject to an environmental assessment are as follows:
(1) Except as identified in §§ 380.4, 380.6 and 2.55 of this chapter, authorization for the site of new gas import/export facilities under DOE Delegation No. 0204–112 and authorization under section 7 of the Natural Gas Act for the construction, replacement, or abandonment of compression, processing, or interconnecting facilities, onshore and offshore pipelines, metering facilities, LNG peak-shaving facilities, or other facilities necessary for the sale, exchange, storage, or transportation of natural gas;
(2) Prior notice filings under § 157.208 of this chapter for the rearrangement of any facility specified in §§ 157.202 (b)(3) and (6) of this chapter or the acquisition, construction, or operation of any eligible facility as specified in §§ 157.202 (b)(2) and (3) of this chapter;
(3) Abandonment or reduction of natural gas service under section 7 of the Natural Gas Act unless excluded under § 380.4 (a)(21), (28) or (29);
(4) Except as identified in § 380.6, conversion of existing depleted oil or natural gas fields to underground storage fields under section 7 of the Natural Gas Act.
(5) New natural gas curtailment plans, or any amendment to an existing curtailment plan under section 4 of the Natural Gas Act and sections 401 through 404 of the Natural Gas Policy Act of 1978 that has a major effect on an entire pipeline system;
(6) Licenses under Part I of the Federal Power Act and part 4 of this chapter for construction of any water power project—existing dam;
(7) Exemptions under section 405 of the Public Utility Regulatory Policies Act of 1978, as amended, and §§ 4.30(b)(31) and 4.101–4.108 of this chapter for small hydroelectric power projects of 10 MW or less;
(8) Licenses for additional project works at licensed projects under Part I of the Federal Power Act whether or not these are styled license amendments or original licenses;
(9) Licenses under Part I of the Federal Power Act and part 4 of this chapter for transmission lines only;
(10) Applications for new licenses under section 15 of the Federal Power Act;
(11) Approval of electric interconnections and wheeling under section 202(b), 210, 211, and 212 of the Federal Power Act, unless excluded under § 380.4(a)(17);
(12) Regulations or proposals for legislation not included under § 380.4(a)(2);
(13) Surrender of water power licenses and exemptions where project works exist or ground disturbing activity has occurred and amendments to water power licenses and exemptions that require ground disturbing activity or changes to project works or operations; and
(14) Except as identified in § 380.6, authorization to site new electric transmission facilities under section 216 of the Federal Power Act and DOE Delegation Order No. 00–004.00A.
§ 380.6 Actions that require an environmental impact statement.
(a) Except as provided in paragraph (b) of this section, an environmental impact statement will normally be prepared first for the following projects:
(1) Authorization under sections 3 or 7 of the Natural Gas Act and DOE Delegation Order No. 0204–112 for the siting, construction, and operation of jurisdictional liquefied natural gas import/export facilities used wholly or in part to liquefy, store, or regasify liquefied natural gas transported by water;
(2) Certificate applications under section 7 of the Natural Gas Act to develop an underground natural gas storage facility except where depleted oil or natural gas producing fields are used;
(3) Major pipeline construction projects under section 7 of the Natural Gas Act using rights-of-way in which there is no existing natural gas pipeline;
(4) Licenses under Part I of the Federal Power Act and part 4 of this chapter for construction of any unconstructed water power projects; and
(5) Major electric transmission facilities under section 216 of the Federal Power Act and DOE Delegation Order No. 00–004.00A using right-of-way in which there is no existing facility.
(b) If the Commission believes that a proposed action identified in paragraph (a) of this section may not be a major Federal action significantly affecting the quality of the human environment, an environmental assessment, rather than an environmental impact statement, will be prepared first. Depending on the outcome of the environmental assessment, an environmental impact statement may or may not be prepared.
(c) An environmental impact statement will not be required if an environmental assessment indicates that a proposal has adverse environmental affects and the proposal is not approved.
§ 380.7 Format of an environmental impact statement.
In addition to the requirements for an environmental impact statement prescribed in 40 CFR 1502.10 of the regulations of the Council, an environmental impact statement prepared by the Commission will include a section on the literature cited in the environmental impact statement and a staff conclusion section. The staff conclusion section will include summaries of:
(a) The significant environmental impacts of the proposed action;
(b) Any alternative to the proposed action that would have a less severe environmental impact or impacts and the action preferred by the staff;
(c) Any mitigation measures proposed by the applicant, as well as additional mitigation measures that might be more effective;
(d) Any significant environmental impacts of the proposed action that cannot be mitigated; and
(e) References to any pending, completed, or recommended studies that might provide baseline data or additional data on the proposed action.
§ 380.8 Preparation of environmental documents.
The preparation of environmental documents, as defined in § 1508.10 of the regulations of the Council (40 CFR 1508.10), on hydroelectric projects, natural gas facilities, and electric transmission facilities in national interest electric transmission corridors is the responsibility of the Commission’s Office of Energy Projects, 888 First Street NE., Washington, DC 20426, (202) 502–8700. Persons interested in status reports or information on environmental impact statements or other elements of the NEPA process, including the studies or other information the Commission may require on these projects, can contact this office.
(a)(1) The Commission will comply with the requirements of 40 CFR 1506.6 of the regulations of the Council for public involvement in NEPA.
(2) If an action has effects of primarily local concern, the Commission may give additional notice in a Commission order.
(b) The Commission will make environmental impact statements, environmental assessments, the comments received, and any underlaying documents available to the public pursuant to the provisions of the Freedom of Information Act (5 U.S.C. 552 (1982)). The exclusion in the Freedom of Information Act for interagency memoranda is not applicable where such memoranda transmit comments of Federal agencies on the environmental impact of the proposed action. Such materials will be made available to the public through the Commission’s website, https://www.ferc.gov, at a fee and in the manner described in part 388 of this chapter. A copy of an environmental impact statement or environmental assessment for hydroelectric projects may also be made available for inspection at the Commission’s regional office for the region where the proposed action is located.
§ 380.10 Participation in Commission proceedings.
(a) Intervention proceedings involving a party or parties—(1) Motion to intervene. (i) In addition to submitting comments on the NEPA process and NEPA related documents, any person may file a motion to intervene in a Commission proceeding dealing with environmental issues under the terms of § 385.214 of this chapter. Any person who files a motion to intervene on the basis of a draft environmental impact statement will be deemed to have filed a timely motion, in accordance with § 385.214, as long as the motion is filed within the comment period for the draft environmental impact statement.
(ii) Any person that is granted intervention after petitioning becomes a party to the proceeding and accepts the record as developed by the parties as of the time that intervention is granted.
(2)(i) Issues not set for trial-type hearing. An intervenor who takes a position on any environmental issue that has not yet been set for hearing must file a timely motion with the Secretary containing an analysis of its position on such issue and specifying any differences with the position of Commission staff or an applicant upon which the intervenor wishes to be heard at a hearing.
(ii) Issues set for trial-type hearing. (A) Any intervenor that takes a position on an environmental issue set for hearing may offer evidence for the record in support of such position and otherwise participate in accordance with the Commission’s Rules of Practice and Procedure. Any intervenor must specify any differences from the staff’s and the applicant’s positions.
(B) To be considered, any facts or opinions on an environmental issue set for hearing must be admitted into evidence and made part of the record of the proceeding.
(iii) Commission pre-filing activities commenced under §§ 157.21 and 50.5 of this chapter, respectively, are not considered proceedings under part 385 of this chapter and are not open to motions to intervene. Once an application is filed under part 157 subpart A or part 50 of this chapter, any person may file a motion to intervene in accordance with §§ 157.10 or 50.10 of this chapter or in accordance with this section.
(b) Rulemaking proceedings. Any person may file comments on any environmental issue in a rulemaking proceeding.
§ 380.11 Environmental decisionmaking.
(a) Decision points. For the actions which require an environmental assessment or environmental impact statement, environmental considerations will be addressed at appropriate major decision points.
(1) In proceedings involving a party or parties and not set for trial-type hearing, major decision points are the approval or denial of proposals by the Commission or its designees.
(2) In matters set for trial-type hearing, the major decision points are the initial decision of an administrative law judge or the decision of the Commission.
(3) In a rulemaking proceeding, the major decision points are the Notice of Proposed Rulemaking and the Final Rule.
(b) Environmental documents as part of the record. The Commission will include environmental assessments, findings of no significant impact, or environmental impact statements, and any supplements in the record of the proceeding.
(c) Application denials. Notwithstanding any provision in this part, the Commission may dismiss or deny an application without performing an environmental impact statement or without undertaking environmental analysis.
§ 380.12 Environmental reports for Natural Gas Act applications.
(a) Introduction. (1) The applicant must submit an environmental report with any application that proposes the construction, operation, or abandonment of any facility identified in § 380.3(c)(2)(i). The environmental report shall consist of the thirteen resource reports and related material described in this section.
(2) The detail of each resource report must be commensurate with the complexity of the proposal and its potential for environmental impact. Each topic in each resource report shall be addressed or its omission justified, unless the resource report description indicates that the data is not required for that type of proposal. If material required for one resource report is provided in another resource report or in another exhibit, it may be incorporated by reference. If any resource report topic is required for a particular project but is not provided at the time the application is filed, the environmental report shall explain why it is missing and when the applicant anticipates it will be filed.
(3) The appendix to this part contains a checklist of the minimum filing requirements for an environmental report. Failure to provide at least the applicable checklist items will result in rejection of the application unless the Director of the Office of Energy Projects determines that the applicant has provided an acceptable reason for the item’s absence and an acceptable schedule for filing it. Failure to file within the accepted schedule will result in rejection of the application.
(b) General requirements. As appropriate, each resource report shall:
(1) Address conditions or resources that might be directly or indirectly affected by the project;
(2) Identify significant environmental effects expected to occur as a result of the project;
(3) Identify the effects of construction, operation (including maintenance and malfunctions), and termination of the project, as well as cumulative effects resulting from existing or reasonably foreseeable projects;
(4) Identify measures proposed to enhance the environment or to avoid, mitigate, or compensate for adverse effects of the project;
(5) Provide a list of publications, reports, and other literature or communications, including agency contacts, that were cited or relied upon to prepare each report. This list should include the name and title of the person contacted, their affiliations, and telephone number;
(6) Whenever this section refers to “mileposts” the applicant may substitute “survey centerline stationing” if so desired. However, whatever method is chosen should be used consistently throughout the resource reports.
(c) Resource Report 1—General project description. This report is required for all applications. It will describe facilities associated with the project, special construction and operation procedures, construction timetables, future plans for related construction, compliance with regulations and codes, and permits that must be obtained. Resource Report 1 must:
(1) Describe and provide location maps of all jurisdictional facilities, including all aboveground facilities associated with the project (such as: meter stations, pig launchers/receivers, valves), to be constructed, modified, abandoned, replaced, or removed, including related construction and operational support activities and areas such as maintenance bases, staging areas, communications towers, power lines, and new access roads (roads to be built or modified). As relevant, the report must describe the length and diameter of the pipeline, the types of aboveground facilities that would be installed, and associated land requirements. It must also identify other companies that must construct jurisdictional facilities related to the project, where the facilities would be located, and where they are in the Commission’s approval process.
(2) Identify and describe all nonjurisdictional facilities, including auxiliary facilities, that will be built in association with the project, including facilities to be built by other companies.
(i) Provide the following information:
(A) A brief description of each facility, including as appropriate: Ownership, land requirements, gas consumption, megawatt size, construction status, and an update of the latest status of Federal, state, and local permits/approvals;
(B) The length and diameter of any interconnecting pipeline;
(C) Current 1:24,000/1:25,000 scale topographic maps showing the location of the facilities;
(D) Correspondence with the appropriate State Historic Preservation Officer (SHPO) or duly authorized Tribal Historic Preservation Officer (THPO) for tribal lands regarding whether properties eligible for listing on the National Register of Historic Places (NRHP) would be affected;
(E) Correspondence with the U.S. Fish and Wildlife Service (and National Marine Fisheries Service, if appropriate) regarding potential impacts of the proposed facility on federally listed threatened and endangered species; and
(F) For facilities within a designated coastal zone management area, a consistency determination or evidence that the owner has requested a consistency determination from the state’s coastal zone management program.
(ii) Address each of the following factors and indicate which ones, if any, appear to indicate the need for the Commission to do an environmental review of project-related nonjurisdictional facilities.
(A) Whether or not the regulated activity comprises “merely a link” in a corridor type project (e.g., a transportation or utility transmission project).
(B) Whether there are aspects of the nonjurisdictional facility in the immediate vicinity of the regulated activity which uniquely determine the location and configuration of the regulated activity.
(C) The extent to which the entire project will be within the Commission’s jurisdiction.
(D) The extent of cumulative Federal control and responsibility.
(3) Provide the following maps and photos:
(i) Current, original United States Geological Survey (USGS) 7.5-minute series topographic maps or maps of equivalent detail, covering at least a 0.5-mile-wide corridor centered on the pipeline, with integer mileposts identified, showing the location of rights-of-way, new access roads, other linear construction areas, compressor stations, and pipe storage areas. Show nonlinear construction areas on maps at a scale of 1:3,600 or larger keyed graphically and by milepost to the right-of-way maps.
(ii) Original aerial images or photographs or photo-based alignment sheets based on these sources, not more than 1 year old (unless older ones accurately depict current land use and development) and with a scale of 1:6,000 or larger, showing the proposed pipeline route and location of major aboveground facilities, covering at least a 0.5 mile-wide corridor, and including mileposts. Older images/photographs/alignment sheets should be modified to show any residences not depicted in the original. Alternative formats (e.g., blue-line prints of acceptable resolution) need prior approval by the environmental staff of the Office of Energy Projects.
(iii) In addition to the copy required under § 157.6(a)(2) of this chapter, applicant should send two additional copies of topographic maps and aerial images/photographs directly to the environmental staff of the Office of Energy Projects.
(4) When new or additional compression is proposed, include large scale (1:3,600 or greater) plot plans of each compressor station. The plot plan should reference a readily identifiable point(s) on the USGS maps required in paragraph (c)(3) of this section. The maps and plot plans must identify the location of the nearest noise-sensitive areas (schools, hospitals, or residences) within 1 mile of the compressor station, existing and proposed compressor and auxiliary buildings, access roads, and the limits of areas that would be permanently disturbed.
(5)(i) Identify facilities to be abandoned, and state how they would be abandoned, how the site would be restored, who would own the site or right-of-way after abandonment, and who would be responsible for any facilities abandoned in place.
(ii) When the right-of-way or the easement would be abandoned, identify whether landowners were given the opportunity to request that the facilities on their property, including foundations and below ground components, be removed. Identify any landowners whose preferences the company does not intend to honor, and the reasons therefore.
(6) Describe and identify by milepost, proposed construction and restoration methods to be used in areas of rugged topography, residential areas, active croplands, sites where the pipeline would be located parallel to and under roads, and sites where explosives are likely to be used.
(7) Unless provided in response to Resource Report 5, describe estimated workforce requirements, including the number of pipeline construction spreads, average workforce requirements for each construction spread and meter or compressor station, estimated duration of construction from initial clearing to final restoration, and number of personnel to be hired to operate the proposed project.
(8) Describe reasonably foreseeable plans for future expansion of facilities, including additional land requirements and the compatibility of those plans with the current proposal.
(9) Describe all authorizations required to complete the proposed action and the status of applications for such authorizations. Identify environmental mitigation requirements specified in any permit or proposed in any permit application to the extent not specified elsewhere in this section.
(10) Provide the names and mailing addresses of all affected landowners specified in § 157.6(d) and certify that all affected landowners will be notified as required in § 157.6(d).
(d) Resource Report 2—Water use and quality. This report is required for all applications, except those which involve only facilities within the areas of an existing compressor, meter, or regulator station that were disturbed by construction of the existing facilities, no wetlands or waterbodies are on the site and there would not be a significant increase in water use. The report must describe water quality and provide data sufficient to determine the expected impact of the project and the effectiveness of mitigative, enhancement, or protective measures. Resource Report 2 must:
(1) Identify and describe by milepost perennial waterbodies and municipal water supply or watershed areas, specially designated surface water protection areas and sensitive waterbodies, and wetlands that would be crossed. For each waterbody crossing, identify the approximate width, state water quality classifications, any known potential pollutants present in the water or sediments, and any potable water intake sources within 3 miles downstream.
(2) Compare proposed mitigation measures with the staff’s current “Wetland and Waterbody Construction and Mitigation Procedures,” which are available from the Commission Internet home page or the Commission staff, describe what proposed alternative mitigation would provide equivalent or greater protection to the environment, and provide a description of site- specific construction techniques that would be used at each major waterbody crossing.
(3) Describe typical staging area requirements at waterbody and wetland crossings. Also, identify and describe waterbodies and wetlands where staging areas are likely to be more extensive.
(4) Include National Wetland Inventory (NWI) maps. If NWI maps are not available, provide the appropriate state wetland maps. Identify for each crossing, the milepost, the wetland classification specified by the U.S. Fish and Wildlife Service, and the length of the crossing. Include two copies of the NWI maps (or the substitutes, if NWI maps are not available) clearly showing the proposed route and mileposts directed to the environmental staff. Describe by milepost, wetland crossings as determined by field delineations using the current Federal methodology.
(5) Identify aquifers within excavation depth in the project area, including the depth of the aquifer, current and projected use, water quality and average yield, and known or suspected contamination problems.
(6) Describe specific locations, the quantity required, and the method and rate of withdrawal and discharge of hydrostatic test water. Describe suspended or dissolved material likely to be present in the water as a result of contact with the pipeline, particularly if an existing pipeline is being retested. Describe chemical or physical treatment of the pipeline or hydrostatic test water. Discuss waste products generated and disposal methods.
(7) If underground storage of natural gas is proposed:
(i) Identify how water produced from the storage field will be disposed of, and
(ii) For salt caverns, identify the source locations, the quantity required, and the method and rate of withdrawal of water for creating salt cavern(s), as well as the means of disposal of brine resulting from cavern leaching.
(8) Discuss proposed mitigation measures to reduce the potential for adverse impacts to surface water, wetlands, or groundwater quality to the extent they are not described in response to paragraph (d)(2) of this section. Discuss the potential for blasting to affect water wells, springs, and wetlands, and measures to be taken to detect and remedy such effects.
(9) Identify the location of known public and private groundwater supply wells or springs within 150 feet of proposed construction areas. Identify locations of EPA or state-designated sole-source aquifers and wellhead protection areas crossed by the proposed pipeline facilities.
(e) Resource Report 3—Fish, wildlife, and vegetation. This report is required for all applications, except those involving only facilities within the improved area of an existing compressor, meter, or regulator station. It must describe aquatic life, wildlife, and vegetation in the vicinity of the proposed project; expected impacts on these resources including potential effects on biodiversity; and proposed mitigation, enhancement or protection measures. Resource Report 3 must:
(1) Describe commercial and recreational warmwater, coldwater, and saltwater fisheries in the affected area and associated significant habitats such as spawning or rearing areas and estuaries.
(2) Describe terrestrial habitats, including wetlands, typical wildlife habitats, and rare, unique, or otherwise significant habitats that might be affected by the proposed action. Describe typical species that have commercial, recreational, or aesthetic value.
(3) Describe and provide the acreage of vegetation cover types that would be affected, including unique ecosystems or communities such as remnant prairie or old-growth forest, or significant individual plants, such as old-growth specimen trees.
(4) Describe the impact of construction and operation on aquatic and terrestrial species and their habitats, including the possibility of a major alteration to ecosystems or biodiversity, and any potential impact on state-listed endangered or threatened species. Describe the impact of maintenance, clearing and treatment of the project area on fish, wildlife, and vegetation. Surveys may be required to determine specific areas of significant habitats or communities of species of special concern to state or local agencies.
(5) Identify all federally listed or proposed endangered or threatened species and critical habitat that potentially occur in the vicinity of the project. Discuss the results of the consultation requirements listed in § 380.13(b) at least through § 380.13(b)(5)(i) and include any written correspondence that resulted from the consultation. The initial application must include the results of any required surveys unless seasonal considerations make this impractical. If species surveys are impractical, there must be field surveys to determine the presence of suitable habitat unless the entire project area is suitable habitat.
(6) Identify all federally listed essential fish habitat (EFH) that potentially occurs in the vicinity of the project. Provide information on all EFH, as identified by the pertinent Federal fishery management plans, that may be adversely affected by the project and the results of abbreviated consultations with NMFS, and any resulting EFH assessments.
(7) Describe site-specific mitigation measures to minimize impacts on fisheries, wildlife, and vegetation.
(8) Include copies of correspondence not provided pursuant to paragraph (e)(5) of this section, containing recommendations from appropriate Federal and state fish and wildlife agencies to avoid or limit impact on wildlife, fisheries, and vegetation, and the applicant’s response to the recommendations.
(f) Resource Report 4—Cultural resources. This report is required for all applications. In preparing this report, the applicant must follow the principles in § 380.14 of this part. Guidance on the content and the format for the documentation listed below, as well as professional qualifications of preparers, is detailed in “ Office of Energy Projects’ (OEP) Guidelines for Reporting on Cultural Resources Investigations,” which is available from the Commission Internet home page or from the Commission staff.
(1) Resource Report 4 must contain:
(i) Documentation of the applicant’s initial cultural resources consultation, including consultations with Native Americans and other interested persons (if appropriate);
(ii) Overview and Survey Reports, as appropriate;
(iii) Evaluation Report, as appropriate;
(iv) Treatment Plan, as appropriate; and
(v) Written comments from State Historic Preservation Officer(s) (SHPO), Tribal Historic Preservation Officers (THPO), as appropriate, and applicable land-managing agencies on the reports in paragraphs (f)(1)(i)–(iv) of this section.
(2) Initial filing requirements. The initial application must include the documentation of initial cultural resource consultation, the Overview and Survey Reports, if required, and written comments from SHPOs, THPOs and land-managing agencies, if available. The initial cultural resources consultations should establish the need for surveys. If surveys are deemed necessary by the consultation with the SHPO/THPO, the survey report must be filed with the application.
(i) If the comments of the SHPOs, THPOs, or land-management agencies are not available at the time the application is filed, they may be filed separately, but they must be filed before a final certificate is issued.
(ii) If landowners deny access to private property and certain areas are not surveyed, the unsurveyed area must be identified by mileposts, and supplemental surveys or evaluations shall be conducted after access is granted. In such circumstances, reports, and treatment plans, if necessary, for those inaccessible lands may be filed after a certificate is issued.
(3) The Evaluation Report and Treatment Plan, if required, for the entire project must be filed before a final certificate is issued.
(i) The Evaluation Report may be combined in a single synthetic report with the Overview and Survey Reports if the SHPOs, THPOs, and land-management agencies allow and if it is available at the time the application is filed.
(ii) In preparing the Treatment Plan, the applicant must consult with the Commission staff, the SHPO, and any applicable THPO and land-management agencies.
(iii) Authorization to implement the Treatment Plan will occur only after the final certificate is issued.
(4) Applicant must request privileged treatment for all material filed with the Commission containing location, character, and ownership information about cultural resources in accordance with § 388.112 of this chapter. The cover and relevant pages or portions of the report should be clearly labeled in bold lettering: “CONTAINS PRIVILEGED INFORMATION—DO NOT RELEASE.”
(5) Except as specified in a final Commission order, or by the Director of the Office of Energy Projects, construction may not begin until all cultural resource reports and plans have been approved.
(g) Resource Report 5—Socioeconomics. This report is required only for applications involving significant aboveground facilities, including, among others, conditioning or liquefied natural gas (LNG) plants. It must identify and quantify the impacts of constructing and operating the proposed project on factors affecting towns and counties in the vicinity of the project. Resource Report 5 must:
(1) Describe the socioeconomic impact area.
(2) Evaluate the impact of any substantial immigration of people on governmental facilities and services and plans to reduce the impact on the local infrastructure.
(3) Describe on-site manpower requirements and payroll during construction and operation, including the number of construction personnel who currently reside within the impact area, would commute daily to the site from outside the impact area, or would relocate temporarily within the impact area.
(4) Determine whether existing housing within the impact area is sufficient to meet the needs of the additional population.
(5) Describe the number and types of residences and businesses that would be displaced by the project, procedures to be used to acquire these properties, and types and amounts of relocation assistance payments.
(6) Conduct a fiscal impact analysis evaluating incremental local government expenditures in relation to incremental local government revenues that would result from construction of the project. Incremental expenditures include, but are not limited to, school operating costs, road maintenance and repair, public safety, and public utility costs.
(h) Resource Report 6—Geological resources. This report is required for applications involving LNG facilities and all other applications, except those involving only facilities within the boundaries of existing aboveground facilities, such as a compressor, meter, or regulator station. It must describe geological resources and hazards in the project area that might be directly or indirectly affected by the proposed action or that could place the proposed facilities at risk, the potential effects of those hazards on the facility, and methods proposed to reduce the effects or risks. Resource Report 6 must:
(1) Describe, by milepost, mineral resources that are currently or potentially exploitable;
(2) Describe, by milepost, existing and potential geological hazards and areas of nonroutine geotechnical concern, such as high seismicity areas, active faults, and areas susceptible to soil liquefaction; planned, active, and abandoned mines; karst terrain; and areas of potential ground failure, such as subsidence, slumping, and landsliding. Discuss the hazards posed to the facility from each one.
(3) Describe how the project would be located or designed to avoid or minimize adverse effects to the resources or risk to itself, including geotechnical investigations and monitoring that would be conducted before, during, and after construction. Discuss also the potential for blasting to affect structures, and the measures to be taken to remedy such effects.
(4) Specify methods to be used to prevent project-induced contamination from surface mines or from mine tailings along the right-of-way and whether the project would hinder mine reclamation or expansion efforts.
(5) If the application is for underground storage facilities:
(i) Describe how the applicant would control and monitor the drilling activity of others within the field and buffer zone;
(ii) Describe how the applicant would monitor potential effects of the operation of adjacent storage or production facilities on the proposed facility, and vice versa;
(iii) Describe measures taken to locate and determine the condition of old wells within the field and buffer zone and how the applicant would reduce risk from failure of known and undiscovered wells; and
(iv) Identify and discuss safety and environmental safeguards required by state and Federal drilling regulations.
(i) Resource Report 7—Soils. This report is required for all applications except those not involving soil disturbance. It must describe the soils that would be affected by the proposed project, the effect on those soils, and measures proposed to minimize or avoid impact. Resource Report 7 must:
(1) List, by milepost, the soil associations that would be crossed and describe the erosion potential, fertility, and drainage characteristics of each association.
(2) If an aboveground facility site is greater than 5 acres:
(i) List the soil series within the property and the percentage of the property comprised of each series;
(ii) List the percentage of each series which would be permanently disturbed;
(iii) Describe the characteristics of each soil series; and
(iv) Indicate which are classified as prime or unique farmland by the U.S. Department of Agriculture, Natural Resources Conservation Service.
(3) Identify, by milepost, potential impact from: Soil erosion due to water, wind, or loss of vegetation; soil compaction and damage to soil structure resulting from movement of construction vehicles; wet soils and soils with poor drainage that are especially prone to structural damage; damage to drainage tile systems due to movement of construction vehicles and trenching activities; and interference with the operation of agricultural equipment due to the probability of large stones or blasted rock occurring on or near the surface as a result of construction.
(4) Identify, by milepost, cropland and residential areas where loss of soil fertility due to trenching and backfilling could occur.
(5) Describe proposed mitigation measures to reduce the potential for adverse impact to soils or agricultural productivity. Compare proposed mitigation measures with the staff’s current “Upland Erosion Control, Revegetation and Maintenance Plan,” which is available from the Commission Internet home page or from the Commission staff, and explain how proposed mitigation measures provide equivalent or greater protections to the environment.
(j) Resource Report 8—Land use, recreation and aesthetics. This report is required for all applications except those involving only facilities which are of comparable use at existing compressor, meter, and regulator stations. It must describe the existing uses of land on, and (where specified) within 0.25 mile of, the proposed project and changes to those land uses that would occur if the project is approved. The report shall discuss proposed mitigation measures, including protection and enhancement of existing land use. Resource Report 8 must:
(1) Describe the width and acreage requirements of all construction and permanent rights-of-way and the acreage required for each proposed plant and operational site, including injection or withdrawal wells.
(i) List, by milepost, locations where the proposed right-of-way would be adjacent to existing rights-of-way of any kind.
(ii) Identify, preferably by diagrams, existing rights-of-way that would be used for a portion of the construction or operational right-of-way, the overlap and how much additional width would be required.
(iii) Identify the total amount of land to be purchased or leased for each aboveground facility, the amount of land that would be disturbed for construction and operation of the facility, and the use of the remaining land not required for project operation.
(iv) Identify the size of typical staging areas and expanded work areas, such as those at railroad, road, and waterbody crossings, and the size and location of all pipe storage yards and access roads.
(2) Identify, by milepost, the existing use of lands crossed by the proposed pipeline, or on or adjacent to each proposed plant and operational site.
(3) Describe planned development on land crossed or within 0.25 mile of proposed facilities, the time frame (if available) for such development, and proposed coordination to minimize impacts on land use. Planned development means development which is included in a master plan or is on file with the local planning board or the county.
(4) Identify, by milepost and length of crossing, the area of direct effect of each proposed facility and operational site on sugar maple stands, orchards and nurseries, landfills, operating mines, hazardous waste sites, state wild and scenic rivers, state or local designated trails, nature preserves, game management areas, remnant prairie, old-growth forest, national or state forests, parks, golf courses, designated natural, recreational or scenic areas, or registered natural landmarks, Native American religious sites and traditional cultural properties to the extent they are known to the public at large, and reservations, lands identified under the Special Area Management Plan of the Office of Coastal Zone Management, National Oceanic and Atmospheric Administration, and lands owned or controlled by Federal or state agencies or private preservation groups. Also identify if any of those areas are located within 0.25 mile of any proposed facility.
(5) Identify, by milepost, all residences and buildings within 50 feet of the proposed pipeline construction right-of-way and the distance of the residence or building from the right-of-way. Provide survey drawings or alignment sheets to illustrate the location of the facilities in relation to the buildings.
(6) Describe any areas crossed by or within 0.25 mile of the proposed pipeline or plant and operational sites which are included in, or are designated for study for inclusion in: The National Wild and Scenic Rivers System (16 U.S.C. 1271); The National Trails System (16 U.S.C. 1241); or a wilderness area designated under the Wilderness Act (16 U.S.C. 1132).
(7) For facilities within a designated coastal zone management area, provide a consistency determination or evidence that the applicant has requested a consistency determination from the state’s coastal zone management program.
(8) Describe the impact the project will have on present uses of the affected area as identified above, including commercial uses, mineral resources, recreational areas, public health and safety, and the aesthetic value of the land and its features. Describe any temporary or permanent restrictions on land use resulting from the project.
(9) Describe mitigation measures intended for all special use areas identified under paragraphs (j)(2) through (6) of this section.
(10) Describe proposed typical mitigation measures for each residence that is within 50 feet of the edge of the pipeline construction right-of-way, as well as any proposed residence-specific mitigation. Describe how residential property, including for example, fences, driveways, stone walls, sidewalks, water supply, and septic systems, would be restored. Describe compensation plans for temporary and permanent rights-of-way and the eminent domain process for the affected areas.
(11) Describe measures proposed to mitigate the aesthetic impact of the facilities especially for aboveground facilities such as compressor or meter stations.
(12) Demonstrate that applications for rights-of-way or other proposed land use have been or soon will be filed with Federal land-management agencies with jurisdiction over land that would be affected by the project.
(k) Resource Report 9—Air and noise quality. This report is required for applications involving compressor facilities at new or existing stations, and for all new LNG facilities. It must identify the effects of the project on the existing air quality and noise environment and describe proposed measures to mitigate the effects. Resource Report 9 must:
(1) Describe the existing air quality, including background levels of nitrogen dioxide and other criteria pollutants which may be emitted above EPA-identified significance levels.
(2) Quantitatively describe existing noise levels at noise-sensitive areas, such as schools, hospitals, or residences and include any areas covered by relevant state or local noise ordinances.
(i) Report existing noise levels as the L
(ii) For existing compressor stations, include the results of a sound level survey at the site property line and nearby noise-sensitive areas while the compressors are operated at full load.
(iii) For proposed new compressor station sites, measure or estimate the existing ambient sound environment based on current land uses and activities.
(iv) Include a plot plan that identifies the locations and duration of noise measurements, the time of day, weather conditions, wind speed and direction, engine load, and other noise sources present during each measurement.
(3) Estimate the impact of the project on air quality, including how existing regulatory standards would be met.
(i) Provide the emission rate of nitrogen oxides from existing and proposed facilities, expressed in pounds per hour and tons per year for maximum operating conditions, include supporting calculations, emission factors, fuel consumption rates, and annual hours of operation.
(ii) For major sources of air emissions (as defined by the Environmental Protection Agency), provide copies of applications for permits to construct (and operate, if applicable) or for applicability determinations under regulations for the prevention of significant air quality deterioration and subsequent determinations.
(4) Provide a quantitative estimate of the impact of the project on noise levels at noise-sensitive areas, such as schools, hospitals, or residences.
(i) Include step-by-step supporting calculations or identify the computer program used to model the noise levels, the input and raw output data and all assumptions made when running the model, far-field sound level data for maximum facility operation, and the source of the data.
(ii) Include sound pressure levels for unmuffled engine inlets and exhausts, engine casings, and cooling equipment; dynamic insertion loss for all mufflers; sound transmission loss for all compressor building components, including walls, roof, doors, windows and ventilation openings; sound attenuation from the station to nearby noise-sensitive areas; the manufacturer’s name, the model number, the performance rating; and a description of each noise source and noise control component to be employed at the proposed compressor station. For proposed compressors the initial filing must include at least the proposed horsepower, type of compression, and energy source for the compressor.
(iii) Far-field sound level data measured from similar units in service elsewhere, when available, may be substituted for manufacturer’s far-field sound level data.
(iv) If specific noise control equipment has not been chosen, include a schedule for submitting the data prior to certification.
(v) The estimate must demonstrate that the project will comply with applicable noise regulations and show how the facility will meet the following requirements:
(A) The noise attributable to any new compressor station, compression added to an existing station, or any modification, upgrade or update of an existing station, must not exceed a day- night sound level (L
(B) New compressor stations or modifications of existing stations shall not result in a perceptible increase in vibration at any noise-sensitive area.
(5) Describe measures and manufacturer’s specifications for equipment proposed to mitigate impact to air and noise quality, including emission control systems, installation of filters, mufflers, or insulation of piping and buildings, and orientation of equipment away from noise-sensitive areas.
(l) Resource Report 10—Alternatives. This report is required for all applications. It must describe alternatives to the project and compare the environmental impacts of such alternatives to those of the proposal. The discussion must demonstrate how environmental benefits and costs were weighed against economic benefits and costs, and technological and procedural constraints. The potential for each alternative to meet project deadlines and the environmental consequences of each alternative shall be discussed. Resource Report 10 must:
(1) Discuss the “no action” alternative and the potential for accomplishing the proposed objectives through the use of other systems and/or energy conservation. Provide an analysis of the relative environmental benefits and costs for each alternative.
(2) Describe alternative routes or locations considered for each facility during the initial screening for the project.
(i) For alternative routes considered in the initial screening for the project but eliminated, describe the environmental characteristics of each route or site, and the reasons for rejecting it. Identify the location of such alternatives on maps of sufficient scale to depict their location and relationship to the proposed action, and the relationship of the pipeline to existing rights-of-way.
(ii) For alternative routes or locations considered for more in-depth consideration, describe the environmental characteristics of each route or site and the reasons for rejecting it. Provide comparative tables showing the differences in environmental characteristics for the alternative and proposed action. The location of any alternatives in this paragraph shall be provided on maps equivalent to those required in paragraph (c)(2) of this section.
(m) Resource Report 11—Reliability and safety. This report is required for applications involving new or recommissioned LNG facilities. Information previously filed with the Commission need not be refiled if the applicant verifies its continued validity. This report shall address the potential hazard to the public from failure of facility components resulting from accidents or natural catastrophes, how these events would affect reliability, and what procedures and design features have been used to reduce potential hazards. Resource Report 11 must:
(1) Describe measures proposed to protect the public from failure of the proposed facilities (including coordination with local agencies).
(2) Discuss hazards, the environmental impact, and service interruptions which could reasonably ensue from failure of the proposed facilities.
(3) Discuss design and operational measures to avoid or reduce risk.
(4) Discuss contingency plans for maintaining service or reducing downtime.
(5) Describe measures used to exclude the public from hazardous areas. Discuss measures used to minimize problems arising from malfunctions and accidents (with estimates of probability of occurrence) and identify standard procedures for protecting services and public safety during maintenance and breakdowns.
(n) Resource Report 12—PCB contamination. This report is required for applications involving the replacement, abandonment by removal, or abandonment in place of pipeline facilities determined to have polychlorinated biphenyls (PCBs) in excess of 50 ppm in pipeline liquids. Resource Report 12 must:
(1) Provide a statement that activities would comply with an approved EPA disposal permit, with the dates of issuance and expiration specified, or with the requirements of the Toxic Substances Control Act.
(2) For compressor station modifications on sites that have been determined to have soils contaminated with PCBs, describe the status of remediation efforts completed to date.
(o) Resource Report 13—Engineering and design material. This report is required for construction of new liquefied natural gas (LNG) facilities, or the recommissioning of existing LNG facilities. If the recommissioned facility is existing and is not being replaced, relocated, or significantly altered, resubmittal of information already on file with the Commission is unnecessary. Resource Report 13 must:
(1) Provide a detailed plot plan showing the location of all major components to be installed, including compression, pretreatment, liquefaction, storage, transfer piping, vaporization, truck loading/unloading, vent stacks, pumps, and auxiliary or appurtenant service facilities.
(2) Provide a detailed layout of the fire protection system showing the location of fire water pumps, piping, hydrants, hose reels, dry chemical systems, high expansion foam systems, and auxiliary or appurtenant service facilities.
(3) Provide a layout of the hazard detection system showing the location of combustible-gas detectors, fire detectors, heat detectors, smoke or combustion product detectors, and low temperature detectors. Identify those detectors that activate automatic shutdowns and the equipment that would shut down. Include all safety provisions incorporated in the plant design, including automatic and manually activated emergency shutdown systems.
(4) Provide a detailed layout of the spill containment system showing the location of impoundments, sumps, subdikes, channels, and water removal systems.
(5) Provide manufacturer’s specifications, drawings, and literature on the fail-safe shut-off valve for each loading area at a marine terminal (if applicable).
(6) Provide a detailed layout of the fuel gas system showing all taps with process components.
(7) Provide copies of company, engineering firm, or consultant studies of a conceptual nature that show the engineering planning or design approach to the construction of new facilities or plants.
(8) Provide engineering information on major process components related to the first six items above, which include (as applicable) function, capacity, type, manufacturer, drive system (horsepower, voltage), operating pressure, and temperature.
(9) Provide manuals and construction drawings for LNG storage tank(s).
(10) Provide up-to-date piping and instrumentation diagrams. Include a description of the instrumentation and control philosophy, type of instrumentation (pneumatic, electronic), use of computer technology, and control room display and operation. Also, provide an overall schematic diagram of the entire process flow system, including maps, materials, and energy balances.
(11) Provide engineering information on the plant’s electrical power generation system, distribution system, emergency power system, uninterruptible power system, and battery backup system.
(12) Identify all codes and standards under which the plant (and marine terminal, if applicable) will be sited, designed, constructed, tested, monitored, operated, and maintained, and any special considerations or safety provisions that were applied to the design of plant components.
(13) Provide a list of all permits or approvals from local, state, Federal, or Native American groups or Indian agencies required prior to and during construction of the plant, and the status of each, including the date filed, the date issued, and any known obstacles to approval. Include a description of data records required for submission to such agencies and transcripts of any public hearings by such agencies. Also provide copies of any correspondence relating to the actions by all, or any, of these agencies regarding all required approvals.
(14) Identify all Federal, state, and local regulations and requirements that apply to the siting, design, construction, testing, monitoring, operation, and maintenance of the proposed project and explain how the proposed project will comply with the applicable Federal regulations, including codes and standards incorporated by reference into Federal regulations.
(15) Provide information to demonstrate that the proposed facilities will be sited, designed, constructed, and operated to maintain reliability and will not significantly impact public safety given geotechnical conditions and the occurrence of a natural hazard identified in paragraphs (o)(15)(i) through (iii) of this section. Site information must provide geotechnical studies and natural hazard studies based on the site location, which must provide impacts and magnitude of historical events and projected impacts and magnitude of events based on projected prescriptive/deterministic events and projected probabilistic events corresponding to mean recurrence intervals. Design information must provide the basis of design supported by site information, including design parameters and criteria and preliminary resultant design loads used in the geotechnical and structural design of LNG facilities. Construction and operation information must also include discussion of quality assurance and quality control plans, monitoring programs, and action programs developed in preparation of and response to geotechnical and natural hazards. All information provided must, at a minimum, demonstrate compliance with all applicable Federal requirements and applicable codes and standards, and identify any applicable state and local requirements for the siting, design, construction, testing, monitoring, operation, and maintenance used to safeguard against significant impacts caused by geotechnical conditions and natural hazards.
(i) General information. Provide site information that includes:
(A) A description of all structures, systems, and components, including, at a minimum, the layout of all proposed above ground and below ground structures, systems, and components including temporary access roads used during construction and permanent roads used during operation.
(B) The design classification for each structure, system, and component in accordance with, at a minimum, all applicable Federal requirements and applicable codes and standards.
(C) The derivation and values for risk category and mean recurrence intervals that are, at a minimum, in accordance with all applicable Federal requirements and applicable codes and standards.
(D) A description of all load combinations for each design classification for all structures, systems, and components that are, at a minimum, in accordance with design methods and all applicable Federal requirements and applicable codes and standards.
(E) A description of all preliminary dead loads that are, at a minimum, in accordance with all applicable Federal requirements and applicable codes and standards, and include, at a minimum, weight of materials of construction of structures, systems, and components; weight of any hydrostatic test fluid service within structures, systems, and components during commissioning; weight of fluid services within structures, systems, and components during startup, normal operation, abnormal operation, and shutdown; and soil and hydrostatic pressure loads and potential uplift of below ground structures, systems, and components.
(F) A description of all preliminary live loads that are, at a minimum, in accordance with all applicable Federal requirements and applicable codes and standards, and include, at a minimum, dynamic loads from movement during transportation of structures, systems, and components; induced loads from construction equipment atop of below ground structures, systems, and components; uniform and concentrated loads from construction and operation personnel and equipment on structures, systems, and components; and crane loads for structures, systems, and components.
(G) A description of all preliminary loads induced from natural hazards for all structures, systems, and components that are, at a minimum, in accordance with all applicable Federal requirements and applicable codes and standards as described in paragraph (o)(15)(iii) of this section.
(H) A description of all mitigation measures to protect against natural hazards (like earthquakes) including, at a minimum, a discussion of the proposed site elevation and design of any storm walls or barriers relative to information described in paragraphs (o)(15)(ii) and (iii) of this section.
(I) A description of a natural hazard preparedness and action program, which includes facilitating timely decisions concerning the present or future state of the LNG facility that address, at a minimum, the natural hazards described in paragraph (o)(15)(iii) of this section.
(ii) Geotechnical information. Provide a geotechnical investigation that includes:
(A) A summary of the site investigation that lists the applicant’s exploratory program for the site and the types of subsurface investigations performed and planned to be performed for the site.
(B) A list and description of all in situ tests performed, standards used for tests, and their results including all standard penetration tests, cone penetration tests (static and dynamic), test pits, trenches, borings, rock coring, soil sampling, plate load tests, and in situ shear strength tests.
(C) A plot plan that identifies the number, location, spacing, cross-sections, and depths of each in situ test.
(D) A description of completed surveys, standards used for surveys, and the results of surveys that were conducted to obtain continuous lateral and depth information for the evaluation of subsurface conditions including all seismic refraction and reflection surveys.
(E) A description of the applicant’s laboratory testing program that includes the treatment of samples, the preparation of the soil specimen for testing, the techniques to detect sample disturbance, and the laboratory testing specifications.
(F) A list and description of all laboratory tests performed, standards used for tests, and their results, including results from all soil classification tests, index tests, strength and compressibility tests, permeability tests, and soil corrosivity tests.
(G) A description of proposed mitigation measures for soil improvement or other mitigation that would remediate low bearing strength, poor consolidation, poor permeability, high corrosivity, or other geotechnical issues discovered during in situ or laboratory tests.
(H) A discussion of subsurface conditions and profiles based on the results of the subsurface exploration and field test conducted at the site. Subsurface profiles must identify groundwater conditions and the physicochemical properties of the groundwater, soil/rock layers and parameters, and various soil strata in various cross-section drawings spanning across the site including the LNG storage tank areas.
(I) A description of soil conditions that indicate compressible or expansive soils, corrosive soils, collapsible soils, erodible soils, liquefaction-susceptible soils, frost-heave susceptible soils, frozen soils, sanitary landfill, or contaminated soils.
(J) An analysis of actual or potential hazards (e.g., landslides, subsidence, uplift, capable faults, or collapse resulting from natural features such as tectonic depressions and cavernous or karst terrains) to the site.
(K) A discussion of the relationship between the regional and local geology and the site location.
(L) An evaluation and discussion of surface displacement caused by faulting or seismically induced lateral spreading or lateral flow, regional subsidence, local subsidence, and heave.
(M) Drawings of existing and proposed site elevation contours.
(N) A slope-stability analysis, including slope stabilization methods, sloping topography for the site, recommendations for slope stability, static and seismic stability, and factor of safety.
(O) Recommendations for site improvement to increase bearing capacity, reduce the potential of liquefaction and lateral spreading, and mitigate poor or unusual soil conditions.
(P) Recommendations for site improvement to mitigate soil contaminants and shoreline erosion control.
(Q) An evaluation and discussion of the expected total settlement over the design life of the facilities that considers soil conditions, regional subsidence, and local subsidence.
(R) Recommendations for shallow foundations, including, at a minimum, ultimate bearing capacity, factor of safety, allowable bearing capacity, total and differential settlement criteria, liquefaction settlements, settlement monitoring, and lateral resistance.
(S) Recommendations for deep foundations, including, at a minimum, acceptable foundation type, bearing capacity, total pile capacities, axial capacity, lateral capacity, group effects, down-drag, factor of safety, settlement of single pile and pile groups, lateral movement of pile groups, pile installation, pile cap, indicator piles and pile load test programs, static axial pile load test, lateral load test, and dynamic pile load test.
(T) A summary of information needed to establish broad design parameters and conclusions used to determine the proposed layout and design of buildings, structures, and support facilities.
(U) A description of the implementation of the geotechnical monitoring system for the site and structures, including inclinometer, extensometers, piezometer, tiltmeter, settlement monuments or cells, pressure and load cells, and crack monitoring devices.
(iii) Natural hazard information. Provide studies, basis of design, and plans for all natural hazards, including, at a minimum, each natural hazard in paragraphs (o)(15)(iii)(A) through (G) of this section:
(A) Seismic information. Provide a discussion of seismic design and hazards analysis that includes:
(1) The seismic design basis and criteria that are, at a minimum, in accordance with all applicable Federal requirements, and applicable codes, standards, and specifications used as basis of design.
(2) A description of seismic setting and seismic hazard investigation.
(3) A description of seismological characteristics of the geographical region within 100 miles of the site.
(4) A description of capable faults, including any part of a fault within five miles of the site, the fault characteristics in the site vicinity, the methods and techniques used for fault analysis and investigations, and the potential effect of fault displacement on structures, systems, and components.
(5) Derivation of the site class describing the soil conditions and supportive geotechnical studies that are, at a minimum, in accordance with all applicable Federal requirements and applicable codes and standards.
(6) Criteria used to determine potential soil liquefaction, subsidence, fault rupture, seismic slope stability, and lateral spreading.
(7) A historical ground motion analysis, including a description of past seismic events of Modified Mercalli Intensity greater than IV or magnitude greater than 3.0 within 100 miles of the site, including date of seismic events, magnitude of seismic events, distance from site to epicenter of seismic events, depth of seismic events, and resultant ground motions recorded or estimated at site location.
(8) A site-specific ground motion analysis based on ground motions projected from the U.S. Geological Survey national seismic maps and any deterministic seismic hazard analyses (DSHA) and probabilistic seismic hazard analyses (PSHA).
(9) Derivation of all ground motions used for the Operating Basis Earthquake (OBE), Safe Shutdown Earthquake (SSE), site-specific design earthquake (DE), site-specific peak ground motion (PGA), and aftershock level earthquake (ALE) that are, at a minimum, in accordance with all applicable Federal requirements and applicable codes and standards.
(10) A list of OBE, SSE, and ALE site-specific ground motion spectral values for 0.5%, 1%, 2%, 5%, 7%, 10%, 15%, and 20% damping during all periods range.
(11) The DE seismic coefficients and seismic design parameters, including the spectral response acceleration and five percent damped design spectral response acceleration parameters at a short-period, at a period of one second, and at other periods; short-period site coefficient and long-period site coefficient; importance factor; component importance factor; fundamental period of the structure; long-period transition period; and response modification coefficient that are, at a minimum, in accordance with all applicable Federal requirements and applicable codes and standards.
(12) A description of site-specific response spectrum analysis method, time history analysis method, or equivalent static load analysis.
(13) A seismic analysis for soil-structure interaction that is, at a minimum, in accordance with all applicable Federal requirements and applicable codes and standards, and includes, at a minimum, a discussion of the modeling methods and the factors considered in the modeling methods, including the extent of embedment, the layering of the soil/rock strata, and the boundary of soil-structure model.
(14) A comparison of seismic responses used for each design classification for all structures, systems, and components.
(15) A list of seismic hazard curves of spectral accelerations for all periods for the site.
(16) Vertical response spectra for seismic design and ratio to horizontal response spectra.
(17) Natural frequencies and responses for each LNG tank system and associated safety systems and associated structures, systems, and components.
(18) A description of procedures used for structural analyses, including consideration of incorporating the stiffness, mass, and damping characteristics of the structural systems into the analytical models.
(19) A description of determination of seismic overturning moments and sliding forces for each LNG tank system and associated safety related structures, systems, and components, including consideration of the three components of input motion and the simultaneous action of vertical and horizontal seismic forces.
(20) A description of design procedure for seismically isolated structures, systems, and components.
(21) A description of seismic design basis and criteria for the LNG storage tank(s) and foundation(s). The seismic design basis and criteria must include the flexibility of the tank shell(s) and its influence on the natural frequencies of the tank(s), liquid level, effects of liquid motion or pressure changes; minimum design freeboard; sloshing and impulsive loads; seismic coefficients; importance factor(s); reduction factor(s); slosh height(s); sloshing periods of LNG storage tank(s); global stability of the tank(s) in terms of the potential for overturning and sliding; differential displacement between the tank(s) and the first support; and a total settlement monitoring program for the tank foundation(s).
(22) A description of seismic monitoring system in accordance with, at a minimum, all applicable Federal requirements and applicable codes and standards, including any triaxial ground motion recorder installed to register the free-field ground motion and additional triaxial ground motion recorders on each LNG tank system foundation, LNG tank roof, and associated safety related structures, systems, and components. The proposed seismic monitoring must include the installation locations on a plot plan; description of the triaxial strong motion recorders or other seismic instrumentation; the proposed alarm set points, and operating procedures (including emergency operating procedures) for control room operators in response to such alarms/data obtained from seismic instrumentation; and maintenance procedures.
(23) A cross reference to potential for earthquake generated tsunamis and seiches provided in paragraph (o)(15)(iii)(B) of this section, earthquake generated floods in paragraph (o)(15)(iii)(C) of this section, earthquake generated landslides in paragraph (o)(15)(iii)(G) of this section, and earthquake generated releases and fires in paragraph (m) of this section.
(B) Tsunami and seiche information. Provide a discussion of tsunami and seiche design and hazards that includes:
(1) The tsunami and seismic design basis and criteria with a description of the applicable requirements and guidelines, and generally accepted codes, standards, and specifications used as basis of design.
(2) The seiche design inundation and run-up elevations and corresponding return periods for all structures, systems, and components.
(3) The maximum considered tsunami (MCT) inundation and run-up elevation for the site, including the maximum considered earthquake (MCE) level ground motions at the site if the MCE is the triggering source of the MCT.
(4) A comparison of design loads of seiche water inundation elevations with inundation elevation corresponding to return periods of MCE and MCT for all structures, systems, and components.
(5) The Tsunami Risk Category for the site and a description of potential tsunami generation by seismic sources, and the prevention and mitigation plan for potential tsunami and seiche hazards.
(6) A cross reference to potential tsunami and seiche generated floods in paragraph (o)(15)(iii)(C) of this section, tsunami and seiche generated landslides in paragraph (o)(15)(iii)(G) of this section, and tsunami and seiche generated releases and fires in paragraph (m) of this section.
(C) Flood information. Provide a discussion of flood design criteria and hazards that includes:
(1) The floods design basis and criteria with references to applicable requirements and guidelines, and generally accepted codes, standards, and specifications used as basis of design.
(2) A description of flooding potential in the region surrounding the site due to one or more natural causes such as storm surge, tides, wind generated waves, meteorological tsunamis or seiches, extreme precipitation, or other natural hazard events that have a common cause.
(3) A comparison of flood design loads corresponding to return periods of 10,000-year, 5,000-year, 1,000-year, 500-year, and 100-year for all structures, systems, and components.
(4) A discussion of final designed site elevations and storm surge walls or floodwalls for the site that includes tsunami considerations, flood design considerations, site total settlements, sea level rise, subsidence.
(D) Hurricane information. Provide a discussion of hurricanes and other meteorological events design criteria and hazards that includes:
(1) The wind and storm surge design basis and criteria that are, at a minimum, in accordance with all applicable Federal requirements, and applicable codes, standards, and specifications used as basis of design.
(2) A comparison of design wind loads for both sustained and three-second gusts and storm surge elevations, including consideration for still water, wind/wave run-up effects, and crest elevations, with hurricanes and other meteorological events at the site location corresponding to return periods of 10,000-year, 5,000-year, 1,000-year, 500-year, and 100-year for all structures, systems, and components.
(3) A discussion of historic hurricane frequencies and hurricane categories equivalent on the Saffir-Simpson Hurricane Wind Scale at the site and associated wind speeds and storm surge.
(4) The design regional subsidence that includes a discussion of the elevation change used to account for regional subsidence for the design life of the facilities at the site.
(E) Tornado information. Provide a discussion of tornado design criteria and hazards that includes:
(1) The tornadoes design basis and criteria that are, at a minimum, in accordance with all applicable Federal requirements, and applicable codes, standards, and specifications used as basis of design.
(2) A comparison of tornado design loads corresponding to return periods of 10,000-year, 5,000-year, 1,000-year, 500-year, and 100-year for all structures, systems, and components.
(3) A discussion of historic tornado frequencies and tornado categories as classified on the Enhanced Fujita (EF) Scale at the site and associated wind speeds.
(4) A discussion of tornado loads determination and design procedure.
(5) A comparison of impact between wind loads and tornado loads for the site.
(F) Rain, ice, snow, and related precipitation information. Provide a discussion of rain, ice, snow, and related precipitation design criteria and hazards that includes:
(1) The rain, ice, and snow design basis and criteria that are, at a minimum, in accordance with all applicable Federal requirements, and applicable codes, standards, and specifications used as basis of design.
(2) The identification of stormwater flows, outfalls, and stormwater management systems for all surfaces, including spill containment system with sump pumps or other water removal systems.
(3) The comparison of rain, ice, and snow design loads with rainfall rates, snow loads, and ice loads corresponding to return periods of 10,000-year, 5,000-year, 1,000-year, 500-year, and 100-year for all structures, systems, and components.
(4) A discussion of historic ice and blizzard events and frequencies and other ice and snow events at the site and associated loads.
(G) Landslides, wildfires, volcanic activity, and geomagnetism information. Provide a discussion of landslides, wildfires, volcanic activity, and geomagnetism design criteria and hazards that includes:
(1) The landslides, wildfires, volcanic activity, and geomagnetism design basis and criteria that are, at a minimum, in accordance with all applicable Federal requirements, and applicable codes, standards, and specifications used as basis of design.
(2) A discussion of historic landslide, wildfire, volcano activity, and geomagnetic disturbance risks and intensities at the site.
(3) A description of capable volcanoes, volcanic characteristics of the region, and a discussion of potentially hazardous volcanic phenomena considerations.
§ 380.13 Compliance with the Endangered Species Act.
(a) Definitions. For purposes of this section:
(1) Listed species and critical habitat have the same meaning as provided in 50 CFR 402.02.
(2) Project area means any area subject to construction activities (for example, material storage sites, temporary work areas, and new access roads) necessary to install or abandon the facilities.
(b) Procedures for informal consultation—(1) Designation of non-Federal representative. The project sponsor is designated as the Commission’s non-Federal representative for purposes of informal consultations with the U.S. Fish and Wildlife Service (FWS) and the National Marine Fisheries Service (NMFS) under the Endangered Species Act of 1973, as amended (ESA).
(2) Consultation requirement. (i) Prior to the filing of the environmental report specified in § 380.12, the project sponsor must contact the appropriate regional or field office of the FWS or the NMFS, or both if appropriate, to initiate informal consultations, unless it is proceeding pursuant to a blanket clearance issued by the FWS and/or NMFS which is less than 1 year old and the clearance does not specify more frequent consultation.
(ii) If a blanket clearance is more than 1 year old or less than 1 year old and specifies more frequent consultations, or if the project sponsor is not proceeding pursuant to a blanket clearance, the project sponsor must request a list of federally listed or proposed species and designated or proposed critical habitat that may be present in the project area, or provide the consulted agency with such a list for its concurrence.
(iii) The consulted agency will provide a species and critical habitat list or concur with the species list provided within 30 days of its receipt of the initial request. In the event that the consulted agency does not provide this information within this time period, the project sponsor may notify the Director of the Office of Energy Projects and continue with the remaining procedures of this section.
(3) End of informal consultation. (i) At any time during the informal consultations, the consulted agency may determine or confirm:
(A) That no listed or proposed species, or designated or proposed critical habitat, occurs in the project area; or
(B) That the project is not likely to adversely affect a listed species or critical habitat;
(ii) If the consulted agency provides the determination or confirmation described in paragraph (b)(3)(i) of this section, no further consultation is required.
(4) Potential impact to proposed species. (i) If the consulted agency, pursuant to informal consultations, initially determines that any species proposed to be listed, or proposed critical habitat, occurs in the project area, the project sponsor must confer with the consulted agency on methods to avoid or reduce the potential impact.
(ii) The project sponsor shall include in its proposal, a discussion of any mitigating measures recommended through the consultation process.
(5) Continued informal consultations for listed species. (i) If the consulted agency initially determines, pursuant to the informal consultations, that a listed species or designated critical habitat may occur in the project area, the project sponsor must continue informal consultations with the consulted agency to determine if the proposed project may affect the species or designated critical habitat. These consultations may include discussions with experts (including experts provided by the consulted agency), habitat identification, field surveys, biological analyses, and the formulation of mitigation measures. If the provided information indicates that the project is not likely to adversely affect a listed species or critical habitat, the consulting agency will provide a letter of concurrence which completes informal consultation.
(ii) The project sponsor must prepare a Biological Assessment unless the consulted agency indicates that the proposed project is not likely to adversely affect a specific listed species or its designated critical habitat. The Biological Assessment must contain the following information for each species contained in the consulted agency’s species list:
(A) Life history and habitat requirements;
(B) Results of detailed surveys to determine if individuals, populations, or suitable, unoccupied habitat exists in the proposed project’s area of effect;
(C) Potential impacts, both beneficial and negative, that could result from the construction and operation of the proposed project, or disturbance associated with the abandonment, if applicable; and
(D) Proposed mitigation that would eliminate or minimize these potential impacts.
(iii) All surveys must be conducted by qualified biologists and must use FWS and/or NMFS approved survey methodology. In addition, the Biological Assessment must include the following information:
(A) Name(s) and qualifications of person(s) conducting the survey;
(B) Survey methodology;
(C) Date of survey(s); and
(D) Detailed and site-specific identification of size and location of all areas surveyed.
(iv) The project sponsor must provide a draft Biological Assessment directly to the environmental staff of the Office of Energy Projects for review and comment and/or submission to the consulted agency. If the consulted agency fails to provide formal comments on the Biological Assessment to the project sponsor within 30 days of its receipt, as specified in 50 CFR 402.120, the project sponsor may notify the Director, OEP, and follow the procedures in paragraph (c) of this section.
(v) The consulted agency’s comments on the Biological Assessment’s determination must be filed with the Commission.
(c) Notification to Director. In the event that the consulted agency fails to respond to requests by the project sponsor under paragraph (b) of this section, the project sponsor must notify the Director of the Office of Energy Projects. The notification must include all information, reports, letters, and other correspondence prepared pursuant to this section. The Director will determine whether:
(1) Additional informal consultation is required;
(2) Formal consultation must be initiated under paragraph (d) of this section; or
(3) Construction may proceed.
(d) Procedures for formal consultation. (1) In the event that formal consultation is required pursuant to paragraphs (b)(5)(v) or (c)(2) of this section, the Commission staff will initiate formal consultation with the FWS and/or NMFS, as appropriate, and will request that the consulted agency designate a lead Regional Office, lead Field/District Office, and Project Manager, as necessary, to facilitate the formal consultation process. In addition, the Commission will designate a contact for formal consultation purposes.
(2) During formal consultation, the consulted agency, the Commission, and the project sponsor will coordinate and consult to determine potential impacts and mitigation which can be implemented to minimize impacts. The Commission and the consulted agency will schedule coordination meetings and/or field visits as necessary.
(3) The formal consultation period will last no longer than 90 days, unless the consulted agency, the Commission, and project sponsor mutually agree to an extension of this time period.
(4) The consulted agency will provide the Commission with a Biological Opinion on the proposed project, as specified in 50 CFR 402.14(e), within 45 days of the completion of formal consultation.
§ 380.14 Compliance with the National Historic Preservation Act.
(a) Section 106 of the National Historic Preservation Act, as amended (16 U.S.C. 470(f)) (NHPA), requires the Commission to take into account the effect of a proposed project on any historic property and to afford the Advisory Council on Historic Preservation (Council) an opportunity to comment on projects if required under 36 CFR 800. The project sponsor, as a non-Federal party, assists the Commission in meeting its obligations under NHPA section 106 and the implementing regulations at 36 CFR part 800 by following the procedures at § 380.12(f). The project sponsor may contact the Commission at any time for assistance. The Commission will review the resultant filings.
(1) The Commission’s NHPA section 106 responsibilities apply to public and private lands, unless subject to the provisions of paragraph (a)(2) of this section. The project sponsor will assist the Commission in taking into account the views of interested parties, Native Americans, and tribal leaders.
(2) If Federal or Tribal land is affected by a proposed project, the project sponsor shall adhere to any requirements for cultural resources studies of the applicable Federal land- managing agencies on Federal lands and any tribal requirements on Tribal lands. The project sponsor must identify, in Resource Report 4 filed with the application, the status of cultural resources studies on Federal or Tribal lands, as applicable.
(3) The project sponsor must consult with the SHPO(s) and THPOs, if appropriate. If the SHPO or THPO declines to consult with the project sponsor, the project sponsor shall not continue with consultations, except as instructed by the Director of the Office of Energy Projects.
(4) If the project is covered by an agreement document among the Commission, Council, SHPO(s), THPO(s), land-managing agencies, project sponsors, and interested persons, as appropriate, then that agreement will provide for compliance with NHPA section 106, as applicable.
(b) [Reserved]
§ 380.15 Siting and maintenance requirements.
(a) Avoidance or minimization of effects. The siting, construction, and maintenance of facilities shall be undertaken in a way that avoids or minimizes effects on scenic, historic, wildlife, and recreational values.
(b) Landowner consideration. The desires of landowners should be taken into account in the planning, locating, clearing, and maintenance of rights-of-way and the construction of facilities on their property, so long as the result is consistent with applicable requirements of law, including laws relating to land-use and any requirements imposed by the Commission.
(c) Landowner notification. (1) (i) No activity described in paragraphs (a) and (b) of this section that involves ground disturbance is authorized unless a company makes a good faith effort to notify in writing each affected landowner, as noted in the most recent county/city tax records as receiving the tax notice, whose property will be used and subject to ground disturbance as a result of the proposed activity, at least five days prior to commencing any activity under this section. A landowner may waive the five-day prior notice requirement in writing, so long as the notice has been provided. No landowner notice under this section is required:
(A) If all ground disturbance will be confined entirely to areas within the fence line of an existing above-ground site of facilities operated by the company; or
(B) For activities done for safety, DOT compliance, or environmental or unplanned maintenance reasons that are not foreseen and that require immediate attention by the company.
(ii) The notification shall include at least:
(A) A brief description of the facilities to be constructed or replaced and the effect the activity may have on the landowner’s property;
(B) The name and phone number of a company representative who is knowledgeable about the project; and
(C) A description of the Commission’s Landowner Helpline, which an affected person may contact to seek an informal resolution of a dispute as explained in § 1b.22(a) of this chapter and the Landowner Helpline number.
(2) “Affected landowners” include owners of interests, as noted in the most recent county/city tax records as receiving tax notice, in properties (including properties subject to rights-of-way and easements for facility sites, compressor stations, well sites, and all above-ground facilities, and access roads, pipe and contractor yards, and temporary work space) that will be directly affected by (i.e., used) and subject to ground disturbance as a result of activity under this section.
(d) Safety regulations. The requirements of this paragraph do not affect a project sponsor’s obligations to comply with safety regulations of the U.S. Department of Transportation and recognized safe engineering practices for Natural Gas Act projects and the National Electric Safety Code for section 216 Federal Power Act projects.
(e) Pipeline and electric transmission facilities construction. (1) The use, widening, or extension of existing rights-of-way must be considered in locating proposed facilities.
(2) In locating proposed facilities, the project sponsor shall, to the extent practicable, avoid places listed on, or eligible for listing on, the National Register of Historic Places; natural landmarks listed on the National Register of Natural Landmarks; officially designated parks; wetlands; and scenic, recreational, and wildlife lands. If rights-of-way must be routed near or through such places, attempts should be made to minimize visibility from areas of public view and to preserve the character and existing environment of the area.
(3) Rights-of-way should avoid forested areas and steep slopes where practical.
(4) Rights-of-way clearing should be kept to the minimum width necessary.
(5) In selecting a method to clear rights-of-way, soil stability and protection of natural vegetation and adjacent resources should be taken into account.
(6) Trees and vegetation cleared from rights-of-way in areas of public view should be disposed of without undue delay.
(7) Remaining trees and shrubs should not be unnecessarily damaged.
(8) Long foreground views of cleared rights-of-way through wooded areas that are visible from areas of public view should be avoided.
(9) Where practical, rights-of-way should avoid crossing hills and other high points at their crests where the crossing is in a forested area and the resulting notch is clearly visible in the foreground from areas of public view.
(10) Screen plantings should be employed where rights-of-way enter forested areas from a clearing and where the clearing is plainly visible in the foreground from areas of public view.
(11) Temporary roads should be designed for proper drainage and built to minimize soil erosion. Upon abandonment, the road area should be restored and stabilized without undue delay.
(f) Right-of-way maintenance. (1) Vegetation covers established on a right-of-way should be properly maintained.
(2) Access and service roads should be maintained with proper cover, water bars, and the proper slope to minimize soil erosion. They should be jointly used with other utilities and land-management agencies where practical.
(3) Chemical control of vegetation should not be used unless authorized by the landowner or land-managing agency. When chemicals are used for control of vegetation, they should be approved by EPA for such use and used in conformance with all applicable regulations.
(g) Construction of aboveground facilities. (1) Unobtrusive sites should be selected for the location of aboveground facilities.
(2) Aboveground facilities should cover the minimum area practicable.
(3) Noise potential should be considered in locating compressor stations, or other aboveground facilities.
(4) The exterior of aboveground facilities should be harmonious with the surroundings and other buildings in the area.
(5) For Natural Gas Act projects, the site of aboveground facilities which are visible from nearby residences or public areas, should be planted in trees and shrubs, or other appropriate landscaping and should be installed to enhance the appearance of the facilities, consistent with operating needs.
§ 380.16 Environmental reports for section 216 Federal Power Act Permits.
(a) Introduction. (1) The applicant must submit an environmental report with any application that proposes the construction or modification of any facility identified in § 380.3(c)(3). The environmental report must include the 11 resource reports and related material described in this section.
(2) The detail of each resource report must be commensurate with the complexity of the proposal and its potential for environmental impact. Each topic in each resource report must be addressed or its omission justified, unless the data is not required for that type of proposal. If material required for one resource report is provided in another resource report or in another exhibit, it may be cross referenced. If any resource report topic is required for a particular project but is not provided at the time the application is filed, the environmental report must explain why it is missing and when the applicant anticipates it will be filed.
(b) General requirements. As appropriate, each resource report must:
(1) Address conditions or resources that are likely to be directly or indirectly affected by the project;
(2) Identify significant environmental effects expected to occur as a result of the project;
(3) Identify the effects of construction, operation (including maintenance and malfunctions), as well as cumulative effects resulting from existing or reasonably foreseeable projects;
(4) Identify measures proposed to enhance the environment or to avoid, mitigate, or compensate for adverse effects of the project; and
(5) Provide a list of publications, reports, and other literature or communications, including agency contacts, that were cited or relied upon to prepare each report. This list must include the names and titles of the persons contacted, their affiliations, and telephone numbers.
(6) Whenever this section refers to “mileposts” the applicant may substitute “survey centerline stationing” if so preferred. However, whatever method is chosen must be used consistently throughout the resource reports.
(c) Resource Report 1—General project description. This report must describe facilities associated with the project, special construction and operation procedures, construction timetables, future plans for related construction, compliance with regulations and codes, and permits that must be obtained. Resource Report 1 must:
(1) Describe and provide location maps of all project facilities, include all facilities associated with the project (such as transmission line towers, substations, and any appurtenant facilities), to be constructed, modified, replaced, or removed, including related construction and operational support activities and areas such as maintenance bases, staging areas, communications towers, power lines, and new access roads (roads to be built or modified). As relevant, the report must describe the length and size of the proposed transmission line conductor cables, the types of appurtenant facilities that would be constructed, and associated land requirements.
(2) Provide the following maps and photos:
(i) Current, original United States Geological Survey (USGS) 7.5-minute series topographic maps or maps of equivalent detail, covering at least a 0.5-mile-wide corridor centered on the electric transmission facility centerline, with integer mileposts identified, showing the location of rights-of-way, new access roads, other linear construction areas, substations, and construction materials storage areas. Nonlinear construction areas must be shown on maps at a scale of 1:3,600 or larger keyed graphically and by milepost to the right-of-way maps. In areas where the facilities described in paragraph (j)(6) of this section are located, topographic map coverage must be expanded to depict those facilities.
(ii) Original aerial images or photographs or photo-based alignment sheets based on these sources, not more than one year old (unless older ones accurately depict current land use and development) and with a scale of 1:6,000, or larger, showing the proposed transmission line route and location of transmission line towers, substations and appurtenant facilities, covering at least a 0.5 mile-wide corridor, and including mileposts. The aerial images or photographs or photo-based alignment sheets must show all existing transmission facilities located in the area of the proposed facilities and the location of habitable structures, radio transmitters and other electronic installations, and airstrips. Older images/photographs/alignment sheets must be modified to show any residences not depicted in the original. In areas where the facilities described in paragraph (j)(6) of this section are located, aerial photographic coverage must be expanded to depict those facilities. Alternative formats (e.g., blue-line prints of acceptable resolution) need prior approval by the environmental staff of the Office of Energy Projects.
(iii) In addition to the copies required under § 50.3(b) of this chapter, the applicant must send three additional copies of topographic maps and aerial images/photographs directly to the environmental staff of the Commission’s Office of Energy Projects.
(3) Describe and identify by milepost, proposed construction and restoration methods to be used in areas of rugged topography, residential areas, active croplands and sites where explosives are likely to be used.
(4) Identify the number of construction spreads, average workforce requirements for each construction spread and estimated duration of construction from initial clearing to final restoration, and any identified constraints to the timing of construction.
(5) Describe reasonably foreseeable plans for future expansion of facilities, including additional land requirements and the compatibility of those plans with the current proposal.
(6) Describe all authorizations required to complete the proposed action and the status of applications for such authorizations. Identify environmental mitigation requirements specified in any permit or proposed in any permit application to the extent not specified elsewhere in this section.
(7) Provide the names and mailing addresses of all affected landowners identified in § 50.5(c)(4) of this chapter and certify that all affected landowners will be notified as required in § 50.4(c) of this chapter.
(d) Resource Report 2—Water use and quality. This report must describe water quality and provide data sufficient to determine the expected impact of the project and the effectiveness of mitigative, enhancement, or protective measures. Resource Report 2 must:
(1) Identify and describe by milepost waterbodies and municipal water supply or watershed areas, specially designated surface water protection areas and sensitive waterbodies, and wetlands that would be crossed. For each waterbody crossing, identify the approximate width, State water quality classifications, any known potential pollutants present in the water or sediments, and any potable water intake sources within three miles downstream.
(2) Provide a description of site-specific construction techniques that will be used at each major waterbody crossing.
(3) Describe typical staging area requirements at waterbody and wetland crossings. Also, identify and describe waterbodies and wetlands where staging areas are likely to be more extensive.
(4) Include National Wetland Inventory (NWI) maps. If NWI maps are not available, provide the appropriate State wetland maps. Identify for each crossing, the milepost, the wetland classification specified by the U.S. Fish and Wildlife Service, and the length of the crossing. Include two copies of the NWI maps (or the substitutes, if NWI maps are not available) clearly showing the proposed route and mileposts. Describe by milepost, wetland crossings as determined by field delineations using the current Federal methodology.
(5) Identify aquifers within excavation depth in the project area, including the depth of the aquifer, current and projected use, water quality, and known or suspected contamination problems.
(6) Discuss proposed mitigation measures to reduce the potential for adverse impacts to surface water, wetlands, or groundwater quality. Discuss the potential for blasting to affect water wells, springs, and wetlands, and measures to be taken to detect and remedy such effects.
(7) Identify the location of known public and private groundwater supply wells or springs within 150 feet of proposed construction areas. Identify locations of EPA or State-designated, sole-source aquifers and wellhead protection areas crossed by the proposed transmission line facilities.
(e) Resource Report 3—Fish, wildlife, and vegetation. This report must describe aquatic life, wildlife, and vegetation in the vicinity of the proposed project; expected impacts on these resources including potential effects on biodiversity; and proposed mitigation, enhancement, or protection measures. Resource Report 3 must:
(1) Describe commercial and recreational warmwater, coldwater, and saltwater fisheries in the affected area and associated significant habitats such as spawning or rearing areas and estuaries.
(2) Describe terrestrial habitats, including wetlands, typical wildlife habitats, and rare, unique, or otherwise significant habitats that might be affected by the proposed action. Describe typical species that have commercial, recreational, or aesthetic value.
(3) Describe and provide the affected acreage of vegetation cover types that would be affected, including unique ecosystems or communities such as remnant prairie or old-growth forest, or significant individual plants, such as old-growth specimen trees.
(4) Describe the impact of construction and operation on aquatic and terrestrial species and their habitats, including the possibility of a major alteration to ecosystems or biodiversity, and any potential impact on State-listed endangered or threatened species. Describe the impact of maintenance, clearing and treatment of the project area on fish, wildlife, and vegetation. Surveys may be required to determine specific areas of significant habitats or communities of species of special concern to State, Tribal, or local agencies.
(5) Identify all Federally-listed or proposed threatened or endangered species and critical habitat that potentially occur in the vicinity of the project. Discuss the results of the consultation requirements listed in § 380.13(b) through § 380.13(b)(5)(i) and include any written correspondence that resulted from the consultation. The initial application must include the results of any required surveys unless seasonal considerations make this impractical. If species surveys are impractical, there must be field surveys to determine the presence of suitable habitat unless the entire project area is suitable habitat.
(6) Identify all Federally-listed essential fish habitat (EFH) that potentially occurs in the vicinity of the project. Provide information on all EFH, as identified by the pertinent Federal fishery management plans, that may be adversely affected by the project and the results of abbreviated consultations with NMFS, and any resulting EFH assessments.
(7) Describe site-specific mitigation measures to minimize impacts on fisheries, wildlife, and vegetation.
(8) Include copies of correspondence not provided under paragraph (e)(5) of this section, containing recommendations from appropriate Federal and State fish and wildlife agencies to avoid or limit impact on wildlife, fisheries, and vegetation, and the applicant’s response to the recommendations.
(f) Resource Report 4—Cultural resources. In order to prepare this report, the applicant must follow the principles in § 380.14.
(1) Resource Report 4 must contain:
(i) Documentation of the applicant’s initial cultural resources consultations, including consultations with Native Americans and other interested persons (if appropriate);
(ii) Overview and Survey Reports, as appropriate;
(iii) Evaluation Report, as appropriate;
(iv) Treatment Plan, as appropriate; and
(v) Written comments from State Historic Preservation Officer(s) (SHPO), Tribal Historic Preservation Officers (THPO), as appropriate, and applicable land-managing agencies on the reports in paragraphs (f)(1)(i) through (iv) of this section.
(2) The initial application or pre-filing documents, as applicable, must include the documentation of initial cultural resource consultation(s), the Overview and Survey Reports, if required, and written comments from SHPOs, THPOs, and land-managing agencies, if available. The initial cultural resources consultations should establish the need for surveys. If surveys are deemed necessary by the consultation with the SHPO/THPO, the survey reports must be filed with the initial application or pre-filing documents.
(i) If the comments of the SHPOs, THPOs, or land-management agencies are not available at the time the application is filed, they may be filed separately, but they must be filed before a permit is issued.
(ii) If landowners deny access to private property and certain areas are not surveyed, the unsurveyed area must be identified by mileposts, and supplemental surveys or evaluations must be conducted after access is granted. In those circumstances, reports, and treatment plans, if necessary, for those inaccessible lands may be filed after a permit is issued.
(3) The Evaluation Report and Treatment Plan, if required, for the entire project must be filed before a permit is issued.
(i) In preparing the Treatment Plan, the applicant must consult with the Commission staff, the SHPO, and any applicable THPO and land-management agencies.
(ii) Authorization to implement the Treatment Plan will occur only after the permit is issued.
(4) Applicant must request privileged treatment for all material filed with the Commission containing location, character, and ownership information about cultural resources in accordance with § 388.112 of this chapter. The cover and relevant pages or portions of the report should be clearly labeled in bold lettering: “CONTAINS PRIVILEGED INFORMATION—DO NOT RELEASE.”
(5) Except as specified in a final Commission order, or by the Director of the Office of Energy Projects, construction may not begin until all cultural resource reports and plans have been approved.
(g) Resource Report 5—Socioeconomics. This report must identify and quantify the impacts of constructing and operating the proposed project on factors affecting towns and counties in the vicinity of the project. Resource Report 5 must:
(1) Describe the socioeconomic impact area.
(2) Evaluate the impact of any substantial immigration of people on governmental facilities and services and plans to reduce the impact on the local infrastructure.
(3) Describe on-site manpower requirements and payroll during construction and operation, including the number of construction personnel who currently reside within the impact area, will commute daily to the site from outside the impact area, or will relocate temporarily within the impact area.
(4) Determine whether existing housing within the impact area is sufficient to meet the needs of the additional population.
(5) Describe the number and types of residences and businesses that will be displaced by the project, procedures to be used to acquire these properties, and types and amounts of relocation assistance payments.
(6) Conduct a fiscal impact analysis evaluating incremental local government expenditures in relation to incremental local government revenues that will result from construction of the project. Incremental expenditures include, but are not limited to, school operating costs, road maintenance and repair, public safety, and public utility costs.
(h) Resource Report 6—Geological resources. This report must describe geological resources and hazards in the project area that might be directly or indirectly affected by the proposed action or that could place the proposed facilities at risk, the potential effects of those hazards on the facility, and methods proposed to reduce the effects or risks. Resource Report 6 must:
(1) Describe, by milepost, mineral resources that are currently or potentially exploitable.
(2) Describe, by milepost, existing and potential geological hazards and areas of nonroutine geotechnical concern, such as high seismicity areas, active faults, and areas susceptible to soil liquefaction; planned, active, and abandoned mines; karst terrain; and areas of potential ground failure, such as subsidence, slumping, and landsliding. Discuss the hazards posed to the facility from each one.
(3) Describe how the project will be located or designed to avoid or minimize adverse effects to the resources or risk to itself, including geotechnical investigations and monitoring that would be conducted before, during, and after construction. Discuss also the potential for blasting to affect structures, and the measures to be taken to remedy such effects.
(4) Specify methods to be used to prevent project-induced contamination from surface mines or from mine tailings along the right-of-way and whether the project would hinder mine reclamation or expansion efforts.
(i) Resource Report 7—Soils. This report must describe the soils that will be affected by the proposed project, the effect on those soils, and measures proposed to minimize or avoid impact. Resource Report 7 must:
(1) List, by milepost, the soil associations that would be crossed and describe the erosion potential, fertility, and drainage characteristics of each association.
(2) Identify, by milepost, potential impact from: Soil erosion due to water, wind, or loss of vegetation; soil compaction and damage to soil structure resulting from movement of construction vehicles; wet soils and soils with poor drainage that are especially prone to structural damage; damage to drainage tile systems due to movement of construction vehicles and trenching activities; and interference with the operation of agricultural equipment due to the possibility of large stones or blasted rock occurring on or near the surface as a result of construction.
(3) Identify, by milepost, cropland, and residential areas where loss of soil fertility due to construction activity can occur. Indicate which are classified as prime or unique farmland by the U.S. Department of Agriculture, Natural Resources Conservation Service.
(j) Resource Report 8—Land use, recreation, and aesthetics. This report must describe the existing uses of land on, and (where specified) within 0.25 mile of, the edge of the proposed transmission line right-of-way and changes to those land uses that will occur if the project is approved. The report must discuss proposed mitigation measures, including protection and enhancement of existing land use. Resource Report 8 must:
(1) Describe the width and acreage requirements of all construction and permanent rights-of-way required for project construction, operation and maintenance.
(i) List, by milepost, locations where the proposed right-of-way would be adjacent to existing rights-of-way of any kind.
(ii) Identify, preferably by diagrams, existing rights-of-way that will be used for a portion of the construction or operational right-of-way, the overlap and how much additional width will be required.
(iii) Identify the total amount of land to be purchased or leased for each project facility, the amount of land that would be disturbed for construction, operation, and maintenance of the facility, and the use of the remaining land not required for project operation and maintenance, if any.
(iv) Identify the size of typical staging areas and expanded work areas, such as those at railroad, road, and waterbody crossings, and the size and location of all construction materials storage yards and access roads.
(2) Identify, by milepost, the existing use of lands crossed by the proposed transmission facility, or on or adjacent to each proposed project facility.
(3) Describe planned development on land crossed or within 0.25 mile of proposed facilities, the time frame (if available) for such development, and proposed coordination to minimize impacts on land use. Planned development means development which is included in a master plan or is on file with the local planning board or the county.
(4) Identify, by milepost and length of crossing, the area of direct effect of each proposed facility and operational site on sugar maple stands, orchards and nurseries, landfills, operating mines, hazardous waste sites, wild and scenic rivers, designated trails, nature preserves, game management areas, remnant prairie, old-growth forest, national or State forests, parks, golf courses, designated natural, recreational or scenic areas, or registered natural landmarks, Native American religious sites and traditional cultural properties to the extent they are known to the public at large, and reservations, lands identified under the Special Area Management Plan of the Office of Coastal Zone Management, National Oceanic and Atmospheric Administration, and lands owned or controlled by Federal or State agencies or private preservation groups. Also identify if any of those areas are located within 0.25 mile of any proposed facility.
(5) Tribal resources. Describe Indian tribes, tribal lands, and interests that may be affected by the project.
(i) Identify Indian tribes that may attach religious and cultural significance to historic properties within the project right-of-way or in the project vicinity, as well as available information on Indian traditional cultural and religious properties, whether on or off of any Federally-recognized Indian reservation.
(ii) Information made available under this section must delete specific site or property locations, the disclosure of which will create a risk of harm, theft, or destruction of archaeological or Native American cultural resources or to the site at which the resources are located, or which would violate any Federal law, including the Archaeological Resources Protection Act of 1979, 16 U.S.C. 470w–3, and the National Historic Preservation Act of 1966, 16 U.S.C. 470hh.
(6) Identify, by milepost, all residences and buildings within 200 feet of the edge of the proposed transmission line construction right-of-way and the distance of the residence or building from the edge of the right-of-way. Provide survey drawings or alignment sheets to illustrate the location of the transmission facilities in relation to the buildings.
(i) Buildings: List all single-family and multi-family dwellings and related structures, mobile homes, apartment buildings, commercial structures, industrial structures, business structures, churches, hospitals, nursing homes, schools, or other structures normally inhabited by humans or intended to be inhabited by humans on a daily or regular basis within a 0.5-mile-wide corridor centered on the proposed transmission line alignment. Provide a general description of each habitable structure and its distance from the centerline of the proposed project. In cities, towns, or rural subdivisions, houses can be identified in groups. Provide the number of habitable structures in each group and list the distance from the centerline to the closest habitable structure in the group.
(ii) Electronic installations: List all commercial AM radio Transmitters located within 10,000 feet of the centerline of the proposed project and all FM radio transmitters, microwave relay stations, or other similar electronic installations located within 2,000 feet of the centerline of the proposed project. Provide a general description of each installation and its distance from the centerline of the projects. Locate all installations on a routing map.
(iii) Airstrips: List all known private airstrips within 10,000 feet of the centerline of the project. List all airports registered with the Federal Aviation Administration (FAA) with at least one runway more than 3,200 feet in length that are located within 20,000 feet of the centerline of the proposed project. Indicate whether any transmission structures will exceed a 100:1 horizontal slope (one foot in height for each 100 feet in distance) from the closest point of the closest runway. List all airports registered with the FAA having no runway more than 3,200 feet in length that are located within 10,000 feet of the centerline of the proposed project. Indicate whether any transmission structures will exceed a 50:1 horizontal slope from the closest point of the closest runway. List all heliports located within 5,000 feet of the centerline of the proposed project. Indicate whether any transmission structures will exceed a 25:1 horizontal slope from the closest point of the closest landing and takeoff area of the heliport. Provide a general description of each private airstrip, registered airport, and registered heliport, and state the distance of each from the centerline of the proposed transmission line. Locate all airstrips, airports, and heliports on a routing map.
(7) Describe any areas crossed by or within 0.25 mile of the proposed transmission project facilities which are included in, or are designated for study for inclusion in: The National Wild and Scenic Rivers System (16 U.S.C. 1271); The National Trails System (16 U.S.C. 1241); or a wilderness area designated under the Wilderness Act (16 U.S.C. 1132).
(8) For facilities within a designated coastal zone management area, provide a consistency determination or evidence that the applicant has requested a consistency determination from the State’s coastal zone management program.
(9) Describe the impact the project will have on present uses of the affected areas as identified above, including commercial uses, mineral resources, recreational areas, public health and safety, and the aesthetic value of the land and its features. Describe any temporary or permanent restrictions on land use resulting from the project.
(10) Describe mitigation measures intended for all special use areas identified under this section.
(11) Describe the visual characteristics of the lands and waters affected by the project. Components of this description include a description of how the transmission line project facilities will impact the visual character of project right-of-way and surrounding vicinity, and measures proposed to lessen these impacts. Applicants are encouraged to supplement the text description with visual aids.
(12) Demonstrate that applications for rights-of-way or other proposed land use have been or soon will be filed with Federal land-management agencies with jurisdiction over land that would be affected by the project.
(k) Resource Report 9—Alternatives. This report must describe alternatives to the project and compare the environmental impacts of such alternatives to those of the proposal. It must discuss technological and procedural constraints, costs, and benefits of each alternative. The potential for each alternative to meet project purposes and the environmental consequences of each alternative must be discussed. Resource Report 9 must:
(1) Discuss the “no action” alternative and other alternatives given serious consideration to achieve the proposed objectives.
(2) Provide an analysis of the relative environmental benefits and impacts of each such alternative, including but not limited to:
(i) For alternatives considered in the initial screening for the project but eliminated, describe the environmental characteristics of each alternative, and the reasons for rejecting it. Where applicable, identify the location of such alternatives on maps of sufficient scale to depict their location and relationship to the proposed action, and the relationship of the transmission facilities to existing rights-of-way; and
(ii) For alternatives that were given more in-depth consideration, describe the environmental characteristics of each alternative and the reasons for rejecting it. Provide comparative tables showing the differences in environmental characteristics for the alternative and proposed action. The location, where applicable, of any alternatives in this paragraph shall be provided on maps equivalent to those required in paragraph (c)(2) of this section.
(l) Resource Report 10—Reliability and Safety. This report must address the potential hazard to the public from facility components resulting from accidents or natural catastrophes, how these events will affect reliability, and what procedures and design features have been used to reduce potential hazards. Resource Report 10 must:
(1) Describe measures proposed to protect the public from failure of the proposed facilities (including coordination with local agencies).
(2) Discuss hazards, the environmental impact, and service interruptions which could reasonably ensue from failure of the proposed facilities.
(3) Discuss design and operational measures to avoid or reduce risk.
(4) Discuss contingency plans for maintaining service or reducing downtime.
(5) Describe measures used to exclude the public from hazardous areas. Discuss measures used to minimize problems arising from malfunctions and accidents (with estimates of probability of occurrence) and identify standard procedures for protecting services and public safety during maintenance and breakdowns.
(6) Provide a description of the electromagnetic fields to be generated by the proposed transmission lines, including their strength and extent. Provide a depiction of the expected field compared to distance horizontally along the right-of-way under the conductors, and perpendicular to the centerline of the right-of-way laterally.
(7) Discuss the potential for acoustic and electrical noise from electric and magnetic fields, including shadowing and reradiation, as they may affect health or communication systems along the transmission right-of-way. Indicate the noise level generated by the line in both dB and dBA scales and compare this to any known noise ordinances for the zoning districts through which the transmission line will pass.
(8) Discuss the potential for induced or conducted currents along the transmission right-of-way from electric and magnetic fields.
(m) Resource Report 11—Design and Engineering. This report consists of general design and engineering drawings of the principal project facilities described under Resource Report 1—General project description. If the version of this report submitted with the application is preliminary in nature, applicant must state that in the application. The drawings must conform to the specifications determined in the initial consultation meeting required by § 50.5(b) of this chapter.
(1) The drawings must show all major project structures in sufficient detail to provide a full understanding of the project including:
(i) Plans (overhead view);
(ii) Elevations (front view);
(iii) Profiles (side view); and
(iv) Sections.
(2) The applicant may submit preliminary design drawings with the pre-filing documents or application. The final design drawings may be submitted during the construction permit process or after the Commission issues a permit and must show the precise plans and specifications for proposed structures. If a permit is granted on the basis of preliminary designs, the applicant must submit final design drawings for written approval by the Director of the Office of Energy Project’s prior to commencement of any construction of the project.
(3) Supporting design report. The applicant must submit, at a minimum, the following supporting information to demonstrate that existing and proposed structures are safe and adequate to fulfill their stated functions and must submit such information in a separate report at the time the application is filed:
(i) An assessment of the suitability of the transmission line towers and appurtenant structures locations based on geological and subsurface investigations, including investigations of soils and rock borings and tests for the evaluation of all foundations and construction materials sufficient to determine the location and type of transmission line tower or appurtenant structures suitable for the site;
(ii) Copies of boring logs, geology reports, and laboratory test reports;
(iii) An identification of all borrow areas and quarry sites and an estimate of required quantities of suitable construction material;
(iv) Stability and stress analyses for all major transmission structures and conductors under all probable loading conditions, including seismic, wind, and ice loading, as appropriate, in sufficient detail to permit independent staff evaluation.
(4) The applicant must submit two copies of the supporting design report described in paragraph (m)(3) of this section at the time preliminary and final design drawings are filed. If the report contains preliminary drawings, it must be designated a “Preliminary Supporting Design Report.”
Appendix A to Part 380—Minimum Filing Requirements for Environmental Reports Under the Natural Gas Act
1. Provide a detailed description and location map of the project facilities. (§ 380.12(c)(1)).
2. Describe any nonjurisdictional facilities that would be built in association with the project. (§ 380.12(c)(2)).
3. Provide current original U.S. Geological Survey (USGS) 7.5-minute-series topographic maps with mileposts showing the project facilities; (§ 380.12(c)(3)).
4. Provide aerial images or photographs or alignment sheets based on these sources with mileposts showing the project facilities; (§ 380.12(c)(3)).
5. Provide plot/site plans of compressor stations showing the location of the nearest noise-sensitive areas (NSA) within 1 mile. (§ 380.12(c)(3,4)).
6. Describe construction and restoration methods. (§ 380.12(c)(6)).
7. Identify the permits required for construction across surface waters. (§ 380.12(c)(9)).
8. Provide the names and address of all affected landowners and certify that all affected landowners will be notified as required in § 157.6(d). (§§ 380.12(c)(10))
1. Identify all perennial surface waterbodies crossed by the proposed project and their water quality classification. (§ 380.12(d)(1)).
2. Identify all waterbody crossings that may have contaminated waters or sediments. (§ 380.12(d)(1)).
3. Identify watershed areas, designated surface water protection areas, and sensitive waterbodies crossed by the proposed project. (§ 380.12(d)(1)).
4. Provide a table (based on NWI maps if delineations have not been done) identifying all wetlands, by milepost and length, crossed by the project (including abandoned pipeline), and the total acreage and acreage of each wetland type that would be affected by construction. (§ 380.12(d)(1 & 4)).
5. Discuss construction and restoration methods proposed for crossing wetlands, and compare them to staff’s Wetland and Waterbody Construction and Mitigation Procedures; (§ 380.12(d)(2)).
6. Describe the proposed waterbody construction, impact mitigation, and restoration methods to be used to cross surface waters and compare to the staff’s Wetland and Waterbody Construction and Mitigation Procedures. (§ 380.12(d)(2)).
7. Provide original National Wetlands Inventory (NWI) maps or the appropriate state wetland maps, if NWI maps are not available, that show all proposed facilities and include milepost locations for proposed pipeline routes. (§ 380.12(d)(4)).
8. Identify all U.S. Environmental Protection Agency (EPA)- or state- designated aquifers crossed. (§ 380.12(d)(9)).
1. Classify the fishery type of each surface waterbody that would be crossed, including fisheries of special concern. (§ 380.12(e)(1)).
2. Describe terrestrial and wetland wildlife and habitats that would be affected by the project. (§ 380.12(e)(2)).
3. Describe the major vegetative cover types that would be crossed and provide the acreage of each vegetative cover type that would be affected by construction. (§ 380.12(e)(3)).
4. Describe the effects of construction and operation procedures on the fishery resources and proposed mitigation measures. (§ 380.12(e)(4)).
5. Evaluate the potential for short-term, long-term, and permanent impact on the wildlife resources and state-listed endangered or threatened species caused by construction and operation of the project and proposed mitigation measures. (§ 380.12(e)(4)).
6. Identify all federally listed or proposed endangered or threatened species that potentially occur in the vicinity of the project and discuss the results of the consultations with other agencies. Include survey reports as specified in § 380.12(e)(5).
7. Identify all federally listed essential fish habitat (EFH) that potentially occurs in the vicinity of the project and the results of abbreviated consultations with NMFS, and any resulting EFH assessments. (§ 380.12(e)(6))
8. Describe any significant biological resources that would be affected. Describe impact and any mitigation proposed to avoid or minimize that impact. (§§ 380.12(e)(4 & 7))
See § 380.14 and “OPR’s Guidelines for Reporting on Cultural Resources Investigations” for further guidance.
1. Initial cultural resources consultation and documentation, and documentation of consultation with Native Americans. (§ 380.12(f)(1)(i) & (2)).
2. Overview/Survey Report(s). (§ 380.12(f)(1)(ii) & (2)).
1. For major aboveground facilities and major pipeline projects that require an EIS, describe existing socioeconomic conditions within the project area. (§ 380.12(g)(1)).
2. For major aboveground facilities, quantify impact on employment, housing, local government services, local tax revenues, transportation, and other relevant factors within the project area. (§ 380.12(g)(2–6)).
1. Identify the location (by milepost) of mineral resources and any planned or active surface mines crossed by the proposed facilities. (§ 380.12(h)(1 & 2)).
2. Identify any geologic hazards to the proposed facilities. (§ 380.12(h)(2))
3. Discuss the need for and locations where blasting may be necessary in order to construct the proposed facilities. (§ 380.12(h)(3))
4. For underground storage facilities, how drilling activity by others within or adjacent to the facilities would be monitored, and how old wells would be located and monitored within the facility boundaries. (§ 380.12(h)(5))
1. Identify, describe, and group by milepost the soils affected by the proposed pipeline and aboveground facilities. (§ 380.12(i)(1))
2. For aboveground facilities that would occupy sites over 5 acres, determine the acreage of prime farmland soils that would be affected by construction and operation. (§ 380.12(i)(2))
3. Describe, by milepost, potential impacts on soils. (§ 380.12(i)(3,4))
4. Identify proposed mitigation to minimize impact on soils, and compare with the staff’s Upland Erosion Control, Revegetation, and Maintenance Plan. (§ 380.12(i)(5))
1. Classify and quantify land use affected by: (§ 380.12(j)(1))
a. Pipeline construction and permanent rights-of-way (§ 380.12(j)(1));
b. Extra work/staging areas (§ 380.12(j)(1));
c. Access roads (§ 380.12(j)(1));
d. Pipe and contractor yards (§ 380.12(j)(1)); and
e. Aboveground facilities (§ 380.12(j)(1)).
2. Identify by milepost all locations where the pipeline right-of-way would at least partially coincide with existing right-of-way, where it would be adjacent to existing rights-of-way, and where it would be outside of existing right-of-way. (§ 380.12(j)(1))
3. Provide detailed typical construction right-of-way cross-section diagrams showing information such as widths and relative locations of existing rights-of-way, new permanent right-of-way, and temporary construction right-of-way. (§ 380.12(j)(1))
4. Summarize the total acreage of land affected by construction and operation of the project. (§ 380.12(j)(1))
5. Identify by milepost all planned residential or commercial/business development and the time frame for construction. (§ 380.12(j)(3))
6. Identify by milepost special land uses (e.g., sugar maple stands, specialty crops, natural areas, national and state forests, conservation land, etc.). (§ 380.12(j)(4))
7. Identify by beginning milepost and length of crossing all land administered by Federal, state, or local agencies, or private conservation organizations. (§ 380.12(j)(4))
8. Identify by milepost all natural, recreational, or scenic areas, and all registered natural landmarks crossed by the project. (§ 380.12(j)(4 & 6))
9. Identify all facilities that would be within designated coastal zone management areas. Provide a consistency determination or evidence that a request for a consistency determination has been filed with the appropriate state agency. ((§ 380.12(j)(4 & 7))
10. Identify by milepost all residences that would be within 50 feet of the construction right-of-way or extra work area. (§ 380.12(j)(5))
11. Identify all designated or proposed candidate National or State Wild and Scenic Rivers crossed by the project. (§ 380.12(j)(6))
12. Describe any measures to visually screen aboveground facilities, such as compressor stations. (§ 380.12(j)(11))
13. Demonstrate that applications for rights-of-way or other proposed land use have been or soon will be filed with Federal land-managing agencies with jurisdiction over land that would be affected by the project. (§ 380.12(j)(12))
1. Describe existing air quality in the vicinity of the project. (§ 380.12(k)(1))
2. Quantify the existing noise levels (day-night sound level (L
3. Quantify existing and proposed emissions of compressor equipment, plus construction emissions, including nitrogen oxides (NO
4. Describe the existing compressor units at each station where new, additional, or modified compressor units are proposed, including the manufacturer, model number, and horsepower of the compressor units. For proposed new, additional, or modified compressor units include the horsepower, type, and energy source. (§ 380.12(k)(4)).
5. Identify any nearby noise-sensitive area by distance and direction from the proposed compressor unit building/enclosure. (§ 380.12(k)(4))
6. Identify any applicable state or local noise regulations. (§ 380.12(k)(4))
7. Calculate the noise impact at noise-sensitive areas of the proposed compressor unit modifications or additions, specifying how the impact was calculated, including manufacturer’s data and proposed noise control equipment. (§ 380.12(k)(4))
1. Address the “no action” alternative. (§ 380.12(l)(1))
2. For large projects, address the effect of energy conservation or energy alternatives to the project. (§ 380.12(l)(1))
3. Identify system alternatives considered during the identification of the project and provide the rationale for rejecting each alternative. (§ 380.12(l)(1))
4. Identify major and minor route alternatives considered to avoid impact on sensitive environmental areas (e.g., wetlands, parks, or residences) and provide sufficient comparative data to justify the selection of the proposed route. (§ 380.12(l)(2)(ii))
5. Identify alternative sites considered for the location of major new aboveground facilities and provide sufficient comparative data to justify the selection of the proposed site. (§ 380.12(l)(2)(ii))
Describe how the project facilities would be designed, constructed, operated, and maintained to minimize potential hazard to the public from the failure of project components as a result of accidents or natural catastrophes. (§ 380.12(m))
1. For projects involving the replacement or abandonment of facilities determined to have PCBs, provide a statement that activities would comply with an approved EPA disposal permit or with the requirements of the TSCA. (§ 380.12(n)(1))
2. For compressor station modifications on sites that have been determined to have soils contaminated with PCBs, describe the status of remediation efforts completed to date. (§ 380.12(n)(2))
Provide all the listed detailed engineering materials. (§ 380.12(o))
PART 381—FEES
Subpart A—General Provisions
§ 381.101 Purpose.
The purpose of this part is to set forth the fees charged by the Commission for services and benefits provided by the Commission.
§ 381.102 Definitions.
For purposes of this part, the following definitions apply.
(a) Person means any person, group, association, organization, partnership, corporation, or business, except those authorized to engage in the transaction of official business for the United States Government.
(b) Work year cost means the ratio of the Commission’s budgeted expenses during any given fiscal year to the authorized staff level for that fiscal year.
(c) Work-month means the amount of work represented by one employee’s devotion of 100 percent of his or her time for one month.
(d) Filing means any application, tariff or rate filing, intervention, complaint, petition, request, or motion submitted to the Commission in connection with any of the services or benefits for which a fee is established in this part.
§ 381.103 Filings.
(a) Submittal of fees. Except as provided in §§ 274.201(e) and 381.106, a fee in the amount set forth in this part shall accompany each filing for which a fee has been established.
(b) Deficiencies. (1) Any filing that is not accompanied by either the fee established for that filing or a petition for waiver in accordance with § 381.106(b) is deficient.
(2) The Secretary will inform any person submitting a deficient filing that:
(i) Such filing will be rejected unless the appropriate fee is submitted within a time specified by the Secretary;
(ii) The Commission will not process any filing that is deficient under this paragraph; and
(iii) The date of filing is the date on which the Commission receives the appropriate fee.
(3) This provision does not preclude a determination that a filing is deficient for any other reason.
(c) Choice of two or more fees. If a filing for one service or benefit may be considered as falling within two or more categories or services for which a fee is established, that filing must be accompanied by the higher or highest of the applicable fees.
§ 381.104 Annual adjustment of fees.
(a) Update and publication. The Commission, by its designee the Executive Director, will update its fees each fiscal year according to the formula in paragraph (c) of this section. The Executive Director will publish the fees in the
(b) Payment of updated fees. Any person who submits a filing for which a fee is established in this part must pay the currently effective fee unless a waiver is granted.
(c) Formula. (1) Except as provided in paragraph (c)(2) of this section, the formula for determining each fee is the work months dedicated to the given fee category for the six fiscal years 1987 through 1992 or all years prior to FY 93 for which data are available divided by the number of actual completions in the six fiscal years 1987 through 1992 or all years prior to FY 93 for which data are available multiplied by the average monthly employee cost in the most recent fiscal year for which data are available.
(2) With respect to the fees charged to pipelines filing pursuant to § 381.207(a), the fee for the first year will be $1,000. The formula for the fee in future years will be the work months from the immediately prior year divided by the number of actual completions in that year multiplied by the average monthly employee cost in the most recent fiscal year for which data are available. With the addition of future years, the formula for § 381.207(a) fees will be updated to include that year as part of the base period.
(d) Effective date of fee. Any fee updated under this section is effective on the thirtieth day after publication in the
§ 381.105 Method of payment.
Fee payment shall be made by check or money order payable to the Treasurer of the United States. The check should state the nature of the filing and the docket number where applicable so that the fee category for which the check is being submitted is clearly identifiable.
§ 381.106 Waivers.
(a) Filing of petition. If an applicant is suffering from severe economic hardship at the time of filing an application which makes the applicant economically unable to pay the appropriate fee for the application, rate change, tariff, petition, request or other filing requiring a fee, the applicant may submit an original and two copies of a petition for waiver with the application in lieu of the applicable fee. The petition for waiver must include evidence, such as a financial statement, clearly showing either that the applicant does not have the money to pay all or part of the fee, or that if the applicant does pay the fee, the applicant will be placed in financial distress or emergency.
(b) Decision on petition. The Commission or its designee will analyze each petition to determine whether the applicant has met the standards for waiver and then will notify the applicant of its grant or denial, in whole or in part. If the petition is denied, the applicant will have 30 days from the date of notification of the denial to submit the appropriate fee to the Commission.
§ 381.107 Direct billing.
(a) Applicability. If a filing presents an issue of fact, law, policy, procedural difficulty, or technical complexity that requires an extraordinary amount of expense to process, the Commission may institute a direct billing procedure for the direct and indirect costs of processing that filing. The Commission will make a direct billing determination under this paragraph not later than one year after receiving a complete filing from an applicant.
(b) Procedures. (1) Direct billing will not be instituted with respect to any filing until the person who submitted the filing is notified that direct billing will be applied to the filing in lieu of the fees established under this part.
(2) Any fee submitted with the filing will be applied, as a credit, to the amount billed directly for processing costs. The Secretary will thereafter periodically bill the person who submitted the filing for the actual direct and indirect costs of processing the filing.
(3) If the Commission institutes a direct billing for the costs of a hearing and reduces the fee to the applicant to less than full cost recovery due to the presence of intervenors, the Commission will consider, on a case-by-case basis, direct billing the intervenors for all or part of the reduced portion.
§ 381.108 Exemptions.
(a) Filing of petition. States, municipalities and anyone who is engaged in the official business of the Federal Government are exempt from the fees required by this part and may file a petition for exemption in lieu of the applicable fee.
(b) Decision on petition. A petitioner may claim this exemption by filing an original and two copies of a petition for exemption that includes evidence that the petitioner is a State or municipality, or is engaged in the official business of the Federal Government. The Commission or its designee will analyze each petition to determine whether the petition has met the standards for exemption and will notify the petitioner whether it is granted or denied. If the petition is denied, the person will have thirty days from the date of notification of the denial to submit the appropriate fee to the Commission.
§ 381.109 Refunds.
Fees established under this part may be refunded only if the related filing is withdrawn within fifteen (15) days of the date of filing or, if applicable, before the filing is noticed in the
§ 381.110 Fees for substantial amendments.
Fees established under this part for any filing will also be charged, as appropriate, for any substantial amendment to a pending filing. An amendment is considered substantial if it changes the character, nature, or the magnitude of the proposed activity or rate in the pending filing. For purposes of this section, an application for a temporary certificate is not considered to be an amendment to a pending certificate application.
Subpart B—Fees Applicable to the Natural Gas Act and Related Authorities
§ 381.207 Pipeline certificate applications.
(a) Definition. For purposes of this section, “pipeline certificate application” means any application for authorization or exemption, any substantial amendment to such an application, and any application, other than an application for a temporary certificate, for authorization to amend an outstanding authorization or exemption, by any person, made pursuant to section 7(c) of the Natural Gas Act filed in accordance with § 284.224 of this chapter.
(b) Fee. Unless the Commission orders direct billing under § 381.107 or otherwise, the fee established for a blanket certificate application is $1,000. The fee filed under this paragraph must be submitted in accordance with § 284.224 of this chapter.
(c) Effective date. Any pipeline certificate application filed with the Commission prior to November 4, 1985, is subject to the fees established by part 159 of this chapter to the extent that part 159 applies to such an application.
Subpart C—Fees Applicable to General Activities
§ 381.302 Petition for issuance of a declaratory order (except under Part I of the Federal Power Act).
(a) Except as provided in paragraph (b) of this section, the fee established for filing a petition for issuance of a declaratory order under § 385.207 of this chapter is $37,760. The fee must be submitted in accordance with subpart A of this part.
(b) No fee is necessary to file a petition for issuance of a declaratory order that solely concerns the investigation, issuance, transfer, renewal, revocation, and enforcement of licenses and permits for the construction, operation, and maintenance of dams, water conduits, reservoirs, powerhouses, transmission lines, or other works for the development and improvement of navigation and for the development and utilization of power across, along, from, or in navigable waters under Part I of the Federal Power Act.
(c) A person claiming the exemption provided in paragraph (b) of this section must file an original and two copies of a petition for exemption in lieu of a fee along with its petition for issuance of a declaratory order. The petition for exemption should summarize the issues raised in the petition for issuance of a declaratory order and explain why the exemption is applicable. The Commission or its designee will analyze each petition to determine whether the petition has met the standards for exemption and will notify the applicant whether it is granted or denied. If the petition is denied, the petitioner will have thirty days from the date of notification of the denial to submit the appropriate fee to the Commission.
§ 381.303 Review of a Department of Energy remedial order.
(a) Except as provided in § 381.303(b), the fee established for an answer to a Department of Energy remedial order under subpart I of the Commission’s Rules of Practice and Procedure, 18 CFR part 385, subpart I (1983), is $55,120. The fee must be submitted in accordance with subpart A of this part.
(b) If the amount in controversy is below $30,000, then the fee to file a petition for review of a DOE remedial order is reduced as follows:
| Fee | |
|---|---|
| Amount in controversy: | |
| $0 to $9,999 | $100 |
| $10,000 to $29,999 | 600 |
(c) In order to qualify for the fees in paragraph (b) of this section, the check must be accompanied by an affidavit by the petitioner that states the amount in controversy.
§ 381.304 Review of Department of Energy denial of adjustment.
(a) Except as provided in § 381.304(b), the fee established for filing a petition for review of a Department of Energy denial of an adjustment request under subpart J of the Commission’s Rules of Practice and Procedure, 18 CFR part 385, subpart J (1983), is $28,900. The fee must be submitted in accordance with subpart A of this part.
(b) If the amount in controversy is below $30,000, then the fee to file a petition for review of a DOE denial of an adjustment is reduced as follows:
| Fee | |
|---|---|
| Amount in controversy: | |
| $0 to $9,999 | $100 |
| $10,000 to $29,999 | 600 |
(c) In order to qualify for the fees in paragraph (b) of this section, the check must be accompanied by an affidavit by the petitioner that states the amount in controversy.
§ 381.305 Interpretations by the Office of the General Counsel.
(a) Except as provided in paragraph (b) of this section, the fee established for a written interpretation by the Office of the General Counsel of any statute or implementing regulation under the jurisdiction of the Commission is $10,830. The fee must be submitted in accordance with subpart A of this part and § 385.1901 or § 388.104 of this chapter.
(b) No fee is necessary to file a request for a written interpretation by the Office of the General Counsel that solely concerns matters under Part I of the Federal Power Act.
(c) A person claiming the exemption provided in paragraph (b) of this section must file an original and two copies of a petition for exemption in lieu of a fee along with the request for a written interpretation. The petition for exemption should summarize the issues raised in the request for a legal opinion and explain why the exemption is applicable. The Commission or its designee will analyze each petition to determine whether the petition has met the standards for exemption and will notify the applicant whether it is granted or denied. If the petition is denied, the applicant will have 30 days from the date of notification of the denial to submit the appropriate fee to the Commission.
Subpart D—Fees Applicable to the Natural Gas Policy Act of 1978
§ 381.401 Review of jurisdictional agency determinations.
The fee established for review of a jurisdictional agency determination is $115. The fee must be submitted in accordance with subpart A of this part and § 270.301(c) of this chapter.
§ 381.403 Petitions for rate approval pursuant to § 284.123(b)(2).
The fee established for a petition for rate approval pursuant to § 284.123(b)(2) is $18,790. Such fee must be submitted in accordance with subpart A of this part and § 284.123(b)(2).
§ 381.404 [Reserved]
Subpart E—Fees Applicable to Certain Matters Under Parts II and III of the Federal Power Act and the Public Utility Regulatory Policies Act
§ 381.501 Applicability.
The fees set forth in this subpart apply to filings submitted on or after November 4, 1985.
§ 381.505 Certification of qualifying status as a small power production facility or cogeneration facility.
(a) Unless the Commission orders direct billing under § 381.107 of this chapter or otherwise, the fee established for an application for Commission certification as a qualifying small power production facility, as defined in section 3(17) of the Federal Power Act, is $32,470 and the fee established for an application for Commission certification as a qualifying cogeneration facility, as defined in section 3(18) of the Federal Power Act, is $36,750.
(b) The fee filed under this section must be submitted in accordance with subpart A of this part and § 292.207(b)(2) of this chapter.
Subpart F [Reserved]
Subpart G—Fees Applicable to the Interstate Commerce Act and Related Authorities [Reserved]
PART 382—ANNUAL CHARGES
Subpart A—General Provisions
§ 382.101 Purpose.
The purpose of this part is to establish procedures for calculating and assessing annual charges to reimburse the United States for all of the costs incurred by the Commission, other than costs incurred in administering Part I of the Federal Power Act and costs recovered through the Commission’s filing fees.
§ 382.102 Definitions.
For the purpose of this part:
(a) Natural gas pipeline company means any person:
(1) Engaged in natural gas sales for resale or natural gas transportation subject to the jurisdiction of the Commission under the Natural Gas Act whose sales for resale and transportation exceed 200,000 Mcf at 14.73 psi (60 °F) in any of the three calendar years immediately preceding the fiscal year for which the Commission is assessing annual charges; and
(2) Not engaged solely in “first sales” of natural gas as that term is defined in section 2(21) of the Natural Gas Policy Act of 1978; and
(3) To whom the Commission has not issued a Natural Gas Act Section 7(f) declaration; and
(4) Not holding a limited jurisdiction certificate.
(b) Public utility means any person who owns or operates facilities subject to the jurisdiction of the Commission under Parts II and III of the Federal Power Act, and who has rate schedule(s) on file with the Commission and who is not a “qualifying small power producer” or a “qualifying cogenerator”, as those terms are defined in section 3 of the Federal Power Act, or the United States or a state, or any political subdivision of the United States or a state, or any agency, authority, or instrumentality of the United States, a state, political subdivision of the United States, or political subdivision of a state.
(c) Oil pipeline company means any person engaged in the transportation of crude oil and petroleum products subject to the Commission’s jurisdiction under the Interstate Commerce Act with annual operating revenues greater than $350,000 in any of the three calendar years immediately preceding the fiscal year for which the Commission is assessing annual charges.
(d) Natural gas regulatory program is the Commission’s regulation of the natural gas industry under the Natural Gas Act; Natural Gas Policy Act of 1978; Alaska Natural Gas Transportation Act; Public Utility Regulatory Policies Act; Department of Energy Organization Act; Outer Continental Shelf Lands Act; Energy Security Act; Regulatory Flexibility Act; Crude Oil Windfall Profit Tax Act; National Environmental Policy Act; National Historic Preservation Act.
(e) Electric regulatory program is the Commission’s regulation of the electric industry under Parts II and III of the Federal Power Act; Public Utility Regulatory Policies Act; Powerplant and Industrial Fuel Use Act; Department of Energy Organization Act; Energy Security Act; Regulatory Flexibility Act; Pacific Northwest Electric Power Planning and Conservation Act; Flood Control and River and Harbor Acts; Bonneville Project Act; Federal Columbia River Transmission Act; Reclamation Project Act; Nuclear Waste Policy Act; National Environmental Policy Act; and the Public Utility Holding Company Act.
(f) Oil regulatory program is the Commission’s regulation of the oil pipeline industry under the Interstate Commerce Act; Department of Energy Organization Act; Regulatory Flexibility Act; Outer Continental Shelf Lands Act; and the Crude Oil Windfall Profit Tax Act.
(g) Person means an individual, partnership, corporation, association, joint stock company, public trust, or organized group of persons, whether incorporated or not.
(h) Operating revenues means the monies:
(1) Received by an oil pipeline company for providing interstate common carrier services regulated by the Commission, and
(2) Included in FERC Account No. 200, 210, or 220 in FERC Annual Report Form No. 6, page 301, lines 1, 2 and 3, column d, under part 352 of the Commission’s regulations.
(i) Fiscal year means the twelve-month period that begins on the first day of October and ends on the last day of September.
(j) Preceding calendar year means the twelve-month period that begins on the first day of January and ends the last day of December and immediately precedes the end of the fiscal year for which the Commission is assessing annual charges.
(k) Adjusted costs of administration means the difference between the estimated costs of administering a regulatory program for each fiscal year adjusted to reflect any overcollection or undercollection of cost attributable to that regulatory program in the annual charge assessment for the preceding fiscal year, and the estimated amount of filing fees collected during that fiscal year under the provisions of parts 346 and 381 of the Commission’s regulations for activities that relate to that regulatory program.
(l) Power Marketing Agencies means the Bonneville Power Administration, the Alaska Power Administration, the Southeastern Power Administration, the Southwestern Power Administration, and the Western Area Power Administration.
§ 382.103 Payment.
(a) Annual charges assessed under this part must be paid within 45 days of the issuance of the bill by the Commission, unless a petition for waiver has been filed under § 382.105 of this part.
(b) Payment must be made by check, draft, or money order, payable to the United States Treasury.
(c) If payment is not made within 45 days of issuance of a bill, interest will be assessed. Interest will be computed in accordance with § 154.501(d) of this chapter, from the date on which the bill becomes delinquent.
§ 382.104 Enforcement.
The Commission may refuse to process any petition, application, or other filing submitted by or on the behalf of any person that does not pay the annual charge assessed when due, or may take any other appropriate action permitted by law.
§ 382.105 Waiver.
(a) Filing of petition. Any annual charges bill recipient may submit a petition for waiver of the regulations in this part. An original and two copies of a petition for waiver must include evidence, such as a financial statement, clearly showing either that the petitioner does not have the money to pay all or part of the annual charge, or, if the petitioner does pay the annual charge, that the petitioner will be placed in financial distress or emergency. Petitions for waiver must be filed with the Office of the Secretary of the Commission within 15 days of issuance of the bill.
(b) Decision on petition. The Commission or its designee will review the petition for waiver and then will notify the applicant of its grant or denial, in whole or in part. If the petition is denied in whole or in part, the annual charge becomes due 30 days from the date of notification of the denial.
§ 382.106 Accounting for annual charges paid under part 382.
(a) Any natural gas pipeline company subject to the provisions of this part must account for annual charges paid by charging the account to Account No. 928, Regulatory Commission Expenses, of the Commission’s Uniform System of Accounts.
(b) Any public utility subject to the provisions of this part must account for annual charges paid by charging the amount to Account No. 928, Regulatory Commission Expenses, of the Commission’s Uniform System Accounts.
(c) Any oil pipeline company subject to the provisions of this part must account for annual charges paid by charging the amount to Account No. 510, Supplies and Expenses, of the Commission’s Uniform System of Accounts.
Subpart B—Annual Charges
(a) Determination of costs to be assessed to public utilities. The adjusted costs of administration of the electric regulatory program, excluding the costs of regulating the Power Marketing Agencies, will be assessed to public utilities that provide transmission service (measured, as discussed in paragraph (c) of this section, by the sum of the megawatt-hours of all unbundled transmission and the megawatt-hours of all bundled wholesale power sales (to the extent these latter megawatt-hours were not separately reported as unbundled transmission)).
(b) Determination of annual charges to be assessed to public utilities. The costs determined under paragraph (a) of this section will be assessed as annual charges to each public utility providing transmission service based on the proportion of the megawatt-hours of transmission of electric energy in interstate commerce of each such public utility in the immediately preceding reporting year (either a calendar year or fiscal year, depending on which accounting convention is used by the public utility to be charged) to the sum of the megawatt-hours of transmission of electric energy in interstate commerce in the immediately preceding reporting year of all such public utilities.
(c) Reporting requirement. (1) For purposes of computing annual charges, as of January 1, 2002, a public utility, as defined in § 382.102(b), that provides transmission service must submit under oath to the Office of the Secretary by April 30 of each year an original and conformed copies of the following information (designated as FERC Reporting Requirement No. 582 (FERC–582)): The total megawatt-hours of transmission of electric energy in interstate commerce, which for purposes of computing the annual charges and for purposes of this reporting requirement, will be measured by the sum of the megawatt-hours of all unbundled transmission (including MWh delivered in wheeling transactions and MWh delivered in exchange transactions) and the megawatt-hours of all bundled wholesale power sales (to the extent these latter megawatt-hours were not separately reported as unbundled transmission). This information must be reported to 3 decimal places; e.g., 3,105 KWh will be reported as 3.105 MWh.
(2) Corrections to the information reported on FERC–582, as of January 1, 2002, must be submitted under oath to the Office of the Secretary on or before the end of each calendar year in which the information was originally reported (i.e., on or before the last day of the year that the Commission is open to accept such filings).
(d) Determination of annual charges to be assessed to power marketing agencies. The adjusted costs of administration of the electric regulatory program as it applies to Power Marketing Agencies will be assessed against each power marketing agency based on the proportion of the megawatt-hours of sales of each power marketing agency in the immediately preceding reporting year (either a calendar year or fiscal year, depending on which accounting convention is used by the power marketing agency to be charged) to the sum of the megawatt-hours of sales in the immediately preceding reporting year of all power marketing agencies being assessed annual charges.
The adjusted costs of administration of the natural gas regulatory program will be assessed against each natural gas pipeline company based on the proportion of the total gas subject to Commission regulation which was sold and transported by each company in the immediately preceding calendar year to the sum of the gas subject to the Commission regulation which was sold and transported in the immediately preceding calendar year by all natural gas pipeline companies being assessed annual charges.
§ 382.203 Annual charges under the Interstate Commerce Act.
(a) The adjusted costs of administration of the oil regulatory program will be assessed against each oil pipeline company based on the proportion of the total operation revenues of each oil pipeline company for the immediately preceding calendar year to the sum of the operating revenues for the immediately preceding calendar year of all oil pipeline companies being assessed annual charges.
(b) No oil pipeline company’s annual charge may exceed a maximum charge established each year by the Commission to equal 6.339 percent of the adjusted costs of administration of the oil regulatory program. The maximum charge will be rounded to the nearest $1000. For every company with an annual charge determined to be above the maximum charge, that company’s annual charge will be set at the maximum charge, and any amount above the maximum charge will be reapportioned to the remaining companies. The reapportionment will be computed using the method outlined in paragraph (a) of this section (but excluding any company whose annual charge is already set at the maximum amount). This procedure will be repeated until no company’s annual charge exceeds the maximum charge.
SUBCHAPTER X—PROCEDURAL RULES
PART 385—RULES OF PRACTICE AND PROCEDURE
Subpart A—Applicability and Definitions
§ 385.101 Applicability (Rule 101).
(a) General rules. Except as provided in paragraph (b) of this section, this part applies to:
(1) Any filing or proceeding under this chapter; and
(2) Any oil pipeline filing or proceeding under this chapter or 49 CFR Chapter X and replaces the Interstate Commerce Commission General Rules of Practice (49 CFR part 1100) with respect to any oil pipeline filing or proceeding.
(b) Exceptions. (1) This part does not apply to investigations under part 1b of this chapter.
(2) If any provision of this part is inconsistent with any provision of another part of this chapter, the provision of this part is inapplicable and the provision of the other part governs to the extent of the inconsistency.
(3) If any provision of this part is inconsistent with any provision of 49 CFR Chapter X that is not otherwise replaced by this part or Commission rule or order, the provision of this part is inapplicable and the provision of 49 CFR Chapter X governs to the extent of the inconsistency.
(c) Transitional provisions. (1) This part applies to any filing submitted on or after and to any proceeding pending on or initiated after, August 26, 1982.
(2) A decisional authority may, in the interest of justice:
(i) Apply the appropriate provisions of the prior Rules of Practice and Procedure (18 CFR part 1) to any filing submitted after, or to any proceeding or part of a proceeding pending on August 26, 1982;
(ii) Apply the provisions of this part to any filing submitted, or any proceeding or part of a proceeding initiated, after April 28, 1982 but before August 26, 1982.
(d) [Reserved]
(e) Waiver. To the extent permitted by law, the Commission may, for good cause, waive any provision of this part or prescribe any alternative procedures that it determines to be appropriate.
§ 385.102 Definitions (Rule 102).
For purposes of this part—
(a) Decisional authority means the Commission or Commission employee that, at the time for decision on a question, has authority or responsibility under this chapter to decide that particular question.
(b) Participant means:
(1) Any party; or
(2) Any employee of the Commission assigned to present the position of the Commission staff in a proceeding before the Commission.
(c) Party means, with respect to a proceeding:
(1) A person filing any application, petition, tariff or rate filing, complaint, or any protest under section 19a(i) of the Interstate Commerce Act (49 U.S.C. 19a(i));
(2) Any respondent to a proceeding; or
(3) Any person whose intervention in a proceeding is effective under Rule 214.
(d) Person means an individual, partnership, corporation, association, joint stock company, public trust, an organized group of persons, whether incorporated or not, a receiver or trustee of the foregoing, a municipality, including a city, county, or any other political subdivision of a State, a State, the District of Columbia, any territory of the United States or any agency of any of the foregoing, any agency, authority, or instrumentality of the United States (other than the Commission), or any corporation which is owned directly or indirectly by the United States, or any officer, agent, or employee of any of the foregoing acting as such in the course of his or her official duty. The term also includes a foreign government or any agency, authority, or instrumentality thereof.
(e) Presiding officer means:
(1) With respect to any proceeding set for hearing under subpart E of this part, one or more Members of the Commission, or any administrative law judge, designated to preside at such hearing, or, if no Commissioner or administrative law judge is designated, the Chief Administrative Law Judge; or
(2) With respect to any proceeding not set for hearing under subpart E, any employee designated by rule or order to conduct the proceeding.
(f) Respondent means any person:
(1) To whom an order to show cause or notice of tariff or rate examination is issued by the Commission;
(2) Against whom a complaint is directed; or
(3) Designated as a respondent by the Commission or by the terms of this chapter.
§ 385.103 References to rules (Rule 103).
This part cross-references its sections according to rule number, as indicated by the section titles. Any filing with the Commission may refer to any section of this part by rule number; for example, “Rule 103.”
§ 385.104 Rule of construction (Rule 104).
To the extent that the text of a rule is inconsistent with its caption, the text of the rule controls.
Subpart B—Pleadings, Tariff and Rate Filings, Notices of Tariff or Rate Examination, Orders To Show Cause, Intervention, and Summary Disposition
§ 385.201 Applicability (Rule 201).
This subpart applies to any pleading, tariff or rate filing, notice of tariff or rate examination, order to show cause, intervention, or summary disposition.
§ 385.202 Types of pleadings (Rule 202).
Pleadings include any application, complaint, petition, protest, notice of protest, answer, motion, and any amendment or withdrawal of a pleading. Pleadings do not include comments on rulemakings or comments on offers of settlement.
§ 385.203 Content of pleadings and tariff or rate filings (Rule 203).
(a) Requirements for a pleading or a tariff or rate filing. Each pleading and each tariff or rate filing must include, as appropriate:
(1) If known, the reference numbers, docket numbers, or other identifying symbols of any relevant tariff, rate, schedule, contract, application, rule, or similar matter or material;
(2) The name of each participant for whom the filing is made or, if the filing is made for a group of participants, the name of the group, provided that the name of each member of the group is set forth in a previously filed document which is identified in the filing being made;
(3) The specific authorization or relief sought;
(4) The tariff or rate sheets or sections;
(5) The name and address of each person against whom the complaint is directed;
(6) The relevant facts, if not set forth in a previously filed document which is identified in the filing being made;
(7) The position taken by the participant filing any pleading, to the extent known when the pleading is filed, and the basis in fact and law for such position;
(8) Subscription or verification, if required;
(9) A certificate of service under Rule 2010(h), if service is required;
(10) The name, address, and telephone number of an individual who, with respect to any matter contained in the filing, represents the person for whom filing is made; and
(11) Any additional information required to be included by statute, rule, or order.
(b) Requirement for any initial pleading or tariff or rate filing. The initial pleading or tariff or rate filing submitted by a participant or a person seeking to become a party must conform to the requirements of paragraph (a) of this section and must include:
(1) The exact name of the person for whom the filing is made;
(2) The location of that person’s principal place of business; and
(3) The name, address, and telephone number of at least one, but not more than two, persons upon whom service is to be made and to whom communications are to be addressed in the proceeding.
(c) Combined filings. If two or more pleadings, or one or more pleadings and a tariff or rate filing are included as items in a single filing each such item must be separately designated and must conform to the requirements which would be applicable to it if filed separately.
(d) Form of notice. If a pleading or tariff or rate filing must include a form of notice suitable for publication in the
§ 385.204 Applications (Rule 204).
Any person seeking a license, permit, certification, or similar authorization or permission, must file an application to obtain that authorization or permission.
§ 385.205 Tariff or rate filings (Rule 205).
(a) A person must make a tariff or rate filing in order to establish or change any specific rate, rate schedule, tariff, tariff schedule, fare, charge, or term or condition of service, or any classification, contract, practice, or any related regulation established by and for the applicant.
(b) A tariff or rate filing must be made electronically in accordance with the requirements and formats for electronic filing listed in the instructions for electronic filings. A tariff or rate filing not made in accordance with these requirements and formats will not have a statutory action date and will not become effective should the Commission not act by the requested action date.
§ 385.206 Complaints (Rule 206).
(a) General rule. Any person may file a complaint seeking Commission action against any other person alleged to be in contravention or violation of any statute, rule, order, or other law administered by the Commission, or for any other alleged wrong over which the Commission may have jurisdiction.
(b) Contents. A complaint must:
(1) Clearly identify the action or inaction which is alleged to violate applicable statutory standards or regulatory requirements;
(2) Explain how the action or inaction violates applicable statutory standards or regulatory requirements;
(3) Set forth the business, commercial, economic or other issues presented by the action or inaction as such relate to or affect the complainant;
(4) Make a good faith effort to quantify the financial impact or burden (if any) created for the complainant as a result of the action or inaction;
(5) Indicate the practical, operational, or other nonfinancial impacts imposed as a result of the action or inaction, including, where applicable, the environmental, safety or reliability impacts of the action or inaction;
(6) State whether the issues presented are pending in an existing Commission proceeding or a proceeding in any other forum in which the complainant is a party, and if so, provide an explanation why timely resolution cannot be achieved in that forum;
(7) State the specific relief or remedy requested, including any request for stay or extension of time, and the basis for that relief;
(8) Include all documents that support the facts in the complaint in possession of, or otherwise attainable by, the complainant, including, but not limited to, contracts and affidavits;
(9) State
(i) Whether the Enforcement Hotline, Dispute Resolution Service, tariff-based dispute resolution mechanisms, or other informal dispute resolution procedures were used, or why these procedures were not used;
(ii) Whether the complainant believes that alternative dispute resolution (ADR) under the Commission’s supervision could successfully resolve the complaint;
(iii) What types of ADR procedures could be used; and
(iv) Any process that has been agreed on for resolving the complaint.
(10) Include a form of notice of the complaint suitable for publication in the
(11) Explain with respect to requests for Fast Track processing pursuant to section 385.206(h), why the standard processes will not be adequate for expeditiously resolving the complaint.
(c) Service. Any person filing a complaint must serve a copy of the complaint on the respondent, affected regulatory agencies, and others the complainant reasonably knows may be expected to be affected by the complaint. Service must be simultaneous with filing at the Commission for respondents. Simultaneous or overnight service is permissible for other affected entities. Simultaneous service can be accomplished by electronic mail in accordance with § 385.2010(f)(3), facsimile, express delivery, or messenger.
(d) Notice. Public notice of the complaint will be issued by the Commission.
(e) [Reserved]
(f) Answers, interventions and comments. Unless otherwise ordered by the Commission, answers, interventions, and comments to a complaint must be filed within 20 days after the complaint is filed. In cases where the complainant requests privileged treatment for information in its complaint, answers, interventions, and comments are due within 30 days after the complaint is filed. In the event there is an objection to the protective agreement, the Commission will establish when answers will be due.
(g) Complaint resolution paths. One of the following procedures may be used to resolve complaints:
(1) The Commission may assign a case to be resolved through alternative dispute resolution procedures in accordance with §§ 385.604–385.606, in cases where the affected parties consent, or the Commission may order the appointment of a settlement judge in accordance with § 385.603;
(2) The Commission may issue an order on the merits based upon the pleadings;
(3) The Commission may establish a hearing before an ALJ;
(h) Fast Track processing. (1) The Commission may resolve complaints using Fast Track procedures if the complaint requires expeditious resolution. Fast Track procedures may include expedited action on the pleadings by the Commission, expedited hearing before an ALJ, or expedited action on requests for stay, extension of time, or other relief by the Commission or an ALJ.
(2) A complainant may request Fast Track processing of a complaint by including such a request in its complaint, captioning the complaint in bold type face “COMPLAINT REQUESTING FAST TRACK PROCESSING,” and explaining why expedition is necessary as required by section 385.206(b)(11).
(3) Based on an assessment of the need for expedition, the period for filing answers, interventions and comments to a complaint requesting Fast Track processing may be shortened by the Commission from the time provided in section 385.206(f).
(4) After the answer is filed, the Commission will issue promptly an order specifying the procedure and any schedule to be followed.
(i) Simplified procedure for small controversies. A simplified procedure for complaints involving small controversies is found in section 385.218 of this subpart.
(j) Satisfaction. (1) If the respondent to a complaint satisfies such complaint, in whole or in part, either before or after an answer is filed, the complainant and the respondent must sign and file:
(i) A statement setting forth when and how the complaint was satisfied; and
(ii) A motion for dismissal of, or an amendment to, the complaint based on the satisfaction.
(2) The decisional authority may order the submission of additional information before acting on a motion for dismissal or an amendment under paragraph (c)(1)(ii) of this section.
§ 385.207 Petitions (Rule 207).
(a) General rule. A person must file a petition when seeking:
(1) Relief under subpart I, J, or K of this part;
(2) A declaratory order or rule to terminate a controversy or remove uncertainty;
(3) Action on appeal from a staff action, other than a decision or ruling of a presiding officer, under Rule 1902;
(4) A rule of general applicability; or
(5) Any other action which is in the discretion of the Commission and for which this chapter prescribes no other form of pleading.
(b) Declarations of intent under the Federal Power Act. For purposes of this part, a declaration of intent under section 23(b) of the Federal Power Act is treated as a petition for a declaratory order.
(c) Except as provided in § 381.302(b), each petition for issuance of a declaratory order must be accompanied by the fee prescribed in § 381.302(a).
§ 385.208 [Reserved]
§ 385.209 Notices of tariff or rate examination and orders to show cause (Rule 209).
(a) Issuance. (1) If the Commission seeks to determine the validity of any rate, rate schedule, tariff, tariff schedule, fare, charge, or term or condition of service, or any classification, contract, practice, or any related regulation established by and for the applicant which is demanded, observed, charged, or collected, the Commission will initiate a proceeding by issuing a notice of tariff or rate examination.
(2) The Commission may initiate a proceeding against a person by issuing an order to show cause.
(b) Contents. A notice of examination or an order to show cause will contain a statement of the matters about which the Commission is inquiring, and a statement of the authority under which the Commission is acting. The statement is tentative and sets forth issues to be considered by the Commission.
(c) Answers. A person who is ordered to show cause must answer in accordance with Rule 213.
§ 385.210 Method of notice; dates established in notice (Rule 210).
(a) Method. When the Secretary gives notice of tariff or rate filings, applications, petitions, notices of tariff or rate examinations, and orders to show cause, the Secretary will give such notice in accordance with Rule 2009.
(b) Dates for filing interventions and protests. A notice given under this section will establish the dates for filing interventions and protests. Only those filings made within the time prescribed in the notice will be considered timely.
§ 385.211 Protests other than under Rule 208 (Rule 211).
(a) General rule. (1) Any person may file a protest to object to any application, complaint, petition, order to show cause, notice of tariff or rate examination, or tariff or rate filing.
(2) The filing of a protest does not make the protestant a party to the proceeding. The protestant must intervene under Rule 214 to become a party.
(3) Subject to paragraph (a)(4) of this section, the Commission will consider protests in determining further appropriate action. Protests will be placed in the public file associated with the proceeding.
(4) If a proceeding is set for hearing under subpart E of this part, the protest is not part of the record upon which the decision is made.
(b) Service. (1) Any protest directed against a person in a proceeding must be served by the protestant on the person against whom the protest is directed.
(2) The Secretary may waive any procedural requirement of this subpart applicable to protests. If the requirement of service under this paragraph is waived, the Secretary will place the protest in the public file and may send a copy thereof to any person against whom the protest is directed.
§ 385.212 Motions (Rule 212).
(a) General rule. A motion may be filed:
(1) At any time, unless otherwise provided;
(2) By a participant or a person who has filed a timely motion to intervene which has not been denied;
(3) In any proceeding except an informal rulemaking proceeding.
(b) Written and oral motions. Any motion must be filed in writing, except that the presiding officer may permit an oral motion to be made on the record during a hearing or conference.
(c) Contents. A motion must contain a clear and concise statement of:
(1) The facts and law which support the motion; and
(2) The specific relief or ruling requested.
§ 385.213 Answers (Rule 213).
(a) Required or permitted. (1) Any respondent to a complaint or order to show cause must make an answer, unless the Commission orders otherwise.
(2) An answer may not be made to a protest, an answer, a motion for oral argument, or a request for rehearing, unless otherwise ordered by the decisional authority. A presiding officer may prohibit an answer to a motion for interlocutory appeal. If an answer is not otherwise permitted under this paragraph, no responsive pleading may be made.
(3) An answer may be made to any pleading, if not prohibited under paragraph (a)(2) of this section.
(4) An answer to a notice of tariff or rate examination must be made in accordance with the provisions of such notice.
(b) Written or oral answers. Any answer must be in writing, except that the presiding officer may permit an oral answer to a motion made on the record during a hearing conducted under subpart E or during a conference.
(c) Contents. (1) An answer must contain a clear and concise statement of:
(i) Any disputed factual allegations; and
(ii) Any law upon which the answer relies.
(2) When an answer is made in response to a complaint, an order to show cause, or an amendment to such pleading, the answerer must, to the extent practicable:
(i) Admit or deny, specifically and in detail, each material allegation of the pleading answered; and
(ii) Set forth every defense relied on.
(3) General denials of facts referred to in any order to show cause, unsupported by the specific facts upon which the respondent relies, do not comply with paragraph (a)(1) of this section and may be a basis for summary disposition under Rule 217, unless otherwise required by statute.
(4) An answer to a complaint must include documents that support the facts in the answer in possession of, or otherwise attainable by, the respondent, including, but not limited to, contracts and affidavits. An answer is also required to describe the formal or consensual process it proposes for resolving the complaint.
(5) When submitting with its answer any request for privileged treatment of documents and information in accordance with this chapter, a respondent must provide a public version of its answer without the information for which privileged treatment is claimed and its proposed form of protective agreement to each entity that has either been served pursuant to § 385.206(c) or whose name is on the official service list for the proceeding compiled by the Secretary.
(d) Time limitations. (1) Any answer to a motion or to an amendment to a motion must be made within 15 days after the motion or amendment is filed, except as described below or unless otherwise ordered.
(i) If a motion requests an extension of time or a shortened time period for action, then answers to the motion to extend or shorten the time period shall be made within 5 days after the motion is filed, unless otherwise ordered.
(ii) [Reserved]
(2) Any answer to a pleading or amendment to a pleading, other than a complaint or an answer to a motion under paragraph (d)(1) of this section, must be made:
(i) If notice of the pleading or amendment is published in the
(ii) If notice of the pleading or amendment is not published in the
(e) Failure to answer. (1) Any person failing to answer a complaint may be considered in default, and all relevant facts stated in such complaint may be deemed admitted.
(2) Failure to answer an order to show cause will be treated as a general denial to which paragraph (c)(3) of this section applies.
§ 385.214 Intervention (Rule 214).
(a) Filing. (1) The Secretary of Energy is a party to any proceeding upon filing a notice of intervention in that proceeding. If the Secretary’s notice is not filed within the period prescribed under Rule 210(b), the notice must state the position of the Secretary on the issues in the proceeding.
(2) Any State Commission, the Advisory Council on Historic Preservation, the U.S. Departments of Agriculture, Commerce, and the Interior, any state fish and wildlife, water quality certification, or water rights agency; or Indian tribe with authority to issue a water quality certification is a party to any proceeding upon filing a notice of intervention in that proceeding, if the notice is filed within the period established under Rule 210(b). If the period for filing notice has expired, each entity identified in this paragraph must comply with the rules for motions to intervene applicable to any person under paragraph (a)(3) of this section including the content requirements of paragraph (b) of this section.
(3) Any person seeking to intervene to become a party, other than the entities specified in paragraphs (a)(1) and (a)(2) of this section, must file a motion to intervene.
(4) No person, including entities listed in paragraphs (a)(1) and (a)(2) of this section, may intervene as a matter of right in a proceeding arising from an investigation pursuant to Part 1b of this chapter.
(b) Contents of motion. (1) Any motion to intervene must state, to the extent known, the position taken by the movant and the basis in fact and law for that position.
(2) A motion to intervene must also state the movant’s interest in sufficient factual detail to demonstrate that:
(i) The movant has a right to participate which is expressly conferred by statute or by Commission rule, order, or other action;
(ii) The movant has or represents an interest which may be directly affected by the outcome of the proceeding, including any interest as a:
(A) Consumer,
(B) Customer,
(C) Competitor, or
(D) Security holder of a party; or
(iii) The movant’s participation is in the public interest.
(3) If a motion to intervene is filed after the end of any time period established under Rule 210, such a motion must, in addition to complying with paragraph (b)(1) of this section, show good cause why the time limitation should be waived.
(c) Grant of party status. (1) If no answer in opposition to a timely motion to intervene is filed within 15 days after the motion to intervene is filed, the movant becomes a party at the end of the 15 day period.
(2) If an answer in opposition to a timely motion to intervene is filed not later than 15 days after the motion to intervene is filed or, if the motion is not timely, the movant becomes a party only when the motion is expressly granted.
(d) Grant of late intervention. (1) In acting on any motion to intervene filed after the period prescribed under Rule 210, the decisional authority may consider whether:
(i) The movant had good cause for failing to file the motion within the time prescribed;
(ii) Any disruption of the proceeding might result from permitting intervention;
(iii) The movant’s interest is not adequately represented by other parties in the proceeding;
(iv) Any prejudice to, or additional burdens upon, the existing parties might result from permitting the intervention; and
(v) The motion conforms to the requirements of paragraph (b) of this section.
(2) Except as otherwise ordered, a grant of an untimely motion to intervene must not be a basis for delaying or deferring any procedural schedule established prior to the grant of that motion.
(3)(i) The decisional authority may impose limitations on the participation of a late intervener to avoid delay and prejudice to the other participants.
(ii) Except as otherwise ordered, a late intervener must accept the record of the proceeding as the record was developed prior to the late intervention.
(4) If the presiding officer orally grants a motion for late intervention, the officer will promptly issue a written order confirming the oral order.
§ 385.215 Amendment of pleadings and tariff or rate filings (Rule 215).
(a) General rules. (1) Any participant, or any person who has filed a timely motion to intervene which has not been denied, may seek to modify its pleading by filing an amendment which conforms to the requirements applicable to the pleading to be amended.
(2) A tariff or rate filing may be amended or modified only as provided in the regulations under this chapter. A tariff or rate filing may not be amended, except as allowed by statute. The procedures provided in this section do not apply to amendment of tariff or rate filings.
(3)(i) If a written amendment is filed in a proceeding, or part of a proceeding, that is not set for hearing under subpart E, the amendment becomes effective as an amendment on the date filed.
(ii) If a written amendment is filed in a proceeding, or part of a proceeding, which is set for hearing under subpart E, that amendment is effective on the date filed only if the amendment is filed more than five days before the earlier of either the first prehearing conference or the first day of evidentiary hearings.
(iii) If, in a proceeding, or part of a proceeding, that is set for hearing under subpart E, a written amendment is filed after the time for filing provided under paragraph (a)(3)(ii) of this section, or if an oral amendment is made to a presiding officer during a hearing or conference, the amendment becomes effective as an amendment only as provided under paragraph (d) of this section.
(b) Answers. Any participant, or any person who has filed a timely motion to intervene which has not been denied, may answer a written or oral amendment in accordance with Rule 213.
(c) Motion opposing an amendment. Any participant, or any person who has filed a timely motion to intervene which has not been denied, may file a motion opposing the acceptance of any amendment, other than an amendment under paragraph (a)(3)(i) of this section, not later than 15 days after the filing of the amendment.
(d) Acceptance of amendments. (1) An amendment becomes effective as an amendment at the end of 15 days from the date of filing, if no motion in opposition to the acceptance of an amendment under paragraph (a)(3)(iii) of this section is filed within the 15 day period.
(2) If a motion in opposition to the acceptance of an amendment is filed within 15 days after the filing of the amendment, the amendment becomes effective as an amendment on the twentieth day after the filing of the amendment, except to the extent that the decisional authority, before such date, issues an order rejecting the amendment, wholly or in part, for good cause.
(e) Directed amendments. A decisional authority, on motion or otherwise, may direct any participant, or any person seeking to be a party, to file a written amendment to amplify, clarify, or technically correct a pleading.
§ 385.216 Withdrawal of pleadings (Rule 216).
(a) Filing. Any person that filed a pleading may seek to withdraw it by filing a notice of withdrawal. The procedures provided in this section do not apply to withdrawals of tariff or rate filings, which may be withdrawn only as provided in the regulations under this chapter.
(b) Action on withdrawals. (1) The withdrawal of any pleading is effective at the end of 15 days from the date of filing of a notice of withdrawal, if no motion in opposition to the notice of withdrawal is filed within that period and the decisional authority does not issue an order disallowing the withdrawal within that period. The decisional authority may disallow, for a good cause, all or part of a withdrawal.
(2) If a motion in opposition to a notice of withdrawal is filed within the 15 day period, the withdrawal is not effective until the decisional authority issues an order accepting the withdrawal.
(c) Conditional withdrawal. In order to prevent prejudice to other participants, a decisional authority may, on motion or otherwise, condition the withdrawal of any pleading upon a requirement that the withdrawing person leave material in the record or otherwise make material available to other participants.
§ 385.217 Summary disposition (Rule 217).
(a) Applicability. This section applies to:
(1) Any proceeding, or any part of a proceeding, while the Commission is the decisional authority; and
(2) Any proceeding, or part of a proceeding, which is set for hearing under subpart E.
(b) General rule. If the decisional authority determines that there is no genuine issue of fact material to the decision of a proceeding or part of a proceeding, the decisional authority may summarily dispose of all or part of the proceeding.
(c) Procedures. (1) Any participant may make a motion for summary disposition of all or part of a proceeding.
(2) If a decisional authority, other than the Commission, is considering summary disposition of a proceeding, or part of a proceeding, in the absence of a motion for summary disposition by a participant, the decisional authority will grant the participants an opportunity to comment on the proposed disposition prior to any summary disposition, unless, for good cause shown, the decisional authority provides otherwise.
(3) If, prior to setting a matter for hearing, the Commission is considering summary disposition of a proceeding or part of a proceeding in the absence of a motion for summary disposition by any participant and the Commission determines that notice and comment on summary disposition are practicable and necessary, the Commission may notify the participants and afford them an opportunity to comment on any proposed summary disposition.
(d) Disposition. (1)(i) If a decisional authority, other than the Commission, summarily disposes of an entire proceeding, the decisional authority will issue an initial decision for the entire proceeding.
(ii) Except as provided under paragraph (d)(1)(iii) of this section, a decisional authority, other than the Commission, which summarily disposes of part of a proceeding may:
(A) Issue a partial initial decision; or
(B) Postpone issuing an initial decision on the summarily disposed part and combine it with the initial decision on the entire proceeding or other appropriate part of the proceeding.
(iii) If the decisional authority, other than the Commission, summarily disposes of part of a proceeding and such disposition requires the filing of new tariff or rate schedule sheets or sections, the decisional authority will issue an initial decision on that part of the proceeding.
(2) Any initial decision issued under paragraph (d)(1) of this section is considered an initial decision issued under subpart G of this part, except that the following rules do not apply: Rule 704 (rights of participants before initial decision), Rule 705 (discretion of presiding officer before initial decision), Rule 706 (initial and reply briefs before initial decision), Rule 707 (oral argument before initial decision), and Rule 709 (other types of decisions).
§ 385.218 Simplified procedure for complaints involving small controversies (Rule 218).
(a) Eligibility. The procedures under this section are available to complainants if the amount in controversy is less than $100,000 and the impact on other entities is de minimis.
(b) Contents. A complaint filed under this section must contain:
(1) The name of the complainant;
(2) The name of the respondent;
(3) A description of the relationship to the respondent;
(4) The amount in controversy;
(5) A statement why the complaint will have a de minimis impact on other entities;
(6) The facts and circumstances surrounding the complaint, including the legal or regulatory obligation breached by the respondent; and
(7) The requested relief.
(c) Service. The complainant is required to simultaneously serve the complaint on the respondent and any other entity referenced in the complaint.
(d) Notice. Public notice of the complaint will be issued by the Commission.
(e) Answers, interventions and comments. (1) An answer to a complaint is required to conform to the requirements of § 385.213(c)(1), (2), and (3).
(2) Answers, interventions and comments must be filed within 10 days after the complaint is filed. In cases where the complainant requests privileged treatment for information in its complaint, answers, interventions, and comments must be filed within 20 days after the complaint is filed. In the event there is an objection to the protective agreement, the Commission will establish when answers, interventions, and comments are due.
(f) Privileged treatment. If a complainant seeks privileged treatment for any documents submitted with the complaint, a complainant must use the procedures described in section 385.206(e). If a respondent seeks privileged treatment for any documents submitted with the answer, a respondent must use the procedures described in section 385.213(c)(5).
Subpart C [Reserved]
Subpart D—Discovery Procedures for Matters Set for Hearing Under Subpart E
§ 385.401 Applicability (Rule 401).
(a) General rule. Except as provided in paragraph (b) of this section, this subpart applies to discovery in proceedings set for hearing under subpart E of this part, and to such other proceedings as the Commission may order.
(b) Exceptions. Unless otherwise ordered by the Commission, this subpart does not apply to:
(1) Requests for information under the Freedom of Information Act, 5 U.S.C. 552, governed by Part 388 of this chapter; or,
(2) Requests by the Commission or its staff who are not participants in a proceeding set for hearing under subpart E of this part to obtain information, reports, or data from persons subject to the Commission’s regulatory jurisdiction; or
(3) Investigations conducted pursuant to Part 1b of this chapter.
§ 385.402 Scope of discovery (Rule 402).
(a) General. Unless otherwise provided under paragraphs (b) and (c) of this section or ordered by the presiding officer under Rule 410(c), participants may obtain discovery of any matter, not privileged, that is relevant to the subject matter of the pending proceeding, including the existence, description, nature, custody, condition, and location of any books, documents, or other tangible things, and the identity and location of persons having any knowledge of any discoverable matter. It is not ground for objection that the information sought will be inadmissible in the Commission proceeding if the information sought appears reasonably calculated to lead to the discovery of admissible evidence.
(b) Material prepared for litigation. A participant may not obtain discovery of material prepared in anticipation of litigation by another participant, unless that participant demonstrates a substantial need for the material and that substantially equivalent material cannot be obtained by other means without undue hardship. In ordering any such discovery, the presiding officer will prevent disclosure of the mental impressions, conclusions, opinions, or legal theories of an attorney.
(c) Expert testimony. Unless otherwise restricted by the presiding officer under Rule 410(c), a participant may discover any facts known or opinions held by an expert concerning any relevant matters, not privileged. Such discovery will be permitted only if:
(1) The expert is expected to be a witness at hearing; or
(2) The expert is relied on by another expert who is expected to be a witness at hearing, and the participant seeking discovery shows a compelling need for the information and it cannot practicably be obtained by other means.
§ 385.403 Methods of discovery; general provisions (Rule 403).
(a) Discovery methods. Participants may obtain discovery by data requests, written interrogatories, and requests for production of documents or things (Rule 406), depositions by oral examination (Rule 404), requests for inspection of documents and other property (Rule 407), and requests for admission (Rule 408).
(b) Discovery conferences. (1) The presiding officer may direct the participants in a proceeding or their representatives to appear for one or more conferences, either separately or as part of any other prehearing conference in the proceeding under Rule 601(a), for the purpose of scheduling discovery, identifying discovery issues, and resolving discovery disputes. Except as provided in paragraph (b)(2) of this section, the presiding officer, upon the conclusion of a conference, will issue an order stating any and all decisions made and agreements reached during the conference.
(2) The Chief Administrative Law Judge may, upon a showing of extraordinary circumstances, waive the requirement to issue an order under paragraph (b)(1) of this section.
(c) Identification and certification of preparer. Each response to discovery under this subpart must:
(1) Identify the preparer or person under whose direct supervision the response was prepared; and
(2) Be under oath or, for representatives of a public or private corporation or a partnership or association or a governmental agency, be accompanied by a signed certification of the preparer or person supervising the preparation of the response on behalf of the entity that the response is true and accurate to the best of that person’s knowledge, information, and belief formed after a reasonable inquiry.
(d) Supplementation of responses. (1) Except as otherwise provided by this paragraph, a participant that has responded to a request for discovery with a response that was complete when made is not under a continuing duty to supplement that response to include information later acquired.
(2) A participant must make timely amendment to any prior response if the participant obtains information upon the basis of which the participant knows that the response was incorrect when made, or though correct when made is now incorrect in any material respect.
(3) A participant may be required to supplement a response by order of the presiding officer or by agreement of all participants.
(4) A participant may request supplementation of prior responses, if such request is permitted under the procedural schedule.
§ 385.404 Depositions during proceedings (Rule 404).
(a) In general. (1) A participant may obtain the attendance for a deposition by oral examination of any other participant, an employee or agent of that participant, or a person retained by that participant as a potential witness, by providing a notice of intent to depose.
(2) Any participant may obtain the attendance of a nonparticipant for a deposition by oral examination by obtaining a subpoena, in accordance with Rule 409. For purposes of this rule, a Commission decisional employee, as defined in Rule 2201(a), is a nonparticipant.
(b) Notice. (1) A participant seeking to take a deposition under this section must provide to all other participants written notice reasonably in advance of the deposition. The notice must be filed with the Commission and served on all participants. An original must be served on each person whose deposition is sought.
(2) A notice of intent under this section must:
(i) State the time and place at which the deposition will be taken, the name and address of each person to be examined, and the subject matter of the deposition; and
(ii) If known at the time that the deposition is noticed that its purpose is to preserve testimony, state that the deponent will be unable to testify at the hearing.
(3)(i) A notice of intent under this section or a subpoena under Rule 409 may name as the deponent a public or private corporation or a partnership or association or a governmental agency, and describe with reasonable particularity the matters on which examination is requested. Such organization must, in response, designate one or more officers, directors, or managing agents, or other persons to testify on its behalf, and set forth, for each person designated, the matters on which that person will testify.
(ii) A subpoena must advise any organization that is named as a deponent but is not a participant that it has a duty to designate a person to testify. Any person designated under this section must testify on matters known by, or reasonably available to, the organization.
(c) Taking of deposition. (1) Each deponent must swear to or affirm the truth of the testimony given before any testimony is taken.
(2) Any participant may examine and cross-examine a deponent.
(3) Any objection made during the examination must be noted by the officer taking the deposition. After the objection is noted, the deponent must answer the question, unless a claim of privilege is asserted or the presiding officer rules otherwise.
(4) The deposition must be transcribed verbatim.
(d) Nonstenographic means of recording; telephonic depositions. Testimony at a deposition may be recorded by means other than stenography if all participants so stipulate or if the presiding officer, upon motion, so orders. Such stipulation or order shall designate the person before whom the deposition. will be taken, and the manner in which the deposition will be preserved, filed, and certified. Depositions may also be taken by telephone, if all participants so stipulate or the presiding officer, upon motion, orders.
(e) Officer taking deposition. Depositions must be taken before an officer authorized to administer oaths or affirmations by the laws of the United States or of the place where the deposition is held. A deposition may not be taken before an officer who is a relative or employee or attorney of any of the participants, or is financially or in any other way interested in the action.
(f) Submission to deponent. (1) Unless examination is waived by the deponent, the transcription of the deposition must be submitted to the deponent for examination.
(2) If the deponent requests any changes in form or substance, the officer must enter the changes on the deposition transcript with a statement of the witness’ reasons for the changes. The deponent must sign the deposition within 30 days after submittal to the deponent, unless the participants by stipulation waive the signing or the deponent cannot or will not sign. By signing the deposition the deponent certifies that the transcript is a true record of the testimony given.
(3) The officer who took the deposition must sign any deposition not signed by the deponent in accordance with this section and must state on the record that the signature is waived or that the deponent cannot or will not sign, accompanied by any reason given for a deponent’s refusal to sign. If the officer complies with this paragraph, a deposition that is unsigned by the deponent may be used as though signed, unless the presiding officer rules otherwise.
(g) Certification and copies. (1) The officer must certify on the transcript of the deposition that the deponent swore to or affirmed the truth of the testimony given and the deposition transcript is a true record of the testimony given by the deponent. The officer must provide the participant conducting the deposition with a copy of the transcription.
(2) Documents and things produced for inspection during the examination of the witness will, upon the request of a participant, be marked for identification and annexed to the deposition and the officer will certify the document or thing as the original offered during the deposition, or as a true and correct copy of the original offered.
(3) Copies of the transcript of a deposition may be purchased from the reporting service that made the transcription, subject to protections established by the presiding officer.
§ 385.405 Use of depositions (Rule 405).
(a) In general. During a hearing, the hearing of a motion, or an interlocutory proceeding under Rule 715, any part or all of a deposition taken pursuant to Rule 404, so far as admissible as though the witness were then present and testifying, may be used against any participant who was present or represented at the taking of the deposition or who had reasonable notice thereof, in accordance with any of the provisions of this section.
(1) If the deponent is a witness at a hearing, any participant may use the deposition of that witness at the time of the witness’ examination to contradict, impeach, or complete the testimony of that witness.
(2) The deposition of a participant or of any person who, at the time of taking the deposition, was an officer, director, or managing agent of a participant, or a person designated under Rule 404(b)(3) to testify on behalf of a participant may be used by another participant for any purpose.
(3) The deposition of any witness, whether or not a participant, may be used by a participant for any purpose, if the presiding officer finds that:
(i) The witness is dead;
(ii) The witness is unable to attend or testify because of age, illness, infirmity or imprisonment;
(iii) The participant offering the deposition is unable after the exercise of due diligence to procure the attendance of the witness by subpoena; or
(iv) Exceptional circumstances make it necessary in the interest of fairness with due regard to the importance of presenting the witness in open hearing, to allow use of the deposition.
(4) If only part of a deposition is offered in evidence by a participant, a participant may require the introduction of any other part which ought, in fairness, to be considered with the part introduced, and any adverse participant may introduce any other part.
(b) Objections to admissibility. No part of a deposition will constitute a part of the record in the proceeding, unless received in evidence by the Commission or presiding officer. Subject to paragraph (c) of this section, a participant may object to receiving into evidence all or part of any deposition for any reason that the evidence would be excluded if the deponent were present and testifying.
(c) Effect of errors and irregularities in depositions. (1) Any objection to the taking of a deposition based on errors or irregularities in notice of the deposition is waived, unless written objection is promptly served on the participant giving the notice.
(2) Any objection to the taking of a deposition based on the disqualification of the officer before whom it is to be taken is waived, unless the objection is made before the deposition begins or as soon thereafter as the disqualification becomes known or could be discovered with reasonable diligence.
(3) Any objection to the competency of the witness or the competency, relevancy, or materiality of testimony is not waived by failure to make the objection before or during the taking of the deposition, unless the basis for the objection might have been removed if the objection had been presented at the taking of the deposition.
(4) Any objection to errors and irregularities occurring at the oral examination in the manner of taking the deposition, in the form of the questions and answers, in the oath or affirmation, or in the conduct of participants, and errors of any kind that might be obviated, removed or cured if presented at the deposition, is waived unless objection is made at the taking of the deposition.
(5) Any objection based on errors or irregularities in the manner in which the testimony is transcribed or the deposition is prepared, signed, certified, endorsed, or otherwise dealt with by the officer is waived, unless the objection is made with reasonable promptness after the defect is, or with due diligence should have been, ascertained.
§ 385.406 Data requests, interrogatories, and requests for production of documents or things (Rule 406).
(a) Availability. Any participant may serve upon any other participant a written request to supply information, such as responses to data requests and interrogatories, or copies of documents.
(b) Procedures. (1) A request under this section must identify with specificity the information or material sought and will specify a reasonable time within which the matter sought must be furnished.
(2) Unless provided otherwise by the presiding officer, copies of any discovery request must be served upon the presiding officer and on all participants to the proceeding.
(3) Each discovery request must be answered separately and fully in writing.
(4) Responses to discovery requests are required to be served only on the participant requesting the information, Commission trial staff, and any other participant that specifically requests service. The presiding officer may direct that a copy of any responses be furnished to the presiding officer. Responses must be served within the time limit specified in the request or otherwise provided by the presiding officer.
(5) If the matter sought is not furnished, the responding participant must provide, in accordance with Rule 410, written explanation of the specific grounds for the failure to furnish it.
§ 385.407 Inspection of documents and other property (Rule 407).
(a) Availability. On request, the presiding officer may order any other participant to:
(1) Permit inspection and copying of any designated documents (including writings, drawings, graphs, charts, photographs, sound recordings, computer tapes or other compilations of data from which information can be obtained) that are not privileged and that are in the possession, custody, or control of the participant to whom the order is directed;
(2) Permit inspection, copying or photographing, testing, or sampling of any tangible thing that is not privileged and that is in the possession, custody, or control of the participant to whom the order is directed; and
(3) Permit entry upon or into designated land, buildings, or other property in the possession, custody, or control of the participant to whom the order is directed for the purpose of inspecting, measuring, surveying, or photographing the property or any activity or operation that is not privileged and that is conducted in or upon the property.
(b) Procedures. A request for inspection of documents or property under this section must describe with reasonable particularity the documents or other property to which access is sought. The request must also specify a reasonable time, place, and manner of making the inspection.
§ 385.408 Admissions (Rule 408).
(a) General rule. A participant may serve upon any other participant a written request for admission of the genuineness of any document or the truth of any matter of fact. The request must be served upon all participants.
(b) Procedures. (1) Any request for admission of the genuineness of a document must be accompanied by a legible copy of the document, unless it was previously furnished, is in the possession of the recipient of the request, or is readily available for inspection and copying.
(2) The truth of specified matters of fact or the genuineness of the documents described in a request are deemed admitted unless, within 20 days after service of the request or any longer period designated in the request, the participant that receives the request serves upon the requesting participant a written answer or objection addressed to the matters in the request.
(3) An answer must specifically admit or deny the truth of the matters in the request or set forth in detail the reasons why the answering participant cannot admit or deny the truth of each matter. A denial of the truthfulness of the requested admission must fairly discuss the substance of the requested admission and, when good faith requires that a participant qualify the answer or deny only a part of the matter of which an admission is requested, the participant must specify that which is true and qualify or deny the remainder. The answer must be served on all participants.
(c) Effect of admission. Any admission made by a participant under this section is for the purpose of the pending proceeding only, is not an admission for any other purpose, and may not be used against the participant in any other proceeding. Any matter admitted under this rule is conclusively established unless the presiding officer, on motion, permits withdrawal or amendment of the admission. The presiding officer may permit withdrawal or amendment of an admission, if the presiding officer finds that the presentation of the merits of the proceeding will be promoted and the participant who obtained the admission has failed to satisfy the presiding officer that withdrawal or amendment of the admission will prejudice that participant in maintaining his position in the proceeding.
§ 385.409 Subpoenas (Rule 409).
(a) Issuance. On request, the presiding officer may issue a subpoena for the attendance of a witness at a deposition or hearing or for the production of documents. A request for a subpoena must be served on all participants.
(b) Service and return. A subpoena issued under this section must be served by personal service, substituted service, registered mail, or certified mail. A subpoena may be served by the marshal, by his deputy, or by any other person who is not a party or an employee of a party and is at least 18 years of age. If personal service is made by any person other than a United States marshal or deputy marshal, return of service must be accompanied by an affidavit to the Secretary or the presiding officer and must state the time and manner of service of the subpoena.
(c) Fees. Fees paid to subpoenaed persons will be in accordance with Rule 510(e).
(d) Objections. Objections to subpoenas must be made in accordance with Rule 410.
§ 385.410 Objections to discovery, motions to quash or to compel, and protective orders (Rule 410).
(a) Objection to discovery—(1) Notice of objections or motion to quash. A participant, or a recipient of a subpoena, who does not intend to comply with a discovery request must notify in writing the participant seeking discovery within a reasonable time in advance of the date on which a response or other action in conformance with the discovery request is due. A recipient of a subpoena may either provide a notice of objection or file a motion to quash.
(2) Objections to production of documents. (i) Unless an objection to discovery under this section is based on the ground that production would impose an undue burden, the objecting participant must provide the participant seeking discovery with a schedule of items withheld and a statement of:
(A) The character and specific subject matter of each item; and
(B) The specific objection asserted for each item.
(ii) If an objection under this section is based on the ground that production of the requested material would impose an undue burden, the objecting participant must provide the participant seeking discovery with a description of the approximate number of documents that would have to be produced and a summary of the information contained in such documents.
(3) Objections to other discovery requests. If the discovery to which objection is made is not a request for documents, the objection must clearly state the grounds on which the participant bases its objection.
(4) Objections to compile or process information. The fact that information has not been compiled or processed in the form requested is not a basis for objection unless the objection presents grounds for limiting discovery under paragraph (c) of this section.
(b) Motions to compel. Any participant seeking discovery may file a motion to compel discovery, if:
(1) A participant to whom a data request is made or upon whom an interrogatory is served under Rule 406 fails or refuses to make a full, complete, and accurate response;
(2) A person named in a notice of intent to take a deposition or a subpoena fails or refuses to appear for the deposition;
(3) An organization named in a notice of intent to take a deposition fails or refuses to designate one or more persons to testify on its behalf under Rule 404(b)(3);
(4) A deponent fails or refuses to answer fully, completely, and accurately a question propounded or to sign the transcript of the testimony as required by Rule 404(f)(2);
(5) A participant upon whom a request for admissions is served fails or refuses to respond to the request in accordance with Rule 408(b); or
(6) A participant upon whom an order to produce or to permit inspection or entry is served under Rule 407 fails or refuses to comply with that order.
(c) Orders limiting discovery. A presiding officer may, by order, deny or limit discovery or restrict public disclosure of discoverable matter in order to:
(1) Protect a participant or other person from undue annoyance, burden, harassment or oppression;
(2) Prevent undue delay in the proceeding;
(3) Preserve a privilege of a participant, person, or governmental agency;
(4) Prevent a participant from requiring another participant to provide information which is readily available to the requesting participant from other sources with a reasonable expenditure of effort given the requesting participant’s position and resources;
(5) Prevent unreasonably cumulative or duplicative discovery requests; or
(6) Provide a means by which confidential matters may be made available to participants so as to prevent public disclosure. Material submitted under a protective order may nevertheless be subject to Freedom of Information Act requests and review.
(d) Privilege—(1) In general. (i) In the absence of controlling Commission precedent, privileges will be determined in accordance with decisions of the Federal courts with due consideration to the Commission’s need to obtain information necessary to discharge its regulatory responsibilities.
(ii) A presiding officer may not quash a subpoena or otherwise deny or limit discovery on the ground of privilege unless the presiding officer expressly finds that the privilege claimed is applicable. If a presiding officer finds that a qualified privilege has been established, the participant seeking discovery must make a showing sufficient to warrant discovery despite the qualified privilege.
(iii) A presiding officer may issue a protective order under Rule 410(c) to deny or limit discovery in order to preserve a privilege of a participant, person, or governmental agency.
(2) Of the Commission. (i) If discovery under this subpart would require the production of Commission information, documents, or other matter that might fall within a privilege, the Commission trial staff must identify in writing the applicable privilege along with the matters claimed to be privileged or the individuals from whom privileged information is sought, to the presiding officer and the parties.
(ii) If the presiding officer determines that the privilege claimed for the Commission is applicable, the Commission information, documents, or other matter may not be produced. If the presiding officer determines that no privilege is applicable, that a privilege is waived, or that a qualified privilege is overcome, the presiding officer will certify the matter to the Commission in accordance with Rule 714. Certification to the Commission under this paragraph must describe the material to be disclosed and the reasons which, in the presiding officer’s view, justify disclosure. The information will not be disclosed unless the Commission affirmatively orders the material disclosed.
§ 385.411 Sanctions (Rule 411).
(a) Disobedience of order compelling discovery. If a participant or any other person fails to obey an order compelling discovery, the presiding officer may, after notice to the participant or person and an opportunity to be heard, take one or more of the following actions, but may not dismiss or otherwise terminate the proceeding:
(1) Certify the matter to the Commission with a recommendation for dismissal or termination of the proceeding, termination of that participant’s right to participate in the proceeding, institution of civil action, or any other sanction available to the Commission by law;
(2) Order that the matters to which the order compelling discovery relates are taken as established for the purposes of the proceeding in accordance with the position of the participant obtaining the order;
(3) Order that a participant be precluded from supporting or opposing such positions or introducing such matters in evidence as the presiding officer designates;
(4) Order that all or part of any pleading by a participant be struck or that the proceeding or a phase of the proceeding be stayed until the order compelling discovery is obeyed; and
(5) Recommend to the Commission that it take action under Rule 2102 against a representative of the participant if the presiding officer believes that the representative has engaged in unethical or improper professional conduct.
(b) Against representative of a participant. If the person disobeying an order compelling discovery is an agent, officer, employee, attorney, partner, or director of a participant, the presiding officer may take any of the actions described in paragraph (a) against that participant.
Subpart E—Hearings
§ 385.501 Applicability (Rule 501).
This subpart applies to any proceeding, or part of a proceeding, that the Commission or the Secretary under delegated authority sets for a hearing to be conducted in accordance with this subpart.
§ 385.502 Initiation of hearing (Rule 502).
(a) Notice or order initiating hearing. A hearing under this subpart will be initiated by:
(1) Order of the Commission; or
(2) Notice by the Secretary at the direction of the Commission or under delegated authority.
(b) Contents of notice or order initiating hearing. Any order or notice under paragraph (a) of this section will set forth:
(1) The authority and jurisdiction under which the hearing is to be held;
(2) The nature of the proceeding;
(3) The final date for the filing of interventions, if the dates were not fixed by an earlier notice;
(4) The presiding officer, if designated at that time; and
(5) The date, time, and location of the hearing or prehearing conference, if known; and
(6) Any other appropriate matter.
(c) Consolidation, severance, and phasing. Any notice or order under this section may direct consolidation of proceedings, phasing of a proceeding, or severance of proceedings or issues in a proceeding.
§ 385.503 Consolidation, severance and extension of close-of-record date by Chief Administrative Law Judge (Rule 503).
(a) The Chief Administrative Law Judge may, on motion or otherwise, order proceedings pending under this subpart consolidated for hearing on, or settlement of, any or all matters in issue in the proceedings, or order the severance of proceedings or issues in a proceeding. The order may be appealed to the Commission pursuant to Rule 715.
(b) If the Commission orders that the presiding officer close the record in any proceeding by a specific date, the Chief Administrative Law Judge may, upon motion or otherwise, extend the close-of-record date for good cause. This staff action may be appealed to the Commission only under Rule 1902.
§ 385.504 Duties and powers of presiding officers (Rule 504).
(a) Duties. (1) It shall be the duty of the presiding officer to conduct a fair and impartial hearing and to determine the matter justly under the law.
(2) The presiding officer will cause all appearances during a hearing to be entered on the record with a notation in whose behalf each appearance is made.
(3) The presiding officer will establish the order of presentation of the cases of all participants in the hearing.
(4) The presiding officer will assure that the taking of evidence and subsequent matters proceed with all reasonable diligence and with the least delay practicable.
(5) The presiding officer will prepare and certify an initial decision or a revised initial decision, whichever is appropriate, to the Commission as provided in Subpart G of this part.
(b) Powers. Except as otherwise ordered by the Commission or provided by law, the presiding officer may:
(1) Schedule and otherwise regulate the course of the hearing;
(2) Recess, reconvene, postpone, or adjourn the hearing;
(3) Administer oaths;
(4) Rule on and receive evidence;
(5) Cause Discovery to be conducted;
(6) Exercise powers granted a presiding officer under Subpart D;
(7) Hold conferences of the participants, as provided in Subpart F of this part, including for the purpose of considering the use of alternative dispute resolution procedures;
(8) Rule on, and dispose of, procedural matters, including oral or written motions;
(9) Summarily dispose of a proceeding or part of a proceeding, as provided in Rule 217;
(10) Certify a question to the Commission, as provided in Rule 714;
(11) Permit or deny appeal of an interlocutory ruling, as provided in Rule 715;
(12) Rule on motions to intervene, as provided in Rule 214;
(13) Separate any issue or group of issues from other issues in a proceeding and treat such issue or group of issues as a separate phase of the proceeding;
(14) Maintain order, as follows:
(i) Ensure that any disregard by any person of rulings on matters of order and procedure is noted on the record or, if appropriate, is made the subject of a special written report to the Commission;
(ii) In the event any person engages in disrespectful, disorderly, or contumacious language or conduct in connection with the hearing, recess the hearing for such time as necessary to regain order;
(iii) Request that the Commission take appropriate action, including removal from the proceeding, against a participant or counsel, if necessary to maintain order.
(15) Modify any time period, if such modification is in the interest of justice and will result in no undue prejudice to any participant;
(16) Limit the number of expert witnesses who may testify on any issue, consistent with the rule against repetitious testimony in Rule 509(a);
(17) Limit the number of persons, other than staff, representing a similar interest who may examine witnesses or make or argue motions or objections;
(18) Require; or authorize the admission of, further evidence upon any issue at any time before the close of the evidentiary record;
(19) Rule on motions for reconsideration of an initial decision as provided in Rule 717;
(20) Take any other action necessary or appropriate to the discharge of the duties of a presiding officer, consistent with applicable law and policy.
(c) Disqualification. (1) A presiding officer may withdraw from a proceeding, if that officer believes himself or herself disqualified.
(2) The Commission may, for good cause, order the removal of any presiding officer from a proceeding, on motion filed with the Commission or otherwise.
§ 385.505 Right of participants to present evidence (Rule 505).
Consistent with the provisions of this part, a participant has the right to present such evidence, including rebuttal evidence, to make such objections and arguments, and to conduct such cross-examination, as may be necessary to assure true and full disclosure of the facts.
§ 385.506 Examination of witnesses during hearing (Rule 506).
(a) Prepared written direct and rebuttal testimony. Unless the presiding officer orders such testimony to be presented orally, direct and rebuttal testimony of a witness in a hearing must be prepared and submitted in written form, as required by Rule 507. Any witness submitting written testimony must be available for cross-examination, as provided in this subpart.
(b) Oral testimony during hearing. Oral examination of a witness in a hearing must be conducted under oath and in the presence of the presiding officer, with opportunity for all participants to question the witness to the extent consistent with Rules 504(b)(17), 505, and 509(a).
§ 385.507 Prepared written testimony (Rule 507).
(a) Offered as an exhibit. The prepared written testimony of any witness must be offered as an exhibit. The presiding officer will allow a reasonable period of time for the preparation of such written testimony.
(b) Time for filing. Any prepared written testimony must be filed and served within the time provided by the presiding officer, in no case later than 10 days before the session of the hearing at which such exhibit is offered, unless a shorter period is permitted under paragraph (c) of this section.
(c) Late-filed testimony. (1) If all participants in attendance at the hearing agree, the 10-day requirement for filing any written testimony under paragraph (b) of this section is waived.
(2) The presiding officer may permit the introduction of any prepared written testimony without compliance with paragraph (b) of this section, if the presiding officer determines that the introduction of the testimony:
(i) Is necessary for a full disclosure of the facts or is warranted by any other showing of good cause; and
(ii) Would not be unduly prejudicial to any participant.
(3) If any written testimony is served and filed within the 10 day period provided in paragraph (b) of this section, the presiding officer will provide the participants in attendance with a reasonable opportunity to inspect the testimony.
(d) Form; authentication. Prepared written testimony must have line numbers inserted in the left-hand margin of each page and must be authenticated by an affidavit of the witness.
§ 385.508 Exhibits (Rule 508).
(a) General rules. (1) Except as provided in paragraphs (b) through (e) of this section, any material offered in evidence, other than oral testimony, must be offered in the form of an exhibit.
(2) The presiding officer will cause each exhibit offered by a participant to be marked for identification.
(b) Designation and treatment of matter sought to be admitted. (1) If a document offered as an exhibit contains material not offered as evidence, the participant offering the exhibit must:
(i) Plainly designate the matter offered as evidence; and
(ii) Segregate and exclude the material not offered in evidence, to the extent practicable.
(2) If, in a document offered as an exhibit, material not offered in evidence is so extensive as to unnecessarily encumber the record, the material offered in evidence will be marked for identification. The remainder of the document will be considered not to have been offered in evidence.
(3) Copies of any document offered as an exhibit under paragraph (b)(2) of this section must be delivered to the other participants appearing at the hearing by the participant offering the exhibit in evidence. The participants will be offered an opportunity to inspect the entire document and to offer as an exhibit in evidence, in like manner, any other portions of the document.
(c) Public document items by reference. If all or part of a public document is offered in evidence and the participant offering the document shows that all or the pertinent part of the document, is reasonably available to the public, the document need not be produced or marked for identification but may be offered in evidence as a public document by identifying all or the relevant part of the document to be offered.
(d) Official notice of facts. (1) A presiding officer may take official notice of any matter that may be judicially noticed by the courts of the United States, or of any matter about which the Commission, by reason of its functions, is expert.
(2) The presiding officer must afford any participant, making a timely request, an opportunity to show the contrary of an officially noticed fact.
(3) Any participant requesting official notice of facts after the conclusion of the hearing must set forth reasons to justify the failure to request official notice prior to the close of the hearing.
(e) Stipulations. (1) Participants in a proceeding may stipulate to any relevant matters of fact or the authenticity of any relevant documents.
(2) A stipulation may be received in evidence at the hearing and, if received in evidence, the stipulation is binding on the stipulating participants with respect to any matter stipulated.
(3) A stipulation may be written or made orally at the hearing.
§ 385.509 Admissibility of evidence (Rule 509).
(a) General standard. The presiding officer should exclude from evidence any irrelevant, immaterial, or unduly repetitious material. The presiding officer may also exclude from evidence any other material which the presiding officer determines is not of the kind which would affect reasonable and fair-minded persons in the conduct of their daily affairs.
(b) Ruling on evidence. (1) The presiding officer will rule on the admissibility of any evidence offered.
(2) If any participant objects to the admission or exclusion of evidence, the participant must state briefly the grounds for the objection.
(3) The presiding officer will not permit formal exceptions to any ruling on evidence. This prohibition against formal exceptions does not preclude a participant from raising, as an issue, the validity of any ruling on evidence later in the proceeding, consistent with Rule 711.
§ 385.510 Miscellaneous provisions (Rule 510).
(a) Transcript. (1) Any statement made at a hearing session will be transcribed in a verbatim report, with nothing omitted except as directed by the presiding officer on the record. A statement at a hearing may not occur off-the-record, except as otherwise directed by the presiding officer.
(2) After the closing of a record, changes in the transcript are not permitted, except as provided in paragraph (b) of this section.
(b) Transcript corrections. (1) Any correction in the transcript of a hearing may be made only if the correction conforms the transcript to the evidence presented at the hearing and to the truth.
(2) A transcript correction may be incorporated in the record, in accordance with a ruling of the presiding officer, if:
(i) Agreed to by all participants and approved by the presiding officer; or
(ii) The presiding officer requests submittal of transcript corrections and rules on the corrections submitted.
(3) Transcript corrections may be made at any time during the hearing or after the close of evidence, as the presiding officer determines appropriate, but only if the correction is made not less than 10 days before the time for filing final briefs.
(c) Close of evidentiary record. The presiding officer will designate the time at which the evidentiary record is closed. Evidence may not be added to the evidentiary record after the record is closed, unless the record is reopened under Rule 716.
(d) Copies of exhibits and motions to participants. Except as otherwise provided in this subpart, copies of exhibits and motions will be provided at the hearing to any participants who have not been provided copies.
(e) Fees of subpoenaed witnesses. (1) Any witnesses subpoenaed by the Commission must be paid the same fees and mileage provided for similar services in the district courts of the United States.
(2) Any fees and mileage paid to a subpoenaed witness under paragraph (e)(1) of this section will be paid by the Commission, unless the witness is subpoenaed at the instance of a party.
(3) If the witness is subpoenaed at the instance of a party, any fees and mileage paid to the witness under paragraph (e)(1) of this section must be paid by the party. The Commission, before issuing any subpoena at the instance of the party, may require the party to deposit an amount adequate to cover the witness probable fees and mileage under paragraph (e)(1) of this section. The deposit will be refunded when the party pays the witness in full.
(f) Offers of proof. (1) Any offer of proof made in connection with a ruling of the presiding officer rejecting or excluding proffered oral testimony must consist of a statement of the substance of the evidence which the participant claims would be adduced by the testimony.
(2) If any excluded evidence is in the form of an exhibit or is a public document, a copy of such exhibit will constitute the offer of proof or the public document will be specified for identification.
Subpart F—Conferences, Settlements, and Stipulations
§ 385.601 Conferences (Rule 601).
(a) Convening. The Commission or other decisional authority, upon motion or otherwise, may convene a conference of the participants in a proceeding at any time for any purpose related to the conduct or disposition of the proceeding, including submission and consideration of offers of settlement or the use of alternative dispute resolution procedures.
(b) General requirements. (1) The participants in a proceeding must be given due notice of the time and place of a conference under paragraph (a) of this section and of the matters to be addressed at the conference. Participants attending the conference must be prepared to discuss the matters to be addressed at the conference, unless there is good cause for a failure to be prepared.
(2) Any person appearing at the conference in a representative capacity must be authorized to act on behalf of that person’s principal with respect to matters to be addressed at the conference.
(3) If any party fails to attend the conference such failure will constitute a waiver of all objections to any order or ruling arising out of, or any agreement reached at, the conference.
(c) Powers of decisional authority at conference. (1) The decisional authority, before which the conference is held or to which the conference reports, may dispose, during a conference, of any procedural matter on which the decisional authority is authorized to rule and which may appropriately and usefully be disposed of at that time.
(2) If, in a proceeding set for hearing under subpart E, the presiding officer determines that the proceeding would be substantially expedited by distribution of proposed exhibits, including written prepared testimony and other documents, reasonably in advance of the hearing session, the presiding officer may, with due regard for the convenience of the participants, direct advance distribution of the exhibits by a prescribed date. The presiding officer may also direct the preparation and distribution of any briefs and other documents which the presiding officer determines will substantially expedite the proceeding.
§ 385.602 Submission of settlement offers (Rule 602).
(a) Applicability. This section applies to written offers of settlement filed in any proceeding pending before the Commission or set for hearing under subpart E. For purposes of this section, the term “offer of settlement” includes any written proposal to modify an offer of settlement.
(b) Submission of offer. (1) Any participant in a proceeding may submit an offer of settlement at any time.
(2) An offer of settlement must be filed with the Secretary. The Secretary will transmit the offer to:
(i) The presiding officer, if the offer is filed after a hearing has been ordered under subpart E of this part and before the presiding officer certifies the record to the Commission; or
(ii) The Commission.
(3) If an offer of settlement pertains to multiple proceedings that are in part pending before the Commission and in part set for hearing, any participant may by motion request the Commission to consolidate the multiple proceedings and to provide any other appropriate procedural relief for purposes of disposition of the settlement.
(c) Contents of offer. (1) An offer of settlement must include:
(i) The settlement offer;
(ii) A separate explanatory statement;
(iii) Copies of, or references to, any document, testimony, or exhibit, including record citations if there is a record, and any other matters that the offerer considers relevant to the offer of settlement; and
(2) If an offer of settlement pertains to a tariff or rate filing, the offer must include any proposed change in a form suitable for inclusion in the filed rate schedules or tariffs, and a number of copies sufficient to satisfy the filing requirements applicable to tariff or rate filings of the type at issue in the proceeding.
(d) Service. (1) A participant offering settlement under this section must serve a copy of the offer of settlement:
(i) On every participant in accordance with Rule 2010;
(ii) On any person required by the Commission’s rules to be served with the pleading or tariff or rate schedule filing, with respect to which the proceeding was initiated.
(2) The participant serving the offer of settlement must notify any person or participant served under paragraph (d)(1) of this section of the date on which comments on the settlement are due under paragraph (f) of this section.
(e) Use of non-approved offers of settlement as evidence. (1) An offer of settlement that is not approved by the Commission, and any comment on that offer, is not admissible in evidence against any participant who objects to its admission.
(2) Any discussion of the parties with respect to an offer of settlement that is not approved by the Commission is not subject to discovery or admissible in evidence.
(f) Comments. (1) A comment on an offer of settlement must be filed with the Secretary who will transmit the comment to the Commission, if the offer of settlement was transmitted to the Commission, or to the presiding officer in any other case.
(2) A comment on an offer of settlement may be filed not later than 20 days after the filing of the offer of settlement and reply comments may be filed not later than 30 days after the filing of the offer, unless otherwise provided by the Commission or the presiding officer.
(3) Any failure to file a comment constitutes a waiver of all objections to the offer of settlement.
(4) Any comment that contests an offer of settlement by alleging a dispute as to a genuine issue of material fact must include an affidavit detailing any genuine issue of material fact by specific reference to documents, testimony, or other items included in the offer of settlement, or items not included in the settlement, that are relevant to support the claim. Reply comments may include responding affidavits.
(g) Uncontested offers of settlement. (1) If comments on an offer are transmitted to the presiding officer and the presiding officer finds that the offer is not contested by any participant, the presiding officer will certify to the Commission the offer of settlement, a statement that the offer of settlement is uncontested, and any hearing record or pleadings which relate to the offer of settlement.
(2) If comments on an offer of settlement are transmitted to the Commission, the Commission will determine whether the offer is uncontested.
(3) An uncontested offer of settlement may be approved by the Commission upon a finding that the settlement appears to be fair and reasonable and in the public interest.
(h) Contested offers of settlement. (1)(i) If the Commission determines that any offer of settlement is contested in whole or in part, by any party, the Commission may decide the merits of the contested settlement issues, if the record contains substantial evidence upon which to base a reasoned decision or the Commission determines there is no genuine issue of material fact.
(ii) If the Commission finds that the record lacks substantial evidence or that the contesting parties or contested issues can not be severed from the offer of settlement, the Commission will:
(A) Establish procedures for the purpose of receiving additional evidence before a presiding officer upon which a decision on the contested issues may reasonably be based; or
(B) Take other action which the Commission determines to be appropriate.
(iii) If contesting parties or contested issues are severable, the contesting parties or uncontested portions may be severed. The uncontested portions will be decided in accordance with paragraph (g) of this section.
(2)(i) If any comment on an offer of settlement is transmitted to the presiding officer and the presiding officer determines that the offer is contested, whole or in part, by any participant, the presiding officer may certify all or part of the offer to the Commission. If any offer or part of an offer is contested by a party, the offer may be certified to the Commission only if paragraph (h)(2)(ii) or (iii) of this section applies.
(ii) Any offer of settlement or part of any offer may be certified to the Commission if the presiding officer determines that there is no genuine issue of material fact. Any certification by the presiding officer must contain the determination that there is no genuine issue of material fact and any hearing record or pleadings which relate to the offer or part of the offer being certified.
(iii) Any offer of settlement or part of any offer may be certified to the Commission, if:
(A) The parties concur on a motion for omission of the initial decision as provided in Rule 710, or, if all parties do not concur in the motion, the presiding officer determines that omission of the initial decision is appropriate under Rule 710(d), and
(B) The presiding officer determines that the record contains substantial evidence from which the Commission may reach a reasoned decision on the merits of the contested issues.
(iv) If any contesting parties or contested issues are severable, the uncontested portions of the settlement may be certified immediately by the presiding officer to the Commission for decision, as provided in paragraph (g) of this section.
(i) Reservation of rights. Any procedural right that a participant has in the absence of an offer of settlement is not affected by Commission disapproval, or approval subject to condition, of the uncontested portion of the offer of settlement.
§ 385.603 Settlement of negotiations before a settlement judge (Rule 603).
(a) Applicability. This section applies to any proceeding set for hearing under subpart E of this part and to any other proceeding in which the Commission has ordered the appointment of a settlement judge.
(b) Definition. For purposes of this section, settlement judge means the administrative law judge appointed by the Chief Administrative Law Judge to conduct settlement negotiations under this section.
(c) Requests for appointment of settlement judges. (1) Any participant may file a motion requesting the appointment of a settlement judge with the presiding officer, or, if there is no presiding officer for the proceeding, with the Commission.
(2) A presiding officer may request the Chief Administrative Law Judge to appoint a settlement judge.
(3) A motion under paragraph (c)(1) of this section may be acted upon at any time, and the time limitations on answers in Rule 213(d) do not apply.
(4) Any answer or objection filed after a motion has been acted upon will not be considered.
(d) Commission order directing appointment of settlement judge. The Commission may, on motion or otherwise, order the Chief Administrative Law Judge to appoint a settlement judge.
(e) Appointment of settlement judge by Chief Administrative Law Judge. The Chief Administrative Law Judge may appoint a settlement judge for any proceeding, if requested by the presiding officer under paragraph (c)(2) of this section or if the presiding officer concurs in a motion made under paragraph (c)(1) of this section.
(f) Order appointing settlement judge. The Chief Administrative Law Judge will appoint a settlement judge by an order, which specifies whether, and to what extent, the proceeding is suspended pending termination of settlement negotiations conducted in accordance with this section. The order may confine the scope of any settlement negotiations to specified issues.
(g) Powers and duties of settlement judge. (1) A settlement judge will convene and preside over conferences and settlement negotiations between the participants and assess the practicalities of a potential settlement.
(2)(i) A settlement judge will report to the Chief Administrative Law Judge or the Commission, as appropriate, describing the status of the settlement negotiations and evaluating settlement prospects.
(ii) In any such report, the settlement judge may recommend the termination or continuation of settlement negotiations conducted under this section.
(iii) The first report by the settlement judge will be made not later than 30 days after the appointment of the settlement judge. The Commission or the Chief Administrative Law Judge may order additional reports at any time.
(h) Termination of settlement negotiations before a settlement judge. Unless an order of the Commission directing the appointment of a settlement judge provides otherwise, settlement negotiations conducted under this section will terminate upon the order of the Chief Administrative Law Judge issued after consultation with the settlement judge.
(i) Non-reviewability. Any decision concerning the appointment of a settlement judge or the termination of any settlement negotiations is not subject to review by, appeal to, or rehearing by the presiding officer, Chief Administrative Law Judge, or the Commission.
(j) Multiple settlement negotiations. If settlement negotiations are terminated under paragraph (h) of this section, the Chief Administrative Law Judge may subsequently appoint a settlement judge in the same proceeding to conduct settlement negotiations in accordance with this section.
§ 385.604 Alternative means of dispute resolution (Rule 604).
(a) Applicability. (1) Participants may, subject to the limitations of paragraph (a)(2) of this section, use alternative means of dispute resolution to resolve all or part of any pending matter if the participants agree. The alternative means of dispute resolution authorized under subpart F of this part will be voluntary procedures that supplement rather than limit other available dispute resolution techniques.
(2) Except as provided in paragraph (a)(3) of this section, the decisional authority will not consent to use of an alternative dispute resolution proceeding if:
(i) A definitive or authoritative resolution of the matter is required for precedential value;
(ii) The matter involves or may bear upon significant questions of policy that require additional procedures before a final resolution may be made, and the proceeding would not likely serve to develop a recommended policy;
(iii) Maintaining established policies is of special importance;
(iv) The matter significantly affects persons or organizations who are not parties to the proceeding;
(v) A full public record of the proceeding is important, and a dispute resolution proceeding cannot provide a record; or
(vi) The Commission must maintain continuing jurisdiction over the matter with authority to alter the disposition of the matter in the light of changed circumstances, and a dispute resolution proceeding would interfere with the Commission’s fulfilling that requirement.
(3) If one or more of the factors outlined in paragraph (a)(2) of this section is present, alternative dispute resolution may nevertheless be used if the alternative dispute resolution proceeding can be structured to avoid the identified factor or if other concerns significantly outweigh the identified factor.
(4) A determination to use or not to use a dispute resolution proceeding under subpart F of this part is not subject to judicial review.
(5) Settlement agreements reached through the use of alternative dispute resolution pursuant to subpart F of this part will be subject to the provisions of Rule 602, unless the decisional authority, upon motion or otherwise, orders a different procedure.
(b) Definitions. For the purposes of subpart F of this part:
(1) Alternative means of dispute resolution means any procedure that is used, in lieu of an adjudication, to resolve issues in controversy, including but not limited to, settlement negotiations, conciliation, facilitation, mediation, factfinding, minitrials, and arbitration, or any combination thereof;
(2) Award means any decision by an arbitrator resolving the issues in controversy;
(3) Dispute resolution communication means any oral or written communication prepared for the purposes of a dispute resolution proceeding, including any memoranda, notes or work product of the neutral, parties or non-party participant. A written agreement to enter into a dispute resolution proceeding, or a final written agreement or arbitral award reached as a result of a dispute resolution proceeding, is not a dispute resolution communication;
(4) Dispute resolution proceeding means any alternative means of dispute resolution that is used to resolve an issue in controversy in which a neutral may be appointed and specified parties participate;
(5) In confidence means information is provided:
(i) With the expressed intent of the source that it not be disclosed, or
(ii) Under circumstances that create a reasonable expectation on behalf of the source that the information will not be disclosed;
(6) Issue in controversy means an issue which is or is anticipated to be material to a decision in a proceeding before the Commission and which is the subject of disagreement between participants who would be substantially affected by the decision or between the Commission and any such participants;
(7) Neutral means an individual who, with respect to an issue in controversy, functions specifically to aid the parties in resolving the controversy;
(8) Participants in a dispute resolution proceeding that is used to resolve an issue in controversy in a proceeding involving an application for a license or exemption to construct, operate, and maintain a hydroelectric project pursuant to the Federal Power Act or the Public Utility Regulatory Policies Act shall include such state and federal agencies and Indian tribes as have statutory roles or a direct interest in such hydroelectric proceedings.
(c) Neutrals. (1) A neutral may be a permanent or temporary officer or employee of the Federal Government (including an administrative law judge), or any other individual who is acceptable to the participants to a dispute resolution proceeding. A neutral must have no official, financial, or personal conflict of interest with respect to the issues in controversy, except that a neutral who is not a government employee may serve if the interest is fully disclosed in writing to all participants and all participants agree.
(2) A neutral serves at the will of the participants, unless otherwise provided.
(3) Neutrals may be selected from among the Commission’s administrative law judges or other employees, from rosters kept by the Federal Mediation and Conciliation Service, the Administrative Conference of the United States, the American Arbitration Association, or from any other source.
(d) Submission of proposal to use alternative means of dispute resolution. (1) The participants may at any time submit a written proposal to use alternative means of dispute resolution to resolve all or part of any matter in controversy or anticipated to be in controversy before the Commission.
(2) For matters set for hearing under subpart E of this part, a proposal to use alternative means of dispute resolution must be filed with the presiding administrative law judge.
(3) For all other matters, a proposal to use alternative means of dispute resolution may be filed with the Secretary for consideration by the appropriate decisional authority.
(4) The appropriate decisional authority will issue an order, approving or denying, under the guidelines in Rule 604(a) (2) and (3), a proposal to use alternative means of dispute resolution. Denial of a proposal to use alternative dispute resolution will be in the form of an order and will identify the specific reasons for the denial. A proposal to use alternative dispute resolution is deemed approved unless an order denying approval is issued within 30 days after the proposal is filed.
(5) Any request to modify a previously-approved ADR proposal must follow the same procedure used for the initial approval.
(e) Contents of proposal. A proposal to use alternative means of dispute resolution must be in writing and include:
(1) A general identification of the issues in controversy intended to be resolved by the proposed alternative dispute resolution method,
(2) A description of the alternative dispute resolution method(s) to be used,
(3) The signatures of all participants or evidence otherwise indicating the consent of all participants; and
(4) A certificate of service pursuant to Rule 2010(h).
(f) Monitoring the alternative dispute resolution proceeding. The decisional authority may order reports on the status of the alternative dispute resolution proceeding at any time.
§ 385.605 Arbitration (Rule 605).
(a) Authorization of arbitration. (1) The participants may at any time submit a written proposal to use binding arbitration under the provisions of Rule 605 to resolve all or part of any matter in controversy, or anticipated to be in controversy, before the Commission.
(2) The proposal must be submitted as provided in Rule 604(d).
(3) The proposal must be in writing and contain the information required in Rule 604(e).
(4) An arbitration proceeding under this rule may be monitored as provided in Rule 604(f).
(5) No person may be required to consent to arbitration as a condition of entering into a contract or obtaining a benefit. All interested parties must expressly consent before arbitration may be used.
(b) Arbitrators. (1) The participants to an arbitration proceeding are entitled to select the arbitrator.
(2) The arbitrator must be a neutral who meets the criteria of a neutral under Rule 604(c).
(c) Authority of arbitrator. An arbitrator to whom a dispute is referred under this section may:
(1) Regulate the course of and conduct arbitral hearings;
(2) Administer oaths and affirmations;
(3) Compel the attendance of witnesses and the production of evidence to the extent the Commission is authorized by law to do so; and
(4) Make awards.
(d) Arbitration proceedings. (1) The arbitrator will set a time and place for the hearing on the dispute and must notify the participants not less than 5 days before the hearing.
(2) Any participant wishing that there be a record of the hearing must:
(i) Prepare the record;
(ii) Notify the other participants and the arbitrator of the preparation of the record;
(iii) Furnish copies to all identified participants and the arbitrator; and
(iv) Pay all costs for the record, unless the participants agree otherwise or the arbitrator determines that the costs should be apportioned.
(3)(i) Participants to the arbitration are entitled to be heard, to present evidence material to the controversy, and to cross-examine witnesses appearing at the hearing to the same extent as in a proceeding under Subpart E of this part;
(ii) The arbitrator may, with the consent of the participants, conduct all or part of the hearing by telephone, television, computer, or other electronic means, if each participant has an opportunity to participate.
(iii) The hearing must be conducted expeditiously and in an informal manner.
(iv) The arbitrator may receive any oral or documentary evidence, except that irrelevant, immaterial, unduly repetitious, or privileged evidence may be excluded by the arbitrator.
(v) The arbitrator will interpret and apply relevant statutory and regulatory requirements, legal precedents, and policy directives.
(4) No interested person will make or knowingly cause to be made to the arbitrator an unauthorized ex parte communication relevant to the merits of the proceeding, unless the participants agree otherwise. If a communication is made in violation of this prohibition, the arbitrator will ensure that a memorandum of the communication is prepared and made a part of the record, and that an opportunity for rebuttal is allowed. Upon receipt of such communication, the arbitrator may require the offending participant to show cause why the claim of the participant should not be resolved against the participant as a result of the improper conduct.
(5) The arbitrator will make the award within 30 days after the close of the hearing or the date of the filing of any briefs authorized by the arbitrator, whichever date is later, unless the participants and the arbitrator agree to some other time limit.
(e) Arbitration awards. (1)(i) The award in an arbitration proceeding under Subpart F of this chapter will include a brief, informal discussion of the factual and legal basis for the award.
(ii) The prevailing participants must file the award with the Commission, along with proof of service on all participants.
(2) The award in an arbitration proceeding will become final 30 days after it is served on all parties.
(3) A final award is binding on the participants to the arbitration proceeding.
(4) An award may not serve as an estoppel in any other proceeding for any issue that was resolved in the proceeding. The award also may not be used as precedent or otherwise be considered in any factually unrelated proceeding or in any other arbitration proceeding.
§ 385.606 Confidentiality in dispute resolution proceedings (Rule 606).
(a) Except as provided in paragraphs (d) and (e) of this section, a neutral in a dispute resolution proceeding shall not voluntarily disclose, or through discovery or compulsory process be required to disclose, any information concerning any dispute resolution communication or any communication provided in confidence to the neutral, unless:
(1) All participants in the dispute resolution proceeding and the neutral consent in writing;
(2) The dispute resolution communication has otherwise already been made public;
(3) The dispute resolution communication is required by statute to be made public, but a neutral should make the communication public only if no other person is reasonably available to disclose the communication; or
(4) A court determines that the testimony or disclosure is necessary to:
(i) Prevent a manifest injustice;
(ii) Help establish a violation of law; or
(iii) Prevent harm to the public health or safety of sufficient magnitude in the particular case to outweigh the integrity of dispute resolution proceedings in general by reducing the confidence of participants in future cases that their communications will remain confidential.
(b) A participant in a dispute resolution proceeding shall not voluntarily disclose, or through discovery or compulsory process be required to disclose, any information concerning any dispute resolution communication, unless:
(1) All participants to the dispute resolution proceeding consent in writing;
(2) The dispute resolution communication has otherwise already been made public;
(3) The dispute resolution communication is required by statute to be made public;
(4) A court determines that the testimony or disclosure is necessary to:
(i) Prevent a manifest injustice;
(ii) Help establish a violation of law; or
(iii) Prevent harm to the public health and safety of sufficient magnitude in the particular case to outweigh the integrity of dispute resolution proceedings in general by reducing the confidence of participants in future cases that their communications will remain confidential; or
(5) The dispute resolution communication is relevant to determining the existence or meaning of an agreement or award that resulted from the dispute resolution proceeding or to the enforcement of the agreement or award.
(c) Any dispute resolution communication that is disclosed in violation of paragraphs (a) or (b) of this section shall not be admissible in any proceeding.
(d)(1) The participants may agree to alternative confidential procedures for disclosures by a neutral. The participants must inform the neutral before the commencement of the dispute resolution proceeding of any modifications to the provisions of paragraph (a) of this section that will govern the confidentiality of the dispute resolution proceeding. If the participants do not so inform the neutral, paragraph (a) of this section shall apply.
(2) To qualify for the exemption established under paragraph (l) of this section, an alternative confidential procedure under this paragraph may not provide for less disclosure than confidential procedures otherwise provided under this rule.
(e) If a demand for disclosure, by way of discovery request or other legal process, is made upon a participant regarding a dispute resolution communication, the participant will make reasonable efforts to notify the neutral and the other participants of the demand. Any participant who receives the notice and within 15 calendar days does not offer to defend a refusal of the neutral to disclose the requested information waives any objection to the disclosure.
(f) Nothing in Rule 606 prevents the discovery or admissibility of any evidence that is otherwise discoverable, merely because the evidence was presented in the course of a dispute resolution proceeding.
(g) Paragraphs (a) and (b) of this section do not preclude disclosure of information and data that are necessary to document an agreement reached or order issued pursuant to a dispute resolution proceeding.
(h) Paragraphs (a) and (b) of this section do not prevent the gathering of information for research and educational purposes, in cooperation with other agencies, governmental entities, or dispute resolution programs, so long as the participants and the specific issues in controversy are not identifiable.
(i) Paragraphs (a) and (b) of this section do not prevent use of a dispute resolution communication to resolve a dispute between the neutral in a dispute resolution proceeding and a participant in the proceeding, so long as the communication is disclosed only to the extent necessary to resolve the dispute.
(j) Nothing in this section precludes parties from seeking privileged treatment for documents under this chapter.
(k) Where disclosure is authorized by this section, nothing in this section precludes use of a protective agreement or protective orders.
(l) A dispute resolution communication that may not be disclosed under this rule shall also be exempt from disclosure under 5 U.S.C. 552(b)(3).
Subpart G—Decisions
§ 385.701 Applicability (Rule 701).
This subpart applies to decisions in proceedings set for hearing under subpart E of this part, including any decision on a certified question, interlocutory appeal, or reopening, and to any decision on rehearing, except that:
(a) The provisions of this subpart, other than those relating to rehearing or reopening, do not apply to consideration of an offer of settlement; and
(b) This subpart applies to summary disposition only to the extent provided in Rule 217.
§ 385.702 Definitions (Rule 702).
For purposes of this subpart:
(a) Initial decision means any decision rendered by a presiding officer in accordance with Rule 708;
(b) Final decision means any decision referred to in Rule 713.
§ 385.703 Contents of decisions (Rule 703).
Any decision in a proceeding is part of the record of that proceeding and will contain:
(a) A ruling on each exception presented and any finding or conclusion, with supporting reasons, on any material issue of fact, law, or discretion presented on the record; and
(b) The appropriate rule, order, sanction, relief, or a denial of any rule, order, motion, or relief.
§ 385.704 Rights of participants before initial decision (Rule 704).
After testimony is taken in a proceeding, or phase of a proceeding, the presiding officer will afford every participant an opportunity to:
(a) Submit written initial briefs in accordance with Rule 706, except that the presiding officer may provide an opportunity for oral argument in lieu of, or in addition to, initial briefs; and
(b) Submit written reply briefs in accordance with Rule 706, except that the presiding officer may:
(1) Provide an opportunity for oral reply argument in lieu of, or in addition to, reply briefs; or
(2) For good cause, deny opportunity for reply or limit the issues which may be addressed in any reply.
§ 385.705 Additional powers of presiding officer with respect to briefs (Rule 705).
(a) Limitations on briefs. A presiding officer, with due regard to the nature of the proceeding, may limit the length of any brief to be filed under Rule 706.
(b) Additional briefs and other filings. If appropriate, the presiding officer may permit or require briefs or other filings in addition to those provided for in Rule 706.
§ 385.706 Initial and reply briefs before initial decision (Rule 706).
(a) When filed. The presiding officer will prescribe a time for filing initial or reply briefs and for service of such briefs, giving due regard to the nature of the proceeding, the extent of the record, and the number and complexity of the issues. Unless the presiding officer otherwise orders, the time prescribed in a proceeding for filing briefs will be the same for all initial briefs and the same for all reply briefs.
(b) Contents. (1) An initial brief filed with the presiding officer must include:
(i) A concise statement of the case;
(ii) A separate section containing proposed findings and conclusions, unless waived by the presiding officer;
(iii) Arguments in support of the participant’s position; and
(iv) Any other matter required by the presiding officer.
(2)(i) A reply brief filed with the presiding officer must be limited to a response to any arguments and issues raised in the initial briefs.
(ii) The presiding officer may impose limits on the reply brief in addition to any prescribed under paragraph (b)(2)(i) of this section.
(c) Form. (1) An exhibit admitted in evidence or marked for identification in the record may not be reproduced in the brief, but may be reproduced, within reasonable limits, in an appendix to the brief. Any pertinent analysis of an exhibit may be included in a brief.
(2) If a brief exceeds 20 pages, the brief must be accompanied by a table of contents and of points made, including page references, and an alphabetical list of citations, with page references.
(d) Record. All initial and reply briefs will accompany the record and be available to the Commission and the presiding officer for consideration in deciding the case.
§ 385.707 Oral argument before initial decision (Rule 707).
(a) Procedure. The presiding officer will designate the order of any oral argument to be held, set a time limit on each argument, and make any other procedural rulings.
(b) Scope. (1) If oral argument is held without an initial brief, each participant must be given the opportunity to present orally the information required or permitted to be included in initial briefs under Rule 706(b).
(2) If oral argument is held in addition to an initial or reply brief, oral argument may be limited to issues considered by the presiding officer to be appropriate issues for oral argument.
(c) Inclusion of transcript of oral argument. All oral arguments will be transcribed and included in the record and will be available to the Commission and the presiding officer in deciding the case.
§ 385.708 Initial decisions by presiding officer (Rule 708).
(a) Applicability. This section applies to any proceeding in which a presiding officer, other than the Commission, presided over the reception of the evidence.
(b) General rule. (1) Except as otherwise ordered by the Commission or provided in paragraph (b)(2) of this section, the presiding officer will prepare a written initial decision.
(2)(i) If time and circumstances require, the presiding officer may issue an order stating that an oral initial decision will be issued.
(ii) An oral decision is considered served upon all participants when the decision is issued orally on the record. Promptly after service of the oral decision, the presiding officer will prepare the oral initial decision contained in the transcript in the format of a written initial decision.
(3) Any initial decision prepared under paragraph (b)(1) or (b)(2) of this section will be certified to the Commission by the presiding officer with a copy of the record in the proceeding.
(4) Not later than 35 days after the certification of an initial decision, under paragraph (b)(3) of this section, the presiding officer, after notifying the participants and receiving no objection from them, may make technical corrections to the initial decision.
(c) Initial decision prepared and certified by presiding officer. (1) The presiding officer who presides over the reception of evidence will prepare and certify the initial decision, if any, unless the officer is unavailable or the Commission provides otherwise in accordance with 5 U.S.C. 557(b).
(2) If the presiding officer who presided over the reception of evidence becomes unavailable, the Chief Administrative Law Judge may issue an order designating another qualified presiding officer to prepare and certify the initial decision.
(d) Finality of initial decision. For purposes of requests for rehearing under Rule 713, an initial decision becomes a final Commission decision 10 days after exceptions are due under Rule 711 unless:
(1) Exceptions are timely filed under Rule 711; or
(2) The Commission issues an order staying the effectiveness of the decision pending review under Rule 712.
§ 385.709 Other types of decisions (Rule 709).
In lieu of an initial decision under Rule 708, the Commission may order any type of decision as provided by 5 U.S.C. 557(b), or permit waiver of the initial decision as provided by Rule 710.
§ 385.710 Waiver of the initial decision (Rule 710).
(a) General rule. Any participant may file a motion requesting the Commission to issue a final decision without any initial decision. If all participants join in the motion, the motion is granted, unless the Commission denies the motion within 10 days after the date of filing of the motion or, in the case of an oral motion under paragraph (c)(2) of this section, within 10 days after the motion is transmitted to the Commission. If all participants do not join in the motion, the motion is denied unless the Commission grants the motion within 30 days of filing of the motion or, in the case of an oral motion under paragraph (c)(2) of this section, within 30 days after the motion is transmitted to the Commission.
(b) Content. Any motion to waive the initial decision filed with the Commission must specify:
(1) Whether any participant waives any procedural right;
(2) Whether all participants concur in the request to waive the initial decision;
(3) The reasons that waiver of the initial decision is in the interest of parties and the public interest;
(4) Whether any participant desires an opportunity for filing briefs; and
(5) Whether any participant desires an opportunity for oral argument before the presiding officer, the Commission, or an individual Commissioner.
(c) How and when made. (1) Any written motion under this section may be filed at any time, but not later than the fifth day following the close of the hearing conducted under subpart E of this part.
(2) An oral motion under this section may be made during a hearing session, in which case the presiding officer will transmit to the Commission the relevant portions of the transcript of the hearing in which the motion was made.
(d) Waiver by presiding officer. A motion for waiver of the initial decision, requested for the purpose of certification of a contested settlement pursuant to Rule 602(h)(2)(iii)(A), may be filed with, and decided by, the presiding officer. If all parties join in the motion, the presiding officer will grant the motion. If not all parties join in the motion, the motion is denied unless the presiding officer grants the motion within 30 days of filing the written motion or presenting an oral motion. The contents of any motion filed under paragraph (d) of this section must comply with the requirements in paragraph (b) of this section. A motion may be oral or written, and may be made whenever appropriate for the consideration of the presiding officer.
§ 385.711 Exceptions and briefs on and opposing exceptions after initial decision (Rule 711).
(a) Exceptions. (1)(i) Any participant may file with the Commission exceptions to the initial decision in a brief on exceptions not later than 30 days after service of the initial decision.
(ii) Not later than 20 days after the latest date for filing a brief on exceptions, any participant may file a brief opposing exceptions in response to a brief on exceptions.
(iii) A participant may file, within the time set for filing briefs opposing exceptions, a brief on exceptions solely for the purpose of incorporating by reference one or more numbered exceptions contained in the brief of another participant. A brief filed under this clause need not comply with the requirements set forth in paragraph (b) of this section.
(2) A brief on exceptions or a brief opposing exceptions may not exceed 100 pages, unless the Chief Administrative Law Judge, upon motion, changes the page limitation.
(3) The Secretary may extend, on motion or upon direction of the Commission, the time limits for any brief on or opposing exceptions. No additional briefs are permitted, unless specifically ordered by the Commission.
(4) A participant may not attach to, or incorporate by reference in, any brief on exceptions or brief opposing exceptions any portion of an initial or reply brief filed in the proceeding.
(b) Nature of briefs on exceptions and of briefs opposing exceptions. (1) Any brief on exceptions and any brief opposing exceptions must include:
(i) If the brief exceeds 10 pages in length, a separate summary of the brief not longer than five pages; and
(ii) A presentation of the participant’s position and arguments in support of that position, including references to the pages of the record or exhibits containing evidence and arguments in support of that position.
(2) Any brief on exceptions must include, in addition to matters required by paragraph (b)(1) of this section:
(i) A short statement of the case;
(ii) A list of numbered exceptions, including a specification of each error of fact or law asserted; and
(iii) A concise discussion of the policy considerations that may warrant full Commission review and opinion.
(3) A brief opposing exceptions must include, in addition to matters required by paragraph (b)(1) of this section:
(i) A list of exceptions opposed, by number; and
(ii) A rebuttal of policy considerations claimed to warrant Commission review.
(c) Oral argument. (1) Any participant filing a brief on exceptions or brief opposing exceptions may request, by written motion, oral argument before the Commission or an individual Commissioner.
(2) A motion under paragraph (c)(1) of this section must be filed within the time limit for filing briefs opposing exceptions.
(3) No answer may be made to a motion under paragraph (c)(1) and, to that extent, Rule 213(a)(3) is inapplicable to a motion for oral argument.
(4) A motion under paragraph (c)(1) of this section may be granted at the discretion of the Commission. If the motion is granted, any oral argument will be limited, unless otherwise specified, to matters properly raised by the briefs.
(d) Failure to take exceptions results in waiver—(1) Complete waiver. If a participant does not file a brief on exceptions within the time permitted under this section, any objection to the initial decision by the participant is waived.
(2) Partial waiver. If a participant does not object to a part of an initial decision in a brief on exceptions, any objections by the participant to that part of the initial decision are waived.
(3) Effect of waiver. Unless otherwise ordered by the Commission for good cause shown, a participant who has waived objections under paragraph (d)(1) or (d)(2) of this section to all or part of an initial decision may not raise such objections before the Commission in oral argument or on rehearing.
§ 385.712 Commission review of initial decisions in the absence of exceptions (Rule 712).
(a) General rule. If no briefs on exceptions to an initial decision are filed within the time established by rule or order under Rule 711, the Commission may, within 10 days after the expiration of such time, issue an order staying the effectiveness of the decision pending Commission review.
(b) Briefs and argument. When the Commission reviews a decision under this section, the Commission may require that participants file briefs or present oral arguments on any issue.
(c) Effect of review. After completing review under this section, the Commission will issue a decision which is final for purposes of rehearing under Rule 713.
§ 385.713 Request for rehearing (Rule 713).
(a) Applicability. (1) This section applies to any request for rehearing of a final Commission decision or other final order, if rehearing is provided for by statute, rule, or order.
(2) For the purposes of rehearing under this section, a final decision in any proceeding set for hearing under subpart E of this part includes any Commission decision:
(i) On exceptions taken by participants to an initial decision;
(ii) When the Commission presides at the reception of the evidence;
(iii) If the initial decision procedure has been waived by consent of the participants in accordance with Rule 710;
(iv) On review of an initial decision without exceptions under Rule 712; and
(v) On any other action designated as a final decision by the Commission for purposes of rehearing.
(3) For the purposes of rehearing under this section, any initial decision under Rule 709 is a final Commission decision after the time provided for Commission review under Rule 712, if there are no exceptions filed to the decision and no review of the decision is initiated under Rule 712.
(b) Time for filing; who may file. A request for rehearing by a party must be filed not later than 30 days after issuance of any final decision or other final order in a proceeding.
(c) Content of request. Any request for rehearing must:
(1) State concisely the alleged error in the final decision or final order;
(2) Conform to the requirements in Rule 203(a), which are applicable to pleadings, and, in addition, include a separate section entitled “Statement of Issues,” listing each issue in a separately enumerated paragraph that includes representative Commission and court precedent on which the party is relying; any issue not so listed will be deemed waived; and
(3) Set forth the matters relied upon by the party requesting rehearing, if rehearing is sought based on matters not available for consideration by the Commission at the time of the final decision or final order.
(d) Answers. (1) The Commission will not permit answers to requests for rehearing.
(2) The Commission may afford parties an opportunity to file briefs or present oral argument on one or more issues presented by a request for rehearing.
(e) Request is not a stay. Unless otherwise ordered by the Commission, the filing of a request for rehearing does not stay the Commission decision or order.
(f) Commission action on rehearing. Unless the Commission acts upon a request for rehearing within 30 days after the request is filed, the request is denied.
§ 385.714 Certified questions (Rule 714).
(a) General rule. During any proceeding, a presiding officer may certify or, if the Commission so directs, will certify, to the Commission for consideration and disposition any question arising in the proceeding, including any question of law, policy, or procedure.
(b) Notice. A presiding officer will notify the participants of the certification of any question to the Commission and of the date of any certification. Any such notification may be given orally during the hearing session or by order.
(c) Presiding officer’s memorandum; views of the participants. (1) A presiding officer should solicit, to the extent practicable, the oral or written views of the participants on any question certified under this section.
(2) The presiding officer must prepare a memorandum which sets forth the relevant issues, discusses all the views of participants, and recommends a disposition of the issues.
(3) The presiding officer must append to any question certified under this section the written views submitted by the participants, the transcript pages containing oral views, and the memorandum of the presiding officer.
(d) Return of certified question to presiding officer. If the Commission does not act on any certified question within 30 days after receipt of the certification under paragraph (a) of this section, the question is deemed returned to the presiding officer for decision in accordance with the other provisions of this subpart.
(e) Certification not suspension. Unless otherwise directed by the Commission or the presiding officer, certification under this section does not suspend the proceeding.
§ 385.715 Interlocutory appeals to the Commission from rulings of presiding officers (Rule 715).
(a) General rule. A participant may not appeal to the Commission any ruling of a presiding officer during a proceeding, unless the presiding officer under paragraph (b) of this section, or the motions Commissioner, under paragraph (c) of this section, finds extraordinary circumstances which make prompt Commission review of the contested ruling necessary to prevent detriment to the public interest or irreparable harm to any person.
(b) Motion to the presiding officer to permit appeal. (1) Any participant in a proceeding may, during the proceeding, move that the presiding officer permit appeal to the Commission from a ruling of the presiding officer. The motion must be made within 15 days of the ruling of the presiding officer and must state why prompt Commission review is necessary under the standards of paragraph (a) of this section
(2) Upon receipt of a motion to permit appeal under subparagraph (a)(1) of this section, the presiding officer will determine, according to the standards of paragraph (a) of this section, whether to permit appeal of the ruling to the Commission. The presiding officer need not consider any answer to this motion.
(3) Any motion to permit appeal to the Commission of an order issued under Rule 604, or appeal of a ruling under paragraph (a) or (b) of Rule 905, must be granted by the presiding officer.
(4) A presiding officer must issue an order, orally or in writing, containing the determination made under paragraph (b)(2) of this section, including the date of the action taken.
(5) If the presiding officer permits appeal, the presiding officer will transmit to the Commission:
(i) A memorandum which sets forth the relevant issues and an explanation of the rulings on the issues; and
(ii) the participant’s motion under paragraph (b)(1) of this section and any answer permitted to the motion.
(6) If the presiding officer does not issue an order under paragraph (b)(1) of this section within 15 days after the motion is filed under paragraph (b)(1) of this section, the motion is denied.
(c) Appeal of a presiding officer’s denial of motion to permit appeal. (1) If a motion to permit appeal is denied by the presiding officer, the participant who made the motion may appeal the denial to the Commissioner who is designated Motions Commissioner, in accordance with this paragraph. For purposes of this section, “Motions Commissioner” means the Chairman or a member of the Commission designated by the Chairman to rule on motions to permit interlocutory appeal. Any person filing an appeal under this paragraph must serve separate copies of the appeal on the Motions Commissioner and on the General Counsel by Express Mail or by hand delivery.
(2) A participant must submit an appeal under this paragraph not later than 7 days after the motion to permit appeal under paragraph (b) of this section is denied. The appeal must state why prompt Commission review is necessary under the standards set forth in paragraph (c)(5) of this section. The appeal must be labeled in accordance with § 385.2002(b) of this chapter.
(3) A participant who appeals under this paragraph must file with the appeal a copy of the written order denying the motion or, if the denial was issued orally, the relevant portions of the transcript.
(4) The Motions Commissioner may, in considering an appeal under this paragraph, order the presiding officer or any participant in the proceeding to provide additional information.
(5) The Motions Commissioner will permit an appeal to the Commission under this paragraph only if the Motions Commissioner finds extraordinary circumstances which make prompt Commission review of the contested ruling necessary to prevent detriment to the public interest or to prevent irreparable harm to a person. If the Motions Commissioner makes no determination within 7 days after filing the appeal under this paragraph or within the time the Motions Commissioner otherwise provides to receive and consider information under this paragraph, the appeal to the Commission under paragraph (b) of this section will not be permitted.
(6) If appeal under paragraph (b) of this section is not permitted, the contested ruling of the presiding officer will be reviewed in the ordinary course of the proceeding as if the appeal had not been made.
(7) If the Motions Commissioner permits an appeal to the Commission, the Secretary will issue an order containing that decision.
(d) Commission action. Unless the Commission acts upon an appeal permitted by a presiding officer under paragraph (b) of this section, or by the Motions Commissioner under paragraph (c) of this section, within 15 days after the date on which the presiding officer or Motions Commissioner permits appeal, the ruling of the presiding officer will be reviewed in the ordinary course of the proceeding as if the appeal had not been made.
(e) Appeal not to suspend proceeding. Any decision by a presiding officer to permit appeal under paragraph (b) of this section or by the Motions Commissioner to permit an appeal under paragraph (c) of this section will not suspend the proceeding, unless otherwise ordered by the presiding officer or the Motions Commissioner.
§ 385.716 Reopening (Rule 716).
(a) General rule. To the extent permitted by law, the presiding officer or the Commission may, for good cause under paragraph (c) of this section, reopen the evidentiary record in a proceeding for the purpose of taking additional evidence.
(b) By motion. (1) Any participant may file a motion to reopen the record.
(2) Any motion to reopen must set forth clearly the facts sought to be proven and the reasons claimed to constitute grounds for reopening.
(3) A participant who does not file an answer to any motion to reopen will be deemed to have waived any objection to the motion provided that no other participant has raised the same objection.
(c) By action of the presiding officer or the Commission. If the presiding officer or the Commission, as appropriate, has reason to believe that reopening of a proceeding is warranted by any changes in conditions of fact or of law or by the public interest, the record in the proceeding may be reopened by the presiding officer before the initial or revised initial decision is served or by the Commission after the initial decision or, if appropriate, the revised initial decision is served.
Subpart H—Shortened Procedures
§ 385.801 Waiver of hearing (Rule 801).
In any proceeding in which the Commission is authorized to act after opportunity for hearing, if the parties waive hearing, such opportunity will be deemed to have been afforded by service or publication in the
§ 385.802 Noncontested proceedings (Rule 802).
Noncontested proceedings. In any proceeding required by statute to be set for hearing, the Commission, when it appears to be in the public interest and to be in the interest of the parties to grant the relief or authority requested in the initial pleading, and to omit the intermediate decision procedure, may, after a hearing during which no opposition or contest develops, forthwith dispose of the proceedings upon consideration of the pleadings and other evidence filed and incorporated in the record: Provided, (a) The applicant or other initial pleader requests that the intermediate decision procedure be omitted and waives oral hearing and opportunity for filing exceptions to the decision of the Commission; and (b) no issue of substance is raised by any request to be heard, protest or petition filed subsequent to publication in the
Subpart I—Commission Review of Remedial Orders
§ 385.901 Scope (Rule 901).
(a) Proceedings to which applicable. The provisions of this subpart apply to proceedings of the Commission held in accordance with section 503(c) of the Department of Energy Organization Act (42 U.S.C. 7193(c)) to review orders issued by the Secretary of Energy pursuant to section 503(a) of the Department of Energy Organization Act (42 U.S.C. 7193(c)), and initiated by notices of probable violation, proposed remedial orders, or other formal administrative initiating documents issued on or after October 1, 1977, which are contested by the recipient.
(b) Relationship to other rules. (1) Where a provision of this subpart is inconsistent with a provision in any other subpart of this part, the provision in this subpart controls.
(2) Subpart F of this part, except Rule 601, does not apply to proceedings under this subpart.
§ 385.902 Definitions (Rule 902).
For purposes of this subpart:
(a) Contested order means the remedial order, interim remedial order for immediate compliance or order of disallowance being contested in proceeding pursuant to this subpart;
(b) Interim remedial order for immediate compliance means an interim remedial order for immediate compliance issued pursuant to 10 CFR 205.199D (interim remedial order of immediate compliance);
(c) Order of disallowance means an order of disallowance issued pursuant to 10 CFR 205.199E (disallowance);
(d) Participant means, as appropriate, the Secretary, the petitioner, and intervenors;
(e) Petitioner means a person who has received a remedial order, interim remedial order for immediate compliance, or order of disallowance who notifies the Secretary that he intends to contest the order;
(f) Remedial order means a remedial order issued pursuant to 10 CFR 205.199B (remedial orders);
(g) Secretary means the Secretary of Energy or his delegate.
§ 385.903 Request for nondisclosure of information (Rule 903).
(a) For purposes of this section, nondisclosure means nondisclosure except as to the participants in the proceeding under conditions provided in paragraphs (d) and (e) of this section.
(b) If any person filing under this subpart claims that some or all of the information contained in a document is exempt from the mandatory public disclosure requirements of the Freedom of Information Act (5 U.S.C. 552), is information referred to in section 1905 of title 18 of the United States Code (18 U.S.C. 1905) (disclosure of confidential information), or is otherwise exempt by law from public disclosure, the person:
(1) Must request the presiding officer not to disclose such information, except to the participants in the proceeding under the conditions provided in paragraphs (d) and (e) of this section, which request the person must serve upon the participants in the proceeding;
(2) Must file, together with the document, a second copy of the document from which has been deleted the information for which the person requests nondisclosure and must indicate in the original document that the original document is exempt, or contains information which is exempt, from disclosure;
(3) Must include a statement specifying why the information is privileged or confidential, if the information for which nondisclosure is requested is claimed to come within the exception in 5 U.S.C. 552(b)(4) for trade secrets and commercial or financial information;
(4) Must include a statement specifying the justification for nondisclosure, if the information for which nondisclosure is requested is not within the exception in 5 U.S.C. 552(b)(4).
(c) If the person filing a document does not submit a second copy of the document from which the appropriate information has been deleted, the presiding officer may assume that there is no objection to public disclosure of the document in its entirety.
(d) If information is submitted in accordance with paragraph (b) of this section, the information will not be disclosed except as provided in the Freedom of Information Act, in accordance with part 388 of this subchapter and upon request in accordance with paragraph (e) of this section, to participants in the proceeding under the restrictions that the participants may not use or disclose the information except in the context of the proceeding conducted pursuant to this subpart and that the participants must return all copies of the information at the conclusion of the proceeding to the person who submitted the information under paragraph (b) of this section.
(e) At any time, a participant may request the presiding officer to direct a person submitting information under paragraph (b) of this section to provide that information to the participant requesting the information under this paragraph. The presiding officer will so direct if the participant requesting the information agrees:
(1) Not to use or disclose the information except in the context of the proceeding conducted pursuant to this subpart; and
(2) To return all copies of the information, at the conclusion of the proceeding, to the person submitting the information under paragraph (b) of this section.
(f) At any time, a participant may request the presiding officer to direct that the complete record of prior proceedings, including information determined by the Secretary to be exempt from disclosure, be made available to that participant by the Secretary. The presiding officer will so direct if the participant requesting the complete record agrees:
(1) Not to use or disclose the information determined to be exempt except in the context of the proceeding conducted pursuant to this subpart, and
(2) To return all copies of the information determined to be exempt to the presiding officer at the conclusion of the proceeding.
§ 385.904 Commencement of proceeding (Rule 904).
(a) Except as provided in paragraph (b) of this section, the proceeding pursuant to this subpart will be commenced by filing with the Secretary of the Commission either an answer by a petitioner pursuant to Rule 906(b)(1), or a written notice by the Secretary that a petitioner has filed a notice of intent to contest an order reviewable under this subpart, whichever is filed first. The Secretary must file written notice that a petitioner has filed a notice of intent to contest an order reviewable under this subpart within 15 days of the Secretary’s receipt of such notice of intent. When the Secretary files the written notice, the Secretary must serve a copy of the contested order upon other participants in the prior proceedings and upon persons denied intervention in the prior proceedings, and must certify to the Commission that such service has been made, stating the names and addresses of persons served.
(b) The proceeding pursuant to this subpart with respect to an interim remedial order for immediate compliance will be commenced by a petitioner’s filing with the Secretary of the Commission, for the Commission, and serving on other participants in the prior proceedings, if any, a notice of petition for review of an interim remedial order for immediate compliance pursuant to 10 CFR 205.199D(i)(1) (interim remedial order of immediate compliance). The Commission will defer consideration of the merits of the order until a final remedial order is issued by the Secretary.
(c) Upon commencement of a proceeding, the Commission or its designee will designate a presiding officer for the proceeding, and the Commission or its designee will notify participants in the prior proceedings and persons denied intervention in the prior proceedings of such designation.
§ 385.905 Stay of contested order (Rule 905).
(a) Upon commencement of a proceeding, the contested order will be automatically stayed pending review pursuant to this subpart unless and until, upon request of the Secretary or other participant, the presiding officer finds that the public interest requires immediate compliance with the contested order.
(b) The Secretary or other participants may at any time prior to the hearing under Rule 909 (Hearing), if requested; or, if there is no hearing, within 30 days of the commencement of the proceeding under Rule 904 (Commencement of proceeding); file a petition requesting that the contested order not be stayed, or that the stay be lifted, and setting forth the legal and factual basis for the request.
(c) The presiding officer may request a written statement of the views of participants regarding whether the contested order should be stayed or continue to be stayed and may convene an expedited hearing or conference on a petition under paragraph (b) of this section.
(d) The presiding officer may grant the petition requesting immediate compliance where he finds that the public interest so requires and will notify the participants of the determination.
(e) If the presiding officer does not grant the petition under paragraph (b) of this section within 10 days after it is filed, the petition is denied. Prior to the expiration of the 10-day period the presiding officer may extend the period for decision for up to 7 days. At the end of the extension, the petition, if not granted, is denied.
(f) If the petition under paragraph (b) of this section is denied, the presiding officer will notify the participants of such denial.
(g) A grant or denial of petition under paragraphs (b) or (c) of this section may be appealed, within 10 days after the grant or denial, to the Commission in accordance with Rule 715 (relating to interlocutory appeals). The contested order will remain stayed pending the Commission’s disposition of the appeal.
§ 385.906 Pleadings (Rule 906).
(a) By the Secretary. (1) Within 20 days after the commencement of a proceeding, the Secretary:
(i) Will file with the Secretary for the presiding officer a copy of the contested order; and
(ii) May, in addition, elect to file a statement setting forth the factual elements of the alleged violation, which statement the Secretary will serve on all participants in the proceeding.
(2) If the petitioner requests permission to raise new facts or issues pursuant to Rule 907(a) (new facts and issues), the Secretary may file, within 10 days after the filing of the petitioner’s answer, a reply responding to the petitioner’s request to raise new facts or issues. In the reply, the Secretary may also request the permission of the presiding officer to raise new facts or issues under the criteria set forth in Rule 907(b) (new facts and issues) and to conduct discovery relating to the new facts or issues he may raise pursuant to Rule 907(b) (new facts and issues). Failure by the Secretary to request permission to raise new facts or issues or to conduct discovery in this reply constitutes a waiver of the opportunity to do so at a later time in the proceeding.
(3) The Secretary will file with the Secretary of the Commission, for the presiding officer, and serve upon other participants in the proceedings, a brief in support of the affirmative case, which will set forth:
(i) The elements of the alleged violation, including references to the authorities upon which the Secretary relies, including but not limited to regulations, rulings, interpretations and decisions on appeals and exceptions issued by the Department or its predecessor agencies and precedents established by the Commission; and
(ii) A complete statement of the factual and legal basis of the contested order.
(4) The Secretary’s brief will be filed according to the following time period appropriate to the particular proceeding:
(i) If no participant (including persons requesting intervention) has requested permission to raise new facts or issues or to conduct discovery pursuant to paragraphs (a)(2), (b)(2), (c)(7), and (c)(8) of this section, within 20 days after the filing of the petitioner’s answer under paragraph (b)(1) of this section;
(ii) If the presiding officer has determined, under Rule 908(d) (discovery) that no discovery shall be permitted, within 20 days after the presiding officer’s determination under such rule;
(iii) If discovery is permitted under Rule 908(d) (discovery) within 20 days after the conclusion of the time period set for discovery under such rule;
(b) By the petitioner. (1) Within 15 days after petitioner gives written notice to the Office of Hearings and Appeals of the Department of Energy pursuant to 10 CFR 205.199C(b) that petitioner wishes to appeal the remedial order, the petitioner must file with the Secretary of the Commission, for the presiding officer, and serve upon the Secretary and other participants in the proceedings, an answer to the contested order admitting or denying each of the Secretary’s findings in the contested order and setting forth affirmative defenses, if any. Each answer filed with the Secretary of the Commission by the petitioner, in accordance with this paragraph, must be accompanied by the fee prescribed by § 381.303 of this chapter.
(2) In the answer, the petitioner may:
(i) Contest any part of the record;
(ii) Request permission to raise new facts or issues not raised in the prior proceedings if the new facts or issues meet the criteria set forth in Rule 907(a) (new facts and issues); and
(iii) Request permission to conduct discovery, subject to criteria provided in Rule 908(a) (discovery). Failure by the petitioner to contest the record or to request permission to raise new facts or issues or to conduct discovery in this answer constitutes a waiver of the opportunity to do so at a later time in the proceeding.
(3) Within 15 days after filing of the Secretary’s brief under paragraph (a)(3) of this section, the petitioner shall file with the Secretary of the Commission, for the presiding officer, and serve upon other participants in the proceeding, a brief stating fully the objections to the contested order, including references to the authorities upon which the petitioner relies, including but not limited to regulations, rulings, interpretations, and decisions on appeals and exceptions issued by the Department or its predecessor agencies and precedents established by the Commission.
(c) By interveners. (1) A person qualifying under paragraph (c)(2) of this section, may request the presiding officer to permit intervention in the proceeding under this subpart in accordance with the procedures described in this paragraph.
(2) A motion to intervene may be filed by any person claiming:
(i) An interest which may be directly affected and which is not adequately protected by existing parties and as to which the persons requesting intervention may be bound by the Commissions action in the proceeding; or
(ii) Any other interest of such nature that participation by the person requesting intervention may be in the public interest.
(3) A motion to intervene must set forth clearly and concisely the facts from which the nature of the requester’s alleged right or interest can be determined, the grounds of the proposed intervention, and the position of the intervener in the proceeding, so as fully and completely to advise the participants and the presiding officer as to the specific issues of fact or law to be raised or controverted, by admitting, denying, or otherwise answering, specifically and in detail, each material allegation of fact or law raised or controverted, including references to the authorities upon which the requester relies, including, but not limited to, regulations, rulings, interpretations, and decisions on appeals and exceptions issued by the Department or its predecessor agencies and precedents established by the Commission.
(4) Motions to intervene may be filed with the Secretary of the Commission, for the presiding officer, within 20 days after the commencement of the proceeding under Rule 904 (commencement of proceedings) unless, in extraordinary circumstances and for good cause shown, the presiding officer authorizes a late filing. A person requesting intervention must serve the motion to intervene on the participants in the proceeding at the same time the request is filed with the Secretary of the Commission.
(5) A participant in the proceedings may file an answer to a motion to intervene. Failure to object constitutes a waiver of any objection to the granting of such request. If made, answers must be filed within 15 days after the filing of the request to intervene.
(6) After expiration of the time for filing answers to requests to intervene or default thereof, as provided in paragraph (c)(5) of this section, the presiding officer will grant or deny such request, in whole or in part, or may, if found to be appropriate, authorize limited participation. The presiding officer will serve the determination on a motion to intervene upon the participants in the proceeding and upon the person requesting intervention. A person wholly or partially denied intervention may take an interlocutory appeal of the order denying intervention, under Rule 715 (interlocutory appeals to the Commission from rulings of presiding officers), and will be considered a “participant” (as that term is defined in Rule 102(b) (definitions)) for the limited purpose of permitting that person to file an interlocutory appeal under Rule 715 (interlocutory appeals to the Commission from rulings of presiding officers) contesting denial, in whole or in part, of that person’s motion to intervene.
(7) A person filing a motion to intervene, may request therein the permission of the presiding officer to raise new facts or issues not raised in the prior proceedings on the contested order, if the new facts or issues meet the criteria set forth in Rule 903(c) (request for nondisclosure of information). Failure by the person requesting permission to intervene to request permission to raise new facts or issues in the motion to intervene constitutes a waiver of the opportunity to do so at a later time in the proceeding.
(8) A person filing a motion to intervene may request the permission of the presiding officer to conduct discovery, subject to the conditions set forth in Rule 908(c) (discovery). Failure by the person requesting permission to intervene to request permission to conduct discovery in the motion to intervene constitutes a waiver of the opportunity to do so at a later time in the proceeding.
(d) Attachments of pleadings. (1) Each party will file, as an appendix to each pleading which cites documents in the record developed in the prior proceedings on the remedial order, one copy of each such document in its entirety and, if any such document contains information exempt from public disclosure pursuant to Rule 903, a second copy of such document with such information deleted. The top of the first page of each such document will contain the word “PUBLIC” or “NONPUBLIC,” to indicate whether it contains such exempt information.
(2) One copy of each version shall be served on counsel for the petitioner and/or the Secretary, and one copy of the PUBLIC version shall be served on counsel for each other participant separately represented unless the conditions of Rule 903 are met, in which situation such counsel shall be served with copies of both versions.
(3) In compiling their appendices, the parties will include only documents specifically cited and relied upon in their pleadings. They will have regard for the fact that the Secretary’s entire administrative record is always available to the Commission and will not include irrelevant or duplicative documents in the appendices.
§ 385.907 New facts and issues (Rule 907).
(a) Raised by the petitioner. In the answer, as provided in Rule 906(b)(2)(ii) (new facts and issues) the petitioner may request permission of the presiding officer to raise new facts or issues not raised in prior proceedings on the contested order that:
(1)(i) Are facts or issues that were not known and could not, with the exercise of due care, have been known to the petitioner at the time they would otherwise have been raised during the prior proceedings;
(ii) Are facts or issues that the petitioner was unable to raise at the time they could have been raised during the prior proceedings because of unduly restrictive time limits imposed by the Secretary; or
(iii) Are facts or issues that the petitioner was not permitted to raise in the prior proceedings due to erroneous adverse procedural rulings; and
(2) Are necessary for a full and true disclosure of the facts.
(b) Raised by the Secretary. In the reply under Rule 906(a)(2) (pleadings), the Secretary may request permission of the presiding officer to raise new facts or issues not raised in prior proceedings on the contested order that:
(1) Are necessary to support the Secretary’s case as a result of new facts or issues raised by the petitioner under Rule 906(b)(2)(ii) (pleadings) and this section; and
(2) Are necessary for a full and true disclosure of the facts.
(c) Raised by interveners. In the motion to intervene under Rule 906(c)(3) (pleadings) and this section, an intervener may request permission of the presiding officer to raise new facts or issues not raised in prior proceedings on the contested order that:
(1) If the intervener did not participate in the prior proceeding, meet the criteria of paragraphs (a)(1) and (a)(2) of this section; or
(2) If the intervener participated in the prior proceedings, are:
(i)(A) Facts or issues that were not known and could not, with the exercise of due care, have been known to the intervener at the time they would otherwise have been raised during the prior proceedings;
(B) Facts or issues that the intervener was unable to raise at the time they could have been raised during the prior proceedings because of unduly restrictive time limits imposed by the Secretary; or
(C) Facts or issues that the intervener was not permitted to raise in the prior proceedings due to erroneous adverse procedural rulings; and
(ii) Are necessary for a full and true disclosure of the facts.
(d) Determination by the presiding officer. The presiding officer will determine whether to grant or deny, in whole or in part, the requests of the participants to raise new facts or issues and will serve those determinations on the participants in the proceeding.
§ 385.908 Discovery (Rule 908).
(a) By petitioner. In the answer under Rule 906(b)(2) (pleadings), the petitioner may request permission of the presiding officer to conduct discovery, where such discovery:
(1) Relates to new facts or issues raised in accordance with Rule 907(a) (new facts and issues); or
(2)(i) Was not permitted in the prior proceedings on the contested order due to erroneous adverse procedural rulings; and
(ii) Is necessary for a full and true disclosure of the facts.
(b) By the Secretary. In the reply under Rule 906(a)(2) (pleadings), the Secretary may request permission of the presiding officer to conduct discovery where such discovery relates to new facts or issues raised in accordance with Rule 907(b) (new facts and issues).
(c) By interveners. In a motion to intervene under Rule 906(c)(8) (pleadings) an intervener may request permission of the presiding officer to conduct discovery where such discovery:
(1) Relates to new facts or issues raised in accordance with Rule 907(c) (new facts and issues); or
(2) If the intervener participated in the prior proceedings,
(i) Such discovery was not permitted in prior proceedings on the contested order due to erroneous adverse procedural rulings; and
(ii) Such discovery is necessary for a full and true disclosure of the facts.
(d) Determinations by the presiding officer. The presiding officer will determine whether to grant or deny, in whole or in part, the requests of the participants for discovery and will set a time limit within which discovery must be conducted.
(e) Interrogatories. In addition to discovery devices applicable to this subpart under other subparts of this part, participants may conduct discovery by means of written interrogatories under conditions determined by the presiding officer.
§ 385.909 Hearing (Rule 909).
(a) Participant may file, within 20 days after the commencement of the proceeding under Rule 904 (Commencement of proceeding), a request for a hearing or a motion for the opportunity for cross-examination including the reasons why cross-examination is necessary for a full and true disclosure of the facts.
(b) If a participant has filed a request for a hearing, the presiding officer will grant the request for a hearing. The hearing will include an opportunity for the submission of oral or documentary evidence and oral arguments.
(c) The presiding officer may at any time, convene a hearing.
(d) As soon as practicable after receiving a request for hearing under paragraph (a) of this section or after determination that a hearing will be held under paragraph (c) of this section, the presiding officer will give notice to the participants of the time and place of the hearing.
(e) The presiding officer will determine the issues to be resolved in the proceeding, may specify the time available for oral argument, and will give notice thereof to the participants. The presiding officer may require additional information from the participants, and may convene a prehearing conference for the purpose of determining the issues or the nature of the proceeding to be held.
(f) If at any time prior to the certification of the record by the presiding officer under Rule 913 (Certification of the record), with or without a motion of a participant, the presiding officer determines that it is necessary for a full and true disclosure of the facts, the presiding officer may order that the participants be afforded the opportunity for cross-examination on any facts or issues raised in the proceeding.
§ 385.910 Conduct of the hearing (Rule 910).
The presiding officer is responsible for conduct of the hearing, including the order of procedure.
§ 385.911 Burden of proof (Rule 911).
(a) The Secretary has the burden of going forward and must sustain the burden of proof with respect to disputed elements of affirmative case of the Secretary.
(b) The Commission order will be based on a preponderance of the evidence.
§ 385.912 Proposed findings of fact, conclusions of law, and comments (Rule 912).
(a) Within 10 days after the conclusion of the hearing, or, if no hearing is held, within 20 days after the filing of the petitioner’s brief under Rule 906(b)(3) (pleadings), a participant may file with the Secretary of the Commission for the presiding officer, and serve upon the other participants proposed findings of fact and conclusions of law, comments in support thereof and any objections with respect to procedural rulings of the presiding officer.
(b) Within 10 days after the filing of proposed findings of fact and conclusions of law under paragraph (a) of this section, a participant may file, and must serve on other participants, a reply thereto.
§ 385.913 Proposed order (Rule 913).
(a) After the conclusion of the hearing and after the filings under Rule 912 (a) and (b), (proposed findings of fact, conclusions of law, and comments) the presiding officer will issue a decision and proposed order based on findings of fact affirming, modifying, or vacating the contested order or directing other appropriate relief. The proposed order will be based on the entire record before the presiding officer, including the record of prior proceedings certified by the Secretary.
(b) Participants may file with the Secretary of the Commission, within 15 days of issuance of the proposed order of the presiding officer, written comments on the presiding officer’s decision and proposed order.
(c) Participants may file with the Secretary of the Commission, within seven days of the end of comment period prescribed in paragraph (b) of this section, reply comments limited to a response to any arguments and issues raised in the written comment.
(d) The presiding officer will certify and file with the Secretary of the Commission a copy of the record in the proceedings and copies of the written and reply comments filed pursuant to paragraphs (b) and (c) of this section.
(e) Unless otherwise ordered by the Chief Administrative Law Judge, written comments and reply comments must be limited to 15 pages, doublespaced.
§ 385.914 Commission action (Rule 914).
The Commission will upon consideration of the entire record, issue a final order affirming, modifying, or vacating the contested order or directing other appropriate relief. The Commission will serve the final order on the participants.
§ 385.915 Off-the-record communications (Rule 915).
The provisions of Rule 2201 (prohibited communications and other communications requiring disclosure) apply to proceedings pursuant to this subpart, commencing at the time the Secretary issues a proposed remedial order under 10 CFR 205.192, an interim remedial order for immediate compliance under 10 CFR 205.199D, or a proposed order of disallowance under 10 CFR 205.199E.
§ 385.916 Withdrawal of petition for review (Rule 916).
(a) At any time, including after a hearing has been held or convened, the petitioner may submit to the presiding officer, and serve on other participants in the proceeding, a withdrawal of the petition for review of the contested order. The presiding officer will thereupon issue, and serve the participants, an order terminating the proceeding conducted pursuant to this subpart, which order will be effective 10 days after issuance.
(b) Termination of the proceeding under paragraph (a) of this section, may be appealed to the Commission, within 10 days after issuance of the termination order, except that if the Commission does not act on an appeal within 30 days, it is deemed denied. The termination order is stayed pending the appeal. If the Commission rescinds the termination order, the proceeding will continue in accordance with this subpart.
§ 385.917 Sanctions (Rule 917).
Whenever it appears to the Commission that a person is engaged or about to engage in any act or practice which constitutes or will constitute a violation of rule, regulation, or order, made or imposed by the Commission or the presiding officer under this subpart, it may bring an action in the proper court of the United States to enjoin that act or practice and to enforce compliance with the order, and upon a proper showing, a permanent or temporary injunction or decree or restraining order will be granted without bond. The Commission may transmit such evidence as may be available concerning that act or practice to the Attorney General, who may institute the necessary criminal proceedings.
Subpart J—Commission Review of Adjustment Request Denials
§ 385.1001 Scope (Rule 1001).
(a) Applicability. This subpart applies to proceedings of the Commission held in accordance with section 504(b) of the Department of Energy Organization Act, 42 U.S.C. 719(b), to review orders issued by the Secretary of Energy pursuant to section 504(a) of the Department of Energy Organization Act denying, in whole or in part, requests for adjustments.
(b) Relationship to other rules. When a provision of this subpart is inconsistent with a provision of any other subpart of this part, the former provision controls.
§ 385.1002 Definitions (Rule 1002).
For purposes of this subpart:
(a) Commission includes an officer or employee designated as presiding officer in a proceeding under this subpart.
(b) Petitioner means a person who is aggrieved or adversely affected by a contested order, as defined in this section, and who requests a review, pursuant to this subpart, by the Commission of the denial by the Secretary.
(c) Secretary means the Secretary of Energy or his delegate.
(d) Contested order means the decision or order issued by the Secretary denying, in whole or in part, a request for adjustment.
(e) Participant means, as appropriate, the petitioner, the Secretary, or an intervener.
§ 385.1003 Request for nondisclosure of information (Rule 1003).
(a) For purposes of this section, nondisclosure means nondisclosure except to the participants in the proceedings and under the conditions as provided in paragraph (e) of this section.
(b) If a person filing under this subpart claims that some or all of the information contained in a document is exempt from the mandatory public disclosure requirements of the Freedom of Information Act (5 U.S.C. 552), is information referred to in 18 U.S.C. 1905, or is otherwise exempt by law from public disclosure, the person:
(1) Will request the presiding officer not to disclose such information, except to the participants in the proceedings and under the conditions as provided in paragraph (e) of this section, which request the person must serve upon the participants in the proceedings;
(2) Will file, together with the document, a second copy of the document from which has been deleted the information for which the person requests nondisclosure and must indicate in the original document that the original document is confidential or contains confidential information;
(3) If the information is claimed to come within the exception in 5 U.S.C. 552(b)(4), for trade secrets and commercial or financial information, it must include a statement specifying why the information is privileged or confidential;
(4) If the information for which nondisclosure is requested is not within the exception in 5 U.S.C. 552(b)(4), it must include a statement specifying the justification for nondisclosure.
(c) If the person filing a document does not submit a second copy of the document from which the appropriate information has been deleted, the presiding officer may assume that there is no objection to public disclosure of the document in its entirety.
(d) If information is submitted in accordance with paragraph (b) of this section, the information will not be disclosed except as provided in the Freedom of Information Act, in accordance with Part 388 of this subchapter and upon request in accordance with paragraph (e) of this section, to participants in the proceeding under the restrictions that the participants may not use or disclose the information except in the context of the proceeding conducted pursuant to this subpart and that the participants must return all copies of the information at the conclusion of the proceeding to the person who submitted the information under paragraph (b) of this section.
(e) At any time, a participant may request the presiding officer to direct a person submitting information under paragraph (b) of this section to provide that information to the participant requesting the information under this paragraph. The presiding officer will so direct if the participant requesting the information agrees:
(1) Not to use or disclose the information except in the context of the proceeding conducted pursuant to this subpart; and
(2) To return all copies of the information, at the conclusion of the proceeding, to the person submitting the information under paragraph (b) of this section.
(f) At any time, a participant may request the presiding officer to direct that the complete record of prior proceedings, including information determined by the Secretary to be exempt from disclosure, be made available to that participant. The presiding officer will so direct if the participant requesting the complete record agrees:
(1) Not to use or disclose the information determined to be exempt except in the context of the proceeding conducted pursuant to this subpart, and
(2) To return all copies of the information determined to be exempt to the presiding officer at the conclusion of the proceeding.
§ 385.1004 Commencement of proceedings (Rule 1004).
(a) A petitioner commences proceedings, pursuant to this subpart, by filing with the Commission and serving upon the Secretary and any other participants in prior proceedings on the contested order a petition for review, which must contain:
(1) A copy of the decision or order denying, in whole or in part, request for adjustment (the contested order); and
(2) A complete statement of the petitioner’s objections factual or legal to the contested order, including references to all authorities upon which the petitioner relies including but not limited to regulations, rulings, interpretations, and decisions on exceptions and appeals issued by the Department or its predecessor agencies and precedents established by the Commission.
(b) A petition for review must be filed within 30 days of issuance by the Secretary of the order to be contested pursuant to this subpart.
(c) Each petition for review filed with the Secretary of the Commission must be accompanied by the fee prescribed by § 381.304 of this chapter.
(d) Upon receiving a petition for review and the fee required by paragraph (c), of this section, the Commission or its designee will designate a presiding officer for the proceedings.
§ 385.1005 Replies (Rule 1005).
(a) By the Secretary. Within 20 days of service of the petition for review, the Secretary will file with the Commission and serve on the petitioners and the other participants in prior proceedings on the contested order, a reply to the petition for review stating fully his or her position supported by arguments to the petition for review.
(b) By other participants. A person who participated in prior proceedings on the contested order may be a participant in the proceedings pursuant to this subpart and may make filings and submittals as determined by the presiding officer.
(c) By interveners. A person who was denied the opportunity to participate in prior proceedings on the contested order or who is aggrieved or adversely affected by the contested order may move to intervene in accordance with Rule 214 (intervention). In order that the motion be granted, the movant must show, as appropriate, that denial of participation in prior proceedings was wrongful or why he or she is aggrieved or adversely affected by the contested order. If the presiding officer grants the motion, the person submitting the motion to intervene may make filings and submittals as determined by the presiding officer.
(d) A participant may request interim relief in a proceeding pursuant to this subpart.
(e) The presiding officer may require such other filings by the participants as he or she deems necessary in the conduct of the proceedings.
§ 385.1006 Request for hearing (Rule 1006).
A participant may file with the Commission and serve on the other participants a request for hearing, which will be deemed granted. Such request must be filed concurrently with participant’s first pleading.
§ 385.1007 Presiding officer (Rule 1007).
(a) The presiding officer will determine the issues to be resolved in the proceeding and will give notice thereof to the participants. The presiding officer may require additional information from the participants and convene a prehearing conference for the purpose of determining the issues to be considered at a hearing, if one is to be held. The presiding officer may also specify the time available for oral argument and determine the nature of the hearing to be held.
(b) The presiding officer may determine, upon request by a participant, whether to permit the participant to raise new facts or issues not raised in prior proceedings on the contested order. Such a request may be granted if the facts or issues are facts or issues that:
(1)(i) Were not known and could not, with the exercise of due care, have been known to the participant at the time they could have been raised in prior proceedings; or
(ii) Are facts or issues that the participant was not permitted to raise in prior proceedings on the contested order due to an adverse procedural ruling alleged to be erroneous; and
(2) Are necessary for a full and true disclosure of the facts.
(c) The petitioner must file a request to raise new facts or issues simultaneously with its petition for review. The Secretary must file such a request simultaneously with its reply to the petition for review. A third party must make such a request by the filing deadline set by the presiding officer.
§ 385.1008 Hearings (Rule 1008).
As soon as practicable, after receiving any request for hearing and all the pleadings under Rules 1004 (commencement of proceedings) and 1005 (replies), the presiding officer will give notice to the participants as to the time and place of the hearing.
§ 385.1009 Proof (Rule 1009).
(a) A participant seeking relief from the Secretary’s denial of a request for adjustment has the burden of demonstrating the participant’s entitlement to the relief sought.
(b) Relief will be granted under this subpart if a participant demonstrates, by a preponderance of the evidence, that such relief is warranted.
§ 385.1010 Certification of the record (Rule 1010).
The presiding officer will certify and file with the Office of the Secretary of the Commission, for the Commission, a copy of the record in the proceeding.
§ 385.1011 Final order (Rule 1011).
The Commission will issue a final order, affirming, modifying or vacating the contested order or directing other appropriate relief.
§ 385.1012 Off-the-record communications (Rule 1012).
The provisions of Rule 2201 (prohibited communications and other communications requiring disclosure) apply to proceedings pursuant to this subpart, commencing at the time a petitioner files a petition for review under Rule 1004 (commencement of proceedings).
§ 385.1013 Attachments to pleadings (Rule 1013).
(a) Each party will file, as an appendix to each pleading which cites documents in the record developed in the prior proceedings on the adjustment request, one copy of each such document in its entirety and, if such document contains information exempt from public disclosure pursuant to rule 1003, a second copy of such document with such information deleted. The top of the first page of each such document will contain the word “PUBLIC” or “NON-PUBLIC,” to indicate whether it contains exempt information.
(b) One copy of the PUBLIC and NON-PUBLIC versions must be served on counsel for the petitioner and/or the Secretary, and one copy of the PUBLIC version must be served on counsel for each other participant separately represented unless the conditions of Rule 1003 are met, in which situation such counsel must be served with copies of both versions.
(c) In compiling appendices, the parties will include only documents specifically cited and relied upon in their pleadings. In light of the fact that the Commission always has access to the Secretary’s entire administrative record, the parties must not include irrelevant or repetitive documents in the appendices.
Subpart K—Petitions for Adjustments Under the NGPA
§ 385.1101 Applicability (Rule 1101).
(a) Proceedings to which applicable. Except as provided in paragraph (b) of this section, this subpart applies to proceedings of the Commission held in accordance with section 502(c) of the NGPA to provide for adjustments of:
(1) Commission rules, and
(2) Commission orders having the applicability and effect of a rule as defined in section 551(4) of title 5 of the United States Code (5 U.S.C. 551(4)) and issued under the NGPA, except orders issued under sections 301, 302, and 303 of the NGPA.
(b) This subpart does not apply to:
(1) Proceedings wherein the Commission by order grants an adjustment on its own motion or;
(2) Proceedings for which the Commission by order waives the provision of this subpart.
(c) Relationship to other rules. (1) Where a provision of this subpart is inconsistent with a provision in another subpart of this part, the former provision controls.
(2) When provisions of other subparts of this part require Commission action, such provisions as applied under this subpart shall be deemed to require staff action. This subpart does not require a hearing to which subpart E applies.
§ 385.1102 Definitions (Rule 1102).
For purposes of this subpart:
(a) Adjustment means an order issued by Staff under Rule 1109 (orders):
(1) Granting relief from an order or rule issued by the Commission under the NGPA,
(i) Including exceptions, exemptions, modification, and rescissions of rules and orders have the effect of rule as defined in section 551 of title 5 of the United States Code (5 U.S.C. 551(4)) and issued under the NGPA; but
(ii) Excluding requests for just and reasonable rates under sections 104, 106, and 109 of the NGPA; and
(2) Granting an exemption, in whole or in part, for incrementally priced industrial boiler fuel facilities from section 201 of the NGPA, under the authority of section 206(d) of the NGPA and § 282.206 (industrial boiler fuel facilities exemption);
(b) Petitioner means a person who files a petition for adjustment under paragraph (c) of this section;
(c) Petition means a petition for adjustment filed under Rule 1103 (commencement of adjustment proceedings);
(d) NGPA means the Natural Gas Policy Act of 1978;
(e) Party means, with respect to a particular petition for adjustment, the person making the petition, and intervener, or a person who has moved to intervene but whose motion has not been granted or denied under Rule 1105(b) (intervention in adjustment proceedings).
(f) Staff means the Director of the Office of Producer and Pipeline Regulation, or a person who is designated by the Director and who is an employee of the Commission.
§ 385.1103 Commencement of proceeding (Rule 1103).
A person commences a proceeding for an adjustment by filing a petition for adjustment with the Commission.
§ 385.1104 Initial petition (Rule 1104).
(a) Content. (1) The petition must contain:
(i) A full and complete statement of the relevant facts, including the documentary support pertaining to the circumstances, act or transaction that is the subject of the petition;
(ii) A complete statement of the business reasons why the relief should be granted and the business consequences that will result if the relief is denied; and
(iii) A statement specifying how the denial of relief will cause the applicant to suffer special hardship, inequity, or unfair distribution of burdens.
(2) The petition must contain a complete statement of the legal basis of the relief requested including citations to authorities relied upon to support the petition.
(3) The petition must specify the exact nature of the relief sought.
(4) The certificate of service required under Rule 2010(h) (certificate of service) must indicate the names and addresses of all persons served.
(5) The petition must include a form of notice suitable for publication in the
(6) The petition must be accompanied by the fee prescribed in § 381.401 of this chapter or by a petition for waiver pursuant to § 381.106 of this chapter.
(b) Service. (1) The petitioner must serve a copy of the petition, or a copy from which confidential information has been deleted in accordance with Rule 1112 (requests for confidential treatment) on each person who is reasonably ascertainable by the petitioner as a person who may suffer direct and measurable economic impact if the relief is granted.
(2) Notwithstanding paragraph (b)(1) of this section, if a petitioner determines that compliance with such paragraph of this section would be impracticable, the petitioner must:
(i) Comply with the requirements of such paragraph with regard to those persons whom it is reasonable and practicable to serve; and
(ii) Include with the petition a description of the persons or class or classes of persons to whom notice was not sent.
(3) Staff may require the petitioner to provide alternate or additional service and will cause notice of the application to be published in the
§ 385.1105 Intervention (Rule 1105).
(a) A motion to intervene in an adjustment proceeding, in conformity with Rule 214 (intervention) must be filed within 15 days after publication in the
(b) A motion to intervene is granted unless it is denied by staff within 75 days after the day on which it was filed.
§ 385.1106 Other filings (Rule 1106).
(a) Interveners. Responses to the petition must be filed at the time the motion to intervene is filed.
(b) Petitioner. The petitioner may respond to filings of another party within 15 days after service of such filings. Amended pleadings may be filed under Rule 215 (amendments) if the petitioner discovers facts unavailable at the time the initial petition was filed, or if such pleadings are requested or permitted by Staff under Rule 1107 (evaluations).
§ 385.1107 Evaluations (Rule 1107).
(a) Staff will consider the filings made in connection with the petition for adjustment. Staff may also consider information received under paragraph (b) of this section. If Staff obtains information under paragraphs (b)(1) or (b)(3) of this section and relies upon such information, the petitioner will be advised of such information and will be given 15 days to respond to such information.
(b)(1) Staff may initiate an investigation of any statement in a petition and use in its evaluation any relevant fact obtained in such an investigation.
(2) Staff may request additional information from the petitioner.
(3) Staff may solicit and accept submissions from interveners or third persons relevant to the petition.
(4) Staff may consider information obtained in informal conferences held under Rule 1111 (adjustment conferences).
§ 385.1108 Criteria (Rule 1108).
(a) Staff will grant a petition where there are sufficient facts to make a determination on the merits and where Staff determines that an adjustment is necessary to prevent or alleviate:
(1) Special hardship;
(2) Inequity; or
(3) An unfair distribution of burdens.
(b) When there are not sufficient facts to make a determination on the merits, the Staff may dismiss the petition without prejudice; except, that when Staff has requested additional material information under Rule 1107 (adjustment evaluations) of this section and the petitioner has failed to provide the requested information, Staff may deny the petition if the requested information was reasonably available to the petitioner.
§ 385.1109 Orders (Rule 1109).
(a) Staff will issue a decision and an order granting or denying the petition in whole or in part. The order will articulate the basis for the decision, noting any dispute with the factual assertions of the petitioner.
(b) In addition to service otherwise required under this subpart, Staff will serve the decision and order on the persons who sought and were denied an opportunity to participate in the proceeding under this subpart.
(c) If Staff fails to issue an order granting or denying the petition for adjustment within the determination period, the petitioner may treat the application as having been denied and may, within 30 days after the close of the determination period, request review thereof as prescribed in Rule 1110(a) (review of denials). For purposes of this paragraph, “determination period” means the 150 days commencing with the filing of the petition, unless Staff for good cause extends such period.
(d) An order of Staff issued under paragraph (a) of this section granting an adjustment, in whole or in part, is final 30 days after it is issued, unless, during such 30-day period:
(1) A petition for review is filed under subpart J of this subchapter in accordance with Rule 1110(a) (review of denials) in which case the order is final when the review process under subpart J has been completed; or
(2) The Commission directs that the order be reviewed under subpart J in accordance with Rule 1110(b), in which case the order is final when the review process under subpart J has been completed unless the Commission expressly states that the order shall be effective pending review proceeding.
§ 385.1110 Review of initial decision and order for adjustment (Rule 1110).
(a) General rule. (1) Within 30 days after the issuance by Staff of an order granting or denying, in whole or in part, a petition for adjustment relief under this subpart, a person may file a petition for Commission review of that order in accordance with subpart J of this subchapter, if the person:
(i) Is aggrieved or adversely affected by that order; and
(ii) Participated, or sought and was denied an opportunity to participate, in the proceeding under this subpart.
(2) Except as otherwise provided in this paragraph, the provisions of subpart J other than Rule 1013 (attachments to pleadings) shall apply to Commission review of both grants and denials of adjustment petitions under this subpart.
(i) Contested order in subpart J means the order issued by Staff granting or denying, in whole or in part, a petition for adjustment under this subpart.
(ii) “Staff” is substituted for “Secretary” in subpart J. With respect to review of an order denying a petition for adjustment under this subpart, Staff may participate in the proceeding in the same manner prescribed for the Secretary in Rule 1005 (replies in reviews of adjustment denials). With respect to review of an order granting a petition for adjustment under this subpart, Staff may not participate in the proceeding except to the extent necessary to file the list identifying the documents in the record as prescribed in paragraph (a)(2)(iii). With respect to review of an order granting in part and denying in part a petition for adjustment under this subpart, Staff may participate as prescribed in Rule 1005(a)(1) (replies), only if a petition for review has been filed which specifically seeks review of the portion of the order denying the petition for adjustment.
(iii) Within 15 days of service of the petition for review, Staff must file with the Commission a list identifying each document in the record developed in the prior proceedings on the contested order, who filed the document, and the date it was filed.
(3) A motion to intervene under Rule 1005(c) (interventions in adjustment proceedings) may be filed only by a person who sought and was denied an opportunity to participate, in the proceeding under this section. A person who did not file a motion to intervene in the Staff proceeding may file a motion for late intervention under Rule 214(d) (grant of late intervention).
(4) There is no exhaustion of administrative remedies until a request for review is filed under subpart J in accordance with this section and the review process under subpart J is completed by the issuance of an order granting or denying, in whole or in part, the relief requested.
(b) Review initiated by the Commission. Within 30 days after the issuance by Staff of an order granting, in whole or in part, a petition for adjustment relief under this subpart, the Commission may direct that the order be reviewed in a proceeding which, insofar as practicable, will conform to proceedings under subpart J. The order directing such review will specify the manner in which such proceeding will be conducted and the extent to which subpart J apply.
(c) Separation of functions. Any person who participated in the proceeding to review the grant or denial of that adjustment under this Rule as a witness or counsel may not advise the Commission concerning the review of the grant or denial of that adjustment.
§ 385.1111 Conferences (Rule 1111).
Staff may direct that a conference be convened. The conference will be conducted by Staff in accordance with procedures Staff determines will most expeditiously further the purpose of the conference. A conference will be convened only after actual notice of the time, place and nature of the conference is provided to the parties. All parties may attend the conference. However, if a party wishes to present confidential information at the conference, Staff may exclude the other parties from that part of the conference when the confidential information is presented.
§ 385.1112 Requests for confidential treatment (Rule 1112).
(a) If a person filing a document under this subpart claims that some or all of the information contained in a document is exempt from the mandatory disclosure requirements of the Freedom of Information Act, or is otherwise exempt by law from public disclosure, that person may request confidential treatment of such information. At the time request is made for confidential treatment, the person must submit a copy of the document which contains the confidential information and two copies of the document which exclude the information for which confidential treatment is requested. The request for confidential treatment must describe the information deleted and specify the grounds for the claim for confidential treatment. The service requirements of Rule 2010 (service) are deemed satisfied if a copy of the document with the confidential information deleted is served.
(b) If a determination to disclose the information is made under part 388 (public information and requests), the person who has requested confidential treatment will be given notice thereof and will be afforded no less than 10 days to respond to such determination before the information is disclosed.
§ 385.1113 Interim relief (Rule 1113).
(a) The petitioner may at any time file a request for interim relief in a proceeding under this subpart, setting forth the legal and factual basis for the request. Service of such request must comply with the service requirements set forth in Rule 1104(b) (initial petition of adjustment request) and must be made on each person described in such rule as well as on any other party to the proceeding.
(b) The grounds for granting interim relief are:
(1)(i) A showing that irreparable injury will result in the event the interim relief is denied; and
(ii) A showing that denial of the interim relief requested will result in a more immediate special hardship or inequity to the person requesting the interim relief than the consequences that would result to other persons if the interim relief were granted; or
(2) A showing that it will be in the public interest to grant the interim relief.
(c) A party may within 10 days after the filing of the request for interim relief file a reply to the request for interim relief.
(d) Staff may request a written statement of the views of a party regarding whether the interim relief should be granted and may convene an expedited conference on the request for interim relief.
(e) If Staff has not granted the request for interim relief within 30 days after it is filed, the request is denied.
(f)(1) Subject to paragraph (f)(2) of this section, Staff will issue an order granting or denying the request for interim relief and will notify the parties. Any grant of interim relief is subject to further modification in the order issued under Rule 1109 (orders).
(2) The Commission may, on its own motion, at any time revoke, modify, rescind, stay or take any other appropriate action concerning the order granting interim relief.
§ 385.1114 Motions (Rule 1114).
A party may file a motion at any time. Motions must set forth the ruling or relief requested and must state the grounds therefor and the statutory or other authority relied upon. Staff will rule on all motions.
§ 385.1115 Procedural rulings (Rule 1115).
Staff may make any procedural rule or provide any procedural relief.
§ 385.1116 Appeals (Rule 1116).
All actions under this subpart are taken by Staff, except with respect to requests for public information under part 388. Except as provided in Rule 1110 (review of initial adjustment decision) of this section, there are no appeals to the Commission from Staff action taken under this section.
§ 385.1117 Petition for adjustment treated as request for interpretation (Rule 1117).
(a) Staff may, if appropriate, treat a petition filed under Rule 1103 (petition for adjustment) as a request for an interpretation under section 502(c) of the NGPA, or rule or order issued under that Act.
(b) If the Staff exercises its discretion under paragraph (a) of this section to treat a petition for adjustment as a request for an interpretation, then:
(1) Staff will notify the parties to the proceeding that the petition is being treated as a request for an interpretation under Rule 1901; and
(2) The time limits in this section are stayed pending issuance of the interpretation.
(c) After the interpretation is issued, if the petitioner wishes to reinstate the adjustment proceeding, the petitioner may do so by notifying the Commission in writing that the petition should be reinstated.
Subpart L [Reserved]
Subpart M—Cooperative Procedure with State Commissions
§ 385.1301 Policy (Rule 1301).
(a) The Federal Power and Natural Gas Acts, sections 209 and 17, respectively, authorize cooperation between the Federal Energy Regulatory Commission and the State commissions of the several States in the administration of said Acts, which include authorization for:
(1) Reference of any matter arising in the administration of these Acts to a board to be composed of a member or members from a State or States affected, or to be affected, by the particular matters pending before the Commission;
(2) Conferences with State commissions regarding the relationship between rate structures, costs, accounts, charges, practices, classifications, and regulations of public utilities or natural gas companies subject to the jurisdiction of such State commissions and of the Commission; and
(3) Joint hearings with State commissions in connection with any matter with respect to which the Commission is authorized to act.
(b) The matters that should be the subject of a conference referred to a board, or heard at a joint hearing of State commissions and the Commission, obviously, cannot be determined in advance. It is understood, therefore, that the Commission or any State commission will freely suggest cooperation with respect to any proceeding or matter affecting any public utility or natural gas company subject to the jurisdiction of the Commission and of a State commission, and concerning which it is believed that cooperation will be in the public interest.
§ 385.1302 Notice (Rule 1302).
(a) By Commission. (1) Whenever there is instituted before the Commission any proceeding under either the Federal Power Act or the Natural Gas Act, the State commission or commissions of the State or States affected thereby will be given notice thereof immediately by the Commission. As deemed necessary for an understanding of the subject matter, each such notice will be supplemented by copies of applications, complaints, petitions, or orders instituting proceedings. Each such notice given to a State commission will request that the Commission be notified within a reasonable time whether the proceeding is deemed one that should be considered under the cooperative provisions of this subpart, and, if so, to advise the Commission as to the nature of its interest in the matter, and further, to specify whether it desires a conference, the creation of a board, or a joint or concurrent hearing, as defined in this subpart and the reasons for such request.
(2) Any commission suggesting some form of such cooperative procedure should also state whether there is pending, or will be pending before it, a proceeding in which a concurrent hearing might appropriately be held and whether its proposal is for such hearing covering such proceeding and the proceeding pending before the Commission.
(3) A State commission recommending to the Commission reference of a proceeding to a board, under either the Federal Power Act or the Natural Gas Act, should state with fullness the reasons which led it to believe that such reference is desirable and in the public interest.
(4) Upon the receipt from a State commission of a communication suggesting cooperation, the Commission will consider the same, and may confer with the commission making the request and with other interested commissions, if any, in such manner as may be most suitable, and, if cooperation in the manner proposed, or in any other manner, appears to be practicable and desirable, will so advise each interested State commission, and will invite it to participate therein.
(b) By State commission. (1) Each State commission should, in like manner, notify the Commission of any proceeding instituted before it the subject matter of which is also subject to the jurisdiction of the Commission, or in which it believes the Commission is interested. Such notice should be supplemented by copies of applications, petitions, complaints, or orders instituting proceedings which may be necessary to an understanding of the subject matter. Such notice should include the suggestions which the State commission may wish to make concerning cooperative procedure.
(2) Upon receipt of such notice, the Commission will consider the same and will promptly notify the State commission whether or not in its opinion cooperation in the manner proposed, or in any other manner, appears to be practicable and desirable. The Commission is free to propose cooperative procedures whether or not such proposal of cooperation has been made by the State commission first giving notice of the proceeding.
(c) Commission or State commissions to invite participation in cooperative procedure. In the event that cooperation in a particular proceeding has been determined upon, the Commission or a State commission before which the proceeding is pending will so advise each interested State commission and will invite it to take part therein.
§ 385.1303 Conferences (Rule 1303).
Inasmuch as experience has proved that informal conferences are the means most often used to enable commissions to work together to promote good regulation, affording means whereby common understandings may be reached, and the imposition of inconsistent or conflicting regulations upon companies subject to both Federal and State control may be avoided and means whereby State commissions may secure the assistance in State regulatory work which sections 209 and 17, respectively, of the Federal Power and Natural Gas Acts authorize the Commission to extend, any commission, Federal or State, should always feel free to suggest a conference to another commission, concerning any matter of regulation subject to the jurisdiction of either, with respect to which it is believed that a cooperative conference may be in the public interest. The commission desiring a conference upon any such matter should notify other interested commissions without delay, and thereupon the Commission or a State commission, as may be agreed, will promptly arrange for a conference in which all interested commissions will be invited to be represented.
§ 385.1304 Procedure governing matters referred to a board (Rule 1304).
(a) It is believed that the statutory provisions of sections 209 and 17, respectively, of the Federal Power and Natural Gas Acts, for the reference of a proceeding to a board constituted as therein provided, were designed for use in unusual cases, and as a means of relief to the Commission when it might find itself unable to hear and determine cases before it, in the usual course, without undue delay.
(b) Whenever the Commission, either upon its own motion or upon the suggestion of a State commission or at the request of any interested party, determines that it is desirable to refer a matter arising in the administration either of the Natural Gas Act or Part II of the Federal Power Act, to a board to be composed of a member or members from the State or States affected or to be affected by such matter, the procedure will be as follows: The Commission will send a request to each interested State commission to nominate a specified number of members to serve on such board. Whenever more than one State is involved, the representation of each State concerned shall be equal, unless one or more of the States affected chooses to waive such right of equal representation. The Commission will specify the functions to be performed by such board in each instance. When the member or members of any board have been nominated and appointed in accordance with the provisions of either section 209 of the Federal Power Act or section 17 of the Natural Gas Act, the Commission will issue an order referring the particular matter to such board, and such order will fix the time and place of hearing, define the “force and effect” which an action of the board will have, the manner in which the proceedings will be conducted, and specify the allowances to be made for the expense of the members of the board. As far as applicable, the rules of practice and procedure as from time to time adopted or prescribed by the Commission will govern such board. The board will have authority to adjourn the hearing from day to day, subpoena witnesses, rule on the relevancy, competency, and materiality of evidence, and will, after hearing all interested parties, submit its report to the Commission.
§ 385.1305 Joint and concurrent hearings (Rule 1305).
(a) The term “joint hearing” used in sections 209 and 17, respectively, of the Federal Power and Natural Gas Acts is understood to cover any hearing in which members of the Commission and members of one or more State commissions may sit together in a proceeding pending before one such commission, whether or not a proceeding or proceedings involving similar or corresponding issues be pending before any other commission.
(b) Two different types of proceedings have been called “joint hearings”. One is that type of proceeding where members of one or more State commissions sit with members of the Commission for information or in an advisory capacity. The State commissioners in such case do not develop a record for their respective commissions and may not, at their own discretion, make a recommendation to the Commission. The other type of joint hearing is often referred to as a “concurrent hearing”. Under this procedure the Commission and one or more State commissions sit together to hear and jointly make a record upon a matter over which all of the participating commissions have jurisdiction and responsibility for action.
(c) The Commission or any State commission or commissions should feel free to suggest or request a joint or concurrent hearing at any time. It is believed that the concurrent hearing is the type of cooperative hearing which is likely to be most useful and effective.
(d) Whenever a concurrent hearing has been agreed upon by the Commission and one or more State commissions, the procedure will be:
(1) Each commission will designate the representative or representatives of such commission to sit at such concurrent hearing, and will designate the representative who will be the presiding officer for such commission.
(2) It will be understood that participation in such concurrent hearing will in no way affect the complete control by each commission of the proceeding before it. It will be understood, also, that participation in either a joint or concurrent hearing will in no way preclude any commission from causing to be presented in any such case pertinent evidence with respect to matters in issue.
(3) The representative designated by the Commission will be the presiding officer to announce rulings with respect to which there is no disagreement; and such rulings will be considered concurrent rulings. However, the presiding officer for any commission which does not concur in any ruling may announce a divergent ruling and such divergent ruling, whether with respect to the admissibility of evidence or any other matter, will be considered the ruling for his or her commission.
(4) The record of the concurrent hearing will be the record of each commission participating, except that, if divergent rulings are made, the rulings will be reported so as to separate and distinguish clearly the record of the respective participating commissions and the evidence admitted in each record, in accordance with the rulings of the respective commissions. If, in any proceeding, the ruling of one presiding officer has the effect of admitting any voluminous exhibit or testimony which is excluded by the ruling of another presiding officer, the taking of such evidence, whenever possible, will be deferred until after the completion of the proceedings which can be conducted under concurrent rulings. When such testimony is taken, the transcript of such evidence will be made available to the participating commissions, if desired.
(5) In all respects concerning which there is no divergence of ruling, the hearing will be conducted in accordance with the rules of practice and procedure prescribed by the Commission, subject to the express understanding that each participating State commission will control its own record and make its own rulings as to the admissibility of evidence and as to other matters affecting its proceedings, and will make its own separate final decision or order therein.
(e) Before either the Commission or a participating State commission will enter any order or orders in a concurrent proceeding, opportunity will be afforded for conference between the Commission and the State commissions participating.
(f) Whenever a joint hearing other than a concurrent hearing is agreed upon, the commissioners which take part therein will agree upon the procedure to be followed in such hearing in advance of the opening of the same. With respect to any concurrent hearing, a special agreement may be made by the commissions taking part therein for a procedure or action differing from that outlined in this plan.
(g) Cooperation between two or more commissions in a concurrent hearing will preclude either from taking the position of an advocate or a litigant. If a commission wishes to take such a position, it will not be a cooperating participant in that proceeding. In such situation the appropriate method of procedure will be intervention under Rule 214.
§ 385.1306 Intervention by State commissions (Rule 1306).
Any interested State commission may intervene in any proceeding before the Federal Energy Regulatory Commission, as provided in Rule 214.
Subpart N—Oil Pipeline Proceedings
§ 385.1401 Applicability (Rule 1401).
(a) This subpart applies to oil pipeline proceedings.
(b) If any provision of this subpart is inconsistent with any provision of another subpart of this part, the provision of this subpart governs and the provision of the other subpart is inapplicable to the extent of the inconsistency.
§ 385.1402 Subscriber lists (Rule 1402).
(a) Not later than December 31 of each year, an oil pipeline must request, in writing, each of its subscribers and each person who has been served under any of its tariffs during the preceding twelve months to notify the pipeline as to whether the subscriber or person wishes to be included on the subscriber list for any of the oil pipeline’s integrated pipeline systems.
(b) The oil pipeline must immediately add to the specified subscriber list any subscriber or person which responds in writing within 30 days of receipt of the oil pipeline request and which indicates in that response that it wishes to be included on the specified list.
§ 385.1403 Petitions seeking institution of rulemaking proceedings (Rule 1404).
Any person may file a petition requesting the Commission to institute a proceeding for the purpose of issuing statements, rules, or regulations of general applicability and significance designed to implement or interpret law, or to formulate general policy for future effect. No reply to such a petition may be filed. Whether a proceeding shall be instituted as requested is within the discretion of the Commission and the ruling on the petition will be final. In the event a rulemaking proceeding is instituted by the Commission, the procedure to be employed for the taking of evidence or the receipt of views and comments will be designated by Commission order.
Subpart O—Procedures for the Assessment of Civil Penalties Under Section 31 of the Federal Power Act
§ 385.1501 Scope (Rule 1501).
The rules in this subpart apply to and govern proceedings for the assessment of civil penalties pursuant to section 31 of the Federal Power Act, 16 U.S.C. 823b.
§ 385.1502 Persons subject to civil penalties (Rule 1502).
(a) Any licensee or permittee under the Federal Power Act, or exemptee from any requirement of Part I of the Federal Power Act, may be subject to civil penalties; and
(b) Any person who must have a license under, or exemption from, the Federal Power Act, but does not, may be subject to civil penalties.
§ 385.1503 Actions subjecting persons to civil penalties (Rule 1503).
(a) The actions that subject persons to civil penalties are violations of:
(1) Any rule or regulation issued under Part I of the Federal Power Act;
(2) Any term or condition of a license or permit issued under Part I of the Federal Power Act or an exemption issued from any provision of Part I of the Federal Power Act;
(3) Any compliance order issued under section 31(a) of the Federal Power Act; or
(4) Any requirement of Part I of the Federal Power Act.
(b) Only actions occurring on or after October 16, 1986, may subject a person to civil penalties.
§ 385.1504 Maximum civil penalty (Rule 1504).
(a) Except as provided in paragraph (b) of this section, the Commission may assess a civil penalty of up to $27,893 for each day that the violation continues.
(b) No civil penalty may be assessed where a license or exemption is ordered revoked.
§ 385.1505 Determination of proposed penalty amount (Rule 1505).
(a) In determining the amount of a proposed penalty, the Commission will consider the nature and seriousness of the violation, and the efforts of the licensee, exemptee, permittee or one who should possess appropriate authority but does not, to remedy the violation in a timely manner.
(b) In making its determination under paragraph (a), the Commission will consider the following factors:
(1) Whether the person had actual knowledge of the violation;
(2) Whether the person had constructive knowledge of the violation deemed to be possessed by a reasonable individual acting under similar circumstances;
(3) Whether the person has a history of previous violations;
(4) Whether the violation caused loss of life or injury to persons;
(5) Whether economic benefits were derived because of the violation;
(6) Whether the violation caused damage to property or the environment;
(7) Whether the violation endangered persons, property or the environment;
(8) Whether there were timely remedial efforts;
(9) Whether there were untimely remedial efforts;
(10) Whether there were no remedial efforts; and
(11) Whether there are any other pertinent considerations.
§ 385.1506 Notice of proposed penalty (Rule 1506).
(a) Before issuing an order assessing a civil penalty under this subpart against any person, the Commission will provide to the person notice of the proposed penalty.
(b) The notice of proposed penalty will:
(1) Include the amount of the proposed penalty;
(2) Include a statement of the material facts constituting the alleged violation; and
(3)(i) Inform the person of the opportunity to elect in writing within 30 days of receipt of the notice to have the procedures of Rule 1509 (in lieu of those of Rule 1508) apply with respect to the assessment, or,
(ii) If a final compliance order is issued under section 31(a) of the Federal Power Act, no notice of election will be provided for a violation of, or a failure or refusal to comply with, the final order.
§ 385.1507 Election of procedures and answer (Rule 1507).
(a) If the respondent receiving the notice of proposed penalty wishes to have the procedures of Rule 1509 apply, then the respondent must file with the Commission, within 30 days of receipt of the notice, a notification of the election in accordance with subpart T, part 385 of this chapter. The notification may include an answer setting forth factual or legal reasons why the proposed assessment order should not be issued, should be reduced in amount, or should otherwise be modified. If a person fails to file an answer within the 30-day time limit, all material facts stated in the Commission’s notice will be deemed admitted.
(b) Any election to have the procedures of Rule 1509 apply may not be revoked after the 30-day election period in paragraph (a) of this section, without the consent of the Commission.
§ 385.1508 Commission administrative procedures (Rule 1508).
(a) If the respondent is not entitled to an election pursuant to Rule 1506(b)(3)(ii) or does not timely elect to have the procedures of Rule 1509 apply, the Commission will commence a proceeding in accordance with the provisions of subpart E of this chapter.
(b) The Commission’s Rules of Practice and Procedure in part 385 of this chapter will apply, as appropriate, to any evidentiary proceeding to assess a civil penalty.
(c) An assessment order under this section shall include the administrative law judge’s findings and the basis for such assessment.
§ 385.1509 District court procedures (Rule 1509).
(a) After receipt of the notification of election to apply the provisions of this section pursuant to Rule 1507, the Commission will promptly assess the penalty it deems appropriate, in accordance with Rule 1505.
(b) If the civil penalty is not paid within 60 calendar days after the assessment order is issued under paragraph (a) of this section, the General Counsel, unless otherwise directed by the Commission, will institute an action in the appropriate United States District Court for an order affirming the assessment of the civil penalty.
§ 385.1510 Modification of civil penalty (Rule 1510).
(a) The Commission may compromise, modify, or remit, with or without conditions, any civil penalty (with leave of court if necessary).
(b) In exercising its authority under paragraph (a) of this section, the Commission may consider the nature and seriousness of the violation, and the efforts of the licensee, exemptee, permittee, or one who should possess appropriate authority but does not, to remedy the violation in a timely manner.
(c) The Commission’s authority to compromise, modify or remit a civil penalty may be exercised at any time prior to a final decision by the United States Court of Appeals if Rule 1508 procedures are utilized, or prior to a final decision by the United States District Court if Rule 1509 procedures are utilized.
§ 385.1511 Collection of civil penalties (Rule 1511).
If any person fails to pay a civil penalty assessment, the Commission will seek to recover the amount of the penalty plus interest in any appropriate District Court of the United States. Interest will begin to accrue on the date the Commission issues a final order under Rule 1508 or the date on which the appropriate District Court enters final judgment in favor of the Commission under Rule 1509.
Subpart P—Civil Monetary Penalty Inflation Adjustment
§ 385.1601 Scope and purpose (Rule 1601).
The purpose of this subpart is to make inflation adjustments to the civil monetary penalties provided by law within the jurisdiction of the Commission. These penalties shall be subject to review and adjustment as necessary at least every year in accordance with the Federal Civil Penalties Inflation Act of 1990, as amended by the Federal Civil Penalties Inflation Adjustment Act Improvements Act of 2015.
§ 385.1602 Civil penalties, as adjusted (Rule 1602).
The current inflation-adjusted civil monetary penalties provided by law within the jurisdiction of the Commission are:
(a) 15 U.S.C. 3414(b)(6)(A)(i), Natural Gas Policy Act of 1978: $1,544,521 per violation, per day.
(b) 16 U.S.C. 823b(c), Federal Power Act: $27,893 per violation, per day.
(c) 16 U.S.C. 825n(a), Federal Power Act: $3,643 per violation.
(d) 16 U.S.C. 825o–1(b), Federal Power Act: $1,544,521 per violation, per day.
(e) 15 U.S.C. 717t–1, Natural Gas Act: $1,544,521 per violation, per day.
(f) 49 App. U.S.C. 6(10) (1988), Interstate Commerce Act: $1,617 per offense and $78 per day after the first day.
(g) 49 App. U.S.C. 16(8) (1988), Interstate Commerce Act: $16,170 per violation, per day.
(h) 49 App. U.S.C. 19a(k) (1988), Interstate Commerce Act: $1,617 per offense, per day.
(i) 49 App. U.S.C. 20(7)(a) (1988), Interstate Commerce Act: $1,617 per offense, per day.
Subparts Q–R [Reserved]
Subpart S—Miscellaneous
§ 385.1901 Interpretations and interpretative rules under the NGPA (Rule 1901).
(a) Purpose and applicability—(1) Purpose. The purpose of this section is to provide procedures by which:
(i) A person may seek a written interpretation from the General Counsel construing a provision of the NGPA, or clarifying a rule issued by the Commission under the NGPA; and
(ii) The Commission may publish an interpretative rule that will have general applicability and effect.
(2) Applicability. (i) This section applies to requests under section 502(c) of the NGPA for interpretations of the NGPA or of rules or of orders, having the applicability and effect of a rule as defined in 5 U.S.C. 551(4), issued under the NGPA. It does not apply to orders issued under sections 301, 302, and 303 of the NGPA.
(ii) This section applies to requests for interpretations to prospective, existing or completed facts, acts, or transactions. Interpretations based on hypothetical facts, acts, or transactions will not be considered.
(b) Definitions. For the purpose of this section, the following definitions apply.
(1) Direct participant means any person or legal entity who is, or plans to be an actual party in the act, transaction, or circumstance presented, and who has an immediate or direct financial interest in the act, transaction, or circumstance.
(2) Interpretation means a written statement of the General Counsel which applies a particular rule to a particular set of facts, acts, circumstances or transactions. In the discretion of General Counsel, the interpretation may contain a detailed factual and legal analysis, a summary of the facts or the law, or both, or it may be a conclusory statement.
(3) Interpretative rule means an official interpretative statement of general applicability issued by the Commission and published in the
(4) NGPA means the Natural Gas Policy Act of 1978.
(5) Request means a request for an interpretation.
(6) Rule means a rule or an order having the effect of a rule as defined in 5 U.S.C. 551(4).
(c) Persons who may request an interpretation. (1) Any person who is or will be a direct participant in an act, transaction, or circumstance affected by the NGPA or a rule issued by the Commission under the NGPA may file with the Office of the General Counsel a request for an interpretation.
(2) Requests for interpretations must be addressed to the Office of the General Counsel as follows:
(3) Requests for interpretation under this paragraph need not be filed with the Secretary.
(d) Content of request—(1) Facts. A request for interpretation must contain a full and complete statement of the relevant and material facts pertaining to the act, transaction, or circumstance that is the subject of the request for interpretation. When the request pertains to only one step of a larger integrated transaction, the facts, circumstances, and other relevant information pertaining to the entire transaction must be included in the request.
(2) Statement of the question. The request must clearly designate the section of the statute, regulation, rule, or part thereof which the person making the request seeks to have interpreted and must set forth clearly and concisely the question for which an interpretation is sought. The request may also set forth a proposed answer to the question.
(3) Analysis. If the request proposes a particular answer:
(i) The request must set forth a legal analysis in support of the proposed answer and cite relevant authorities in support thereof.
(ii) The request must set forth the legal and business consequences which will flow from the proposed answer.
(4) Factual statements. (i) The request must be accompanied by a statement that to the best of the applicant’s personal information, knowledge, and belief there is no untrue statement of a material or relevant fact and there is no omission of a material or relevant fact made in the request.
(ii) Any untrue statement or omission of a material or relevant fact upon which the Office of the General Counsel relied in a request for an interpretation is deemed to be a statement or entry under section 1001 of Title 18, United States Code.
(5) Notification of other parties. (i) A person submitting a request must specify each person who is a direct participant in the circumstance, act or transaction; must notify them in writing of the request for an interpretation; and must send them a copy of such request. Such notification and the addresses of the persons notified must be included in a request to the General Counsel.
(ii) Each person notified pursuant to paragraph (d)(5)(i) of this section may submit information regarding any fact provided in the request of which it has personal knowledge, if such fact is different from the facts presented by the applicant. Such fact must be presented to the Office of the General Counsel as set forth in paragraph (d)(4) of this section.
(6) The request must be accompanied by the fee prescribed in § 381.405 of this chapter or by a petition for waiver pursuant to § 381.106 of this chapter.
(e) Additional information. The General Counsel may request additional information, documentation or legal analysis in connection with any request for any interpretation.
(f) Referral of information. Information submitted in a request for interpretation may be used by the Commission or its Staff in their official capacity. Any information received will be placed in a public file in the Commission’s Office of Public Information.
(g) The interpretation. (1) Except as provided in paragraph (g)(2) of this section, the General Counsel will provide a copy of his or her written interpretation of the NGPA or rule as applied to the act, transaction, or circumstance presented upon the person who made the request for the interpretation and upon persons named in the request as direct participants in the act, transaction, or circumstance.
(2) The General Counsel may determine not to issue an interpretation, in which case the person who made the request and direct participants as specified in the request will be notified in writing of the decision not to issue an interpretation, and the reason for the decision.
(3) Only those persons to whom an interpretation is specifically addressed and other persons who are named in the request, who have been informed by the applicant for an interpretation of the pendency of the request and who are direct participants in the act, transaction or circumstance presented, may rely upon it. The effectiveness of an interpretation depends entirely on the accuracy of the facts presented to the General Counsel. If a material or relevant fact has been misrepresented or omitted or if any material or relevant fact changes after an interpretation is issued or if the action taken differs from the facts presented in the request, the interpretation may not be relied upon by any person.
(4) An interpretation may be rescinded or modified prospectively at any time. A rescission or modification is effected by notifying persons entitled to rely on the interpretation at the address contained in the original request.
(5) Any interpretation based on the NGPA or a rule issued thereunder in effect at the time of issuance may be relied upon only to the extent such law or rule remains in effect.
(6) Except as provided in paragraphs (g)(3), (g)(4) and (g)(5) of this section, the Staff will not recommend any action to the Commission which is inconsistent with the position espoused in the interpretation. The interpretation of the General Counsel is not the interpretation of the Commission. An interpretation provided by the General Counsel is given without prejudice to the Commission’s authority to consider the same or like question and to issue a declaratory order to take other action which has the effect of rescinding, revoking, or modifying the interpretation of the General Counsel.
(h) Appeal. There is no appeal to the Commission of an interpretation.
(i) Interpretative rules. Upon the petition of any person or upon its own motion, the Commission may publish in the
(j) Applications for adjustments treated as requests for interpretations. Except for the notification provisions of paragraph (d)(5) of this section, the provisions of this section apply to any petition for an adjustment which is deemed a request for an interpretation under Rule 1117. Notice to all parties to an adjustment proceeding under subpart K of this part that is deemed to be a request for an interpretation will be given under Rule 1117(d)(1).
§ 385.1902 Appeals from action of staff (Rule 1902).
(a) Any staff action (other than a decision or ruling of presiding officer, as defined in Rule 102(e)(1), made in a proceeding set for hearing under subpart E of this part) taken pursuant to authority delegated to the staff by the Commission is a final agency action that is subject to a request for rehearing under Rule 713 (request for rehearing).
(b) All appeals of staff action that were timely filed prior to December 3, 1990 and that had not been acted upon by the Commission on their substantive merits are deemed to be timely filed requests for rehearing of final agency action. All notices issued by the Commission prior to December 3, 1990 stating the Commission’s intent to act on appeals of staff action such that they are not deemed denied by the expiration of a 30-day period after the filing of the appeal, are deemed to be orders granting rehearing of final agency action for the sole purpose of further consideration, unless the Commission issued an order on the substantive merits of the appeal prior to December 3, 1990. No later than January 2, 1991, persons who had timely filed appeals of staff action prior to December 3, 1990 which were pending before the Commission on that date may file additional pleadings to update or supplement those appeals.
§ 385.1903 Notice in rulemaking proceedings (Rule 1903).
Before the adoption of rule of general applicability or the commencement of hearing on such a proposed rulemaking, the Commission will cause general notice to be given by publication in the
(a) When the Commission, for good cause, finds it impracticable, unnecessary, or contrary to the public interest to give such notice, it may proceed with the adoption of rules without notice by incorporating therein a finding to such effect and a concise statement of the reasons therefor;
(b) Except when notice or hearing is required by statute, the Commission may issue at any time rules of organization, procedure or practice, or interpretative rules, or statements of policy, without notice or public proceedings; and
(c) This section is not to be construed as applicable to the extent that there may be involved any military, naval, or foreign affairs function of the United States, or any matter relating to the Commission’s management or personnel, or to United States property, loans, grants, benefits, or contracts.
§ 385.1904 Copies of transcripts (Rule 1904).
The Commission will cause to be made a stenographic record of public hearings and such copies of the transcript thereof as it requires for its own purposes. Participants desiring copies of such transcript may obtain the same from the official reporter upon payment of the fees fixed therefor.
§ 385.1907 Reports of compliance (Rule 1907).
When any licensee, permittee, or any other person subject to the jurisdiction of the Commission is required to do or perform any act by Commission order, permit, or license provision, there must be filed with the Commission within 30 days following the date when such requirement became effective, a notice, under oath, stating that such requirement has been met or complied with; Provided, however, That the Commission, by rule or order, or by making specific provision therefor in a license or permit, may provide otherwise for the giving of such notice of compliance. Five conformed copies of such notice must be filed in lieu of the fourteen conformed copies required by Rule 2004 (copies of filings).
Subpart T—Formal Requirements for Filings in Proceedings Before the Commission
§ 385.2001 Filings and Other Submissions.
(a) Filings with the Commission. (1) Except as otherwise provided in this chapter, any document required to be filed with the Commission must comply with Rules 2001 to 2005 and must be submitted to the Secretary by:
(i) Mailing the document through the United States Postal Service to the Secretary, Federal Energy Regulatory Commission, 888 First Street NE, Washington, DC 20426;
(ii) Delivering the document by any source other than United States Postal Service to the Federal Energy Regulatory Commission, 12225 Wilkins Avenue, Rockville, Maryland 20852; or
(iii) By filing via the Internet pursuant to Rule 2003 through the links provided at http://www.ferc.gov.
Assistance for filing via the Internet is available by calling (202) 502–6652 or 1–866–208–3676 (toll free), or by e-mail to [email protected].
(2) Any document is considered filed, if in paper form, on the date stamped by the Secretary or, in the case of a document filed via the Internet, on the date indicated in the acknowledgment that will be sent immediately upon the Commission’s receipt of a submission, unless the document is subsequently rejected. Any document received after regular business hours is considered filed on the next regular business day.
(b) Rejection. (1) If any filing does not comply with any applicable statute, rule, or order, the filing may be rejected, unless the filing is accompanied by a motion requesting a waiver of the applicable requirement of a rule or order and the motion is granted.
(2) If any filing is rejected, the document is deemed not to have been filed with the Commission.
(3) Where a document is rejected under paragraph (b)(1) of this section, the Secretary, or the office director to whom the filing has been referred, will notify the submitter and indicate the deficiencies in the filing and the reason for the rejection.
(4) If a filing does not comply with any applicable requirement, all or part of the filing may be stricken. Any failure to reject a filing which is not in compliance with an applicable statute, rule, or order does not waive any obligation to comply with the requirements of this chapter.
§ 385.2002 Caption of filings (Rule 2002).
A filing must begin with a caption that sets forth:
(a) The docket designation, if any;
(b) The words “INTERLOCUTORY APPEAL” underneath the docket designation if the filing is an appeal under Rule 715(c) of a presiding officer’s denial of a motion for an interlocutory appeal;
(c) The title of the proceeding if a proceeding has been initiated;
(d) A heading which describes the filing; and
(e) The name of the participant for whom the filing is made, or a shortened designation for the participant.
§ 385.2003 Specifications (Rule 2003).
(a) All filings. Any filing with the Commission must be:
(1) Typewritten, printed, reproduced, or prepared using a computer or other word or data processing equipment;
(2) Have double-spaced lines with left margins not less than 1
(3) Have indented and single-spaced any quotation that exceeds 50 words; and
(4) Use not less than 10 point font.
(b) Filing by paper. (1) Any filing with the Commission made in paper form must be:
(i) Printed or reproduced, with each copy clearly legible;
(ii) On letter-size unglazed paper that is 8 to 8
(iii) Bound or stapled at the left side only, if the filing exceeds one page.
(2) Any log, graph, map, drawing, or chart submitted as part of a filing will be accepted on paper larger than provided in paragraph (b)(1) of this section, if it cannot be provided legibly on letter-size paper.
(c) Filing via the Internet. (1) All documents filed under this Chapter may be filed via the Internet except those listed by the Secretary. Except as otherwise specifically provided in this Chapter, filing via the Internet is in lieu of other methods of filing. Internet filings must be made in accordance with instructions issued by the Secretary and made available online at http://www.ferc.gov. Provisions of this chapter or directions from the Commission containing requirements as to the content and format of specific types of filings remain applicable.
(2) The Secretary will make available on the Commission’s Web site a list of document types that may not be filed via the Internet, as well as instructions pertaining to allowable electronic file and document formats, the filing of complex documents, whether paper copies are required, and procedural guidelines.
(3) For purposes of statutes or regulations governing timeliness, a document filed via the Internet will be deemed to have been received by the Commission at the time the last byte of the document is received by the Commission.
(d) Citation form. Any filing with the Commission should comply with the rules of citation, except Rule 1.1, set forth in the most current edition of A Uniform System of Citation, published by The Harvard Law Review Association. Citations to specific pages of documents filed via the Internet should use the page numbers appearing in the PDF (Portable Document Format) version of the document available on the Commission’s web site.
§ 385.2004 Originals and copies of filings (Rule 2004).
The requirements for making filings under this chapter are posted on the Commission’s Web site at http://www.ferc.gov. The requirements cover documents and forms submitted on paper, on electronic media, or via the Commission’s electronic filing systems.
§ 385.2005 Subscription and verification (Rule 2005).
(a) Subscription. (1) Any filing with the Commission must be signed.
(2) The signature on a filing constitutes a certificate that:
(i) The signer has read the filing signed and knows its contents;
(ii) The contents are true as stated, to the best knowledge and belief of the signer; and
(iii) The signer possesses full power and authority to sign the filing.
(3) A filing must be signed by:
(i) The person on behalf of whom the filing is made;
(ii) Any officer of the corporation, trust, association, or other organized group, on behalf of which the filing is made;
(iii) Any officer, agent, or employee of the governmental authority, agency, or instrumentality on behalf of which the filing is made; or
(iv) A representative qualified to practice before the Commission under Rule 2101 who possesses authority to sign.
(4) The signer of any filing may be required to submit evidence of authority to sign the filing.
(b) Verification. (1) The facts alleged in any filing need not be verified, unless verification is required by statute, rule, or order.
(2) If verification of any filing is required, the verification must be under oath by a person having knowledge of the matters set forth in the filing. If any verification is made by a person other than the signer, a statement must be attached to the verification explaining why a person other than the signer provides verification.
(3) Any requirement that a filing include or be supported by a sworn declaration, verification, certificate, statement, oath, or affidavit may be satisfied by compliance with the provisions of 28 U.S.C. 1746, provided that the filer, or an authorized representative of the filer, maintains a copy of the document bearing an original, physical signature until after such time as all administrative and judicial proceedings in the relevant matter are closed and all deadlines for further administrative or judicial review have passed.
(c) Electronic signature. In the case of any document filed in electronic form under the provisions of this Chapter, the typed characters representing the name of a person shall be sufficient to show that such person has signed the document for purposes of this section.
§ 385.2006 Docket system (Rule 2006).
(a) The Secretary will maintain a system for docketing proceedings.
(b) Any public information in any docket is available for inspection and copying by the public during the office hours of the Commission, to the extent that such availability is consistent with the proper discharge of the Commission’s duties and in conformity with part 388 of this chapter.
§ 385.2007 Time (Rule 2007).
(a) Computation. (1) Except as otherwise required by law, any period of time prescribed or allowed by statute or Commission rule or order is computed to exclude the day of the act or event from which the time period begins to run.
(2) The last day of any time period is included in the time period, unless it is a Saturday; Sunday; a day on which the Commission closes due to adverse conditions and does not reopen prior to its official close of business, even though some official duties may continue through telework-ready employees; part-day holiday that affects the Commission; or legal public holiday as designated in section 6103 of title 5, U.S. Code. In each case the period does not end until the close of the Commission business of the next day which is not a Saturday; Sunday; a day on which the Commission closes due to adverse conditions and does not reopen prior to its official close of business even though some official duties may continue through telework-ready employees; part-day holiday that affects the Commission; or legal public holiday.
(b) Date of issuance of Commission rules or orders. (1) Any Commission rule or order is deemed issued when the Secretary does the earliest of the following:
(i) Posts a full-text copy in the Division of Public Information;
(ii) Mails or delivers copies of the order to the parties; or
(iii) Makes such copies public.
(2) Any date of issuance specified in a rule or order need not be the date on which the rule or order is adopted by the Commission.
(c) Effective date of Commission rules or orders. (1) Unless otherwise ordered by the Commission, rules or orders are effective on the date of issuance.
(2) Any initial or revised initial decision issued by a presiding officer is effective when the initial or revised initial decision is final under Rule 708(d).
§ 385.2008 Extensions of time (Rule 2008).
(a) Except as otherwise provided by law, the time by which any person is required or allowed to act under any statute, rule, or order may be extended by the decisional authority for good cause, upon a motion made before the expiration of the period prescribed or previously extended.
(b) If any motion for extension of time is made after the expiration of a specified time period, the decisional authority may permit performance of the act required or allowed, if the movant shows extraordinary circumstances sufficient to justify the failure to act in a timely manner.
§ 385.2009 Notice (Rule 2009).
Unless actual notice is given or unless newspaper notice is given as required by law, notice by the Commission is provided by the Secretary only by publication in the
§ 385.2010 Service (Rule 2010).
(a) By participants. (1) Any participant filing a document in a proceeding must serve a copy of the document on:
(i) Each person whose name is on the official service list, or applicable restricted service list, for the proceeding or phase of the proceeding; and
(ii) Any other person required to be served under Commission rule or order or under law.
(2) If any person receives a rejection letter or deficiency letter from the Commission, the person must serve a copy of the letter on any person previously served copies of the rejected or deficient filing.
(b) By the Secretary. The Secretary will serve, as appropriate:
(1) A copy of any complaint on any person against whom the complaint is directed;
(2) A copy of any notice of tariff or rate examination or order to show cause, on any person to whom the notice or order is issued;
(3) A copy of any rule or any order by a decisional authority in a proceeding on any person included on the official service list, or applicable restricted service list, for the proceeding or phase of the proceeding, provided that such person has complied with paragraph (g) of this section.
(c) Official service list. (1) The official service list for any proceeding will contain:
(i) The name, address and, for proceedings commenced on or after March 21, 2005, e-mail address of any person designated for service in the initial pleading, other than a protest, or in the tariff or rate filing which is filed by any participant; and
(ii) The name of counsel for the staff of the Commission.
(2) Any designation of a person for service may be changed by following the instructions for the Commission’s electronic registration system, located on its Web site at http://www.ferc.gov or, in the event that the proceeding was commenced prior to March 21, 2005, or the person designated for service is unable to use the electronic registration system, by filing a notice with the Commission and serving the notice on each person whose name is included on the official service list.
(d) Restricted service list. (1) For purposes of eliminating unnecessary expense or improving administrative efficiency, the Secretary, an office director, or the presiding officer may establish, by order, a restricted service list for an entire proceeding, a phase of a proceeding, one or more issues in a proceeding, or one or more cases in a consolidated proceeding.
(2) Any restricted service list will contain the names of each person on the official service list, or the person’s representative, who, in the judgment of the decisional authority establishing the list, is an active participant with respect to the proceeding or consolidated proceeding, any phase of the proceeding, or any issue in the proceeding, for which the list is established.
(3) Any restricted service list is maintained in the same manner as, and in addition to, the official service list under paragraph (c) of this section.
(4) Before any restricted service list is established, each person included on the official service list will be given notice of any proposal to establish a restricted service list and an opportunity to show why that person should also be included on the restricted service list or why a restricted service list should not be established.
(5) Any designation of a person for service on a restricted service list may be changed by filing written notice with the Commission and serving that notice on each person whose name is on the applicable restricted service list.
(e) Intervenors. If a motion to intervene or any notice of intervention is filed, the name, address and, for proceedings commenced on or after March 21, 2005, e-mail address of any person designated for service in the motion or notice are placed on the official service list or any applicable restricted service list, provided that such person has complied with paragraph (g) of this section. Any person placed on the official service list under this paragraph is entitled to service in accordance with this section. If a motion to intervene is denied, the name, address and e-mail address of each person designated for service pursuant to that motion will be removed from the official service list.
(f) Methods of service. (1) Except as provided in paragraph (g) of this section, service of any document in proceedings commenced prior to March 21, 2005, must be made by:
(i) Electronic means where the sender and recipient agree to such means;
(ii) United States mail, first class or better; or
(iii) Delivery in a manner that, and to a place where, the person on whom service is required may reasonably be expected to obtain actual and timely receipt.
(2) Except as provided in paragraph (g) of this section, service of any document in proceedings commenced on or after March 21, 2005, must be made by electronic means unless the sender and recipient agree otherwise or the recipient’s e-mail address is unavailable from the official service list, except in the case of a recipient who has secured a waiver under the provisions of § 390.3 of this chapter, or is exempt under the provisions of § 390.4 of this chapter, or in the case of a protected or confidential document the security of which might be jeopardized by electronic service, in which case service upon that recipient or of that document only shall be made by:
(i) United States mail, first class or better; or
(ii) Delivery in a manner that, and to a place where, the person on whom service is required may reasonably be expected to obtain actual and timely receipt.
(3) Service of a document by electronic means shall be made by the transmission of a link to that document in the Commission’s eLibrary system or by alternate means reasonably calculated to make the document available to required recipients. Alternate means may include but are not limited to, attachment of an electronic copy of the document to an e-mail or transmission of a link to an Internet site containing the document. It is the sender’s responsibility to take reasonable steps to ensure that the means employed for service will be within the technological capabilities of the recipients.
(g) Methods of Service by the Secretary. Service by the Secretary shall be made by electronic means, unless such means are impractical, in which case service shall be made by United States mail.
(h) Electronic registration. In the case of proceedings commenced on or after March 21, 2005, any person, to be included on a service list, must have complied with the procedures for electronic registration made available on the Commission’s Web site, at http://www.ferc.gov, unless such person has secured a waiver under the provisions of § 390.3 of this Chapter, or is exempt under the provisions of § 390.4 of this Chapter.
(i) Timing of service. (1) Service is made under this section when the document served is deposited in the mail or is delivered in another manner.
(2) Service of any document must be made not later than the date of the filing of the document.
(3) In the case of a document served through a link to the Commission’s eLibrary system, as specified in paragraph (f)(2) of this section, if a link to the document does not become available in eLibrary within two business days after the document is filed, the person responsible for serving the document must immediately serve the document by other means, as specified in paragraph (f)(1) or (f)(2) of this section.
(j) Certification. (1) At the time any document required to be served is filed with the Commission, the original of a certificate of service must be attached to the document and a copy of the certificate must be attached to each copy of the document filed with the Commission.
(2) The certificate of service must conform to the following format:
I hereby certify that I have this day served the foregoing document upon each person designated on the official service list [or the restricted service list, if applicable] compiled by the Secretary in this proceeding.
(k) Designation of corporate officials to receive service. (1) Any entity subject to regulation by the Commission must designate at least one, but not more than two, corporate officials or other persons to receive service of complaints, petitions for declaratory order, show cause orders, data requests, investigatory letters or other documents where a person to receive service has not otherwise been designated under Commission regulations. Each entity must file with the Secretary of the Commission:
(i) The name of the corporate official or person that is to receive service;
(ii) The title of the corporate official or person, if applicable;
(iii) The address of the corporate official or person, including, where applicable, department, room number, or mail routing code;
(iv) The telephone number of the corporate official or person;
(v) The facsimile number of the corporate official or person, if applicable; and
(vi) The electronic mail address of the corporate official or person, if applicable.
(2) Each regulated entity has a continuing obligation to file with the Secretary of the Commission updated information concerning the corporate official or person designated to receive service.
(3) A list of corporate officials and persons designated to receive service pursuant to this paragraph will be maintained by the Secretary of the Commission and will be made available to the public in hard copy upon request and through the Commission’s web site at http://www.ferc.gov.
(4) Any person who wishes to serve a complaint or petition for declaratory order on any entity regulated by the Commission must serve the corporate official or person designated pursuant to this paragraph (i).
(5) The Commission will serve show cause orders, data requests, investigatory letters or other documents on the corporate official or person designated under this paragraph (i).
§ 385.2011 Procedures for filing on electronic media (Rule 2011).
(a) FERC Forms subject to the procedures provided in this section include:
(1) FERC Form No. 2, Annual report for major natural gas companies.
(2) FERC Form No. 2–A, Annual report for nonmajor natural gas companies.
(3) FERC Form No. 8, Underground gas storage report.
(4) FERC Form No. 11, Natural gas pipeline monthly statement.
(5) FERC Form No. 14, Annual report for importers and exporters of natural gas.
(6) FERC Form No. 1, Annual report of Major electric utilities, licensees and others.
(7) FERC Form No. 6, Annual Report of Oil Pipeline Companies.
(8) FERC Form No. 1–F, Annual report for Nonmajor public utilities and licensees.
(9) FERC Form No. 60, Annual report of centralized service companies.
(10) FERC Form No. 714, Annual Electric Balancing Authority Area and Planning Area Report.
(11) FERC Form No. 552, Annual Report of Natural Gas Transactions.
(b) These procedures also apply to:
(1) [Reserved]
(2) Certificate and abandonment applications filed under subparts A, E, and F of part 157 of this chapter.
(3) Blanket certificate applications filed under subpart G of part 284 of this chapter.
(c) What to file. (1) Except as provided in paragraph (e) of this section, any filing of a schedule or an update described in paragraphs (a) or (b) of this section must be submitted on electronic media.
(2) Electronic media suitable for Commission filings are listed in the instructions for each form and filings. Additionally, lists of suitable electronic media are available upon request from the Commission.
(3) With the exception of the FERC Form Nos. 1, 1–F, 2, 2–A, 6, 60, and 714, the electronic media must be accompanied by the traditional prescribed number of paper copies.
(4) The formats for the electronic filing and the paper copy are available through the Commission’s website, https://www.ferc.gov.
(5) The subscription required by § 385.2005(a) must state that the paper copies contain the same information as contained on the electronic media, that the signer knows the contents of the paper copies and electronic media, and that the contents as stated in the copies and on the electronic media are true to the best knowledge and belief of the signer.
(d)(1) Where to file. The electronic media, the paper copies, and accompanying cover letter must be submitted to: Office of the Secretary, Federal Energy Regulatory Commission, Washington, DC 20426.
(2) EDI data submissions must be made as indicated in the electronic filing instructions and formats for the particular form or filing, and the paper copies and accompanying cover letter must be submitted to: Office of the Secretary, Federal Energy Regulatory Commission, Washington, DC 20426.
(e) Waiver—(1) Filing of petition. If a natural gas company, electric utility, licensee or other entity does not have and is unable to acquire the computer capability to file the information required to be filed on electronic media, the company may request waiver from the requirement of this part, by filing an original and two copies of a petition. The natural gas company, electric utility, licensee or other entity may renew the waiver if the company can continue to show that it does not have and is unable to acquire the computer capability for electric filing.
(2) Standard for waiver. The petition for waiver must show that the natural gas company, electric utility, licensee or other entity does not have the computer capability to file the information required under this section on electronic media and that acquisition of the capability would cause the company severe economic hardship. This waiver may be granted for up to one year.
(3) Timing. The petition for waiver must be filed by the date on which the information in the manner affected by the petition is required to be initially filed.
(4) Decision on petition. The Commission or its designee will review a petition for waiver and notify the applicant of its grant or denial. Once the petition is decided, the natural gas company, electric utility, licensee or other entity will have 30 days from the date of notification of the decision to submit any information, in the manner specified by the Commission in the decision on the waiver petition, that was required to be filed while the petition was pending.
§ 385.2012 Petitions for review of Commission Orders (Rule 2012).
When a petition for review of an order issued by the Commission is filed in a United States Court of Appeals, a copy of the petition which has been stamped by the court with the date of filing must be mailed or hand delivered to the Office of the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426. If within ten days after issuance of the Commission order, the Office of the Secretary has physically received court-stamped copies of petitions for review of the same order, which petitions have been filed in two or more U.S. Courts of Appeals, the Commission will forward copies of those petitions to the Judicial Panel on Multidistrict Litigation pursuant to 28 U.S.C. 2112(a).
(a) For each Federal authorization—i.e., permit, special use authorization, certification, concurrence, opinion, or other approval—required under Federal law with respect to a natural gas project for which an application has been filed under section 3 of the Natural Gas Act for a certificate of public convenience and necessity under section 7 of the Natural Gas Act, each Federal agency or officer, or State agency or officer acting pursuant to delegated Federal authority, responsible for a Federal authorization must file with the Commission within 30 days of the date of receipt of a request for a Federal authorization, notice of the following:
(1) Whether the application is ready for processing, and if not, what additional information or materials will be necessary to assess the merits of the request;
(2) The time the agency or official will allot the applicant to provide the necessary additional information or materials;
(3) What, if any, studies will be necessary in order to evaluate the request;
(4) The anticipated effective date of the agency’s or official’s decision; and
(5) If applicable, the schedule set by Federal law for the agency or official to act.
(b) A Federal agency or officer, or State agency or officer acting pursuant to delegated Federal authority, considering a request for a Federal authorization that submits a data request to an applicant must file a copy of the data request with the Commission within 10 business days.
(a) For each Federal authorization—i.e., permit, special use authorization, certification, concurrence, opinion, or other approval—required under Federal law with respect to a natural gas project for which an application has been filed for authorization under section 3 of the Natural Gas Act for a certificate of public convenience and necessity under section 7 of the Natural Gas Act, the Federal agency or officer, or State agency or officer acting pursuant to delegated Federal authority, responsible for each Federal authorization must file with the Commission within 30 days of the effective date of a final decision or action on a request for a Federal authorization or the expiration of the time provided by the Commission or by Federal law for a final decision or action, the following:
(1) A copy of any final decision or action;
(2) An index identifying all documents and materials—including pleadings, comments, evidence, exhibits, testimony, project alternatives, studies, and maps—relied upon by the agency or official in reaching a decision or action; and
(3) The designation “Consolidated Record” and the docket number for the Commission proceeding applicable to the requested Federal authorization.
(b) The agencies’ and officers’ decisions, actions, and indices, and the Commission’s record in each proceeding, constitute the complete consolidated record. The original documents and materials that make up the complete consolidated record must be retained by agencies, officers, and the Commission for at least three years from the effective date of a decision or action or until an appeal or review is concluded.
(c) Upon appeal or review of a Federal authorization, agencies, officers, and the Commission will transmit to the reviewing authority, as requested, documents and materials that constitute the complete consolidated record.
§ 385.2015 Videotapes (Rule 2015).
Any person may file a videotape that portrays the site of, or some physical aspect of, an energy project, such as a waterfall or flood waters at the site of an existing or proposed hydroelectric project, or construction activities at the site of a natural gas pipeline. The filing must include a written statement describing the place, date, and time at which the videotape was filmed, who filmed it, what it purports to depict, and the caption and docket number of the proceeding (if any) in which it is to be filed. Any person who files a videotape and who is also a party (either as an applicant or as an intervenor) to a docketed proceeding in which the videotape is filed must file four copies of the videotape with the Commission’s Secretary, in VHS format with voice-over or pictorial inclusion of the data contained in the accompanying written statement, serve copies of the videotape on all of the other parties to the proceeding, and include a certificate of service with the filing.
Subpart U—Appearance and Practice Before the Commission
§ 385.2101 Appearances (Rule 2101).
(a) A participant may appear in a proceeding in person or by an attorney or other qualified representative. An individual may appear in his or her own behalf, a member of a partnership may represent the partnership, a bona-fide officer of a corporation, trust, association or organized group may represent the corporation, trust, association or group, and an officer or employee of a State commission, of a department or political subdivision of a State or other governmental authority, may represent the State commission or the department or political subdivision of the State or other governmental authority, in any proceeding.
(b) A person compelled to appear or voluntarily testifying or making a statement before the Commission or the presiding officer, may be accompanied, represented, and advised by an attorney or other qualified representative.
(c) A person appearing before the Commission or the presiding officer must conform to the standards of ethical conduct required of practitioners before the Courts of the United States, and where applicable, to the requirements of Section 12(i) of the Public Utility Holding Company Act of 1935 (15 U.S.C. 791(i)).
§ 385.2102 Suspension (Rule 2102).
(a) After a hearing the Commission may disqualify and deny, temporarily or permanently, the privilege of appearing or practicing before it in any way to a person who is found:
(1) Not to possess the requisite qualifications to represent others, or
(2) To have engaged in unethical or improper professional conduct, or
(3) Otherwise to be not qualified.
(b) Contumacious conduct in a hearing before the Commission or a presiding officer will be grounds for exclusion of any person from such hearing and for summary suspension for the duration of the hearing by the Commission or the presiding officer.
§ 385.2103 Appearance of former employees (Rule 2103).
(a) No person having served as a member, officer, expert, administrative law judge, attorney, accountant, engineer, or other employee of the Commission may practice before or act as attorney, expert witness, or representative in connection with any proceeding or matter before the Commission which such person has handled, investigated, advised, or participated in the consideration of while in the service of the Commission.
(b) No person having been so employed may within 1 year after his or her employment has ceased, practice before or act as attorney, expert witness, or representative in connection with any proceeding or matter before the Commission which was under the official responsibility of such person, as defined in 18 U.S.C. 202, while in the service of the Commission.
(c) Nothing in paragraphs (a) and (b) of this section prevents a former member, officer, expert, administrative law judge, attorney, accountant, engineer, or other employee of the Commission with outstanding scientific or technological qualifications from practicing before or acting as an attorney or representative in connection with a particular matter in a scientific or technological field if the Chairman of the Commission makes a certification in writing, published in the
Subpart V—Off-the-Record Communications; Separation of Functions
§ 385.2201 Rules governing off-the-record communications (Rule 2201).
(a) Purpose and scope. This section governs off-the-record communications with the Commission in a manner that permits fully informed decision making by the Commission while ensuring the integrity and fairness of the Commission’s decisional process. This rule will apply to all contested on-the-record proceedings, except that the Commission may, by rule or order, modify any provision of this subpart, as it applies to all or part of a proceeding, to the extent permitted by law.
(b) General rule prohibiting off-the-record communications. Except as permitted in paragraph (e) of this section, in any contested on-the-record proceeding, no person outside the Commission shall make or knowingly cause to be made to any decisional employee, and no decisional employee shall make or knowingly cause to be made to any person outside the Commission, any off-the-record communication.
(c) Definitions. For purposes of this section:
(1) Contested on-the-record proceeding means
(i) Except as provided in paragraph (c)(1)(ii) of this section, any proceeding before the Commission to which there is a right to intervene and in which an intervenor disputes any material issue, any proceeding initiated pursuant to rule 206 by the filing of a complaint with the Commission, any proceeding initiated by the Commission on its own motion or in response to a filing, or any proceeding arising from an investigation under part 1b of this chapter beginning from the time the Commission initiates a proceeding governed by part 385 of this chapter.
(ii) The term does not include notice-and-comment rulemakings under 5 U.S.C. 553, investigations under part 1b of this chapter, proceedings not having a party or parties, or any proceeding in which no party disputes any material issue.
(2) Contractor means a direct Commission contractor and its subcontractors, or a third-party contractor and its subcontractors, working subject to Commission supervision and control.
(3) Decisional employee means a Commissioner or member of his or her personal staff, an administrative law judge, or any other employee of the Commission, or contractor, who is or may reasonably be expected to be involved in the decisional process of a proceeding, but does not include an employee designated as part of the Commission’s trial staff in a proceeding, a settlement judge appointed under Rule 603, a neutral (other than an arbitrator) under Rule 604 in an alternative dispute resolution proceeding, or an employee designated as being non-decisional in a proceeding.
(4) Off-the-record communication means any communication relevant to the merits of a contested on-the-record proceeding that, if written, is not filed with the Secretary and not served on the parties to the proceeding in accordance with Rule 2010, or if oral, is made without reasonable prior notice to the parties to the proceeding and without the opportunity for such parties to be present when the communication is made.
(5) Relevant to the merits means capable of affecting the outcome of a proceeding, or of influencing a decision, or providing an opportunity to influence a decision, on any issue in the proceeding, but does not include:
(i) Procedural inquiries, such as a request for information relating solely to the status of a proceeding, unless the inquiry states or implies a preference for a particular party or position, or is otherwise intended, directly or indirectly, to address the merits or influence the outcome of a proceeding;
(ii) A general background or broad policy discussion involving an industry or a substantial segment of an industry, where the discussion occurs outside the context of any particular proceeding involving a party or parties and does not address the specific merits of the proceeding; or,
(iii) Communications relating to compliance matters not the subject of an ongoing proceeding.
(d) Applicability of prohibitions. (1) The prohibitions in paragraph (b) of this section apply to:
(i) Proceedings initiated by the Commission from the time an order initiating the proceeding is issued;
(ii) Proceedings returned to the Commission on judicial remand from the date the court issues its mandate;
(iii) Complaints initiated pursuant to rule 206 from the date of the filing of the complaint with the Commission, or from the date the Commission initiates an investigation (other than an investigation under part 1b of this chapter) on its own motion; and
(iv) All other proceedings from the time of the filing of an intervention disputing any material issue that is the subject of a proceeding.
(2) The prohibitions remain in force until:
(i) A final Commission decision or other final order disposing of the merits of the proceeding is issued; or, when applicable, after the time for seeking rehearing of a final Commission decision, or other final order disposing of the merits, expires;
(ii) The Commission otherwise terminates the proceeding; or
(iii) The proceeding is no longer contested.
(e) Exempt off-the-record communications. (1) Except as provided by paragraph (e)(2), the general prohibitions in paragraph (b) of this section do not apply to:
(i) An off-the-record communication permitted by law and authorized by the Commission;
(ii) An off-the-record communication related to any emergency concerning a facility regulated by the Commission or a facility that provides Commission-regulated services, involving injury or threat of injury to persons, property, or the environment, subject to disclosure under paragraph (g) of this section;
(iii) An off-the-record communication provided for in a written agreement among all parties to a proceeding that has been approved by the Commission;
(iv) An off-the-record written communication from a non-party elected official, subject to disclosure under paragraph (g) of this section;
(v) An off-the-record communication to or from a Federal, state, local or Tribal agency that is not a party in the Commission proceeding, subject to disclosure under paragraph (g) of this section, if the communication involves:
(A) an oral or written response to a request for information made by the Commission or Commission staff; or
(B) a matter before the Commission in which a Federal, state, local, or Tribal agency has regulatory responsibilities, including authority to impose or recommend conditions in connection with a Commission license, certificate, or exemption;
(vi) An off-the-record communication, subject to disclosure under paragraph (g) of this section, that relates to:
(A) The preparation of an environmental impact statement if communications occur prior to the issuance of the final environmental impact statement; or
(B) The preparation of an environmental assessment where the Commission has determined to solicit public comment on the environmental assessment, if such communications occur prior to the issuance of the final environmental document.
(vii) An off-the-record communication involving individual landowners who are not parties to the proceeding and whose property would be used or abuts property that would be used by the project that is the subject of the proceeding, subject to disclosure under paragraph (g) of this section.
(viii) An off-the-record communication from any person related to any national security-related issue concerning a facility regulated by the Commission or a facility that provides Commission-regulated services.
(2) Except as may be provided by Commission order in a proceeding to which this subpart applies, the exceptions listed under paragraph (e)(1) will not apply to any off-the-record communications made to or by a presiding officer in any proceeding set for hearing under subpart E of this part.
(f) Treatment of prohibited off-the-record communications—(1) Commission consideration. Prohibited off-the-record communications will not be considered part of the record for decision in the applicable Commission proceeding, except to the extent that the Commission by order determines otherwise.
(2) Disclosure requirement. Any decisional employee who makes or receives a prohibited off-the-record communication will promptly submit to the Secretary that communication, if written, or a summary of the substance of that communication, if oral. The Secretary will place the communication or the summary in the public file associated with, but not part of, the decisional record of the proceeding.
(3) Responses to prohibited off-the-record communications. Any party may file a response to a prohibited off-the-record communication placed in the public file under paragraph (f)(2) of this section. A party may also file a written request to have the prohibited off-the-record communication and the response included in the decisional record of the proceeding. The communication and the response will be made a part of the decisional record if the request is granted by the Commission.
(4) Service of prohibited off-the-record communications. The Secretary will instruct any person making a prohibited written off-the-record communication to serve the document, pursuant to Rule 2010, on all parties listed on the Commission’s official service list for the applicable proceeding.
(g) Disclosure of exempt off-the-record communications. (1) Any document, or a summary of the substance of any oral communication, obtained through an exempt off-the-record communication under paragraphs (e)(1)(ii), (iv), (v), (vi) or (vii) of this section, promptly will be submitted to the Secretary and placed in the decisional record of the relevant Commission proceeding, unless the communication was with a cooperating agency as described by 40 CFR 1501.6, made under paragraph (e)(1)(v) of this section.
(2) Any person may respond to an exempted off-the-record communication.
(3) Any document, or a summary of the substance of any oral communications, obtained through an exempt off-the-record communication under paragraphs (e)(1)(viii) of this section, will be submitted promptly to the Secretary and placed in a non-public decisional file of the relevant Commission proceeding and made available to parties to the proceeding, subject to their signing a non-disclosure agreement. Responses will also be placed in the non-public decisional file and held confidential. If the Commission determines that the communication does not contain sensitive national security-related information, it will be placed in the decisional file.
(h) Public notice requirement of prohibited and exempt off-the-record communications. (1) The Secretary will, not less than every 14 days, issue a public notice listing any prohibited off-the-record communications or summaries of the communication received by his or her office. For each prohibited off-the-record communication the Secretary places in the non-decisional public file under paragraph (f)(2) of this section, the notice will identify the maker of the off-the-record communication, the date the off-the-record communication was received, and the docket number to which it relates.
(2) The Secretary will not less than every 14 days, issue a public notice listing any exempt off-the-record communications or summaries of the communication received by the Secretary for inclusion in the decisional record and required to be disclosed under paragraph (g)(1) of this section.
(3) The public notice required under this paragraph (h) will be posted in accordance with § 388.106 of this chapter, as well as published in the
(i) Sanctions. (1) If a party or its agent or representative knowingly makes or causes to be made a prohibited off-the-record communication, the Commission may require the party, agent, or representative to show cause why the party’s claim or interest in the proceeding should not be dismissed, denied, disregarded, or otherwise adversely affected because of the prohibited off-the-record communication.
(2) If a person knowingly makes or causes to be made a prohibited off-the-record communication, the Commission may disqualify and deny the person, temporarily or permanently, the privilege of practicing or appearing before it, in accordance with Rule 2102 (Suspension).
(3) Commission employees who are found to have knowingly violated this rule may be subject to the disciplinary actions prescribed by the agency’s administrative directives.
(j) Section not exclusive. (1) The Commission may, by rule or order, modify any provision of this section as it applies to all or part of a proceeding, to the extent permitted by law.
(2) The provisions of this section are not intended to limit the authority of a decisional employee to decline to engage in permitted off-the-record communications, or where not required by any law, statute or regulation, to make a public disclosure of any exempted off-the-record communication.
§ 385.2202 Separation of functions (Rule 2202).
In any proceeding in which a Commission adjudication is made after hearing, or in any proceeding arising from an investigation under part 1b of this chapter beginning from the time the Commission initiates a proceeding governed by part 385 of this chapter, no officer, employee, or agent assigned to work upon the proceeding or to assist in the trial thereof, in that or any factually related proceeding, shall participate or advise as to the findings, conclusion or decision, except as a witness or counsel in public proceedings.
PART 388—INFORMATION AND REQUESTS
§ 388.101 Scope.
This part prescribes the rules governing public notice of proceedings, publication of decisions, requests for informal advice from Commission staff, procedures for press, television, radio and photographic coverage, requests for Commission records, requests for confidential treatment of documents submitted to the Commission, procedures for responding to subpoenas seeking documents or testimony from Commission employees or former employees, fees for various requests for documents, and requests for reduction or waiver of these fees.
§ 388.102 Notice of proceedings.
(a) Public sessions of the Commission for taking evidence or hearing argument; public conferences and hearings before a presiding officer; and public conferences or hearings in substantive rulemaking proceedings, will not be held except upon notice.
(b) Notice of applications, complaints, and petitions, is governed by Rule 2009 (notice) in part 385 of this chapter. Notice of applications for certificates of public convenience and necessity under section 7 of the Natural Gas Act is governed by § 157.9 of this chapter (notice of application). Notice of public sessions and proceedings and of meetings of the Commission is governed by Rule 2009 (notice) in part 385 of this chapter. Notice of hearings and of initiation or pendency of rulemaking proceedings is governed by Rule 1903 (notice in rulemaking proceedings) in part 385 of this chapter. Notice of application under Part I of the Federal Power Act for preliminary permits and licenses is governed by §§ 4.31 and 4.81 of this chapter (acceptance or rejection and contents). Notice of proposed alterations or surrenders of license under section 6 of the Federal Power Act may be given by filing and publication in the
§ 388.103 Notice and publication of decisions, rules, statements of policy, organization and operations.
Service of intermediate and final decisions upon parties to the proceedings is governed by Rule 2010 (service) in part 385 of this chapter. Descriptions of the Commission’s organization, its methods of operation, statements of policy and interpretations, procedural and substantive rules, and amendments thereto will be filed with and published in the
§ 388.104 Informal advice from Commission staff.
(a) The Commission staff provides informal advice and assistance to the general public and to prospective applicants for licenses, certificates, and other Commission authorizations. Opinions expressed by the staff do not represent the official views of the Commission, but are designed to aid the public and facilitate the accomplishment of the Commission’s functions. Inquiries may be directed to the chief of the appropriate office or division.
(b) Any inquiry directed to the Chief Accountant that requires a written response must be accompanied by the fee prescribed in § 381.301 of this chapter.
(c) A request directed to the Office of the General Counsel for a legal interpretation of any statute or implementing regulation under the jurisdiction of the Commission must be accompanied by the fee prescribed in § 381.305 of this chapter.
§ 388.105 Procedures for press, television, radio, and photographic coverage.
(a) The Commission issues news releases on major applications, decisions, opinions, orders, rulemakings, new publications, major personnel changes, and other matters of general public interest. Releases are issued by and available to the media from the Office of External Affairs. Releases may be obtained through the Commission’s website, https://www.ferc.gov.
(b) Press, television, radio and photographic coverage of Commission proceedings is permitted as follows:
(1) Press tables are located in each hearing room, and all sessions of hearings are open to the press, subject to standards of conduct applicable to all others present;
(2) Television, movie and still cameras, and recording equipment are permitted in hearing rooms prior to the opening of a hearing or oral arguments, and during recesses, upon prior arrangement with the Commission or presiding administrative law judge. All equipment must be removed from the room before hearings or oral arguments begin or resume;
(3) Television, movie and still cameras, and recording equipment may not be used while hearings and oral arguments before administrative law judges are in progress;
(4) Television and press cameras and recording equipment may be used at Commission press conferences under prior arrangement with the Office of External Affairs, provided their use does not interfere with the orderly conduct of the press conference;
(5) Regulations pertaining to the use of television, movie and still cameras, and recording equipment in connection with the Commission’s open public meetings under the Government in the Sunshine Act are found in § 375.203 of this chapter.
§ 388.106 Requests for Commission records available from the Commission’s website, https://www.ferc.gov.
(a) Publicly available documents may be obtained electronically from the Commission’s website, https://www.ferc.gov, or by requesting them from the [email protected] by reasonably describing the records sought. Additional information on charges and services is available on the website.
(b) The public records of the Commission that are available for inspection and copying upon request via the Commission’s website, include:
(1) Applications, declarations, complaints, petitions, and other papers seeking Commission action;
(2) Financial, statistical, and other reports to the Commission, power system statements of claimed cost of licensed projects, original cost and reclassification studies, proposed accounting entries, certificates of notification (under section 204(e) of the Federal Power Act), rates or rate schedules and related data and concurrences, and other filings and submittals to the Commission in compliance with the requirements of any statute, executive order, or Commission rule, regulation, order, license, or permit;
(3) Answers, replies, responses, objections, protests, motions, stipulations, exceptions, other pleadings, notices, certificates, proofs of service, transcripts of oral arguments, and briefs in any matter of proceeding;
(4) Exhibits, attachments and appendices to, amendments and corrections of, supplements to, or transmittals or withdrawals of any of the foregoing;
(5) All parts of the formal record in any matter or proceeding set for formal or statutory hearing, and any Commission correspondence related thereto;
(6) Presiding officer actions, correspondence, and memoranda to or from others, with the exception of internal communications within the Office of Administrative Law Judges:
(7) Commission orders, notices, findings, opinions, determinations, and other actions in a matter or proceeding;
(8) Commission correspondence relating to any furnishing of data or information, except to or by another branch, department, or agency of the Government;
(9) Commission correspondence with respect to the furnishing of data, information, comments, or recommendations to or by another branch, department, or agency of the Government where furnished to satisfy a specific requirement of a statute or where made public by that branch, department or agency;
(10) Staff reports on statements of claimed cost by licensees when such reports have been served on the licensee;
(11) Commission correspondence on interpretation of the Uniform System of Accounts and letters on such interpretation signed by the Chief Accountant and sent to persons outside the Commission;
(12) Commission correspondence on the interpretation or applicability of any statute, rule, regulation, order, license, or permit issued or administered by the Commission, and letters of opinion on that subject signed by the General Counsel and sent to persons outside the Commission;
(13) Copies of the filings, certifications, pleadings, records, briefs, orders, judgments, decrees, and mandates in court proceedings to which the Commission is a party and the correspondence with the courts or clerks of court;
(14) The Commission’s Directives System;
(15) The Commission’s opinions, decisions, orders and rulemakings;
(16) Reports, decisions, maps, and other information on electric power and natural gas industries;
(17) Subject index of major Commission actions;
(18) Annual report to Congress in which the Commission’s operations during a past fiscal year are described; and
(19) Statements of policy and interpretations which have been adopted by the Commission and are not published in the
(20) Administrative staff manuals and instructions to staff that affect a member of the public;
(21)(i) Copies of all records released under § 388.108, which, because of their nature and subject, the Director of the Office of External Affairs has determined are likely to be requested again, and
(ii) An index of the records so designated;
(22) Reference materials and guides for requesting Commission records as required by 5 U.S.C. § 552(g), as amended; and
(23) Commission correspondence relating to the foregoing.
(24) Records that have been requested three or more times and determined eligible for public disclosure will be made publicly available on the Commission’s Web site or through other electronic means.
(c) For purposes of this section,
(1) Commission correspondence includes written communications and enclosures, in hard copy or electronic format, received from others outside the staff and intended for the Commission or sent to others outside the staff and signed by the Chairman, a Commissioner, the Secretary, the Executive Director, or other authorized official, except those which are personal.
(2) Formal record includes:
(i) Filings and submittals in a matter or proceeding,
(ii) Any notice or Commission order initiating the matter or proceeding, and
(iii) If a hearing is held, the designation of the presiding officer, transcript of hearing, exhibits received in evidence, exhibits offered but not received in evidence, offers of proof, motions, stipulations, subpoenas, proofs or service, references to the Commission, and determinations made by the Commission thereon, certifications to the Commission, and anything else upon which action of the presiding officer or the Commission may be based.
(3) Matter or proceeding means the Commission’s elucidation of the relevant facts and applicable law, consideration thereof, and action thereupon with respect to a particular subject within the Commission’s jurisdiction, initiated by a filing or submittal or a Commission notice or order.
§ 388.107 Commission records exempt from public disclosure.
The following records are exempt from disclosure.
(a)(1) Records specifically authorized under criteria established by an Executive order to be kept secret in the interest of national defense or foreign policy, and
(2) Those records are in fact properly classified pursuant to such Executive order;
(b) Records related solely to the internal personnel rules and practices of an agency;
(c) Records specifically exempted from disclosure by statute, provided that such statute:
(1) Requires that the matters be withheld from the public in such a manner as to leave no discretion on the issue, or
(2) Establishes particular criteria for withholding or refers to particular types of matters to be withheld;
(d) Trade secrets and commercial or financial information obtained from a person and privileged or confidential;
(e) Interagency or intraagency memoranda or letters which would not be available by law to a party other than an agency in litigation with the agency, except that the deliberative process privilege shall not exempt any record 25 years or older.
(f) Personnel and medical files and similar files the disclosure of which would constitute a clearly unwarranted invasion of personal privacy;
(g) Records or information compiled for law enforcement purposes, but only to the extent that the production of such law enforcement records or information:
(1) Could reasonably be expected to interfere with enforcement proceedings,
(2) Would deprive a person of a right to a fair trial or an impartial adjudication,
(3) Could reasonably be expected to constitute an unwarranted invasion of personal privacy,
(4) Could reasonably be expected to disclose the identity of a confidential source, including a state, local, or foreign agency or authority or any private institution which furnished information on a confidential basis, and, in the case of a record or information compiled by a criminal law enforcement authority in the course of a criminal investigation, or by an agency conducting a lawful national security intelligence investigation, information furnished by a confidential source,
(5) Would disclose techniques and procedures for law enforcement investigations or prosecutions, or would disclose guidelines for law enforcement investigations or prosecutions if such disclosure could reasonably be expected to risk circumvention of the law, or
(6) Could reasonably be expected to endanger the life or physical safety of any individual;
(h) Geological and geophysical information and data, including maps, concerning wells.
§ 388.108 Requests for Commission records not available from the Commission’s website, https://www.ferc.gov.
(a)(1) Except as provided in paragraph (a)(2) of this section, a person may request access to Commission records, including records maintained in electronic format, that are not available through the Commission’s website, https://www.ferc.gov, by using the following procedures:
(i) The request must be in writing, addressed to the Director, Office of External Affairs, and clearly marked “Freedom of Information Act Request.”
(ii) The request must include:
(A) A statement by the requester of a willingness to pay a reasonable fee or fees not to exceed a specific amount, or
(B) A request for waiver or reduction or fees.
(iii) The request must identify the fee category of the request, consistent with the provisions of § 388.109(b) (1) and (2).
(2) A request that fails to provide the identification required in paragraph (a)(1)(iii) of this section will not be processed until the Director, Office of External Affairs, can ascertain the requester’s fee category.
(3) A request for records received by the Commission not addressed and marked as indicated in paragraph (a)(1)(i) of this section will be so addressed and marked by Commission personnel as soon as it is properly identified, and forwarded immediately to the Director, Office of External Affairs.
(4) Requests made pursuant to this section will be considered to be received upon actual receipt by the Director, Office of External Affairs, unless otherwise indicated in paragraph (a)(5) of this section.
(5) Except for the purpose of making a determination regarding expedited processing under paragraph (d)(3) of this section, no request will be deemed received while there is an unresolved fee waiver issue under § 388.109(b)(6), unless the requester has provided a written statement agreeing to pay some or all fees pending the outcome of the waiver question.
(b)(1) Multitrack processing. Upon receipt of a request, the Director, Office of External Affairs, will place the request in one of three tracks for processing:
(i) Track One—records that are readily identifiable and were previously cleared for release (including those subject to multiple requests and placed on https://www.ferc.gov);
(ii) Track Two—records that are readily identifiable, and require limited review; and
(iii) Track Three—complex and/or voluminous records requiring a significant search and/or review.
(2) Each track specified in paragraph (b)(1) of this section will be processed on a first in, first out basis, where practicable. A requester may modify a request to obtain processing on a faster track.
(c)(1) Timing of response. Except as provided in paragraphs (c)(4) and (d)(3) of this section, within 20 working days after receipt of the request for agency records, the Director, Office of External Affairs, will comply with the request or deny the request in whole or in part, and will notify the requester of the determination, of the reasons for a decision to withhold any part of a requested document, and of the right of the requester to appeal any adverse determination in writing to the General Counsel or General Counsel’s designee.
(2) The Director, Office of External Affairs, will attempt to provide records in the form or format requested, where feasible, but will not provide more than one copy of any record to a requester.
(3) Any determination by the Director, Office of External Affairs, to withhold information will, where feasible, indicate the approximate volume of information withheld, and will indicate, for partially-released materials, where redactions have been made, unless to do so would harm an interest protected by a FOIA exemption.
(4) The Director will consider whether partial disclosure of information is possible whenever it is determined that a document is exempt and will take reasonable steps to segregate and release nonexempt information.
(5) The Director will only withhold information where it is reasonably foreseeable that disclosure would harm an interest protected by an exemption or disclosure is prohibited by law or otherwise exempted from disclosure under FOIA Exemption 3.
(d)(1) Expedited processing. A requester may seek expedited processing on the basis of a compelling need. Expedited processing will be granted if the requester demonstrates that:
(i) Failure to obtain the records on an expedited basis can reasonably be expected to pose an imminent threat to the life or physical safety of an individual, or
(ii) In the case of a requester primarily engaged in the dissemination of information, there is an urgency to inform the public concerning Federal Government activity.
(2) A request for expedited processing under this section must be supported with detailed credible documentation, including a statement certified to be true and correct to the requester’s best knowledge and belief.
(3) The Director, Office of External Affairs, will decide within 10 calendar days of receipt of the request whether it is eligible for expedited processing. The Director will notify the requester of the reasons for denial of expedited processing and of the right of the requester to appeal to the General Counsel or General Counsel’s designee.
(e) The procedure for appeal of denial of a request for Commission records, or denial of a request for expedited processing, is set forth in § 388.110.
§ 388.109 Fees for record requests.
(a) Fees for records available through the Commission’s website. (1) The fee for finding and duplicating records available from the Commission’s website, https://www.ferc.gov, will vary depending on the size and complexity of the request. A person can obtain a copy of the schedule of fees from the Commission’s website, https://www.ferc.gov. In addition, copies of data extracted from the Commission’s files through electronic media are available on a reimbursable basis, upon written request to the Commission.
(2) Stenographic reports of Commission hearings are made by a private contractor. Interested persons may obtain copies of public hearing transcripts from the contractor at prices set in the contract, or through the search and duplication service noted above. Copies of the contract are available for public inspection on the Commission’s website, https://www.ferc.gov.
(b) Fees for records not available through the Commission’s website (FOIA or CEII requests). The cost of duplication of records not available from the Commission’s website, https://www.ferc.gov, will depend on the number of documents requested, the time necessary to locate the documents requested, and the category of the persons requesting the records. The procedures for appeal of denial of requests for fee waiver or reduction are set forth in § 388.110.
(1) Definitions: For the purpose of paragraph (b) of this section.
(i) Commercial use request means a request from or on behalf of one who seeks information for a use or purpose that furthers commercial trade, or profit interests as these phrases are commonly known or have been interpreted by the courts in the context of the Freedom of Information Act.
(ii) Educational institution refers to a preschool, a public or private elementary or secondary school, an institution of graduate higher education, an institution of undergraduate higher education, an institution of professional education, and an institution of vocational education, which operates a program of scholarly research.
(iii) Noncommercial scientific institution refers to an installation that is not operated on a commercial basis and which is operated solely for the purpose of conducting scientific research the results of which are not intended to promote any particular product or industry.
(iv) Representatives of the news media refers to any person actively gathering news for an entity that is organized and operated to publish or broadcast news to the public. The term news means information that is about current events that would be of current interest to the public. Examples of news media entities include television or radio stations broadcasting to the public at large, and publishers of periodicals (but only in those instances when the periodicals can qualify as disseminations of “news”) who make their products available for purchase or subscription by the general public. These examples are not intended to be all-inclusive. Moreover, as traditional methods of news delivery evolve (e.g. electronic dissemination of newspapers through telecommunication services), such alternative media may be included in this category. A freelance journalist may be regarded as working for a news organization if the journalist can demonstrate a solid basis for expecting publication through that organization, even though the journalist is not actually employed by the news organization. A publication contract would be the clearest proof, but the Commission may also look to the past publication record of a requester in making this determination.
(2) Fees. (i) If documents are requested for commercial use, the Commission will charge the employee’s hourly pay rate plus 16% for benefits for document search time and for document review time, and 15 cents per page for duplication. Commercial use requests are not entitled to two hours of free search time or 100 free pages of reproduction of documents.
(ii) If documents are not sought for commercial use and the request is made by an educational or non-commercial scientific institution, whose purpose is scholarly or scientific research, or a representative of the news media, the Commission will charge 15 cents per page for duplication. There is no charge for the first 100 pages.
(iii) For a request not described in paragraphs (b)(2)(i) or (ii) of this section, the Commission will charge the employees hourly pay rate plus 16 percent for benefits for document search and 15 cents per page for duplication. There is no charge for the first 100 pages of reproduction and the first two hours of search time will be furnished without charge.
(iv) The Director, Office of External Affairs, will normally provide documents by regular mail, with postage prepaid by the Commission. However, the requester may authorize special delivery, such as express mail, at the requester’s own expense.
(v) The Commission, or its designee, may establish minimum fees below which no charges will be collected, if it determines that the costs of routine collection and processing of the fees are likely to equal or exceed the amount of the fees. If total fees assessed by Commission staff for a Freedom of Information Act request are less than the appropriate threshold, the Commission may not charge the requesters.
(vi) Payment of fees must be by check or money order made payable to the U.S. Treasury.
(vii) Requesters may not file multiple requests at the same time, each seeking portions of a document or documents, solely in order to avoid payment of fees. When the Commission reasonably believes that a requester, or a group of requesters acting in concert, is attempting to break a request down into a series of requests for the purpose of evading assessment of fees, or otherwise reasonably believes that two or more requests constitute a single request, the Commission may aggregate any such requests accordingly. The Commission will not aggregate multiple requests on unrelated subjects from a requester. Aggregated requests may qualify for an extension of time under § 388.110(b).
(3) Fees for unsuccessful search. The Commission may assess charges for time spent searching, even if it fails to locate the records, or if records located are determined to be exempt from disclosure. If the Commission estimates that search charges are likely to exceed $25, it will notify the requester of the estimated amount of search fees, unless the requester has indicated in advance willingness to pay fees as high as those anticipated. The requester can meet with Commission personnel with the object of reformulating the request to meet his or her needs at a lower cost.
(4) Interest—notice and rate. The Commission will assess interest charges on an unpaid bill starting on the 31st day following the day on which the billing was sent. Interest will be at the rate prescribed in 31 U.S.C. 3717 and will accrue from the date of the billing.
(5) Advance payments. The Commission will require a requester to make an advance payment, i.e., payments before work is commenced or continued on a request, if:
(i) The Commission estimates or determines that allowable charges that a requester may be required to pay are likely to exceed $250. The Commission will notify the requester of the estimated cost and either require satisfactory assurance of full payment where the requester has a history of prompt payment of fees, or require advance payment of charges if a requester has no history of payment; or
(ii) A requester has previously failed to pay a fee charged in a timely fashion. The Commission will require the requester to pay the full amount owed plus any applicable interest, and to make an advance payment of the full amount of the estimated fee before the Commission will begin to process a new request or a pending request from that requester. When the Commission requires advance payment or an agreement to pay under this paragraph, or under § 388.108(a)(5), the administrative time limits prescribed in this part will begin only after the Commission has received the required payments, or agreements.
(c) Fee reduction or waiver. (1) Any fee described in this section may be reduced or waived if the requester demonstrates that disclosure of the information sought is:
(i) In the public interest because it is likely to contribute significantly to public understanding of the operations or activities of the government, and
(ii) Not primarily in the commercial interest of the requester.
(2) The Commission will consider the following criteria to determine the public interest standard:
(i) Whether the subject of the requested records concerns the operations or activities of the government;
(ii) Whether the disclosure is likely to contribute to an understanding of government operations or activities;
(iii) Whether disclosure of the requested information will contribute to public understanding; and
(iv) Whether the disclosure is likely to contribute significantly to public understanding of government operations or facilities.
(3) The Commission will consider the following criteria to determine the commercial interest of the requester:
(i) Whether the requester has a commercial interest that would be furthered by the requested disclosure; and, if so
(ii) Whether the magnitude of the identified commercial interest of the requester is sufficiently large, in comparison with the public interest in disclosure, that disclosure is primarily in the commercial interest of the requester.
(4) This request for fee reduction or waiver must accompany the initial request for records and will be decided under the same procedures used for record requests.
(d) Debt collection. The Commission will use the authorities mandated in the Debt Collection Act of 1982, 31 U.S.C. 3711, 3716–3719 (1982), including disclosure to consumer reporting agencies and use of collection agencies, where appropriate, to encourage payment of outstanding unpaid FOIA invoices.
(e) Annual adjustment of fees—(1) Update and publication. The Commission, by its designee, the Executive Director, will update the fees established in this section each fiscal year. The Executive Director will publish the fees in the
(2) Payment of updated fees. The fee applicable to a particular Freedom of Information Act request will be the fee in effect on the date that the request is received.
(f) The Commission will not charge search fees (or duplication fees for requesters with preferred fee status) where, after extending the time limit for unusual circumstances, as described in § 388.110, the Director does not provide a timely determination.
(1) If there are unusual circumstances, as described in § 388.110, and there are more than 5,000 responsive pages to the request, the Commission may charge search fees (or, for requesters in preferred fee status, may charge duplication fees) where the requester received timely written notice and the Commission has discussed with the requester via written mail, electronic mail, or telephone (or made not less than 3 good-faith attempts to do so) how the requester could effectively limit the scope of the request; or
(2) If a court determines that exceptional circumstances exist, the Commission’s failure to comply with a time limit will be excused for the length of time provided by the court order.
§ 388.110 Procedure for appeal of denial of requests for Commission records not publicly available, denial of requests for fee waiver or reduction, and denial of requests for expedited processing.
(a)(1) Determination letters shall indicate that a requester may seek assistance from the FOIA Public Liaison. A person whose request for records, request for fee waiver, or request for expedited processing is denied in whole or in part may seek dispute resolution services from the Office of Government Information Services, or may appeal the determination to the General Counsel or General Counsel’s designee within 90 days of the determination.
(2) Appeals filed pursuant to this section must be in writing, addressed to the General Counsel of the Commission, and clearly marked “Freedom of Information Act Appeal.” Such an appeal received by the Commission not addressed and marked as indicated in this paragraph will be so addressed and marked by Commission personnel as soon as it is properly identified and then will be forwarded to the General Counsel. Appeals taken pursuant to this paragraph will be considered to be received upon actual receipt by the General Counsel.
(3) The General Counsel or the General Counsel’s designee will make a determination with respect to any appeal within 20 working days after the receipt of such appeal. An appeal of the denial of expedited processing will be considered as expeditiously as possible within the 20 working day period. If, on appeal, the denial of the request for records, fee reduction, or expedited processing is upheld in whole or in part, the General Counsel or the General Counsel’s designee will notify the person making the appeal of the provisions for judicial review of that determination.
(b)(1) Extension of time. In unusual circumstances, the time limits prescribed for making the initial determination pursuant to § 388.108 and for deciding an appeal pursuant to this section may be extended by up to 10 working days, by the Secretary, who will send written notice to the requester setting forth the reasons for such extension and the date on which a determination or appeal is expected to be dispatched.
(2) The extension permitted by paragraph (b)(1) of this section may be made longer than 10 working days when the Commission notifies the requester within the initial response time that the request cannot be processed in the specified time, and the requester is provided an opportunity to limit the scope of the request to allow processing within 20 working days; or to arrange with the Commission an alternative time frame.
(3) Two or more requests aggregated into a single request under § 388.109(b)(2)(vii) may qualify for an extension of time if the requests, as aggregated, otherwise satisfy the unusual circumstances specified in this section.
(4) Unusual circumstances means:
(i) The need to search for and collect the requested records from field facilities or other establishments that are separate from the office processing the requests;
(ii) The need to search for, collect, and appropriately examine a voluminous amount of separate and distinct records which are demanded in a single request; or
(iii) The need for consultation, which will be conducted with all practicable speed, with another agency having a substantial interest in the determination of the request or among two or more components of the agency having substantial subject-matter interest therein.
(5) Whenever the Commission extends the time limit, pursuant to paragraph (b)(1) of this section, by more than ten additional working days, the written notice will notify the requester of the right to seek dispute resolution services from the Office of Government Information Services.
§ 388.111 Procedures in event of subpoena.
(a)(1) The procedures specified in this section will apply to all subpoenas directed to Commission employees that relate in any way to the employees’ official duties. These procedures will also apply to subpoenas directed to former Commission employees if the subpoenas seek nonpublic materials or information acquired during Commission employment. The provisions of paragraph (c) of this section will also apply to subpoenas directed to the Commission.
(2) For purposes of this section,
(i) Employees, except where otherwise specified, includes “special government employees” and other Commission employees; and
(ii) Nonpublic includes any material or information which is exempt from availability for public inspection and copying;
(iii) Special government employees includes consultants and other employees as defined by section 202 of Title 18 of the United States Code.
(iv) Subpoena means any compulsory process in a case or matter, including a case or matter to which the Commission is not a party;
(b) Any employee who is served with a subpoena must promptly advise the General Counsel of the Commission of the service of the subpoena, the nature of the documents or information sought, and all relevant facts and circumstances. Any former employee who is served with a subpoena that concerns nonpublic information shall promptly advise the General Counsel of the Commission of the service of the subpoena, the nature of the documents or information sought, and all relevant facts and circumstances.
(c) A party causing a subpoena to be issued to the Commission or any employee or former employee of the Commission must furnish a statement to the General Counsel of the Commission. This statement must set forth the party’s interest in the case or matter, the relevance of the desired testimony or documents, and a discussion of whether the desired testimony or documents are reasonably available from other sources. If testimony is desired, the statement must also contain a general summary of the testimony and a discussion of whether Commission records could be produced and used in lieu of testimony. Any authorization for testimony will be limited to the scope of the demand as summarized in such statement.
(d) Commission records or information which are not part of the public record will be produced only upon authorization by the Commission.
(e) The Commission or its designee will consider and act upon subpoenas under this section with due regard for statutory restrictions, the Commission’s Rules of Practice and Procedure, and the public interest, taking into account factors such as applicable privileges including the deliberative process privilege; the need to conserve the time of employees for conducting official business; the need to avoid spending the time and money of the United States for private purposes; the need to maintain impartiality between private litigants in cases where a substantial government interest is not involved; and the established legal standards for determining whether justification exists for the disclosure of confidential information and records.
(f) The Commission authorizes the General Counsel or the General Counsel’s designee to make determinations under this section.
§ 388.112 Requests for privileged treatment for documents submitted to the Commission.
(a) Scope. By following the procedures specified in this section, any person submitting a document to the Commission may request privileged treatment for some or all of the information contained in a particular document that it claims is exempt from the mandatory public disclosure requirements of the Freedom of Information Act, 5 U.S.C. 552 (FOIA), and should be withheld from public disclosure. For the purposes of the Commission’s filing requirements, non-CEII subject to an outstanding claim of exemption from disclosure under FOIA will be referred to as privileged material. The rules governing CEII are contained in § 388.113.
(b) Procedures for filing and obtaining privileged material. (1) General Procedures. A person requesting that material be treated as privileged information must include in its filing a justification for such treatment in accordance with the filing procedures posted on the Commission’s Web site at http://www.ferc.gov. A person requesting that a document filed with the Commission be treated as privileged in whole or in part must designate the document as privileged in making an electronic filing or clearly indicate a request for such treatment on a paper filing. The cover page and pages or portions of the document containing material for which privileged treatment is claimed should be clearly labeled in bold, capital lettering, indicating that it contains privileged or confidential information, as appropriate, and marked “DO NOT RELEASE.” The filer also must submit to the Commission a public version with the information that is claimed to be privileged material redacted, to the extent practicable.
(2) Procedures for Proceedings with a Right to Intervene. The following procedures set forth the methods for filing and obtaining access to material that is filed as privileged in complaint proceedings and in any proceeding to which a right to intervention exists:
(i) If a person files material as privileged material in a complaint proceeding or other proceeding to which a right to intervention exists, that person must include a proposed form of protective agreement with the filing, or identify a protective agreement that has already been filed in the proceeding that applies to the filed material. This requirement does not apply to material submitted in hearing or settlement proceedings, or if the only material for which privileged treatment is claimed consists of landowner lists or privileged information filed under §§ 380.12(f) and 380.16(f) of this chapter.
(ii) The filer must provide the public version of the document and its proposed form of protective agreement to each entity that is required to be served with the filing.
(iii) Any person who is a participant in the proceeding or has filed a motion to intervene or notice of intervention in the proceeding may make a written request to the filer for a copy of the complete, non-public version of the document. The request must include an executed copy of the protective agreement and a statement of the person’s right to party or participant status or a copy of their motion to intervene or notice of intervention. Any person may file an objection to the proposed form of protective agreement. A filer, or any other person, may file an objection to disclosure, generally or to a particular person or persons who have sought intervention.
(iv) If no objection to disclosure is filed, the filer must provide a copy of the complete, non-public document to the requesting person within 5 days after receipt of the written request that is accompanied by an executed copy of the protective agreement. If an objection to disclosure is filed, the filer shall not provide the non-public document to the person or class of persons identified in the objection until ordered by the Commission or a decisional authority.
(v) For material filed in proceedings set for trial-type hearing or settlement judge proceedings, a participant’s access to material for which privileged treatment is claimed is governed by the presiding official’s protective order.
(vi) For landowner lists, information filed as privileged under §§ 380.12(f) and 380.16(f) of this chapter, forms filed with the Commission, and other documents not covered above, access to this material can be sought pursuant to a FOIA request under § 388.108. Applicants are not required under paragraph (b)(2)(iv) of this section to provide intervenors with landowner lists and the other materials identified in the previous sentence.
(c) Effect of privilege or CEII claim. (1) For documents filed with the Commission:
(i) The documents for which privileged treatment is claimed will be maintained in the Commission’s document repositories as non-public until such time as the Commission may determine that the document is not entitled to the treatment sought and is subject to disclosure consistent with § 388.108. By treating the documents as nonpublic, the Commission is not making a determination on any claim of privilege status. The Commission retains the right to make determinations with regard to any claim of privilege status, and the discretion to release information as necessary to carry out its jurisdictional responsibilities.
(ii) The request for privileged treatment and the public version of the document will be made available while the request is pending.
(2) For documents submitted to Commission staff. The notification procedures of paragraphs (d), (e), and (f) of this section will be followed before making a document public.
(d) Notification of request and opportunity to comment. When a FOIA requester seeks a document for which privilege status has been claimed, or when the Commission itself is considering release of such information, the Commission official who will decide whether to release the information or any other appropriate Commission official will notify the person who submitted the document and give the person an opportunity (at least five calendar days) in which to comment in writing on the request. A copy of this notice will be sent to the requester.
(e) Notification before release. Notice of a decision by the Commission, the Chairman of the Commission, the Director, Office of External Affairs, the General Counsel or General Counsel’s designee, a presiding officer in a proceeding under part 385 of this chapter, or any other appropriate official to deny a claim of privilege, in whole or in part, will be given to any person claiming that the information is privileged no less than 5 calendar days before disclosure. The notice will briefly explain why the person’s objections to disclosure are not sustained by the Commission. A copy of this notice will be sent to the FOIA requester.
(f) Notification of suit in Federal courts. When a FOIA requester brings suit to compel disclosure of information for which a person has claimed privileged treatment, the Commission will notify the person who submitted the documents of the suit.
§ 388.113 Critical Energy/Electric Infrastructure Information (CEII).
(a) Scope. This section governs the procedures for submitting, designating, handling, sharing, and disseminating Critical Energy/Electric Infrastructure Information (CEII) submitted to or generated by the Commission. The Commission reserves the right to restrict access to previously filed information as well as Commission-generated information containing CEII. Nothing in this section limits the ability of any other Federal agency to take all necessary steps to protect information within its custody or control that is necessary to ensure the safety and security of the electric grid. To the extent necessary, such agency may consult with the CEII Coordinator regarding the treatment or designation of such information.
(b) Purpose. The procedures in this section implement section 215A of the Federal Power Act, and provide a comprehensive overview of the manner in which the Commission will implement the CEII program.
(c) Definitions. For purposes of this section:
(1) Critical electric infrastructure information means information related to critical electric infrastructure, or proposed critical electrical infrastructure, generated by or provided to the Commission or other Federal agency other than classified national security information, that is designated as critical electric infrastructure information by the Commission or the Secretary of the Department of Energy pursuant to section 215A(d) of the Federal Power Act. Such term includes information that qualifies as critical energy infrastructure information under the Commission’s regulations. Critical Electric Infrastructure Information is exempt from mandatory disclosure under the Freedom of Information Act, 5 U.S.C. 552(b)(3) and shall not be made available by any Federal, State, political subdivision or tribal authority pursuant to any Federal, State, political subdivision or tribal law requiring public disclosure of information or records pursuant to section 215A(d)(1)(A) and (B) of the Federal Power Act.
(2) Critical energy infrastructure information means specific engineering, vulnerability, or detailed design information about proposed or existing critical infrastructure that:
(i) Relates details about the production, generation, transportation, transmission, or distribution of energy;
(ii) Could be useful to a person in planning an attack on critical infrastructure;
(iii) Is exempt from mandatory disclosure under the Freedom of Information Act, 5 U.S.C. 552; and
(iv) Does not simply give the general location of the critical infrastructure.
(3) Critical electric infrastructure means a system or asset of the bulk-power system, whether physical or virtual, the incapacity or destruction of which would negatively affect national security, economic security, public health or safety, or any combination of such matters.
(4) Critical infrastructure means existing and proposed systems and assets, whether physical or virtual, the incapacity or destruction of which would negatively affect security, economic security, public health or safety, or any combination of those matters.
(d) Criteria and procedures for determining what constitutes CEII. The following criteria and procedures apply to information labeled as CEII:
(1) For information submitted to the Commission:
(i) A person requesting that information submitted to the Commission be treated as CEII must include with its submission a justification for such treatment in accordance with the filing procedures posted on the Commission’s Web site at http://www.ferc.gov. The justification must provide how the information, or any portion of the information, qualifies as CEII, as the terms are defined in paragraphs (c)(1) and (2) of this section. The submission must also include a clear statement of the date the information was submitted to the Commission, how long the CEII designation should apply to the information and support for the period proposed. Failure to provide the justification or other required information could result in denial of the designation and release of the information to the public.
(ii) In addition to the justification required by paragraph (d)(1)(i) of this section, a person requesting that information submitted to the Commission be treated as CEII must clearly label the cover page and pages or portions of the information for which CEII treatment is claimed in bold, capital lettering, indicating that it contains CEII, as appropriate, and marked “DO NOT RELEASE.” The submitter must also segregate those portions of the information that contain CEII (or information that reasonably could be expected to lead to the disclosure of the CEII) wherever feasible. The submitter must also submit to the Commission a public version with the information where CEII is redacted, to the extent practicable.
(iii) If a person files material as CEII in a complaint proceeding or other proceeding to which a right to intervention exists, that person must include a proposed form of protective agreement with the filing, or identify a protective agreement that has already been filed in the proceeding that applies to the filed material.
(iv) The information for which CEII treatment is claimed will be maintained in the Commission’s files as non-public until such time as the Commission may determine that the information is not entitled to the treatment sought. By treating the information as CEII, the Commission is not making a determination on any claim of CEII status. The Commission retains the right to make determinations with regard to any claim of CEII status at any time, and the discretion to release information as necessary to carry out its jurisdictional responsibilities. Although unmarked information may be eligible for CEII treatment, the Commission will treat unmarked information as CEII only if it is properly designated as CEII pursuant to Commission regulations.
(v) The CEII Coordinator will evaluate whether the submitted information or portions of the information are covered by the definitions in paragraphs (c)(1) and (2) of this section prior to making a designation as CEII.
(vi) Subject to the exceptions set forth in paragraph (f)(5) of this section, when a CEII requester seeks information for which CEII status has been claimed, or when the Commission itself is considering release of such information, the CEII Coordinator or any other appropriate Commission official will notify the person who submitted the information and give the person an opportunity (at least five business days) in which to comment in writing on the request. A copy of this notice will be sent to the requester. Notice of a decision by the Commission, or the CEII Coordinator to make a release of CEII, will be given to any person claiming that the information is CEII no less than five business days before disclosure. The notice will respond to any objections to disclosure from the submitter that are not sustained. Where applicable, a copy of this notice will be sent to the CEII requester.
(2) For Commission-generated information:
(i) After consultation with the Office Director for the office that created the information, or the Office Director’s designee, the CEII Coordinator will designate Commission-generated information as CEII after determining that the information or portions of the information are covered by the definitions in paragraphs (c)(1) and (2) of this section. Commission-generated CEII shall include clear markings to indicate the information is CEII and the date of the designation.
(ii) The Commission will segregate non-CEII from Commission-generated CEII or information that reasonably could be expected to lead to the disclosure of CEII wherever feasible.
(e) Duration of the CEII designation. All CEII designations will be subject to the following conditions:
(1) A designation may last for up to a five-year period, unless re-designated. In making a determination as to whether the designation should be extended, the CEII Coordinator will take into account information provided in response to paragraph (d)(1)(i) of this section, and any other information, as appropriate.
(2) A designation may be removed at any time, in whole or in part, if the Commission determines that the unauthorized disclosure of CEII could no longer be used to impair the security or reliability of the bulk-power system or distribution facilities or any other form of energy infrastructure.
(3) The Commission will treat CEII or documents marked as CEII as non-public after the designation has lapsed until the CEII Coordinator determines to un-designate the information.
(4) If a CEII designation is removed, the submitter will receive notice and an opportunity to comment. The CEII Coordinator will notify the submitter of the information and give the submitter an opportunity (at least five business days) in which to comment in writing prior to the removal of the designation. Notice of a removal decision will be given to any submitter claiming that the information is CEII no less than five business days before disclosure. The notice will briefly explain why the submitter’s objections to the removal of the designation are not sustained by the Commission
(f) Voluntary sharing of CEII. The Commission, taking into account standards of the Electric Reliability Organization, will facilitate voluntary sharing of CEII with, between, and by Federal, state, political subdivision, and tribal authorities; the Electric Reliability Organization; regional entities; information sharing and analysis centers established pursuant to Presidential Decision Directive 63; owners, operators, and users of critical electric infrastructure in the United States; and other entities determined appropriate by the Commission. The process will be as follows:
(1) The Director of any Office of the Commission or his designee that wishes to voluntarily share CEII shall consult with the CEII Coordinator prior to the Office Director or his designee making a determination on whether to voluntarily share the CEII.
(2) Consistent with paragraph (d) of this section, the Commission retains the discretion to release information as necessary to carry out its jurisdictional responsibilities in facilitating voluntary sharing or, in the case of information provided to other federal agencies, the Commission retains the discretion to release information as necessary for those agencies to carry out their jurisdictional responsibilities.
(3) All entities receiving CEII must execute either a non-disclosure agreement or an acknowledgement and agreement. A copy of each agreement will be maintained by the Office Director with a copy to the CEII Coordinator.
(4) When the Commission voluntarily shares CEII pursuant to this subsection, the Commission may impose additional restrictions on how the information may be used and maintained.
(5) Submitters of CEII shall receive notification of a limited release of CEII no less than five business days before disclosure, except in instances where voluntary sharing is necessary for law enforcement purposes, to maintain infrastructure security, to address potential threats, when notice would not be practicable, and where there is an urgent need to quickly disseminate the information. When prior notice is not given, the Commission will provide submitters of CEII notice of a limited release of the CEII as soon as practicable.
(g) Accessing CEII. (1) An owner/operator of a facility, including employees and officers of the owner/operator, may obtain CEII relating to its own facility, excluding Commission-generated information except inspection reports/operation reports and any information directed to the owner-operators, directly from Commission staff without going through the procedures outlined in paragraph (g)(5) of this section. Non-employee agents of an owner/operator of such facility may obtain CEII relating to the owner/operator’s facility in the same manner as owner/operators as long as they present written authorization from the owner/operator to obtain such information. Notice of such requests must be given to the CEII Coordinator, who shall track this information.
(2) An employee of a federal agency acting within the scope of his or her federal employment may obtain CEII directly from Commission staff without following the procedures outlined in paragraph (g)(5) of this section. Any Commission employee at or above the level of division director or its equivalent may rule on requests for access to CEII by a representative of a federal agency. To obtain access to CEII, an agency employee must sign an acknowledgement and agreement, which states that the agency will protect the CEII in the same manner as the Commission and will refer any requests for the information to the Commission. Notice of each such request also must be given to the CEII Coordinator, who shall track this information.
(3) A landowner whose property is crossed by or in the vicinity of a project may receive detailed alignment sheets containing CEII directly from Commission staff without submitting a non-disclosure agreement as outlined in paragraph (g)(5) of this section. A landowner must provide Commission staff with proof of his or her property interest in the vicinity of a project.
(4) Any person who is a participant in a proceeding or has filed a motion to intervene or notice of intervention in a proceeding may make a written request to the filer for a copy of the complete CEII version of the document without following the procedures outlined in paragraph (g)(5) of this section. The request must include an executed copy of the applicable protective agreement and a statement of the person’s right to party or participant status or a copy of the person’s motion to intervene or notice of intervention. Any person may file an objection to the proposed form of protective agreement. A filer, or any other person, may file an objection to disclosure, generally or to a particular person or persons who have sought intervention. If no objection to disclosure is filed, the filer must provide a copy of the complete, non-public document to the requesting person within five business days after receipt of the written request that is accompanied by an executed copy of the protective agreement. If an objection to disclosure is filed, the filer shall not provide the non-public document to the person or class of persons identified in the objection until ordered by the Commission or a decisional authority.
(5) If any requester not described above in paragraphs (g)(1) through (4) of this section has a particular need for information designated as CEII, the requester may request the information using the following procedures:
(i) File a signed, written request with the Commission’s CEII Coordinator. The request must contain the following:
(A) Requester’s name (including any other name(s) which the requester has used and the dates the requester used such name(s)), title, address, and telephone number; and the name, address, and telephone number of the person or entity on whose behalf the information is requested;
(B) A detailed Statement of Need, which must state: The extent to which a particular function is dependent upon access to the information; why the function cannot be achieved or performed without access to the information; an explanation of whether other information is available to the requester that could facilitate the same objective; how long the information will be needed; whether or not the information is needed to participate in a specific proceeding (with that proceeding identified); and an explanation of whether the information is needed expeditiously.
(C) An executed non-disclosure agreement as described in paragraph (h)(2) of this section;
(D) A signed statement attesting to the accuracy of the information provided in the request; and
(E) A requester shall provide his or her date and place of birth upon request, if it is determined by the CEII Coordinator that this information is necessary to process the request.
(ii) A requester who seeks the information on behalf of all employees of an organization should clearly state that the information is sought for the organization, that the requester is authorized to seek the information on behalf of the organization, and that all individuals in the organization that have access to the CEII will agree to be bound by a non-disclosure agreement that must be executed.
(iii) After the request is received, the CEII Coordinator will determine if the information is CEII, and, if it is, whether to release the CEII to the requester. The CEII Coordinator will balance the requester’s need for the information against the sensitivity of the information. If the requester is determined to be eligible to receive the information requested, the CEII Coordinator will determine what conditions, if any, to place on release of the information.
(iv) If the CEII Coordinator determines that the CEII requester has not demonstrated a valid or legitimate need for the CEII or that access to the CEII should be denied for other reasons, this determination may be appealed to the General Counsel pursuant to § 388.110. The General Counsel will decide whether the information is properly classified as CEII, which by definition is exempt from release under FOIA, and whether the Commission should in its discretion make such CEII available to the CEII requester in view of the requester’s asserted legitimacy and need.
(v) Once a CEII requester has been verified by Commission staff as a legitimate requester who does not pose a security risk, his or her verification will be valid for the remainder of that calendar year. Such a requester is not required to provide detailed information about himself or herself with subsequent requests during the calendar year. He or she is also not required to file a non-disclosure agreement with subsequent requests during the calendar year because the original non-disclosure agreement will apply to all subsequent releases of CEII.
(vi) An organization that is granted access to CEII pursuant to paragraph (g)(5)(ii) of this section may seek to add additional individuals to the non-disclosure agreement within one (1) year of the date of the initial CEII request. Such an organization must provide the names of the added individuals to the CEII Coordinator and certify that notice of each added individual has been given to the submitter. Any newly added individuals must execute a supplement to the original non-disclosure agreement indicating their acceptance of its terms. If there is no written opposition within five business days of notifying the CEII Coordinator and the submitter concerning the addition of any newly added individuals, the CEII Coordinator will issue a standard notice accepting the addition of these names to the non-disclosure agreement. If the submitter files a timely opposition with the CEII Coordinator, the CEII Coordinator will issue a formal determination addressing the merits of such opposition. If an organization that is granted access to CEII pursuant to paragraph (g)(5)(ii) of this section wants to add new individuals to its non-disclosure agreement more than one year after the date of its initial CEII request, the organization must submit a new CEII request pursuant to paragraph (g)(5)(ii) of this section and a new non-disclosure agreement for each new individual added.
(vii) The CEII Coordinator will attempt to respond to the requester under this section according to the timing required for responses under the FOIA in § 388.108(c).
(viii) Fees for processing CEII requests will be determined in accordance with § 388.109.
(ix) Nothing in this section should be construed as requiring the release of proprietary information, personally identifiable information, cultural resource information, information on rare species of plants and animals, and other comparable data protected by statute or any privileged information, including information protected by the deliberative process privilege.
(h) Duty to protect CEII. Unauthorized disclosure of CEII is prohibited.
(1) To ensure that the Commissioners, Commission employees, and Commission contractors protect CEII from unauthorized disclosure, internal controls will describe the handling, marking, and security controls for CEII.
(2) Any individual who requests information pursuant to paragraph (g)(5) of this section must sign and execute a non-disclosure agreement, which indicates the individual’s willingness to adhere to limitations on the use and disclosure of the information requested. The non-disclosure agreement will, at a minimum, require the following: CEII will only be used for the purpose for which it was requested; CEII may only be discussed with authorized recipients; CEII must be kept in a secure place in a manner that would prevent unauthorized access; CEII must be destroyed or returned to the Commission upon request; the Commission may audit the recipient’s compliance with the non-disclosure agreement; CEII provided pursuant to the agreement is not subject to release under either FOIA or Sunshine Laws; a recipient is obligated to protect the CEII even after a designation has lapsed until the CEII Coordinator determines the information should no longer be designated as CEII under paragraph (e)(2) of this section; and a recipient is required to promptly report all unauthorized disclosures of CEII to the Commission.
(i) Sanctions. Any officers, employees, or agents of the Commission who knowingly and willfully disclose CEII in a manner that is not authorized under this section will be subject to appropriate sanctions, such as removal from the federal service, or possible referral for criminal prosecution. Commissioners who knowingly and willfully disclose CEII without authorization may be referred to the Department of Energy Inspector General. The Commission will take responsibility for investigating and, as necessary, imposing sanctions on its employees and agents.
(j) Administrative appeals of CEII determinations. (1) Submitters who receive a determination that the Commission intends to remove a CEII designation may appeal that determination. The submitter must file notice of its intent to appeal that determination within five business days of the determination. The notice of intent to file an appeal must be sent to the General Counsel, with a copy to the CEII Coordinator. A statement in support of the notice of appeal must be submitted to the General Counsel within 20 business days of the date of the determination. The appeal will be considered received upon receipt of the statement in support of the notice of appeal.
(2) Individuals who receive a determination denying a request for the release of CEII, in whole or in part, or a determination denying a request to change the designation of CEII may appeal such determinations. Such appeals must be submitted to the General Counsel within 20 business days of the date of the determination.
(3) The Commission’s General Counsel or the General Counsel’s designee will make a determination with respect to any appeal within 20 business days after the receipt of the appeal. If, on appeal, the General Counsel or the General Counsel’s designee upholds the determination in whole or in part, then the General Counsel or the General Counsel’s designee will notify the person submitting the appeal of the availability of judicial review.
(4) The time limits prescribed for the General Counsel or his designee to act on an appeal may be extended pursuant to § 388.110(b)(1).
(5) Prior to seeking judicial review in federal district court pursuant to section 215A(d)(11) of the Federal Power Act, a person who received a determination from the Commission concerning a CEII designation must first appeal the determination to the Commission’s General Counsel.
PART 389—OMB CONTROL NUMBERS FOR COMMISSION INFORMATION COLLECTION REQUIREMENTS
§ 389.101 OMB control numbers assigned pursuant to the Paperwork Reduction Act.
This part concerns Office of Management and Budget (OMB) control numbers assigned to information collection requirements. Current OMB control numbers are available at https://www.ferc.gov. For the most current information, interested persons should consult the Commission’s website under “Enforcement Legal” and then “Legal” and then “Information Collections” or directly at https://www.ferc.gov/enforcement-legal/legal/information-collections.
PART 390—ELECTRONIC REGISTRATION
§ 390.1 Electronic registration.
Any person who wishes to engage in any of the activities listed in § 390.2 must register electronically through the Commission’s web site, in compliance with instructions located on the Web site, at http://www.ferc.gov.
§ 390.2 Activities requiring registration.
(a) Electronic registration is a requirement for the following activities:
(1) Submission of all documents in proceedings governed by 18 CFR part 385;
(2) Submission of Forms 1, 2, 6 and 423 pursuant to 18 CFR 141.1, 141.61, 260.1, and 357.2.
(3) Submission of reports in compliance with Order No. 2001.
(4) Filing of tariffs pursuant to 18 CFR 385.205.
(5) Receipt of service pursuant to 18 CFR 385.2010(a) or (b).
(b) Any person who wishes to subscribe to the Commission’s automated document delivery system may register electronically but is not required to do so.
§ 390.3 Waiver applications.
(a) A person may satisfy the requirement of Sec. 390.1 by submitting a written statement showing good cause why the person is unable to register electronically, and including the name and address of the person serving as a contact. The statement must be mailed to the Secretary, Federal Energy Regulatory Commission, 888 First Street, NE., Washington, DC 20426, or hand delivered to Room 1A at the same address.
(b) Persons who register pursuant to paragraph (a) of this section will receive a unique numeric identifier that must appear on all paper submissions to the Commission. A submission that does not include the identifier will be rejected. Notification of such rejection will be sent to the submitter at the address indicated on the paper submission. A request for a waiver may be submitted simultaneously with a document submitted for filing. If the waiver is granted, the Secretary will add the assigned numeric identifier to the submitted document(s), but will not do so for subsequent submissions.
(c) A waiver under paragraph (a) of this section will be valid for one year from the date of issuance by the Secretary. The Secretary will send notice of the pending expiration to the registered person’s address of record approximately three months prior to the expiration of the waiver. After the waiver expires, a person wishing to engage in any of the activities listed in § 390.2 must comply with § 390.1, or must apply for another waiver under paragraph (a) of this section.
§ 390.4 Exemptions.
In instances in which the Commission receives communications from persons who are not registered under this part that relate to docketed proceedings and in which it appears that registration under this part offers no value to the person submitting the communication, the Commission may accept the communication for filing without requiring the person to comply with § 390.1 or § 390.3.