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Title 18 – Conservation of Power and Water Resources–Volume 1

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Title 18 – Conservation of Power and Water Resources–Volume 1


Part


chapter i – Federal Energy Regulatory Commission, Department of Energy

1


Abbreviations Used in This Chapter:

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


Authority:Dept. of Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 3 CFR 142 (1978); Administrative Procedure Act, 5 U.S.C. Ch. 5.

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.


[Order 225, 47 FR 19022, May 3, 1982; 48 FR 786, Jan. 7, 1983]


§ 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.


[Order 225, 47 FR 19022, May 3, 1982]


PART 1b – RULES RELATING TO INVESTIGATIONS


Authority:15 U.S.C. 717-717z, 3301-3432; 16 U.S.C. 792-828c, 2601-2645; 42 U.S.C. 7101-7352; 49 U.S.C. 60502; 49 App. U.S.C. 1-85 (1988); E.O. 12009, 3 CFR 1978 Comp., p. 142.


Source:43 FR 27174, June 23, 1978, unless otherwise noted.

§ 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.


[43 FR 27174, June 23, 1978, as amended by Order 602, 64 FR 17097, Apr. 8, 1999]


§ 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.


[43 FR 27174, June 23, 1978, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


§ 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.


[43 FR 27174, June 23, 1978, as amended by Order 225, 47 FR 19054, May 3, 1982; Order 756, 77 FR 4893, Feb. 1, 2012]


§ 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.


[43 FR 27174, June 23, 1978, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


§ 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.


[43 FR 27174, June 23, 1978, as amended by Order 225, 47 FR 19054, May 3, 1982]


§ 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.


[43 FR 27174, June 23, 1978, as amended by Order 225, 47 FR 19054, May 3, 1982]


§ 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.


[Order 711, 73 FR 29433, May 21, 2008]


§ 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.


[Order 602, 64 FR 17097, Apr. 8, 1999, as amended by Order 647, 69 FR 32438, June 10, 2004; Order 734, 75 FR 21505, Apr. 26, 2010; Order 821, 81 FR 5379, Feb. 2, 2016]


§ 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.


[Order 821, 81 FR 5379, Feb. 2, 2016]


PART 1c – PROHIBITION OF ENERGY MARKET MANIPULATION


Authority:15 U.S.C. 717-717z; 16 U.S.C. 791-825r, 2601-2645; 42 U.S.C. 7101-7352.


Source:71 FR 4258, Jan. 26, 2006, unless otherwise noted.

§ 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


Authority:5 U.S.C. 601; 15 U.S.C. 717-717z, 3301-3432; 16 U.S.C. 792-828c, 2601-2645; 42 U.S.C. 4321-4370h, 7101-7352.

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 Federal Register shall be the primary means of informing interested persons and the general public that the proceeding to which the notice or order relates has been instituted before the Commission. The mailing or e-mailing of individual copies shall be confined to that which is required by law, by the Commission’s rules and regulations, or by other considerations deemed valid by the Secretary in specific instances.


(1) It is the policy of the Commission to publish notice in the Federal Register upon the institution of the following proceedings before the Commission:


(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.


(Secs. 308, 309; 49 Stat. 858; 16 U.S.C. 825g, 825h; secs. 15, 16; 52 Stat. 829, 830; 15 U.S.C. 717n, 717o)

[Order 211, 24 FR 1345, Feb. 21, 1959, as amended by Order 463, 37 FR 28054, Dec. 20, 1972; 38 FR 3192, Feb. 2, 1973; 44 FR 34941, June 18, 1979; 45 FR 21224, Apr. 1, 1980; Order 541, 57 FR 21733, May 22, 1992; Order 603, 64 FR 26603, May 14, 1999; Order 2002, 68 FR 51115, Aug. 25, 2003; Order 737, 75 FR 43402, July 26, 2010; Order 756, 77 FR 4893, Feb. 1, 2012]


§ 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.


[Order 547, 41 FR 15004, Apr. 9, 1976, as amended by Order 225, 47 FR 19054, May 3, 1982]


§ 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.


[58 FR 38292, July 16, 1993]


§ 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.


[Order 635, 68 FR 46455, Aug. 6, 2003, as amended at 84 FR 56941, Oct. 24, 2019]


Statements of General Policy and Interpretations Under the Federal Power Act


Authority:Sections 2.2 through 2.13, issued under sec. 309, 49 Stat. 858; 16 U.S.C. 825h, unless otherwise noted.

§ 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.


[Order 141, 12 FR 8471, Dec. 19, 1947. Redesignated by Order 147, 13 FR 8259, Dec. 23, 1948]


§ 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.


(Natural Gas Act, 15 U.S.C. 717-717w (1976 & Supp. IV 1980); Federal Power Act, 16 U.S.C. 791a-828c (1976 & Supp. IV 1980); Dept. of Energy Organization Act, 42 U.S.C. 7101-7352 (Supp. IV 1980); E.O. 12009, 3 CFR part 142 (1978); 5 U.S.C. 553 (1976))

[Order 141, 12 FR 8471, Dec. 19, 1947. Redesignated by Order 147, 13 FR 8259, Dec. 23, 1948, and amended by Order 303, 48 FR 24361, June 1, 1983; Order 575, 60 FR 4852, Jan. 25, 1995]


§ 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.


[Order 313, 30 FR 16198, Dec. 29, 1965, as amended by Order 375-B, 35 FR 6315, Apr. 18, 1970; Order 508, 39 FR 16338, May 8, 1974; Order 2002, 68 FR 51115, Aug. 25, 2003]


§ 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.


(Secs. 3, 4, 15, 16, 301, 304, 308, and 309 (41 Stat. 1063-1066, 1068, 1072, 1075; 49 Stat. 838, 839, 840, 841, 854-856, 858-859; 82 Stat. 617; 16 U.S.C. 796, 797, 803, 808, 809, 816, 825, 825b, 825c, 825g, 825h, 826i), as amended, secs. 8, 10, and 16 (52 Stat. 825-826, 830; 15 U.S.C. 717g, 717i, 717o))

[Order 348, 32 FR 8521, June 14, 1967, as amended by Order 540, 40 FR 51998, Nov. 7, 1975; Order 567, 42 FR 30612, June 16, 1977; Order 699, 72 FR 45323, Aug. 14, 2007; Order 737, 75 FR 43402, July 26, 2010; Order 756, 77 FR 4893, Feb. 1, 2012]


§ 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.


(Secs. 3, 4, 15, 16, 301, 304, 308, and 309 (41 Stat. 1063-1066, 1068, 1072, 1075; 49 Stat. 838, 839, 840, 841, 854-856, 858-859; 82 Stat. 617; 16 U.S.C. 796, 797, 803, 808, 809, 816, 825, 825b, 825c, 825g, 825h, 826i), as amended, Secs. 8, 10, and 16 (52 Stat. 825-826, 830; 15 U.S.C. 717g, 717i, 717o))

[Order 404, 35 FR 7964, May 23, 1970, as amended by Order 567, 42 FR 30612, June 16, 1977]


§ 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.


(Secs. 3, 4, 15, 16, 301, 304, 308, and 309 (41 Stat. 1063-1066, 1068, 1072, 1075; 49 Stat. 838, 839, 840, 841, 854-856, 858-859; 82 Stat. 617; 16 U.S.C. 796, 797, 803, 808, 809, 816, 825, 825b, 825c, 825g, 825h, 826i), as amended, Secs. 8, 10, and 16 (52 Stat. 825-826, 830; 15 U.S.C. 717g, 717i, 717o))

[Order 414, 35 FR 18586, Dec. 8, 1970, as amended by Order 567, 42 FR 30612, June 16, 1977; Order 737, 75 FR 43402, July 26, 2010; Order 756, 77 FR 4893, Feb. 1, 2012; 77 FR 8095, Feb. 14, 2012]


§ 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 Federal Register.


(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.


[Order 550, 41 FR 27032, July 1, 1976]


§ 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.


[Order 563, 42 FR 16132, Mar. 25, 1977, as amended by Order 225, 47 FR 19054, May 3, 1982]


§ 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.


[52 FR 11, Jan. 11, 1987]


§ 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.


[Order 481-A, 53 FR 15804, May 4, 1988]


§ 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).


[58 FR 38969, July 21, 1993]


§ 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.


[58 FR 41632, Aug. 5, 1993]


§ 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.


[59 FR 55039, Nov. 3, 1994]


§ 2.23 Use of reserved authority in hydropower licenses to ameliorate cumulative impacts.

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.


[59 FR 66718, Dec. 28, 1994]


§ 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.


[60 FR 347, Jan. 4, 1995]


§ 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.


[59 FR 65938, Dec. 22, 1994, as amended by Order 579, 60 FR 22261, May 5, 1995]


§ 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.


[Order 592, 61 FR 68606, Dec. 30, 1996, as amended by Order 669-A, 71 FR 28443, May 16, 2006]


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 Web site is at http://www.naesb.org/. Copies may be inspected at the Federal Energy Regulatory Commission, Public Reference and Files Maintenance Branch, 888 First Street NE., Washington, DC 20426, Tel: (202) 502-8371, http://www.ferc.gov.


[79 FR 56954, Sept. 24, 2014, as amended by Order 676-I, 85 FR 10585, Feb. 25, 2020]


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.


(Natural Gas Act, 15 U.S.C. 717-717w (1976 & Supp. IV 1980); Federal Power Act, 16 U.S.C. 791a-828c (1976 & Supp. IV 1980); Dept. of Energy Organization Act, 42 U.S.C. 7101-7352 (Supp. IV 1980); E.O. 12009, 3 CFR part 142 (1978); 5 U.S.C. 553 (1976))

[Order 303, 48 FR 24361, June 1, 1983]


§ 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]


(Sec. 7, 52 Stat. 824; 15 U.S.C. 717f)

[Order 148, 14 FR 681, Feb. 16, 1949]


Editorial Note:For Federal Register citations affecting § 2.55, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 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.


(52 Stat. 824; 56 Stat. 83; 15 U.S.C. 717f)

[Gen. Policy 62-1, 26 FR 10098, Oct. 27, 1961, as amended by Order 737, 75 FR 43402, July 26, 2010]


§ 2.60 Facilities and activities during an emergency – accounting treatment of defense-related expenditures.

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.


(Secs. 3, 4, 15, 16, 301, 304, 308, and 309 (41 Stat. 1063-1066, 1068, 1072, 1075; 49 Stat. 838, 839, 840, 841, 854-856, 858-859; 82 Stat. 617; 16 U.S.C. 796, 797, 803, 808, 809, 816, 825, 825b, 825c, 825g, 825h, 826i), as amended, secs. 8, 10, and 16 (52 Stat. 825-826, 830; 15 U.S.C. 717g, 717i, 717o))

[Order 274, 28 FR 12866, Dec. 4, 1963, as amended by Order 567, 42 FR 30612, June 16, 1977]


§ 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.


(Secs. 3, 4, 5, 8, 9, 10, 15, 16, 301, 304, 308, and 309 (41 Stat. 1063-1066, 1068, 1072, 1075; 49 Stat. 838, 839, 840, 841, 854-856, 858-859; 52 Stat. 822, 823, 825, 826; 76 Stat. 72; 82 Stat. 617; 16 U.S.C. 796, 797, 803, 808, 809, 816, 825, 825b, 825c, 825g, 825h, 826i); as amended, secs. 8, 10, and 16 (52 Stat. 825-826, 830; 15 U.S.C. 717c, 717d, 717g, 717h, 717i, 717o))

[Order 404, 35 FR 7964, May 23, 1970, as amended by Order 567, 42 FR 30612, June 16, 1977]


§ 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.


[50 FR 16080, Apr. 24, 1985, as amended by Order 436, 50 FR 42487, Oct. 18, 1985]


§ 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.


(Sec. 4, 52 Stat. 822, 76 Stat. 72 (15 U.S.C. 717c); Sec. 5, 52 Stat. 823 (15 U.S.C. 717d); Sec. 7, 52 Stat. 824, 825, 56 Stat. 83, 84, 61 Stat. 459 (15 U.S.C. 717f); Sec. 10, 52 Stat. 826 (15 U.S.C. 717i); Sec. 14, 52 Stat. 820 (15 U.S.C. 717m); Sec. 15, 52 Stat. 829 (15 U.S.C. 717n); Sec. 16, 52 Stat. 930 (15 U.S.C. 717o); Pub. L. 96-511, 94 Stat. 2812 (44 U.S.C. 3501 et seq.))

[Order 467A, 38 FR 2171, Jan. 22, 1973, as amended by Order 467B, 38 FR 6386, Mar. 9, 1973; Order 493-A, 38 FR 30433, Nov. 5, 1973; Order 467-C, 39 FR 12984, Apr. 10, 1974; Order 225, 47 FR 19055, May 3, 1982]


Statement of General Policy To Implement Procedures for Compliance With the National Environmental Policy Act of 1969


Authority:Sections 2.80-2.82 issued under secs. 4, 10, 15, 307, 309, 311 and 312 (41 Stat. 1065, 1066, 1068, 1070; 46 Stat. 798, 49 Stat. 839, 840, 841, 942, 843, 844, 856, 857, 858, 859, 860, Stat. 501, 82 Stat. 617; 16 U.S.C. 797, 803, 808, 825f, 825h, 825j, 825k), and the Natural Gas Act, particularly secs. 7 and 16 (52 Stat. 824, 825, 830, 56 Stat. 83, 84; 61 Stat. 459; 15 U.S.C. 717f, 717o), and the National Environmental Policy Act of 1969, Pub. L. 91-190, approved January 1, 1970, particularly secs. 102 and 103 (83 Stat. 853, 854), unless otherwise noted.

§ 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.


[Order 486, 52 FR 47910, Dec. 17, 1987]


Statement of General Policy To Implement the Economic Stabilization Act of 1970, as Amended, and Executive Orders 11615 and 11627


Authority:Sections 2.90 through 2.102 issued under 84 Stat. 799, as amended, 85 Stat. 38, unless otherwise noted.

§§ 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.


(Natural Gas Act, 15 U.S.C. 717-717w; Natural Gas Policy Act of 1978, Pub. L. No. 95-621, 92 Stat. 3350, 15 U.S.C. 3301-3432)

[47 FR 57269, Dec. 23, 1982]


§ 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.


[Order 500, 52 FR 30351, Aug. 14, 1987, as amended at 52 FR 35539, Sept. 22, 1987; Order 500-F, 53 FR 50924, Dec. 19, 1988; 54 FR 52394, Dec. 21, 1989; Order 581, 60 FR 53064, Oct. 11, 1995]


§ 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.


[Order 500, 52 FR 30352, Aug. 14, 1987; 52 FR 35539, Sept. 22, 1987, and 54 FR 52394, Dec. 21, 1989]


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.


(Natural Gas Policy Act of 1978, Pub. L. 95-621, 92 Stat. 3350, (15 U.S.C. 3301-3432))

[47 FR 6262, Feb. 11, 1982]


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.


[Order 471, 52 FR 19310, May 22, 1987]


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.


[Order 594, 62 FR 15830, Apr. 3, 1997]


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 track25-50 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.


[Order 790A, 79 FR 70068, Nov. 25, 2014]


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
production, exploration and development costs
2Direct and indirect lease costs and expenses1-A011,694,893,5581,694,893,55857,287,938$144,679,567$19,763,791$221,731,29690.33207,740,782
2Taxes (except income and production)A-102210,335,720210,335,72016,507,63020,431,4444,360,02441,299,0989.3339,323,337
4Production taxes1-A03479,424,29727,124,21096,699,67310,005,599133,829,48290.33124,478,624
5Other lease expenses1-A0461,102,43361,102,43317,527,07724,988,900336,42742,852,40490.3340,435,977
6Depletion, depreciation and amortization1-A051,716,823,0701,716,823,070105,999,777297,881,31225,502,048429,383,13790.33400,578,014
7Corporate general expense1-A06278,845,909278,845,90913,611,33725,077,7963,579,72842,268,86190.3339,843,838
8Area, district, division and field expense1-A07261,718,41726,178,4177,207,32021,758,6042,778,94431,744,86890.3329,640,811
9Miscellaneous lease revenues1-A09(12,203,136)(12,203,136)(1,348,729)(2,768,788)(314,067)(4,431,584)90.33(4,163,842)
10Return on production rate base at 15 percent1-A132,505,272,6722,505,272,672186,055,524427,939,60169,857,212663,852,33790.33622,470,578
11Exploration and development costs and expenses1-A151,673,945,8531,673,945,853594,971,262
12Return on exploration rate base at 15 percent1-A16588,558,894588,558,894234,604,103
13Regulatory commission expense including return1-A176,514,2796,514,2796,514,852
14
15 Total computed revenue9,465,231,9668,985,807,6692,336,439,376
16 (gross income)
17
18 revenue deductions
19Direct and indirect lease costs and expenses1-A011,694,893,5581,694,893,558207,740,872
20Taxes (except income and production)1-A02210,335,720210,335,72039,323,377
21Production taxes1-A03479,424,297124,478,624
22Other lease expenses1-A0461,102,43361,102,43340,435,977
23Book depletion
7 (283,121,142)
283,121,24224,287,98661,675,8286,177,59692,141,41090.3386,177,357
24Depreciation expense1-A05
7 (654,604,447)
654,604,44730,223,58694,010,5207,007,662131,241,76890.33122,150,951
25Amortization of capitalized IDC
7 (779,097,382)
779,097,38251,488,205142,194,96412,316,790205,999,95990.33192,249,706
26Corporate general expense1-A06278,845,909278,845,90939,843,838
27Area, district, division and field expense1-A07261,718,417261,718,41729,640,811
28Miscellaneous lease revenues1-A09(12,203,136)(12,203,136)(4,163,842)
29Exploration and development costs and expenses1,673,945,8531,673,945,853594,971,262
30Regulatory commission expense4-A016,384,3846,394,3846,394,384
31
32 Total book expenses6,371,380,5055,891,856,2091,479,243,227
33
34Production net income (line 15 less line 32)3,093,951,4613,093,951,460857,190,149
35
36 tax adjustment – add (deduct)
37Amortization of capitalized IDC779,097,282779,097,382192,249,706
38Estimated IDC capitalized in 1972
8 (1,470,935,857)
(1,470,935,857)(362,967,445)
39Interest expense (calculated)
9 (243,846,540)
(243,846,540)(60,587,136)
40
41 Taxable income2,158,266,4452,158,266,445625,891,274
42
43 Federal income tax at 48 percent1,992,245,9491,992,245,949
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.


[Opinion 749, 41 FR 3092, Jan. 21, 1976]


PART 3 [RESERVED]

PART 3a – NATIONAL SECURITY INFORMATION


Authority:15 U.S.C. 717o; 16 U.S.C. 825h.


Source:Order 470, 38 FR 5161, Feb. 26, 1973, unless otherwise noted.

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.


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


§ 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).)


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 225, 47 FR 19055, May 3, 1982]


§ 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;



Such offices in the Executive Office of the President as the President may designate in writing.

Central Intelligence Agency.

Atomic Energy Commission.

Department of State.

Department of the Treasury.

Department of Defense.

Department of the Army.

Department of the Navy.

Department of the Air Force.

U.S. Arms Control and Disarmament Agency

Department of Justice.

National Aeronautics and Space Administration.

Agency for International Development.

(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:



Department of Transportation.

Federal Communications Commission.

Export-Import Bank of the United States.

Department of Commerce.

U.S. Civil Service Commission.

U.S. Information Agency.

General Services Administration.

Department of Health, Education, and Welfare.

Civil Aeronautics Board.

Federal Maritime Commission.

Federal Energy Regulatory Commission.

National Science Foundation.

Overseas Private Investment Corporation.

(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.


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


§ 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.


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


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.


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


§ 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:



Office of the Secretary, Federal Energy Regulatory Commission, Washington, DC 20426.

The Office of the Secretary will assign the request to the appropriate Bureau or Office for action and will acknowledge in writing the receipt of the request. If the request requires the rendering of services for which fair and equitable fees should be charged pursuant to Title 5 of the Independent Offices Appropriations Act, 1952, 31 U.S.C. 483a, the requester shall be so notified. The Bureau or Office which is assigned action will make a determination within 30 days of receipt or explain why further time is necessary. If at the end of 60 days from receipt of the request for review no determination has been made, the requester may apply to the FERC Review Committee (paragraph (g) of this section) for a determination. Should the Bureau or Office assigned the action on a request for review determine that under the criteria set forth in section 5(B) of E.O. 11652 continued classification is required, the requester will be notified promptly and, whenever possible, provided with a brief statement as to why the requested information or material cannot be declassified. The requester may appeal any such determination to the FERC Review Committee and the notice of determination will advise him of this right.

(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.


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


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:



Regarded

(appropriate classification)

When separated from

(identify higher classified components)

(2) If unclassified when separated from its classified enclosures or attachments:



When the Attachments Are Removed, This Transmittal Letter Becomes Unclassified.

(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:



Special Handling Required Not Releasable to Foreign Nationals

(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.


When classification changes are made, the classification markings themselves will be changed or canceled, and each copy or item of the material will be marked with the citation of authority. The notation below will be used for this purpose:


Classification

(changed)



(canceled)

To

Effective on

(date)

Under authority of

(authorizing official or office)

By

(person or office taking 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:


Restricted Data


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:



Formerly Restricted Data

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.



National Security Information

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:



Warning Notice – Sensitive Intelligence Sources and Methods Involved

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.


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


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.


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


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.


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


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:



9006 – Sixth classified document controlled by the central control registry in calendar year 1969.

TS 1006 – Sixth Top Secret document controlled by the central control registry in calendar year 1971.

(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.


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


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.


[Order 470, 38 FR 5161, Feb. 26, 1973, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


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


Authority:Federal Power Act, as amended, sec. 309, 49 Stat. 858-859 (16 U.S.C. 825h); Natural Gas Act, as amended, sec. 16, 52 Stat. 830 (15 U.S.C. 717o); and Pub. L. 93-579 (88 Stat. 1896).


Source:Order 536, 40 FR 44288, Sept. 25, 1975, unless otherwise noted.

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.


[Order 536, 40 FR 44288, Sept. 25, 1975, as amended by Order 737, 75 FR 43402, July 26, 2010]


§ 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 Federal Register a notice identifying the systems of records currently maintained by the Commission. For each system of records, the notice will include the following information:


(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 Federal Register a notice of its intention to establish a new system of records reciting the information required pursuant to paragraphs (a) (1) through (10) of this section and notice of any major change to an existing system.


(c) The Commission will publish in the Federal Register a notice of its intention to establish any new or intended routine use of the information in an existing system of records at least thirty days prior to the disclosure of the record for that routine use. A new routine use is one which involves disclosure of records for a new purpose compatible with the purpose for which the record is maintained or which involves disclosure to a new recipient or category of recipients. At a minimum, the notice will contain the following information:


(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 Federal Register under which the existing system had already been published.


§ 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 Federal Register the specific provisions in law which authorize it to maintain information in a system of records. In determining the relevance and necessity of records, the following considerations will govern:


(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 Federal Register in the notice of the system of records in which the information is maintained, and which are relatable and necessary to a purpose described pursuant to paragraph (b)(2) of this section; and


(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.


Third party sources, where feasible, will be informed of the purposes for which information which they are asked to provide will be used. In appropriate circumstances, pursuant to 5 U.S.C. 552a(k) (2), (5), and (7), the Commission may assure a third party that his identity will not be revealed to the subject of the collected 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.


[Order 536, 40 FR 44288, Sept. 25, 1975, as amended by Order 737, 75 FR 43402, July 26, 2010]


§ 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 Federal Register. The system managers, who are responsible for providing protection and accountability of such records at all times and for insuring that the records are secured in proper containers whenever they are not in use or under direct control of authorized persons, will be identified for each system of records in the Federal Register.


(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 Federal Register as exempt from certain provisions of the Privacy Act of 1974, pursuant to subpart D of this part; and


(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.


[Order 536, 40 FR 44288, Sept. 25, 1975, as amended by Order 737, 75 FR 43402, July 26, 2010]


§ 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.


[Order 536, 40 FR 44288, Sept. 25, 1975, as amended by Order 737, 75 FR 43402, July 26, 2010]


§ 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.


In addition to stripping personally identifying information from records released for statistical purposes, the system manager will ensure that the identity of the individual cannot reasonably be deduced or determined by combining various statistical records, or by reference to public records or other available sources of information;

(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 Federal Register is made in accordance with the requirements (including general public notice) of the Administrative Procedure Act, 5 U.S.C. 553, to include, at a minimum:


(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


Authority:15 U.S.C. 717g; 16 U.S.C. 825(b); 42 U.S.C. 7171, 7172.


Source:Order 589, 61 FR 43415, Aug. 23, 1996, unless otherwise noted.

§ 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.


[Order 589, 61 FR 43415, Aug. 23, 1996, as amended by Order 699, 72 FR 45323, Aug. 14, 2007]


§ 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


Authority:16 U.S.C. 791a-825r; 42 U.S.C. 7101-7352.



Source:Order 141, 12 FR 8485, Dec. 19, 1947, unless otherwise noted.

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)).


[Order 53, 44 FR 61948, Oct. 29, 1979]


§ 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.


[Order 53, 44 FR 61948, Oct. 29, 1979]


§ 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.


(Administrative Procedure Act, 5 U.S.C. 551-557 (1976); Federal Power Act, as amended, 16 U.S.C. 291-628 (1976 & Supp. V 1981), Dept. of Energy Organization Act 42 U.S.C. 7101-7352 (Supp. V 1981); E.O. 12009, 3 CFR 142 (1978))

[Order 141, 12 FR 8485, Dec. 19, 1947, as amended by Order 344, 48 FR 49010, Oct. 24, 1983; Order 737, 75 FR 43402, July 26, 2010]


§ 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.


[Order 141, 12 FR 8485, Dec. 19, 1947, as amended by Order 225, 47 FR 19056, May 3, 1982]


§ 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.


[Order 53, 44 FR 61948, Oct. 29, 1979]


§ 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.


[Order 53, 44 FR 61948, Oct. 29, 1979]


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.


[Order 53, 44 FR 61948, Oct. 29, 1979]


§ 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.


(Administrative Procedure Act, 5 U.S.C. 551-557 (1976); Federal Power Act, as amended, 16 U.S.C. 291-628 (1976 & Supp. V 1981), Dept. of Energy Organization Act 42 U.S.C. 7101-7352 (Supp. V 1981); E.O. 12009, 3 CFR 142 (1978))

[Order 141, 12 FR 8485, Dec. 19, 1947, as amended by Order 344, 48 FR 49010, Oct. 24, 1983; Order 737, 75 FR 43402, July 26, 2010]


§ 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.


[Order 53, 44 FR 61949, Oct. 29, 1979, as amended by Order 225, 47 FR 19056, May 3, 1982]


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)).


[Order 53, 44 FR 61949, Oct. 29, 1979]


§ 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.


(Administrative Procedure Act, 5 U.S.C. 551-557 (1976); Federal Power Act, as amended, 16 U.S.C. 291-628 (1976 & Supp. V 1981), Dept. of Energy Organization Act 42 U.S.C. 7101-7352 (Supp. V 1981); E.O. 12009, 3 CFR 142 (1978))

[Order 141, 12 FR 8485, Dec. 19, 1947, as amended by Order 344, 48 FR 49010, Oct. 24, 1983; Order 737, 75 FR 43402, July 26, 2010]


§ 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.


[Order 141, 12 FR 8485, Dec. 19, 1947, as amended by Order 225, 47 FR 19056, May 3, 1982]


§ 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.


[Order 53, 44 FR 61949, Oct. 29, 1979]


Subpart D – Application for Preliminary Permit, License or Exemption: General Provisions


Authority:Federal Power Act, as amended, 16 U.S.C. 792-828c; Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267; Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601-2645; Pub. L. 96-511, 94 Stat. 2812 (44 U.S.C. 3501 et seq.).

§ 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 Federal Register in accordance with 25 CFR 83.6(b), and whose legal rights as a tribe may be affected by the development and operation of the hydropower project proposed (as where the operation of the proposed project could interfere with the management and harvest of anadromous fish or where the project works would be located within the tribe’s reservation).


(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.


[Order 413, 50 FR 11676, Mar. 25, 1985]


Editorial Note:For Federal Register citations affecting § 4.30, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 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.


[Order 413, 50 FR 11678, Mar. 25, 1985, as amended by Order 800, 79 FR 59109, Oct. 1, 2014]


§ 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



State of

County of

by

(Name)

(Address)

being duly sworn, depose(s) and say(s) that the contents of this (application, etc.) are true to the best of (his or her) knowledge or belief. The undersigned applicant(s) has (have) signed the (application, etc.) this ____________ day of ______________, 19____.



(Applicant(s))

By:

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____.


/SEAL/ [if any]



(Notary Public, or other authorized official)

(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.


[Order 413, 50 FR 11678, Mar. 25, 1985]


Editorial Note:For Federal Register citations affecting § 4.32, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 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.


[Order 413, 50 FR 11680, Mar. 25, 1985, as amended by Order 499, 53 FR 27002, July 18, 1988; Order 2002, 68 FR 51116, Aug. 25, 2003; Order 699, 72 FR 45324, Aug. 14, 2007]


§ 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 Federal Register inviting comment on the applicant’s request to use alternative procedures. The Commission will consider any such comments in determining whether to grant or deny the applicant’s request to use alternative procedures. Such a decision will not be subject to interlocutory rehearing or appeal.


(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 Federal Register and the applicant will give notice, in a local newspaper of general circulation in the county or counties in which the project is located, of the initial information meeting and the scoping of environmental issues. The applicant will also send notice of these stages to a mailing list approved by the Commission.


(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).


[Order 533, 56 FR 23148, May 20, 1991, as amended at 56 FR 61155, Dec. 2, 1991; Order 540, 57 FR 21737, May 22, 1992; Order 596, 62 FR 59810, Nov. 5, 1997; Order 2002, 68 FR 51116, Aug. 25, 2003; Order 643, 68 FR 52094, Sept. 2, 2003; 68 FR 61742, Oct. 30, 2003; Order 756, 77 FR 4893, Feb. 1, 2012; Order 800, 79 FR 59110, Oct. 1, 2014]


§ 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.


[Order 413, 50 FR 11680, Mar. 25, 1985, as amended by Order 499, 53 FR 27002, July 18, 1988; Order 533, 56 FR 23149, May 20, 1991; Order 2002, 68 FR 51115, Aug. 25, 2003; Order 756, 77 FR 4893, Feb. 1, 2012]


§ 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.


[Order 413, 50 FR 11680, Mar. 25, 1985; 50 FR 23947, June 7, 1985]


§ 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.


[Order 413, 50 FR 11682, Mar. 25, 1985, as amended by Order 2002, 68 FR 51117, Aug. 25, 2003]


§ 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).


[Order 533, 56 FR 23153, May 20, 1991, as amended at 56 FR 61155, Dec. 2, 1991; Order 2002, 68 FR 51117, Aug. 25, 2003; Order 643, 68 FR 52094, Sept. 2, 2003; 68 FR 61742, Oct. 30, 2003; Order 756, 77 FR 4894, Feb. 1, 2012; Order 800, 79 FR 59110, Oct. 1, 2014]


§ 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.


[Order 54, 44 FR 61334, Oct. 25, 1979. Redesignated by Order 413, 50 FR 11678, Mar. 25, 1985; Order 2002, 68 FR 51119, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003; Order 756, 77 FR 4894, Feb. 1, 2012; Order 769, 77 FR 65474, Oct. 29, 2012; Order 798, 79 FR 42974, July 24, 2014; Order 800, 79 FR 59110, Oct. 1, 2014; 83 FR 53575, Oct. 24, 2018]


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.


[Order 184, 46 FR 55936, Nov. 13, 1981, as amended by Order 413, 50 FR 11683, Mar. 25, 1985; Order 499, 53 FR 27002, July 18, 1988; Order 2002, 68 FR 51119, Aug. 25, 2003; Order 877, 86 FR 42714, Aug. 5, 2021]


§ 4.41 Contents of application.

Any application under this subpart must contain the following information in the form prescribed:



(a) Initial statement.


Before the Federal Energy Regulatory Commission

Application for License for Major Unconstructed Project or Major Modified Project

(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:


State or territory:

County:

Township or nearby town:

Stream or other body of water:

(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.


[Order 184, 46 FR 55936, Nov. 13, 1981; 48 FR 4459, Feb. 1, 1983, as amended by Order 413, 50 FR 11684, Mar. 25, 1985; Order 464, 52 FR 5449, Feb. 23, 1987; Order 540, 57 FR 21737, May 22, 1992; Order 2002, 68 FR 51119, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003; 68 FR 63194, Nov. 7, 2003; 68 FR 69957, Dec. 16, 2003; Order 699, 72 FR 45324, Aug. 14, 2007]


Subpart F – Application for License for Major Project – Existing Dam


Authority:Federal Power Act, as amended (16 U.S.C. 792-828c); Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 2601-2645); Department of Energy Organization Act (42 U.S.C. 7101-7352); E.O. 12009, 42 FR 46267; Pub. L. 96-511, 94 Stat. 2812 (44 U.S.C. 3501 et seq.).

§ 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.


[Order 59, 44 FR 67651, Nov. 27, 1979, as amended by Order 184, 46 FR 55942, Nov. 13, 1981; Order 413, 50 FR 11684, Mar. 25, 1985; Order 499, 53 FR 27002, July 18, 1988; Order 877, 86 FR 42714, Aug. 5, 2021]


§ 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.



Before the Federal Energy Regulatory Commission

Application for License for Major Project – Existing Dam

(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:


State or territory:

County:

Township or nearby town:

Stream or other body of water:

(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))
1
;




1 33 CFR part 323 was revised at 47 FR 31810, July 22, 1982, and § 323.3(e) no longer exists.


(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.


[Order 141, 12 FR 8485, Dec. 19, 1947, as amended by Order 123, 46 FR 9029, Jan. 28, 1981; Order 183, 46 FR 55251, Nov. 9, 1981; Order 184, 46 FR 55942, Nov. 13, 1981; Order 413, 50 FR 11684, Mar. 25, 1985; Order 464, 52 FR 5449, Feb. 23, 1987; Order 540, 57 FR 21737, May 22, 1992; Order 2002, 68 FR 51120, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003]


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 at the Commission’s Public Reference Room. 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.


[Order 413, 50 FR 11685, Mar. 25, 1985, as amended by Order 513, 54 FR 23806, June 2, 1989; Order 2002, 68 FR 51120, Aug. 25, 2003; Order 877, 86 FR 42714, Aug. 5, 2021]


§ 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.



Before the Federal Energy Regulatory Commission

Application for License for a [Minor Water Power Project, or Major Water Power Project, 10 Megawatts or Less, as Appropriate]

(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:


State or territory:

County:

Township or nearby town:

Stream or other body of water:

(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:


☐ existing dam ☐ unconstructed dam

☐ existing dam, major modified project (see § 4.30(b)(14))

(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:


☐ Surveyed land ☐ Unsurveyed land

(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.


[Order 185, 46 FR 55949, Nov. 13, 1981, as amended by Order 413, 50 FR 11685, Mar. 25, 1985; Order 464, 52 FR 5449, Feb. 23, 1987; Order 513, 54 FR 23806, June 2, 1989; Order 2002, 68 FR 51120, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003; Order 877, 86 FR 42714, Aug. 5, 2021]


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.


[Order 184, 46 FR 55942, Nov. 13, 1981, as amended by Order 2002, 68 FR 51120, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003]


§ 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.



Before the Federal Energy Regulation Commission

Application for License for Transmission Line Only

(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:


State or territory:

County:

Township or nearby town:

(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.


[Order 184, 46 FR 55942, Nov. 13, 1981, as amended by Order 413, 50 FR 11685, Mar. 25, 1985; Order 699, 72 FR 45324, Aug. 14, 2007; Order 877, 86 FR 42714, Aug. 5, 2021]


Subpart I – Application for Preliminary Permit; Amendment and Cancellation of Preliminary Permit


Authority:Federal Power Act, as amended 16 U.S.C. 792-828c; Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267; Public Utility Regulatory Policies Act of 1978, 16 U.S.C. 2601-2645, unless otherwise noted.

§ 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.


[Order 54, 44 FR 61336, Oct. 25, 1979, as amended by Order 413, 50 FR 11685, Mar. 25, 1985]


§ 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:



Before the Federal Energy Regulatory Commission

Application for Preliminary Permit

(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:


State or territory:

County:

Township or nearby town:

Stream or other body of water:



(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.


(Federal Power Act, as amended, 16 U.S.C. 792-828c (1976); Department of Energy Organization Act, 42 U.S.C. 7101-7352 (Supp. IV 1980); E.O. 12009, 3 CFR part 142 (1978); 5 U.S.C. 553 (Supp. IV 1980))

[Order 54, 44 FR 61336, Oct. 25, 1979, as amended by Order 123, 46 FR 9029, Jan. 28, 1981; 46 FR 11811, Feb. 11, 1981; Order 225, 47 FR 19056, May 3, 1982; Order 413, 50 FR 11685, Mar. 25, 1985; Order 2002, 68 FR 51120, Aug. 25, 2003; Order 655, 70 FR 33828, June 10, 2005; Order 699, 72 FR 45324, Aug. 14, 2007; Order 756, 77 FR 4894, Feb. 1, 2012; Order 857, 84 FR 7991, Mar. 6, 2019]


§ 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.


[Order 413, 50 FR 11685, Mar. 25, 1985, as amended by Order 499, 53 FR 27002, July 18, 1988; Order 800, 79 FR 59110, Oct. 1, 2014; Order 857, 84 FR 7991, Mar. 6, 2019]


§ 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.


[Order 413, 50 FR 11686, Mar. 25, 1985]


§ 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.


[Order 413, 50 FR 11686, Mar. 25, 1985]


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.


[Order 800, 79 FR 59110, Oct. 1, 2014]


§ 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:



Before the Federal Energy Regulatory Commission

Application for Exemption for Small Conduit Hydroelectric Facility

[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.


The location of the facility is:

State or Territory:

County:

Township or nearby town:

The exact name and business address of each applicant are:



The exact name and business address of each person authorized to act as agent for the applicant in this application 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)].


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.


[Order 76, 45 FR 28090, Apr. 28, 1980, as amended by Order 413, 50 FR 11686, Mar. 25, 1985; Order 533, 56 FR 23153, May 20, 1991; Order 2002, 68 FR 51121, Aug. 25, 2003; Order 699, 72 FR 45324, Aug. 14, 2007; Order 800, 79 FR 59110, Oct. 1, 2014]


§ 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.


[Order 76, 45 FR 28090, Apr. 28, 1980, as amended by Order 413, 50 FR 11687, Mar. 25, 1985; Order 533, 56 FR 23153, May 20, 1991; Order 2002, 68 FR 51121, Aug. 25, 2003; Order 800, 79 FR 59110, Oct. 1, 2014]


§ 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.


[Order 76, 45 FR 28090, Apr. 28, 1980, as amended by Order 413, 50 FR 11687, Mar. 25, 1985; Order 413-A, 56 FR 31331, July 10, 1991; Order 800, 79 FR 59110, Oct. 1, 2014]


§ 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.


[Order 413, 50 FR 11687, Mar. 25, 1985, as amended by Order 800, 79 FR 59111, Oct. 1, 2014]


§ 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.


[Order 413, 50 FR 11687, Mar. 25, 1985, as amended by Order 699, 72 FR 45324, Aug. 14, 2007]


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).


(Energy Security Act of 1980, Pub. L. 96-294, 94 Stat. 611; Federal Power Act, as amended (16 U.S.C. 792-828c); Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 2601-2645); and the Department of Energy Organization Act (42 U.S.C. 7101-7352); E.O. 12009, 3 CFR 142 (1978))

[Order 202, 47 FR 4243, Jan. 29, 1982, as amended by Order 413, 50 FR 11687, Mar. 25, 1985; Order 482, 52 FR 39630, Oct. 23, 1987; Order 2002, 68 FR 51121, Aug. 25, 2003; Order 800, 79 FR 59111, Oct. 1, 2014]


§ 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.


[Order 413, 50 FR 11688, Mar. 25, 1985, as amended by Order 800, 79 FR 59111, Oct. 1, 2014]


§ 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.


[Order 413, 50 FR 11688, Mar. 25, 1985, as amended by Order 503, 53 FR 36568, Sept. 21, 1988]


§ 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.


[Order 413, 50 FR 11688, Mar. 25, 1985, as amended by Order 699, 72 FR 45324, Aug. 14, 2007]


§ 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.


(Energy Security Act of 1980, Pub. L. 96-294, 94 Stat. 611; Federal Power Act, as amended (16 U.S.C. 792-828c); Public Utility Regulatory Policies Act of 1978 (16 U.S.C. 2601-2645); and the Department of Energy Organization Act (42 U.S.C. 7101-7352); E.O. 12009, 3 CFR 142 (1978))

[Order 106, 45 FR 76123, Nov. 18, 1980, as amended by Order 202, 47 FR 4246, Jan. 29, 1982; Order 413, 50 FR 11688, Mar. 25, 1985; Order 533, 56 FR 23154, May 20, 1991]


§ 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.


[Order 106, 45 FR 76123, Nov. 18, 1980; 45 FR 77420, Nov. 24, 1980, as amended by Order 202, 47 FR 4246, Jan. 29, 1982; Order 413, 50 FR 11688, Mar. 25, 1985; Order 482, 52 FR 39630, Oct. 23, 1987; Order 413-A, 56 FR 31331, July 10, 1991; Order 756, 77 FR 4894, Feb. 1, 2012; Order 800, 79 FR 59111, Oct. 1, 2014]


§ 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:



Before the Federal Energy Regulatory Commission

Application for Exemption of Small Hydroelectric Power Project From Licensing

(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:


[State or territory]



[County]

[Township or nearby town]



[Stream or body of water]



(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.


[Order 106, 45 FR 76123, Nov. 18, 1980, as amended by Order 225, 47 FR 19056, May 3, 1982; Order 413, 50 FR 11689, Mar. 25, 1985; Order 494, 53 FR 15381, Apr. 29, 1988; Order 533, 56 FR 23154, May 20, 1991; Order 2002, 68 FR 51121, Aug. 25, 2003; Order 699, 72 FR 45324, Aug. 14, 2007; Order 800, 79 FR 59111, Oct. 1, 2014]


§ 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.


[Order 106, 45 FR 76123, Nov. 18, 1980]


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.


[Order 184, 46 FR 55943, Nov. 13, 1981, as amended by Order 2002, 68 FR 51121, Aug. 25, 2003]


§ 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.



Before the Federal Energy Regulatory Commission

Application for Amendment of License

(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.


[Order 184, 46 FR 55943, Nov. 13, 1981, as amended by Order 225, 47 FR 19056, May 3, 1982; 48 FR 4459, Feb. 1, 1983; 48 FR 16653, Apr. 19, 1983; Order 413, 50 FR 11689, Mar. 25, 1985; Order 533, 56 FR 23154, May 20, 1991; Order 756, 77 FR 4894, Feb. 1, 2012; Order 877, 86 FR 42714, Aug. 5, 2021]


§ 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.


[Order 184, 46 FR 55943, Nov. 13, 1981]


Subpart M – Fees Under Section 30(e) of the Act


Source:Order 487, 52 FR 48404, Dec. 22, 1987, unless otherwise noted.

§ 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.


[Order 141, 12 FR 8485, Dec. 19, 1947, as amended by Order 756, 77 FR 4894, Feb. 1, 2012]


§ 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.


[Order 487, 52 FR 48404, Dec. 22, 1987, as amended by Order 647, 69 FR 32438, June 10, 2004]


§ 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


Source:Order 800, 79 FR 59111, Oct. 1, 2014, unless otherwise noted.

§ 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.


[Order 800, 79 FR 59111, Oct. 1, 2014, as amended by Order 857, 84 FR 7991, Mar. 6, 2019]


§ 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:


BEFORE THE FEDERAL ENERGY REGULATORY COMMISSION

NOTICE OF INTENT TO CONSTRUCT QUALIFYING CONDUIT HYDROPOWER FACILITY

[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:



State or Territory:

County:

Township or nearby town:

Water source:

The exact name and business address of the applicant(s) are:


Applicant’s Name:

Address:

Telephone Number:

Email Address:

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 Agent:

Address:

Telephone Number:

Email Address:

[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:



State of:

County of:

by:

(Name)

(Address)

being duly sworn, depose(s) and say(s) that the contents of this (notice of intent to construct, etc.) are true to the best of (his or her) knowledge or belief. The undersigned applicant(s) has (have) signed the (notice of intent to construct, etc.) this __________day of ____________, 20____.

By:

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)


[Order 800, 79 FR 59111, Oct. 1, 2014, as amended by Order 857, 84 FR 7991, Mar. 6, 2019; Order 877, 86 FR 42715, Aug. 5, 2021]


PART 5 – INTEGRATED LICENSE APPLICATION PROCESS


Authority:16 U.S.C. 792-828c, 2601-2645; 42 U.S.C. 7101-7352.


Source:Order 2002, 68 FR 51121, Aug. 25, 2003, unless otherwise noted.

§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003; 68 FR 69957, Dec. 16, 2003]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003, as amended by Order 737, 75 FR 43402, July 26, 2010]


§ 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 Federal Register;


(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.


[Order 2002, 68 FR 51121, Aug. 25, 2003, as amended by Order 653, 70 FR 8724, Feb. 23, 2005]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 69957, Dec. 16, 2003, as amended by Order 737, 75 FR 43402, July 26, 2010]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 69957, Dec. 16, 2003, as amended by Order 737, 75 FR 43402, July 26, 2010]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003]


§ 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 Federal Register;


(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.


[Order 2002, 68 FR 51121, Aug. 25, 2003, as amended by Order 653, 70 FR 8724, Feb. 23, 2005]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003; 68 FR 69957, Dec. 16, 2003, as amended by Order 699, 72 FR 45324, Aug. 14, 2007]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003, as amended by Order 756, 77 FR 4893, Feb. 1, 2012]


§ 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:



State of

County of

By:

(Name)

(Address)

being duly sworn, depose(s) and say(s) that the contents of this application are true to the best of (his or her) knowledge or belief. The undersigned Applicant(s) has (have) signed the application this ____ day of __________________, 2______.



(Applicant(s))

By:

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______.


/SEAL [if any]

(Notary Public, or other authorized official)

(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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003; 68 FR 69957, Dec. 16, 2003; Order 699, 72 FR 45324, Aug. 14, 2007; Order 756, 77 FR 4894, Feb. 1, 2012; Order 877, 86 FR 42715, Aug. 5, 2021]


§ 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 Federal Register; and


(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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61742, Oct. 30, 2003; 68 FR 69957, Dec. 16, 2003; Order 653, 70 FR 8724, Feb. 23, 2005]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61743, Oct. 30, 2003]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61743, Oct. 30, 2003]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61743, Oct. 30, 2003]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61743, Oct. 30, 2003]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003; 68 FR 61743, Oct. 30, 2003]


§ 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.


[Order 2002, 68 FR 51121, Aug. 25, 2003, as amended by Order 769, 77 FR 65475, Oct. 29, 2012]


§ 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


Authority:Secs. 6, 10(i), 13, 41 Stat. 1067, 1068, 1071, as amended, sec. 309, 49 Stat. 858; 16 U.S.C. 799, 803(i), 806, 825h; Pub. L. 96-511, 94 Stat. 2812 (44 U.S.C. 3501 et seq.), unless otherwise noted.

§ 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.


(Secs. 308 and 309; 49 Stat. 858, 859 (16 U.S.C. 825g, 825h))

[Order 570, 42 FR 40191, Aug. 9, 1977]


Cross References:

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.


[Order 175, 19 FR 5217, Aug. 18, 1954]


§ 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.


(Administrative Procedure Act, 5 U.S.C. 551-557 (1976); Federal Power Act, as amended, 16 U.S.C. 291-628 (1976 & Supp. V 1981), Dept. of Energy Organization Act 42 U.S.C. 7101-7352 (Supp. V 1981); E.O. 12009, 3 CFR 142 (1978))

[Order 141, 12 FR 8491, Dec. 19, 1947, as amended by Order 344, 48 FR 49010, Oct. 24, 1983]


§ 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.


[Order 141, 12 FR 8491, Dec. 19, 1947]


§ 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.


[Order 175, 19 FR 5217, Aug. 18, 1954]


Cross Reference:

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


Authority:16 U.S.C. 791a-825r; Pub. L. 115-270, 132 Stat. 3765.


Source:84 FR 17078, April 24, 2019, unless otherwise noted.

§ 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


Authority:5 U.S.C. 551-557; 16 U.S.C. 791a-825r; 42 U.S.C. 7101-7352.

§ 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.


[Order 852, 83 FR 67068, Dec. 28, 2018]


§ 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.


[Order 852, 83 FR 67068, Dec. 28, 2018]


§ 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.


[Order 341, 32 FR 6488, Apr. 27, 1967]


PART 9 – TRANSFER OF LICENSE OR LEASE OF PROJECT PROPERTY


Authority:Sec. 8, 41 Stat. 1068, sec. 309, 49 Stat. 858; 16 U.S.C. 801, 825h; Pub. L. 96-511, 94 Stat. 2812 (44 U.S.C. 3501 et seq.)


Cross Reference:

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.


[Order 501, 39 FR 2267, Jan. 18, 1974, as amended by Order 2002, 68 FR 51139, Aug. 25, 2003]


§ 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.


[Order 141, 12 FR 8491, Dec. 19, 1947]


Cross References:

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.


[Order 175, 19 FR 5217, Aug. 18, 1954]


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.


[Order 737, 75 FR 43403, July 26, 2010]


PART 11 – ANNUAL CHARGES UNDER PART I OF THE FEDERAL POWER ACT


Authority:16 U.S.C. 792-828c; 42 U.S.C. 7101-7352.

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.


[60 FR 15047, Mar. 22, 1995, as amended by Order 584, 60 FR 57925, Nov. 24, 1995; Order 815, 80 FR 63671, Oct. 21, 2015; Order 857, 84 FR 7991, Mar. 6, 2019]


§ 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 Federal Register.


(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.


[Order 774, 78 FR 5265, Jan. 25, 2013, as amended by Order 838, 83 FR 7, Jan. 2, 2018]


§ 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
1/2 mills per kilowatt-hour for over 40 up to and including 80 gigawatt-hours, and 2 mills per kilowatt-hour for any energy the project produces over 80 gigawatt-hours.


(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.


[Order 379, 49 FR 22778, June 1, 1984, as amended by Order 379-A, 49 FR 33862, Aug. 27, 1984. Redesignated at 51 FR 24318, July 3, 1986; Order 469, 52 FR 18209, May 14, 1987; 52 FR 33802, Sept. 8, 1987; 53 FR 44859, Nov. 7, 1988; Order 647, 69 FR 32438, June 10, 2004]


§ 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.


[Order 379, 49 FR 22778, June 1, 1984. Redesignated at 51 FR 24318, July 3, 1986; Order 469, 52 FR 18209, May 14, 1987; 52 FR 33802, Sept. 8, 1987; Order 551, 58 FR 15770, Mar. 24, 1993]


§ 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.


[Order 141, 12 FR 8492, Dec. 19, 1947. Redesignated by Order 379, 49 FR 22778, June 1, 1984. Redesignated at 51 FR 24318, July 3, 1986]


§ 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.


[Order 143, 13 FR 6681, Nov. 13, 1948. Redesignated and amended by Order 379, 49 FR 22778, June 1, 1984. Redesignated at 51 FR 24318, July 3, 1986; 60 FR 15048, Mar. 22, 1995; Order 737, 75 FR 43403, July 26, 2010]


§ 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.


[51 FR 24318, July 3, 1986]


§ 11.8 Adjustment of annual charges.

All annual charges imposed under this subpart continue in effect as fixed unless changed as authorized by law.


[51 FR 24318, July 3, 1986]


Subpart B – Charges for Headwater Benefits


Source:Order 453, 51 FR 24318, July 3, 1986, unless otherwise noted.

§ 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.


[Order 453, 51 FR 24318, July 3, 1986, as amended by Order 699, 72 FR 45324, Aug. 14, 2007]


§ 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:





In which:

P = annual payment to be made for headwater benefits received by a downstream project,

Cp = annual section 10(f) cost of the headwater project,

En = annual energy gains received at a downstream project, or group of projects if owned by one entity,

Ed = annual energy gains received at all downstream projects (except those specified in § 11.10(b) of this chapter), and

Ej = portion of the annual energy generated at the headwater project assigned to the joint-use power cost.

(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:





In which:

Ej = annual energy generated at the headwater project to be attributed to the joint-use power cost,

E = total annual generation at the headwater project,

Cj = project investment costs assigned to the joint-use power cost, and

Cs = project investment costs assigned to specific power costs.

(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.


[60 FR 15048, Mar. 22, 1995]


§ 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.


[51 FR 24318, July 3, 1986]


Appendix A to Part 11 – Fee Schedule for FY 2023

State
County
Fee/acre/yr
AlabamaAutauga$60.57
Baldwin159.94
Barbour61.34
Bibb77.11
Blount98.95
Bullock58.84
Butler67.41
Calhoun116.64
Chambers69.03
Cherokee87.00
Chilton96.94
Choctaw56.31
Clarke62.60
Clay77.11
Cleburne95.05
Coffee72.33
Colbert73.21
Conecuh58.84
Coosa62.96
Covington73.73
Crenshaw68.51
Cullman109.25
Dale82.66
Dallas51.51
DeKalb108.09
Elmore82.30
Escambia67.52
Etowah105.37
Fayette60.60
Franklin67.33
Geneva68.02
Greene53.59
Hale62.08
Henry70.87
Houston97.05
Jackson83.56
Jefferson121.23
Lamar51.07
Lauderdale99.61
Lawrence104.28
Lee114.00
Limestone113.51
Lowndes52.14
Macon64.47
Madison145.76
Marengo55.13
Marion64.25
Marshall121.72
Mobile130.15
Monroe65.82
Montgomery73.07
Morgan120.95
Perry60.65
Pickens69.44
Pike71.97
Randolph86.72
Russell69.80
Shelby109.22
St. Clair117.49
Sumter51.42
Talladega90.90
Tallapoosa78.43
Tuscaloosa92.41
Walker82.93
Washington55.65
Wilcox49.94
Winston75.95
AlaskaAleutian Islands0.92
Statewide49.24
ArizonaApache4.56
Cochise33.23
Coconino3.51
Gila6.45
Graham10.74
Greenlee25.84
La Paz33.41
Maricopa153.08
Mohave13.91
Navajo3.66
Pima8.73
Pinal45.81
Santa Cruz33.05
Yavapai27.36
Yuma153.06
ArkansasArkansas64.52
Ashley59.25
Baxter55.08
Benton132.63
Boone53.97
Bradley67.30
Calhoun53.05
Carroll56.31
Chicot60.83
Clark49.57
Clay88.25
Cleburne60.15
Cleveland86.65
Columbia47.56
Conway52.03
Craighead94.45
Crawford62.82
Crittenden78.85
Cross69.00
Dallas39.91
Desha66.62
Drew59.23
Faulkner78.62
Franklin52.50
Fulton38.23
Garland107.00
Grant73.95
Greene86.79
Hempstead51.27
Hot Spring56.98
Howard58.46
Independence47.07
Izard41.91
Jackson68.98
Jefferson66.89
Johnson57.17
Lafayette52.15
Lawrence73.42
Lee64.97
Lincoln63.10
Little River49.43
Logan51.17
Lonoke75.41
Madison64.15
Marion49.92
Miller52.78
Mississippi70.35
Monroe57.80
Montgomery53.21
Nevada48.44
Newton49.88
Ouachita45.68
Perry56.47
Phillips65.23
Pike53.40
Poinsett78.23
Polk60.58
Pope65.72
Prairie59.79
Pulaski80.44
Randolph60.11
Saline70.11
Scott50.24
Searcy38.55
Sebastian68.45
Sevier54.63
Sharp43.65
St. Francis63.64
Stone44.29
Union56.61
Van Buren56.39
Washington105.08
White56.90
Woodruff66.62
Yell55.18
CaliforniaAlameda46.31
Alpine29.80
Amador29.03
Butte78.48
Calaveras23.16
Colusa51.92
Contra Costa45.11
Del Norte54.19
El Dorado64.69
Fresno74.03
Glenn58.10
Humboldt20.14
Imperial72.57
Inyo4.04
Kern48.10
Kings70.48
Lake42.72
Lassen13.94
Los Angeles121.09
Madera71.41
Marin38.20
Mariposa13.45
Mendocino24.95
Merced85.28
Modoc12.75
Mono12.52
Monterey48.02
Napa287.76
Nevada48.39
Orange124.44
Placer43.76
Plumas14.98
Riverside118.25
Sacramento65.48
San Benito23.26
San Bernardino129.67
San Diego151.26
San Francisco506.77
San Joaquin97.89
San Luis Obispo49.18
San Mateo63.67
Santa Barbara67.65
Santa Clara53.02
Santa Cruz139.15
Shasta19.02
Sierra11.09
Siskiyou19.98
Solano59.62
Sonoma144.59
Stanislaus101.79
Sutter62.08
Tehama28.11
Trinity12.52
Tulare76.42
Tuolumne24.21
Ventura166.17
Yolo63.24
Yuba53.58
ColoradoAdams28.08
Alamosa36.90
Arapahoe39.34
Archuleta54.03
Baca13.65
Bent12.01
Boulder218.82
Broomfield95.16
Chaffee88.34
Cheyenne14.59
Clear Creek54.95
Conejos29.37
Costilla21.15
Crowley8.86
Custer33.82
Delta83.78
Denver1,109.32
Dolores31.04
Douglas117.45
Eagle57.60
El Paso24.49
Elbert26.56
Fremont40.66
Garfield41.76
Gilpin73.56
Grand38.28
Gunnison44.68
Hinsdale32.05
Huerfano16.75
Jackson23.03
Jefferson134.30
Kiowa13.12
Kit Carson21.22
La Plata39.32
Lake35.77
Larimer80.72
Las Animas10.48
Lincoln12.25
Logan20.68
Mesa96.14
Mineral59.90
Moffat13.91
Montezuma21.08
Montrose53.84
Morgan30.20
Otero13.06
Ouray53.16
Park29.24
Phillips29.45
Pitkin132.59
Prowers14.03
Pueblo17.89
Rio Blanco23.90
Rio Grande54.36
Routt54.68
Saguache33.04
San Juan27.99
San Miguel25.94
Sedgwick23.55
Summit73.54
Teller35.21
Washington19.11
Weld45.01
Yuma28.43
ConnecticutFairfield284.31
Hartford424.75
Litchfield298.21
Middlesex392.74
New Haven618.71
New London302.03
Tolland255.57
Windham248.96
DelawareKent212.12
New Castle254.31
Sussex226.84
FloridaAlachua156.40
Baker91.62
Bay40.96
Bradford95.39
Brevard100.39
Broward661.79
Calhoun43.01
Charlotte143.30
Citrus158.34
Clay114.34
Collier94.83
Columbia87.09
Dade747.85
DeSoto100.01
Dixie74.33
Duval150.23
Escambia123.93
Flagler111.13
Franklin117.84
Gadsden84.99
Gilchrist106.26
Glades86.03
Gulf28.66
Hamilton77.18
Hardee106.58
Hendry97.85
Hernando209.44
Highlands78.00
Hillsborough233.20
Holmes66.58
Indian River114.72
Jackson73.77
Jefferson69.25
Lafayette60.39
Lake158.40
Lee243.75
Leon85.19
Levy92.02
Liberty78.20
Madison70.43
Manatee155.44
Marion221.94
Martin87.79
Monroe117.84
Nassau74.77
Okaloosa95.11
Okeechobee84.33
Orange168.38
Osceola77.48
Palm Beach167.32
Pasco143.00
Pinellas1,147.52
Polk121.09
Putnam79.42
Santa Rosa107.08
Sarasota183.62
Seminole165.17
St. Johns169.88
St. Lucie119.34
Sumter120.32
Suwannee88.22
Taylor72.89
Union74.33
Volusia205.86
Wakulla68.30
Walton75.30
Washington76.28
GeorgiaAppling83.31
Atkinson74.46
Bacon105.54
Baker56.98
Baldwin55.51
Banks137.98
Barrow168.13
Bartow154.49
Ben Hill63.31
Berrien80.21
Bibb102.72
Bleckley66.15
Brantley74.85
Brooks89.64
Bryan78.90
Bulloch73.44
Burke72.90
Butts99.92
Calhoun77.28
Camden73.46
Candler81.03
Carroll122.72
Catoosa141.10
Charlton62.23
Chatham130.21
Chattahoochee75.85
Chattooga90.82
Cherokee222.44
Clarke198.34
Clay60.69
Clayton214.23
Clinch102.13
Cobb292.95
Coffee77.33
Colquitt84.82
Columbia114.16
Cook77.90
Coweta123.72
Crawford103.31
Crisp78.59
Dade102.08
Dawson179.05
Decatur83.59
DeKalb1,203.43
Dodge66.67
Dooly74.92
Dougherty99.21
Douglas171.67
Early65.87
Echols71.57
Effingham83.33
Elbert100.64
Emanuel53.62
Evans69.21
Fannin151.34
Fayette139.52
Floyd124.77
Forsyth202.03
Franklin147.39
Fulton488.80
Gilmer196.34
Glascock40.82
Glynn395.16
Gordon167.82
Grady96.41
Greene91.95
Gwinnett239.47
Habersham183.59
Hall239.29
Hancock53.64
Haralson121.80
Harris110.82
Hart144.16
Heard92.59
Henry191.85
Houston103.10
Irwin83.31
Jackson163.34
Jasper89.26
Jeff Davis64.23
Jefferson66.41
Jenkins67.18
Johnson53.67
Jones71.95
Lamar89.77
Lanier77.69
Laurens53.74
Lee86.77
Liberty135.62
Lincoln80.13
Long86.18
Lowndes139.77
Lumpkin151.93
Macon82.49
Madison145.23
Marion60.90
McDuffie76.77
McIntosh60.82
Meriwether83.64
Miller83.13
Mitchell94.92
Monroe84.08
Montgomery66.26
Morgan119.82
Murray129.95
Muscogee128.28
Newton114.75
Oconee185.52
Oglethorpe111.62
Paulding148.23
Peach147.85
Pickens218.70
Pierce73.77
Pike125.57
Polk92.72
Pulaski68.49
Putnam107.85
Quitman59.15
Rabun211.29
Randolph72.62
Richmond94.36
Rockdale181.03
Schley73.03
Screven56.41
Seminole80.54
Spalding131.31
Stephens148.05
Stewart53.05
Sumter73.31
Talbot70.13
Taliaferro84.41
Tattnall99.33
Taylor53.31
Telfair56.67
Terrell71.87
Thomas93.33
Tift81.39
Toombs71.28
Towns140.95
Treutlen48.28
Troup83.23
Turner79.08
Twiggs61.98
Union147.98
Upson101.39
Walker108.69
Walton145.23
Ware65.77
Warren76.46
Washington54.00
Wayne53.33
Webster62.62
Wheeler46.90
White208.36
Whitfield158.59
Wilcox66.87
Wilkes88.39
Wilkinson52.56
Worth77.00
HawaiiHawaii153.21
Honolulu547.84
Kauai198.46
Maui253.35
IdahoAda125.77
Adams20.50
Bannock25.83
Bear Lake19.03
Benewah25.60
Bingham33.64
Blaine33.46
Boise18.95
Bonner66.59
Bonneville38.55
Boundary63.26
Butte27.15
Camas17.73
Canyon108.96
Caribou24.54
Cassia42.18
Clark23.21
Clearwater32.65
Custer36.05
Elmore32.95
Franklin30.75
Fremont36.59
Gem37.22
Gooding79.55
Idaho21.74
Jefferson46.57
Jerome79.86
Kootenai73.06
Latah33.61
Lemhi33.40
Lewis25.97
Lincoln48.28
Madison55.04
Minidoka60.02
Nez Perce27.49
Oneida21.92
Owyhee21.53
Payette46.35
Power32.62
Shoshone88.80
Teton52.29
Twin Falls58.70
Valley34.30
Washington17.90
IllinoisAdams181.56
Alexander95.52
Bond191.83
Boone217.97
Brown156.22
Bureau229.36
Calhoun116.90
Carroll224.34
Cass178.54
Champaign260.00
Christian241.05
Clark159.29
Clay142.91
Clinton193.33
Coles219.76
Cook575.84
Crawford146.62
Cumberland177.04
De Witt234.05
DeKalb262.88
Douglas253.14
DuPage469.02
Edgar207.20
Edwards149.91
Effingham184.26
Fayette150.64
Ford216.80
Franklin124.46
Fulton172.82
Gallatin148.10
Greene172.57
Grundy247.47
Hamilton134.23
Hancock197.88
Hardin91.56
Henderson194.25
Henry220.51
Iroquois205.05
Jackson150.30
Jasper157.22
Jefferson116.03
Jersey176.65
Jo Daviess170.51
Johnson103.28
Kane294.63
Kankakee218.28
Kendall252.80
Knox204.24
La Salle254.64
Lake339.03
Lawrence157.67
Lee241.89
Livingston229.67
Logan233.85
Macon258.13
Macoupin200.78
Madison242.95
Marion136.32
Marshall225.34
Mason194.87
Massac108.02
McDonough204.66
McHenry266.25
McLean274.71
Menard217.86
Mercer182.81
Monroe185.83
Montgomery203.04
Morgan230.14
Moultrie243.82
Ogle239.96
Peoria220.23
Perry133.45
Piatt258.41
Pike165.09
Pope97.42
Pulaski114.50
Putnam233.63
Randolph151.33
Richland147.34
Rock Island194.37
Saline134.62
Sangamon249.23
Schuyler153.04
Scott181.33
Shelby196.65
St. Clair206.98
Stark232.01
Stephenson235.08
Tazewell230.84
Union118.54
Vermilion228.91
Wabash154.40
Warren225.82
Washington179.21
Wayne132.94
White139.06
Whiteside220.23
Will248.03
Williamson110.31
Winnebago199.17
Woodford250.37
IndianaAdams230.12
Allen221.11
Bartholomew186.01
Benton215.10
Blackford183.70
Boone211.96
Brown122.10
Carroll209.68
Cass173.64
Clark153.39
Clay141.85
Clinton199.39
Crawford86.05
Daviess211.93
Dearborn135.20
Decatur197.00
DeKalb154.28
Delaware184.48
Dubois151.72
Elkhart310.89
Fayette157.31
Floyd151.75
Fountain187.24
Franklin157.70
Fulton175.55
Gibson180.34
Grant196.33
Greene137.73
Hamilton243.36
Hancock209.79
Harrison127.24
Hendricks212.43
Henry166.52
Howard215.97
Huntington190.63
Jackson147.27
Jasper179.56
Jay210.96
Jefferson115.17
Jennings126.94
Johnson187.60
Knox173.11
Kosciusko198.03
LaGrange257.24
Lake193.74
LaPorte204.56
Lawrence103.35
Madison225.51
Marion293.81
Marshall174.08
Martin108.08
Miami187.74
Monroe182.70
Montgomery194.24
Morgan174.91
Newton187.26
Noble177.84
Ohio121.49
Orange124.85
Owen126.35
Parke162.43
Perry111.61
Pike137.15
Porter188.18
Posey168.91
Pulaski171.05
Putnam178.98
Randolph178.47
Ripley143.60
Rush201.78
Scott149.30
Shelby193.16
Spencer128.19
St. Joseph224.92
Starke139.18
Steuben154.00
Sullivan138.42
Switzerland113.98
Tippecanoe251.07
Tipton227.15
Union176.33
Vanderburgh219.89
Vermillion157.81
Vigo150.88
Wabash174.94
Warren188.74
Warrick151.00
Washington125.19
Wayne152.75
Wells209.82
White217.36
Whitley176.42
IowaAdair146.12
Adams139.33
Allamakee149.33
Appanoose113.57
Audubon191.83
Benton206.39
Black Hawk243.71
Boone222.56
Bremer223.26
Buchanan220.27
Buena Vista224.77
Butler200.30
Calhoun221.89
Carroll224.35
Cass164.70
Cedar219.55
Cerro Gordo205.10
Cherokee221.11
Chickasaw208.51
Clarke119.33
Clay223.09
Clayton154.92
Clinton210.77
Crawford189.26
Dallas228.23
Davis109.41
Decatur107.43
Delaware217.17
Des Moines193.06
Dickinson207.84
Dubuque241.20
Emmet200.66
Fayette200.49
Floyd205.60
Franklin218.32
Fremont167.69
Greene231.81
Grundy253.86
Guthrie176.04
Hamilton226.73
Hancock212.92
Hardin218.29
Harrison172.13
Henry175.09
Howard208.29
Humboldt225.97
Ida205.27
Iowa179.23
Jackson166.88
Jasper181.94
Jefferson154.73
Johnson224.55
Jones194.51
Keokuk163.08
Kossuth220.50
Lee144.33
Linn232.68
Louisa185.26
Lucas95.36
Lyon279.06
Madison158.36
Mahaska173.03
Marion161.24
Marshall212.34
Mills167.41
Mitchell219.74
Monona160.99
Monroe117.51
Montgomery158.69
Muscatine187.75
O’Brien271.76
Osceola244.80
Page150.03
Palo Alto223.90
Plymouth239.19
Pocahontas225.30
Polk247.01
Pottawattamie189.54
Poweshiek187.42
Ringgold107.68
Sac221.92
Scott267.88
Shelby191.47
Sioux290.71
Story264.50
Tama202.73
Taylor134.44
Union124.55
Van Buren130.59
Wapello136.23
Warren157.46
Washington192.47
Wayne118.80
Webster222.06
Winnebago195.27
Winneshiek178.84
Woodbury206.05
Worth194.34
Wright211.58
KansasAllen56.12
Anderson56.37
Atchison84.08
Barber39.72
Barton43.43
Bourbon55.54
Brown97.00
Butler62.73
Chase52.86
Chautauqua45.11
Cherokee61.16
Cheyenne40.85
Clark32.83
Clay75.01
Cloud63.67
Coffey50.48
Comanche32.06
Cowley51.14
Crawford55.71
Decatur40.33
Dickinson59.19
Doniphan94.90
Douglas112.63
Edwards50.98
Elk42.73
Ellis37.31
Ellsworth44.48
Finney43.29
Ford42.79
Franklin66.47
Geary63.64
Gove35.98
Graham35.54
Grant43.59
Gray44.14
Greeley39.17
Greenwood46.11
Hamilton29.48
Harper45.42
Harvey87.60
Haskell42.24
Hodgeman32.53
Jackson74.04
Jefferson80.32
Jewell56.98
Johnson104.36
Kearny39.88
Kingman44.78
Kiowa43.45
Labette58.67
Lane35.24
Leavenworth94.62
Lincoln47.77
Linn70.64
Logan37.23
Lyon54.99
Marion56.48
Marshall85.58
McPherson75.76
Meade40.83
Miami85.61
Mitchell51.67
Montgomery55.60
Morris44.86
Morton28.32
Nemaha83.14
Neosho54.30
Ness29.98
Norton37.64
Osage55.10
Osborne39.00
Ottawa55.62
Pawnee45.86
Phillips39.88
Pottawatomie68.07
Pratt56.84
Rawlins42.65
Reno59.16
Republic71.53
Rice56.31
Riley83.59
Rooks34.60
Rush35.93
Russell37.04
Saline65.58
Scott41.90
Sedgwick95.81
Seward39.00
Shawnee82.78
Sheridan43.26
Sherman48.71
Smith52.80
Stafford49.87
Stanton29.43
Stevens38.36
Sumner50.84
Thomas48.32
Trego31.56
Wabaunsee53.30
Wallace37.40
Washington67.10
Wichita38.75
Wilson53.85
Woodson45.97
Wyandotte186.48
KentuckyAdair83.73
Allen96.37
Anderson103.36
Ballard100.60
Barren100.27
Bath65.70
Bell55.40
Boone167.13
Bourbon158.22
Boyd66.95
Boyle103.55
Bracken69.54
Breathitt43.68
Breckinridge85.93
Bullitt143.67
Butler73.71
Caldwell92.95
Calloway114.74
Campbell140.85
Carlisle105.72
Carroll94.45
Carter53.81
Casey65.22
Christian134.09
Clark123.35
Clay50.50
Clinton77.61
Crittenden76.47
Cumberland57.15
Daviess138.79
Edmonson88.47
Elliott45.07
Estill66.92
Fayette406.95
Fleming73.57
Floyd85.96
Franklin110.43
Fulton102.27
Gallatin79.20
Garrard81.20
Grant92.11
Graves106.48
Grayson82.29
Green72.24
Greenup68.78
Hancock82.87
Hardin127.88
Harlan43.54
Harrison86.29
Hart85.68
Henderson141.86
Henry107.48
Hickman111.74
Hopkins93.87
Jackson65.58
Jefferson342.28
Jessamine184.84
Johnson83.54
Kenton155.80
Knott35.60
Knox66.64
Larue98.79
Laurel93.06
Lawrence44.51
Lee56.98
Leslie106.34
Letcher83.51
Lewis58.35
Lincoln90.36
Livingston78.28
Logan134.42
Lyon86.88
Madison96.54
Magoffin57.62
Marion96.93
Marshall105.67
Martin96.07
Mason82.31
McCracken124.04
McCreary68.34
McLean124.32
Meade120.48
Menifee53.81
Mercer109.26
Metcalfe74.52
Monroe79.25
Montgomery97.57
Morgan54.23
Muhlenberg83.40
Nelson113.05
Nicholas64.64
Ohio95.15
Oldham221.69
Owen78.81
Owsley37.36
Pendleton79.06
Perry31.90
Pike39.36
Powell64.97
Pulaski90.14
Robertson60.88
Rockcastle60.66
Rowan77.11
Russell86.10
Scott155.75
Shelby161.70
Simpson157.97
Spencer126.44
Taylor84.57
Todd144.33
Trigg114.41
Trimble90.33
Union140.27
Warren148.48
Washington89.41
Wayne74.21
Webster102.52
Whitley70.48
Wolfe56.12
Woodford225.78
LouisianaAcadia70.41
Allen65.42
Ascension92.44
Assumption75.05
Avoyelles64.86
Beauregard77.48
Bienville64.93
Bossier79.59
Caddo76.05
Calcasieu88.72
Caldwell63.91
Cameron63.17
Catahoula68.89
Claiborne60.91
Concordia71.43
De Soto75.62
East Baton Rouge210.35
East Carroll94.66
East Feliciana71.36
Evangeline62.23
Franklin72.30
Grant69.80
Iberia73.12
Iberville45.79
Jackson102.05
Jefferson59.50
Jefferson Davis56.78
La Salle81.20
Lafayette142.28
Lafourche73.91
Lincoln81.84
Livingston136.42
Madison70.08
Morehouse81.07
Natchitoches59.53
Orleans263.99
Ouachita108.63
Plaquemines35.97
Pointe Coupee78.80
Rapides95.53
Red River57.06
Richland72.17
Sabine96.34
St. Bernard44.67
St. Charles89.00
St. Helena106.03
St. James78.06
St. John the Baptist89.23
St. Landry74.42
St. Martin81.71
St. Mary84.08
St. Tammany273.58
Tangipahoa129.03
Tensas71.46
Terrebonne104.98
Union77.60
Vermilion73.35
Vernon94.40
Washington92.08
Webster74.93
West Baton Rouge71.89
West Carroll84.03
West Feliciana74.83
Winn71.49
MaineAndroscoggin92.11
Aroostook45.48
Cumberland178.42
Franklin64.89
Hancock72.99
Kennebec78.97
Knox123.43
Lincoln121.31
Oxford76.12
Penobscot64.42
Piscataquis36.78
Sagadahoc107.99
Somerset38.56
Waldo78.32
Washington40.07
York133.75
MarylandAllegany153.12
Anne Arundel282.37
Baltimore405.95
Calvert280.86
Caroline195.13
Carroll223.94
Cecil219.53
Charles258.99
Dorchester155.42
Frederick260.74
Garrett124.89
Harford298.64
Howard250.72
Kent180.97
Montgomery224.89
Prince George’s222.68
Queen Anne’s200.96
Somerset156.79
St. Mary’s272.43
Talbot192.45
Washington220.62
Wicomico192.61
Worcester145.13
MassachusettsBarnstable751.40
Berkshire187.98
Bristol447.23
Dukes281.06
Essex429.13
Franklin157.86
Hampden254.35
Hampshire188.42
Middlesex392.09
Nantucket962.13
Norfolk421.75
Plymouth235.47
Suffolk5,653.64
Worcester302.41
MichiganAlcona70.40
Alger55.45
Allegan162.57
Alpena69.18
Antrim114.24
Arenac91.19
Baraga59.50
Barry130.50
Bay137.32
Benzie107.66
Berrien175.18
Branch115.14
Calhoun144.31
Cass125.63
Charlevoix102.47
Cheboygan69.64
Chippewa58.82
Clare81.84
Clinton153.71
Crawford95.19
Delta48.52
Dickinson74.12
Eaton113.51
Emmet102.39
Genesee143.03
Gladwin106.25
Gogebic70.70
Grand Traverse172.93
Gratiot147.65
Hillsdale117.12
Houghton63.98
Huron164.39
Ingham144.74
Ionia134.68
Iosco85.70
Iron53.71
Isabella111.42
Jackson135.53
Kalamazoo191.76
Kalkaska72.14
Kent200.60
Keweenaw91.74
Lake66.92
Lapeer125.22
Leelanau198.99
Lenawee142.05
Livingston154.96
Luce68.52
Mackinac54.28
Macomb138.49
Manistee78.39
Marquette59.96
Mason84.56
Mecosta95.27
Menominee57.76
Midland150.64
Missaukee99.43
Monroe167.33
Montcalm108.48
Montmorency58.33
Muskegon174.64
Newaygo105.71
Oakland315.93
Oceana113.05
Ogemaw76.03
Ontonagon43.41
Osceola81.63
Oscoda74.50
Otsego75.56
Ottawa224.82
Presque Isle63.74
Roscommon66.62
Saginaw157.79
Sanilac134.00
Schoolcraft49.47
Shiawassee122.61
St. Clair142.81
St. Joseph155.40
Tuscola141.80
Van Buren157.35
Washtenaw212.64
Wayne314.24
Wexford91.55
MinnesotaAitkin58.70
Anoka211.26
Becker80.89
Beltrami54.72
Benton122.19
Big Stone121.02
Blue Earth200.46
Brown182.98
Carlton59.98
Carver187.66
Cass69.67
Chippewa164.05
Chisago127.34
Clay109.89
Clearwater56.39
Cook164.97
Cottonwood175.94
Crow Wing74.82
Dakota192.11
Dodge191.83
Douglas109.83
Faribault189.24
Fillmore154.59
Freeborn167.84
Goodhue172.68
Grant122.55
Hennepin374.76
Houston119.41
Hubbard73.65
Isanti108.19
Itasca79.10
Jackson179.19
Kanabec73.82
Kandiyohi145.24
Kittson62.60
Koochiching40.16
Lac qui Parle124.64
Lake101.01
Lake of the Woods47.23
Le Sueur171.87
Lincoln134.60
Lyon162.88
Mahnomen82.25
Marshall68.86
Martin186.82
McLeod159.32
Meeker144.46
Mille Lacs86.34
Morrison92.13
Mower189.63
Murray171.62
Nicollet194.89
Nobles192.36
Norman91.88
Olmsted185.29
Otter Tail82.64
Pennington53.66
Pine65.80
Pipestone162.36
Polk91.30
Pope115.34
Ramsey741.66
Red Lake65.97
Redwood173.66
Renville182.59
Rice190.86
Rock212.40
Roseau48.51
Scott211.26
Sherburne143.48
Sibley187.77
St. Louis55.45
Stearns143.32
Steele172.60
Stevens141.31
Swift140.37
Todd76.40
Traverse138.58
Wabasha153.62
Wadena61.23
Waseca184.29
Washington242.02
Watonwan197.54
Wilkin107.77
Winona160.13
Wright179.28
Yellow Medicine150.53
MississippiAdams76.97
Alcorn55.60
Amite83.29
Attala48.17
Benton50.25
Bolivar78.93
Calhoun46.34
Carroll55.79
Chickasaw52.26
Choctaw48.04
Claiborne70.66
Clarke58.37
Clay48.98
Coahoma86.29
Copiah66.88
Covington94.06
DeSoto78.51
Forrest110.74
Franklin82.82
George97.35
Greene65.96
Grenada57.40
Hancock100.74
Harrison218.50
Hinds85.90
Holmes63.27
Humphreys85.32
Issaquena71.42
Itawamba44.67
Jackson130.78
Jasper73.19
Jefferson65.75
Jefferson Davis67.06
Jones98.79
Kemper52.76
Lafayette71.49
Lamar92.58
Lauderdale53.62
Lawrence83.78
Leake78.98
Lee47.80
Leflore75.72
Lincoln80.13
Lowndes66.01
Madison68.57
Marion75.17
Marshall62.70
Monroe57.35
Montgomery52.16
Neshoba69.51
Newton61.87
Noxubee66.09
Oktibbeha72.95
Panola64.27
Pearl River92.50
Perry83.76
Pike97.22
Pontotoc51.35
Prentiss53.39
Quitman74.65
Rankin86.11
Scott66.43
Sharkey86.37
Simpson71.96
Smith74.96
Stone86.31
Sunflower83.08
Tallahatchie73.58
Tate73.71
Tippah54.06
Tishomingo49.31
Tunica77.10
Union52.16
Walthall80.99
Warren63.33
Washington96.75
Wayne80.78
Webster47.83
Wilkinson62.65
Winston59.41
Yalobusha48.64
Yazoo72.77
MissouriAdair76.30
Andrew105.02
Atchison133.99
Audrain116.31
Barry93.71
Barton75.24
Bates84.45
Benton74.80
Bollinger68.51
Boone154.52
Buchanan110.76
Butler128.31
Caldwell86.63
Callaway108.22
Camden60.34
Cape Girardeau118.69
Carroll97.84
Carter52.17
Cass102.73
Cedar68.02
Chariton93.98
Christian110.05
Clark97.70
Clay113.93
Clinton101.69
Cole99.64
Cooper89.31
Crawford70.59
Dade76.71
Dallas69.36
Daviess89.23
DeKalb89.45
Dent57.14
Douglas57.39
Dunklin139.10
Franklin105.60
Gasconade76.16
Gentry84.66
Greene129.67
Grundy80.02
Harrison75.65
Henry73.51
Hickory57.61
Holt133.72
Howard82.61
Howell58.59
Iron56.43
Jackson158.89
Jasper88.03
Jefferson114.78
Johnson91.39
Knox83.13
Laclede68.79
Lafayette123.94
Lawrence87.40
Lewis90.51
Lincoln119.18
Linn78.79
Livingston92.15
Macon87.29
Madison57.36
Maries53.86
Marion108.39
McDonald73.30
Mercer73.60
Miller68.24
Mississippi159.52
Moniteau97.56
Monroe97.26
Montgomery103.06
Morgan104.86
New Madrid152.79
Newton99.45
Nodaway109.64
Oregon48.67
Osage66.00
Ozark58.29
Pemiscot143.07
Perry89.45
Pettis95.65
Phelps72.04
Pike96.09
Platte121.04
Polk69.00
Pulaski61.13
Putnam68.87
Ralls105.22
Randolph94.58
Ray96.09
Reynolds43.70
Ripley66.85
Saline109.59
Schuyler70.54
Scotland92.10
Scott139.02
Shannon53.65
Shelby101.91
St Louis118.82
St. Charles133.50
St. Clair67.04
St. Francois80.15
Ste. Genevieve80.65
Stoddard146.29
Stone79.09
Sullivan63.89
Taney61.08
Texas56.46
Vernon77.64
Warren110.63
Washington64.82
Wayne64.22
Webster84.77
Worth77.72
Wright58.98
MontanaBeaverhead27.74
Big Horn8.28
Blaine12.47
Broadwater24.64
Carbon31.25
Carter11.33
Cascade25.53
Chouteau19.65
Custer11.29
Daniels13.35
Dawson14.07
Deer Lodge40.92
Fallon12.72
Fergus23.04
Flathead134.56
Gallatin63.82
Garfield8.51
Glacier24.58
Golden Valley14.11
Granite34.08
Hill18.13
Jefferson35.85
Judith Basin19.57
Lake33.82
Lewis and Clark27.51
Liberty18.89
Lincoln110.57
Madison36.01
McCone11.12
Meagher19.12
Mineral105.35
Missoula58.89
Musselshell13.46
Park54.95
Petroleum14.28
Phillips11.16
Pondera25.42
Powder River11.60
Powell27.27
Prairie16.30
Ravalli120.76
Richland18.47
Roosevelt15.21
Rosebud9.06
Sanders20.81
Sheridan14.62
Silver Bow47.41
Stillwater28.31
Sweet Grass23.93
Teton24.98
Toole18.47
Treasure12.17
Valley13.56
Wheatland14.60
Wibaux12.99
Yellowstone21.12
NebraskaAdams134.74
Antelope116.14
Arthur20.28
Banner22.07
Blaine25.14
Boone112.62
Box Butte33.77
Boyd51.34
Brown29.67
Buffalo111.20
Burt155.93
Butler144.11
Cass141.93
Cedar131.18
Chase52.78
Cherry23.62
Cheyenne25.82
Clay122.77
Colfax156.79
Cuming154.08
Custer62.65
Dakota143.17
Dawes22.50
Dawson86.37
Deuel33.03
Dixon118.37
Dodge162.31
Douglas193.50
Dundy38.73
Fillmore137.91
Franklin87.64
Frontier47.56
Furnas62.45
Gage112.06
Garden21.92
Garfield37.54
Gosper71.18
Grant21.19
Greeley75.05
Hall128.67
Hamilton160.51
Harlan72.85
Hayes35.82
Hitchcock39.84
Holt60.25
Hooker18.61
Howard88.37
Jefferson105.08
Johnson91.91
Kearney132.44
Keith41.16
Keya Paha35.84
Kimball27.21
Knox84.67
Lancaster141.71
Lincoln42.38
Logan30.38
Loup29.44
Madison147.30
McPherson20.73
Merrick128.44
Morrill28.98
Nance107.00
Nemaha115.13
Nuckolls90.83
Otoe125.48
Pawnee82.12
Perkins54.17
Phelps129.45
Pierce123.33
Platte160.18
Polk149.63
Red Willow49.29
Richardson108.01
Rock28.81
Saline119.38
Sarpy188.31
Saunders142.79
Scotts Bluff51.59
Seward144.54
Sheridan24.55
Sherman67.74
Sioux22.81
Stanton126.34
Thayer99.23
Thomas19.74
Thurston122.19
Valley72.85
Washington165.02
Wayne139.53
Webster69.33
Wheeler38.68
York174.11
NevadaCarson City6.44
Churchill13.56
Clark22.02
Douglas14.55
Elko3.89
Esmeralda14.75
Eureka3.54
Humboldt6.28
Lander7.43
Lincoln18.24
Lyon16.19
Mineral2.08
Nye12.27
Pershing5.67
Storey6.44
Washoe7.27
White Pine9.39
New HampshireBelknap130.52
Carroll104.36
Cheshire100.70
Coos68.10
Grafton103.78
Hillsborough206.52
Merrimack154.00
Rockingham299.64
Strafford172.47
Sullivan127.28
New JerseyAtlantic319.76
Bergen2,492.05
Burlington251.82
Camden411.33
Cape May364.78
Cumberland245.53
Essex2,115.16
Gloucester317.56
Hudson1,260.32
Hunterdon391.24
Mercer453.79
Middlesex545.46
Monmouth525.64
Morris536.76
Ocean476.76
Passaic800.49
Salem210.94
Somerset495.43
Sussex288.97
Union3,919.18
Warren305.23
New MexicoBernalillo55.47
Catron8.44
Chaves9.51
Cibola6.37
Colfax10.15
Curry13.97
De Baca7.54
Dona Ana49.94
Eddy11.88
Grant9.79
Guadalupe6.25
Harding7.36
Hidalgo10.47
Lea8.28
Lincoln10.01
Los Alamos10.47
Luna10.35
McKinley8.60
Mora11.10
Otero8.83
Quay7.08
Rio Arriba17.25
Roosevelt9.19
San Juan10.74
San Miguel8.08
Sandoval9.03
Santa Fe17.71
Sierra7.26
Socorro12.63
Taos32.87
Torrance9.59
Union8.30
Valencia23.36
New YorkAlbany120.70
Allegany54.65
Bronx87.66
Broome83.86
Cattaraugus62.20
Cayuga107.37
Chautauqua71.81
Chemung71.10
Chenango55.82
Clinton71.81
Columbia113.70
Cortland62.98
Delaware78.19
Dutchess245.42
Erie124.23
Essex64.67
Franklin67.52
Fulton75.77
Genesee90.81
Greene85.68
Hamilton90.70
Herkimer62.14
Jefferson72.68
Kings12,043.04
Lewis54.54
Livingston100.77
Madison71.16
Monroe116.90
Montgomery67.46
Nassau471.35
New York87.66
Niagara83.34
Oneida72.19
Onondaga111.90
Ontario109.33
Orange188.30
Orleans86.14
Oswego60.08
Otsego72.38
Putnam162.92
Queens1,317.15
Rensselaer95.37
Richmond87.66
Rockland781.11
Saratoga159.90
Schenectady116.41
Schoharie66.11
Schuyler88.77
Seneca101.97
St. Lawrence49.74
Steuben56.98
Suffolk331.72
Sullivan114.38
Tioga62.03
Tompkins102.86
Ulster187.30
Warren113.32
Washington75.85
Wayne93.31
Westchester289.02
Wyoming94.01
Yates141.90
North CarolinaAlamance163.56
Alexander153.53
Alleghany134.58
Anson111.38
Ashe143.33
Avery177.02
Beaufort93.23
Bertie82.65
Bladen90.88
Brunswick106.86
Buncombe271.20
Burke155.41
Cabarrus237.40
Caldwell123.70
Camden86.74
Carteret123.65
Caswell88.35
Catawba178.36
Chatham150.06
Cherokee133.73
Chowan95.24
Clay171.11
Cleveland127.14
Columbus88.97
Craven107.32
Cumberland140.82
Currituck133.73
Dare114.68
Davidson158.02
Davie138.72
Duplin130.79
Durham290.48
Edgecombe83.11
Forsyth253.70
Franklin96.93
Gaston167.40
Gates98.82
Graham130.52
Granville94.97
Greene107.54
Guilford222.93
Halifax69.95
Harnett151.97
Haywood176.12
Henderson211.42
Hertford87.20
Hoke120.00
Hyde81.07
Iredell148.24
Jackson223.39
Johnston129.24
Jones110.51
Lee157.12
Lenoir108.49
Lincoln156.22
Macon217.15
Madison135.18
Martin73.00
McDowell143.33
Mecklenburg934.67
Mitchell158.51
Montgomery129.29
Moore139.05
Nash126.13
New Hanover927.88
Northampton76.24
Onslow171.30
Orange182.26
Pamlico99.55
Pasquotank108.60
Pender145.81
Perquimans97.04
Person102.99
Pitt104.81
Polk175.61
Randolph137.71
Richmond118.99
Robeson90.37
Rockingham105.58
Rowan159.47
Rutherford130.35
Sampson133.33
Scotland98.13
Stanly125.37
Stokes111.33
Surry121.88
Swain99.72
Transylvania210.85
Tyrrell113.07
Union145.46
Vance81.18
Wake317.79
Warren79.30
Washington99.99
Watauga175.52
Wayne136.02
Wilkes139.68
Wilson103.15
Yadkin149.14
Yancey148.46
North DakotaAdams29.75
Barnes64.43
Benson38.14
Billings25.62
Bottineau43.10
Bowman28.66
Burke29.38
Burleigh52.97
Cass103.65
Cavalier57.99
Dickey66.21
Divide29.80
Dunn31.98
Eddy40.56
Emmons44.19
Foster55.98
Golden Valley29.33
Grand Forks95.10
Grant29.86
Griggs49.54
Hettinger39.17
Kidder35.07
LaMoure70.78
Logan33.20
McHenry30.36
McIntosh38.03
McKenzie28.60
McLean49.76
Mercer38.14
Morton39.14
Mountrail35.63
Nelson37.92
Oliver40.23
Pembina76.86
Pierce39.28
Ramsey50.43
Ransom56.09
Renville44.75
Richland88.91
Rolette35.69
Sargent77.70
Sheridan30.61
Sioux34.65
Slope29.47
Stark37.11
Steele61.25
Stutsman55.90
Towner38.61
Traill85.98
Walsh70.06
Ward45.53
Wells47.70
Williams30.56
OhioAdams107.91
Allen201.70
Ashland168.87
Ashtabula121.56
Athens89.31
Auglaize226.30
Belmont106.44
Brown122.53
Butler229.47
Carroll130.93
Champaign199.31
Clark209.65
Clermont155.81
Clinton165.62
Columbiana160.37
Coshocton146.74
Crawford179.18
Cuyahoga453.49
Darke231.25
Defiance159.45
Delaware217.49
Erie181.91
Fairfield214.10
Fayette198.53
Franklin223.52
Fulton194.17
Gallia87.37
Geauga201.39
Greene198.48
Guernsey103.46
Hamilton369.52
Hancock167.95
Hardin163.67
Harrison92.01
Henry182.08
Highland139.57
Hocking125.84
Holmes215.18
Huron169.09
Jackson78.22
Jefferson151.89
Knox168.09
Lake226.89
Lawrence91.37
Licking183.91
Logan168.20
Lorain208.04
Lucas230.08
Madison192.75
Mahoning184.19
Marion162.28
Medina217.74
Meigs96.37
Mercer268.89
Miami206.29
Monroe90.84
Montgomery200.53
Morgan96.12
Morrow166.84
Muskingum114.00
Noble85.56
Ottawa150.36
Paulding174.01
Perry127.15
Pickaway167.70
Pike115.53
Portage180.99
Preble177.82
Putnam186.08
Richland208.62
Ross127.40
Sandusky164.73
Scioto87.23
Seneca163.70
Shelby213.71
Stark256.96
Summit371.52
Trumbull120.39
Tuscarawas154.42
Union176.52
Van Wert208.32
Vinton88.01
Warren217.49
Washington88.65
Wayne248.51
Williams143.46
Wood185.11
Wyandot158.61
OklahomaAdair65.52
Alfalfa46.65
Atoka50.24
Beaver24.60
Beckham36.49
Blaine44.59
Bryan62.10
Caddo47.44
Canadian64.34
Carter55.61
Cherokee68.01
Choctaw48.59
Cimarron22.60
Cleveland132.88
Coal49.88
Comanche52.81
Cotton37.23
Craig57.66
Creek60.07
Custer39.77
Delaware74.75
Dewey37.55
Ellis27.23
Garfield47.55
Garvin52.51
Grady57.47
Grant43.96
Greer31.66
Harmon34.29
Harper30.16
Haskell52.10
Hughes43.69
Jackson38.29
Jefferson42.35
Johnston51.28
Kay45.06
Kingfisher52.67
Kiowa34.35
Latimer49.20
Le Flore59.22
Lincoln61.38
Logan61.36
Love67.25
Major40.65
Marshall66.34
Mayes76.15
McClain72.20
McCurtain58.65
McIntosh52.07
Murray58.56
Muskogee61.80
Noble48.73
Nowata56.51
Okfuskee46.92
Oklahoma177.50
Okmulgee60.59
Osage43.61
Ottawa76.04
Pawnee48.84
Payne66.32
Pittsburg47.99
Pontotoc59.39
Pottawatomie61.74
Pushmataha42.24
Roger Mills35.12
Rogers79.71
Seminole49.94
Sequoyah60.02
Stephens48.18
Texas27.75
Tillman36.35
Tulsa159.67
Wagoner77.60
Washington64.48
Washita40.70
Woods36.32
Woodward33.31
OregonBaker24.24
Benton124.83
Clackamas417.13
Clatsop138.69
Columbia167.79
Coos59.10
Crook18.52
Curry68.66
Deschutes168.04
Douglas66.19
Gilliam13.96
Grant20.07
Harney13.22
Hood River270.01
Jackson164.69
Jefferson16.58
Josephine348.85
Klamath42.44
Lake20.96
Lane165.89
Lincoln106.60
Linn137.51
Malheur28.85
Marion239.78
Morrow21.85
Multnomah404.82
Polk137.97
Sherman16.48
Tillamook151.16
Umatilla35.37
Union35.13
Wallowa31.64
Wasco17.66
Washington331.53
Wheeler17.55
Yamhill197.34
PennsylvaniaAdams189.72
Allegheny241.51
Armstrong100.40
Beaver166.68
Bedford112.30
Berks308.82
Blair185.89
Bradford99.82
Bucks259.20
Butler145.77
Cambria127.59
Cameron78.36
Carbon182.36
Centre184.59
Chester334.47
Clarion88.44
Clearfield99.40
Clinton180.13
Columbia166.11
Crawford92.05
Cumberland209.75
Dauphin242.20
Delaware396.60
Elk115.66
Erie124.28
Fayette114.09
Forest135.00
Franklin207.41
Fulton115.03
Greene100.40
Huntingdon132.63
Indiana99.18
Jefferson91.30
Juniata179.69
Lackawanna146.05
Lancaster503.77
Lawrence120.89
Lebanon396.74
Lehigh216.25
Luzerne167.04
Lycoming141.03
McKean78.47
Mercer110.12
Mifflin170.24
Monroe162.33
Montgomery533.39
Montour177.48
Northampton206.74
Northumberland161.78
Perry182.64
Philadelphia1,617.56
Pike61.33
Potter94.47
Schuylkill183.08
Snyder202.01
Somerset88.80
Sullivan112.71
Susquehanna130.59
Tioga104.61
Union264.46
Venango104.61
Warren95.35
Washington179.39
Wayne118.30
Westmoreland162.80
Wyoming114.17
York225.95
Puerto RicoAll Areas149.23
Rhode IslandBristol1,050.42
Kent329.79
Newport568.65
Providence332.15
Washington317.05
South CarolinaAbbeville83.76
Aiken101.92
Allendale59.68
Anderson153.54
Bamberg79.33
Barnwell75.35
Beaufort97.99
Berkeley72.32
Calhoun82.54
Charleston253.48
Cherokee91.01
Chester89.90
Chesterfield79.87
Clarendon61.52
Colleton81.98
Darlington70.23
Dillon61.98
Dorchester76.05
Edgefield95.42
Fairfield77.57
Florence85.66
Georgetown55.27
Greenville248.58
Greenwood92.42
Hampton65.99
Horry122.02
Jasper99.05
Kershaw83.57
Lancaster106.92
Laurens103.73
Lee65.36
Lexington149.70
Marion63.07
Marlboro52.13
McCormick54.22
Newberry89.66
Oconee172.75
Orangeburg81.65
Pickens190.74
Richland129.78
Saluda83.68
Spartanburg222.69
Sumter81.03
Union68.56
Williamsburg60.74
York188.82
South DakotaAurora73.68
Beadle74.76
Bennett26.43
Bon Homme110.60
Brookings127.76
Brown93.33
Brule71.57
Buffalo42.89
Butte26.62
Campbell50.83
Charles Mix77.40
Clark87.45
Clay130.54
Codington96.25
Corson25.51
Custer44.31
Davison94.33
Day73.43
Deuel95.72
Dewey26.93
Douglas103.30
Edmunds68.29
Fall River19.88
Faulk70.71
Grant103.52
Gregory52.16
Haakon25.62
Hamlin108.99
Hand57.08
Hanson119.99
Harding18.46
Hughes52.50
Hutchinson124.79
Hyde42.39
Jackson24.29
Jerauld66.38
Jones31.73
Kingsbury105.77
Lake142.17
Lawrence49.67
Lincoln191.72
Lyman45.83
Marshall78.12
McCook121.24
McPherson59.80
Meade26.40
Mellette26.79
Miner98.08
Minnehaha179.04
Moody161.57
Pennington18.70
Perkins29.37
Potter23.07
Roberts58.69
Sanborn83.48
Shannon79.32
Spink86.95
Stanley25.57
Sully59.80
Todd23.60
Tripp44.97
Turner139.34
Union163.10
Walworth54.97
Yankton122.76
Ziebach23.74
TennesseeAnderson151.90
Bedford115.82
Benton69.18
Bledsoe95.75
Blount178.89
Bradley168.58
Campbell115.01
Cannon99.70
Carroll76.02
Carter144.51
Cheatham126.66
Chester70.60
Claiborne86.94
Clay92.64
Cocke123.05
Coffee114.10
Crockett93.53
Cumberland112.37
Davidson249.54
Decatur61.40
DeKalb94.06
Dickson116.77
Dyer93.50
Fayette93.75
Fentress96.50
Franklin113.99
Gibson98.42
Giles91.03
Grainger105.56
Greene124.88
Grundy96.14
Hamblen153.07
Hamilton273.78
Hancock73.99
Hardeman63.62
Hardin62.04
Hawkins103.59
Haywood92.25
Henderson70.10
Henry92.39
Hickman87.66
Houston89.86
Humphreys77.35
Jackson86.30
Jefferson143.12
Johnson110.43
Knox273.64
Lake97.59
Lauderdale94.09
Lawrence91.61
Lewis79.47
Lincoln101.81
Loudon158.15
Macon104.59
Madison90.69
Marion90.44
Marshall97.23
Maury112.21
McMinn129.69
McNairy61.23
Meigs92.47
Monroe118.18
Montgomery136.67
Moore100.64
Morgan85.00
Obion100.03
Overton93.78
Perry61.59
Pickett97.31
Polk114.32
Putnam129.22
Rhea119.82
Roane146.37
Robertson146.90
Rutherford204.60
Scott74.24
Sequatchie107.40
Sevier169.94
Shelby145.56
Smith95.92
Stewart73.66
Sullivan196.37
Sumner147.65
Tipton91.44
Trousdale95.39
Unicoi198.59
Union113.74
Van Buren93.11
Warren96.06
Washington218.77
Wayne65.79
Weakley100.51
White106.06
Williamson168.46
Wilson136.50
TexasAnderson75.24
Andrews20.88
Angelina96.68
Aransas44.68
Archer39.43
Armstrong24.65
Atascosa60.57
Austin103.63
Bailey22.60
Bandera67.15
Bastrop109.15
Baylor27.38
Bee54.31
Bell87.08
Bexar157.57
Blanco79.12
Borden23.43
Bosque65.88
Bowie79.67
Brazoria124.19
Brazos150.94
Brewster18.07
Briscoe23.69
Brooks41.18
Brown63.97
Burleson90.92
Burnet78.64
Caldwell101.38
Calhoun56.88
Callahan45.95
Cameron94.45
Camp87.40
Carson36.06
Cass62.22
Castro36.61
Chambers62.80
Cherokee82.43
Childress24.54
Clay51.05
Cochran24.57
Coke25.52
Coleman43.59
Collin263.88
Collingsworth26.90
Colorado79.83
Comal90.61
Comanche70.02
Concho39.13
Cooke87.74
Coryell69.14
Cottle29.45
Crane22.50
Crockett21.54
Crosby25.74
Culberson19.53
Dallam30.09
Dallas214.83
Dawson27.59
Deaf Smith29.93
Delta52.21
Denton253.38
DeWitt81.51
Dickens28.26
Dimmit37.41
Donley22.95
Duval45.02
Eastland52.11
Ector30.72
Edwards31.04
El Paso106.52
Ellis85.19
Erath84.00
Falls66.67
Fannin76.23
Fayette106.98
Fisher30.01
Floyd26.69
Foard29.61
Fort Bend82.33
Franklin82.25
Freestone68.05
Frio49.03
Gaines30.64
Galveston140.59
Garza26.66
Gillespie80.63
Glasscock24.38
Goliad70.52
Gonzales84.37
Gray30.35
Grayson179.62
Gregg149.88
Grimes102.07
Guadalupe103.29
Hale34.52
Hall24.38
Hamilton66.59
Hansford35.61
Hardeman27.70
Hardin82.96
Harris229.10
Harrison69.73
Hartley32.93
Haskell27.91
Hays259.29
Hemphill29.56
Henderson84.58
Hidalgo114.59
Hill67.10
Hockley26.74
Hood90.95
Hopkins77.42
Houston74.05
Howard24.54
Hudspeth23.96
Hunt82.09
Hutchinson25.68
Irion26.40
Jack61.90
Jackson77.21
Jasper85.09
Jeff Davis18.23
Jefferson62.48
Jim Hogg46.09
Jim Wells54.89
Johnson104.83
Jones30.27
Karnes64.90
Kaufman79.86
Kendall82.14
Kenedy19.55
Kent22.74
Kerr66.25
Kimble52.85
King18.39
Kinney32.93
Kleberg35.02
Knox29.56
La Salle42.03
Lamar66.51
Lamb33.06
Lampasas75.03
Lavaca93.15
Lee97.53
Leon80.58
Liberty79.81
Limestone48.87
Lipscomb29.82
Live Oak57.28
Llano69.51
Loving5.07
Lubbock45.16
Lynn26.72
Madison79.49
Marion53.14
Martin23.61
Mason61.50
Matagorda63.60
Maverick37.28
McCulloch52.29
McLennan95.73
McMullen48.18
Medina70.95
Menard39.32
Midland42.69
Milam83.92
Mills66.57
Mitchell26.45
Montague72.48
Montgomery302.83
Moore30.09
Morris60.57
Motley22.47
Nacogdoches76.81
Navarro62.32
Newton58.93
Nolan29.24
Nueces80.97
Ochiltree32.69
Oldham21.62
Orange122.55
Palo Pinto64.74
Panola70.84
Parker113.98
Parmer29.85
Pecos18.36
Polk79.89
Potter26.96
Presidio20.77
Rains92.30
Randall41.97
Reagan22.23
Real50.97
Red River51.13
Reeves13.96
Refugio33.16
Roberts20.19
Robertson76.65
Rockwall146.88
Runnels36.69
Rusk67.95
Sabine59.86
San Augustine74.82
San Jacinto108.78
San Patricio70.31
San Saba64.98
Schleicher31.33
Scurry27.75
Shackelford34.23
Shelby93.05
Sherman37.97
Smith139.24
Somervell83.12
Starr48.66
Stephens46.40
Sterling17.99
Stonewall24.25
Sutton33.70
Swisher27.75
Tarrant161.95
Taylor54.47
Terrell19.93
Terry27.04
Throckmorton37.36
Titus66.86
Tom Green41.71
Travis165.98
Trinity70.15
Tyler90.53
Upshur91.35
Upton21.44
Uvalde34.46
Val Verde26.74
Van Zandt97.45
Victoria77.47
Walker97.61
Waller123.90
Ward28.23
Washington126.85
Webb45.45
Wharton76.99
Wheeler28.89
Wichita39.11
Wilbarger33.93
Willacy46.62
Williamson98.75
Wilson84.21
Winkler29.74
Wise103.37
Wood89.20
Yoakum24.91
Young44.87
Zapata37.46
Zavala46.19
UtahBeaver25.88
Box Elder17.82
Cache56.19
Carbon14.39
Daggett32.29
Davis108.42
Duchesne11.35
Emery24.43
Garfield36.36
Grand9.58
Iron22.73
Juab15.43
Kane21.09
Millard23.75
Morgan25.58
Piute24.20
Rich10.15
Salt Lake112.57
San Juan4.27
Sanpete32.79
Sevier49.79
Summit37.96
Tooele15.99
Uintah7.32
Utah101.55
Wasatch64.61
Washington43.45
Wayne52.77
Weber108.35
VermontAddison91.48
Bennington130.74
Caledonia87.53
Chittenden175.20
Essex53.65
Franklin85.56
Grand Isle118.06
Lamoille95.62
Orange100.97
Orleans74.28
Rutland75.74
Washington117.49
Windham137.46
Windsor106.02
VirginiaAccomack118.06
Albemarle273.64
Alleghany116.60
Amelia85.59
Amherst128.74
Appomattox85.59
Arlington8,243.41
Augusta193.61
Bath101.71
Bedford121.69
Bland95.32
Botetourt116.13
Brunswick69.54
Buchanan66.89
Buckingham103.21
Campbell85.37
Caroline102.24
Carroll89.05
Charles City93.31
Charlotte72.50
Chesapeake City161.77
Chesterfield254.94
Clarke194.91
Craig82.71
Culpeper158.98
Cumberland105.28
Dickenson78.01
Dinwiddie84.87
Essex88.35
Fairfax464.90
Fauquier203.57
Floyd105.17
Fluvanna119.36
Franklin99.64
Frederick199.81
Giles85.01
Gloucester130.48
Goochland150.21
Grayson114.94
Greene180.66
Greensville75.02
Halifax73.33
Hanover139.28
Henrico167.80
Henry81.91
Highland88.46
Isle of Wight102.74
James City279.75
King and Queen93.42
King George141.38
King William111.92
Lancaster117.21
Lee73.19
Loudoun271.53
Louisa137.01
Lunenburg73.69
Madison164.56
Mathews118.34
Mecklenburg76.46
Middlesex109.74
Montgomery133.94
Nelson140.33
New Kent148.08
Northampton126.83
Northumberland83.15
Nottoway87.80
Orange174.19
Page180.22
Patrick76.76
Pittsylvania78.42
Powhatan146.58
Prince Edward78.78
Prince George105.31
Prince William295.82
Pulaski97.32
Rappahannock190.62
Richmond109.41
Roanoke158.87
Rockbridge136.04
Rockingham244.65
Russell79.94
Scott72.95
Shenandoah162.77
Smyth81.05
Southampton85.39
Spotsylvania155.93
Stafford362.49
Suffolk114.16
Surry93.47
Sussex76.76
Tazewell75.68
Virginia Beach City266.89
Warren208.80
Washington139.36
Westmoreland103.24
Wise85.67
Wythe108.46
York334.58
WashingtonAdams25.84
Asotin23.94
Benton70.53
Chelan278.63
Clallam231.03
Clark161.86
Columbia29.46
Cowlitz162.02
Douglas21.35
Ferry9.37
Franklin83.14
Garfield28.46
Grant61.90
Grays Harbor43.33
Island198.64
Jefferson137.70
King637.73
Kitsap636.21
Kittitas74.67
Klickitat32.17
Lewis108.57
Lincoln22.11
Mason154.91
Okanogan21.84
Pacific62.67
Pend Oreille48.22
Pierce388.81
San Juan171.10
Skagit183.28
Skamania218.60
Snohomish349.77
Spokane67.45
Stevens28.39
Thurston214.94
Wahkiakum86.94
Walla Walla45.79
Whatcom303.85
Whitman31.59
Yakima49.85
West VirginiaBarbour64.86
Berkeley148.58
Boone64.97
Braxton57.05
Brooke78.47
Cabell99.00
Calhoun50.64
Clay47.83
Doddridge59.14
Fayette80.91
Gilmer36.58
Grant72.83
Greenbrier72.39
Hampshire83.44
Hancock127.05
Hardy89.25
Harrison69.55
Jackson61.41
Jefferson163.13
Kanawha107.80
Lewis60.00
Lincoln51.19
Logan68.72
Marion82.33
Marshall71.86
Mason67.50
McDowell172.10
Mercer69.86
Mineral77.44
Mingo31.00
Monongalia125.83
Monroe73.94
Morgan145.38
Nicholas72.64
Ohio100.66
Pendleton62.50
Pleasants64.11
Pocahontas52.08
Preston76.30
Putnam79.61
Raleigh103.02
Randolph67.36
Ritchie50.14
Roane53.61
Summers63.11
Taylor85.41
Tucker79.52
Tyler53.14
Upshur73.47
Wayne55.80
Webster63.86
Wetzel53.53
Wirt50.22
Wood92.58
Wyoming92.97
WisconsinAdams123.08
Ashland61.25
Barron93.75
Bayfield60.07
Brown232.92
Buffalo108.03
Burnett74.66
Calumet215.90
Chippewa97.58
Clark111.27
Columbia159.80
Crawford87.19
Dane225.90
Dodge160.24
Door130.43
Douglas53.77
Dunn98.74
Eau Claire125.22
Florence69.29
Fond du Lac199.47
Forest66.52
Grant129.33
Green148.80
Green Lake156.84
Iowa133.37
Iron93.25
Jackson104.19
Jefferson168.74
Juneau101.56
Kenosha207.70
Kewaunee154.09
La Crosse136.74
Lafayette163.88
Langlade89.71
Lincoln88.86
Manitowoc187.11
Marathon130.27
Marinette106.30
Marquette114.50
Menominee47.60
Milwaukee244.80
Monroe108.77
Oconto114.23
Oneida111.46
Outagamie197.61
Ozaukee179.70
Pepin106.22
Pierce126.68
Polk96.98
Portage112.42
Price67.42
Racine210.63
Richland92.02
Rock180.66
Rusk68.14
Sauk115.35
Sawyer71.10
Shawano127.83
Sheboygan180.80
St. Croix128.54
Taylor80.47
Trempealeau108.52
Vernon106.49
Vilas162.13
Walworth190.09
Washburn85.77
Washington193.39
Waukesha151.00
Waupaca123.82
Waushara116.01
Winnebago191.14
Wood90.78
WyomingAlbany10.97
Big Horn23.84
Campbell8.49
Carbon8.25
Converse7.94
Crook14.69
Fremont19.11
Goshen12.93
Hot Springs9.32
Johnson8.82
Laramie12.72
Lincoln27.42
Natrona6.81
Niobrara9.41
Park22.41
Platte13.17
Sheridan18.36
Sublette24.77
Sweetwater4.44
Teton60.74
Uinta16.08
Washakie17.54
Weston10.04

[88 FR 6992, Feb. 2, 2023]


PART 12 – SAFETY OF WATER POWER PROJECTS AND PROJECT WORKS


Authority:16 U.S.C. 791a-825r; 42 U.S.C. 7101-7352.


Source:Order 122, 46 FR 9036, Jan. 28, 1981, unless otherwise noted.


Editorial Note:Nomenclature changes to part 12 appear at 69 FR 32438, June 10, 2004.

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.


[Order 122, 46 FR 9036, Jan. 28, 1981, as amended by Order 225, 47 FR 19056, May 3, 1982; 49 FR 29370, July 20, 1984]


§ 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.


[Order 122, 46 FR 9036, Jan. 28, 1981, as amended at 49 FR 29370, July 20, 1984; Order 647, 69 FR 32438, June 10, 2004; 87 FR 1513, Jan. 11, 2022; 87 FR 8411, Feb. 15, 2022]


§ 12.4 Staff administrative responsibility and supervisory authority.

(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.


[Order 122, 46 FR 9036, Jan. 28, 1981, as amended by Order 225, 47 FR 19056, May 3, 1982; 49 FR 29370, July 20, 1984; Order 756, 77 FR 4894, Feb. 1, 2012; 87 FR 1514, Jan. 11, 2022; 87 FR 2702, Jan. 19, 2022]


§ 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

§ 12.10 Reporting safety-related incidents.

(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.


[Order 122, 46 FR 9036, Jan. 28, 1981, as amended at 87 FR 1514, Jan. 11, 2022; 87 FR 2702, Jan. 19, 2022; 87 FR 8411, Feb. 15, 2022]


§ 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.


[Order 122, 46 FR 9036, Jan. 28, 1981, as amended at 87 FR 1514, Jan. 11, 2022]


§ 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:



State of [ ],

County of [ ], ss:

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.




[Name of person signing]

Sworn to and subscribed before me this [day] of [month], [year].


[Seal]



[Signature of notary public or other state or local official authorized by law to notarize documents.]

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).


[Order 122, 46 FR 9036, Jan. 28, 1981, as amended at 87 FR 1515, Jan. 11, 2022]


§ 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.


[Order 122, 46 FR 9036, Jan. 28, 1981, as amended at 49 FR 29370, July 20, 1984; 87 FR 1515, Jan. 11, 2022]


§ 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.


[Order 122, 46 FR 9036, Jan. 28, 1981, as amended at 87 FR 1515, Jan. 11, 2022]


§ 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


Source:87 FR 1515, Jan. 11, 2022, unless otherwise noted.

§ 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.


[87 FR 1515, Jan. 11, 2022; 87 FR 8411, Feb. 15, 2022]


§ 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.


[Order 122, 46 FR 9036, Jan. 28, 1981. Redesignated and amended at 87 FR 1519, Jan. 11, 2022; 87 FR 8411, Feb. 15, 2022]


§ 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.


[Order 122, 46 FR 9036, Jan. 28, 1981. Redesignated at 87 FR 1519, Jan. 11, 2022; 87 FR 8411, Feb. 15, 2022]


§ 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.


[87 FR 1519, Jan. 11, 2022; 87 FR 8411, Feb. 15, 2022]


§ 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.


[Order 122, 46 FR 9036, Jan. 28, 1981. Redesignated at 87 FR 1519, Jan. 11, 2022; 87 FR 8411, Feb. 15, 2022]


§ 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.


[Order 122, 46 FR 9036, Jan. 28, 1981. Redesignated and amended at 87 FR 1519, Jan. 11, 2022; 87 FR 8411, Feb. 15, 2022]


§§ 12.55-12.59 [Reserved]

Subpart F – Owner’s Dam Safety Program


Source:87 FR 1519, Jan. 11, 2022, unless otherwise noted.

§ 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


Authority:16 U.S.C. 791a-825r, 2601-2645; 42 U.S.C. 7101-7352.


Source:Order 513, 54 FR 23806, June 2, 1989, unless otherwise noted.

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.


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 2002, 68 FR 51139, Aug. 25, 2003]


§ 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.


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 513-A, 55 FR 15, Jan. 2, 1990; Order 533, 56 FR 23154, May 20, 1991]


§ 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 Federal Register, a table showing the projects whose licenses will expire during the succeeding six years. The table will:


(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 Federal Register;


(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 Federal Register;


(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.


[Order 496, 53 FR 15810, May 4, 1988. Redesignated and amended by Order 513, 54 FR 23807, June 2, 1989; Order 2002, 68 FR 51139, Aug. 25, 2003; Order 653, 70 FR 8724, Feb. 23, 2005; Order 737, 75 FR 43403, July 26, 2010]


§ 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).


[Order 496, 53 FR 15810, May 4, 1988. Redesignated by Order 513, 54 FR 23807, June 2, 1989; Order 513-C, 55 FR 10768, Mar. 23, 1990; Order 2002, 68 FR 51139, Aug. 25, 2003; Order 643, 68 FR 52095, Sept. 2, 2003]


§ 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).


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 513-A, 55 FR 16, Jan. 2, 1990; Order 533, 56 FR 23154, May 20, 1991; 56 FR 61156, Dec. 2, 1991; Order 2002, 68 FR 51140, Aug. 25, 2003; Order 643, 68 FR 52095, Sept. 2, 2003; 68 FR 61743, Oct. 30, 2003; Order 769, 77 FR 65475, Oct. 29, 2012]


§ 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 Federal Register;


(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 Federal Register;


(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.


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 2002, 68 FR 51142, Aug. 25, 2003; Order 653, 70 FR 8724, Feb. 23, 2005]


§ 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.”


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 533, 56 FR 23154, May 20, 1991; 56 FR 61156, Dec. 2, 1991; Order 2002, 68 FR 51142, Aug. 25, 2003]


§ 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.


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 2002, 68 FR 51142, Aug. 25, 2003]


§ 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.


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 699, 72 FR 45324, Aug. 14, 2007]


§ 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.


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 699, 72 FR 45324, Aug. 14, 2007]


§ 16.17 Procedures upon Congressional authorization of takeover.

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.


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 513-A, 55 FR 18, Jan. 2, 1990; Order 540, 57 FR 21738, May 22, 1992]


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.


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 2002, 68 FR 51142, Aug. 25, 2003; Order 699, 72 FR 45324, Aug. 14, 2007]


§ 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.


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 2002, 68 FR 51142, Aug. 25, 2003]


§ 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.


[Order 513, 54 FR 23806, June 2, 1989, as amended by Order 699, 72 FR 45324, Aug. 14, 2007]


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 Federal Register and 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, notice soliciting applications from potential applicants other than the existing licensee.


(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


Authority:Secs. 3(16), 19, 20, 41 Stat. 1063, 1073; secs. 201, 309, 49 Stat. 838, 858; 16 U.S.C. 796 (16), 812, 813, 825k.


Source:Order 170, 19 FR 2013, Apr. 8, 1954, unless otherwise noted.

§ 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.



Cross Reference:

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


Authority:16 U.S.C. 791a-825r; 44 U.S.C. 3501 et seq.; 42 U.S.C. 7101-7352.

§ 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.


[Order 175, 19 FR 5217, Aug. 18, 1954, as amended by Order 260, 28 FR 315, Jan. 11, 1963; Order 540, 57 FR 21738, May 22, 1992; Order 737, 75 FR 43403, July 26, 2010]


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.


(Secs. 24, 309, 41 Stat. 1075, as amended; 49 Stat. 858; 16 USC. 818, 825h)

[Order 175, 19 FR 5218, Aug. 18, 1954, as amended by Order 346, 32 FR 7495, May 20, 1967]


Cross Reference:

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.



Note 1:

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.



Note 2:

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.


(Secs. 24, 308, 39, 41 Stat. 1075, as amended, 40 Stat. 858; 16 U.S.C. 818, 825g, 825h)

[Order 141, 12 FR 8493, Dec. 19, 1947, as amended by Order 225, 47 FR 19056, May 3, 1982]


Cross Reference:

For regulations of the Bureau of Land Management, relating to grazing, see the Index to title 43 Chapter II.


PART 32 – INTERCONNECTION OF FACILITIES


Authority:42 U.S.C. 7101-7352; E.O. No. 12,009, 3 CFR 1978 Comp., p. 142; 31 U.S.C. 9701; 16 U.S.C. 791a-825r; 16 U.S.C. 2601-2645 (1988).


Source:Order 141, 12 FR 8494, Dec. 19, 1947, unless otherwise noted.

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.


[Order 141, 12 FR 8494, Dec. 19, 1947, as amended by Order 427, 36 FR 5596, Mar. 25, 1971; Order 435, 50 FR 40357, Oct. 3, 1985; Order 737, 75 FR 43403, July 26, 2010]


§ 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.


[Order 737, 75 FR 43403, July 26, 2010]


PART 33 – APPLICATIONS UNDER FEDERAL POWER ACT SECTION 203


Authority:16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.


Source:Order 642, 65 FR 71014, Nov. 28, 2000, unless otherwise noted.

§ 33.1 Applicability, definitions, and blanket authorizations.

(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).


[Order 669-A, 71 FR 28443, May 16, 2006, as amended by Order 708, 73 FR 11013, Feb. 29, 2008; Order 708-A, 73 FR 43072, July 24, 2008; Order 708-B, 74 FR 25413, May 28, 2009; Order 855, 84 FR 6075, Feb. 26, 2019]


§ 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.


[Order 642, 65 FR 71014, Nov. 28, 2000, as amended by Order 669-A, 71 FR 28446, May 16, 2006; Order 669-B, 71 FR 42586, July 27, 2006; Order 659-B, 71 FR 45736, Aug. 10, 2006]


§ 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.


[65 FR 71014, Nov. 28, 2000; 65 FR 76005, Dec. 5, 2000]


§ 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.


[Order 769, 77 FR 65475, Oct. 29, 2012]


§ 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.


[Order 642, 65 FR 71014, Nov. 28, 2000, as amended by Order 699, 72 FR 45324, Aug. 14, 2007; Order 701, 72 FR 61053, Oct. 29, 2007]


§ 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;
1
and




1 Inquiry Concerning the Commission’s Merger Policy Under the Federal Power Act; Policy Statement, Order No. 592, 61 FR 68,595 (Dec. 30, 1996), FERC Stats. & Regs. ¶ 31,044 (1996), reconsideration denied, Order No. 592-A, 62 FR 33,340 (June 19, 1977), 79 FERC ¶ 61,321 (1997) (Merger Policy Statement).


(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.


[Order 669-A, 71 FR 28446, May 16, 2006]


§ 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.


[Order 855, 84 FR 6075, Feb. 26, 2019]


PART 34 – APPLICATION FOR AUTHORIZATION OF THE ISSUANCE OF SECURITIES OR THE ASSUMPTION OF LIABILITIES


Authority:16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.


Source:Order 182, 46 FR 50514, Oct. 14, 1981, unless otherwise noted.


Cross References:

For rules of practice and procedure, see part 385 of this chapter. For Approved Forms, Federal Power Act, see part 131 of this chapter.



OMB Reference:

“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.


[Order 182, 46 FR 50514, Oct. 14, 1981, as amended at 48 FR 9851, Mar. 9, 1983; Order 575, 60 FR 4852, Jan. 25, 1995]


§ 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.


[Order 575, 60 FR 4853, Jan. 25, 1995]


§ 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.


[Order 182, 46 FR 50514, Oct. 14, 1981, as amended by Order 390, 49 FR 32505, Aug. 14, 1984; Order 575, 60 FR 4853, Jan. 25, 1995; Order 593, 62 FR 1283, Jan. 9, 1997; Order 647, 69 FR 32438, June 10, 2004; Order 737, 75 FR 43403, July 26, 2010]


§ 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.


[Order 182, 46 FR 50514, Oct. 14, 1981, as amended by Order 390, 49 FR 32505, Aug. 14, 1984; Order 575, 60 FR 4853, Jan. 25, 1995; 60 FR 27882, May 26, 1995]


§ 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.


[Order 182, 46 FR 50514, Oct. 14, 1981, as amended by Order 225, 47 FR 19056, May 3, 1982]


§ 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.


[Order 737, 75 FR 43403, July 26, 2010, as amended by Order 769, 77 FR 65474, Oct. 29, 2012]


§ 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.



Effective Date Note:At 70 FR 35375, June 20, 2005, § 34.8 was revised, effective at the time of the next e-filing release during the Commission’s next fiscal year. For the convenience of the user, the revised text follows:

§ 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.


[Order 575, 60 FR 4853, Jan. 25, 1995. Redesignated by Order 737, 75 FR 43403, July 26, 2010]


Effective Date Note:At 70 FR 35375, June 20, 2005, § 34.9 was revised, effective at the time of the next e-filing release during the Commission’s next fiscal year. For the convenience of the user, the revised text follows:

§ 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


Authority:16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.


Source:Order 271, 28 FR 10573, Oct. 2, 1963, unless otherwise noted.

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.


[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 541, 40 FR 56425, Dec. 3, 1975; Order 541-A, 41 FR 27831, July 7, 1976; 46 FR 50520, Oct. 14, 1981; Order 337, 48 FR 46976, Oct. 17, 1983; Order 541, 57 FR 21734, May 22, 1992; Order 2001, 67 FR 31069, May 8, 2002; Order 714, 73 FR 57530, 57533, Oct. 3, 2008; 74 FR 55770, Oct. 29, 2009]


§ 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.


(16 U.S.C. 284(d), 792 et seq.; Pub. L. 95-617; Pub. L. 95-91; E.O. 12009, 42 FR 46267)

[Order 271, 28 FR 10573, Oct. 2, 1963, as amended at 28 FR 11404, Oct. 24, 1963; 43 FR 36437, Aug. 17, 1978; 44 FR 16372, Mar. 19, 1979; 44 FR 20077, Apr. 4, 1979; Order 39, 44 FR 46454, Aug. 8, 1979; Order 699, 72 FR 45325, Aug. 14, 2007; Order 701, 72 FR 61054, Oct. 29, 2007; Order 714, 73 FR 57530, Oct. 3, 2008; Order 755, 76 FR 67285, Oct. 31, 2011]


§ 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.


(16 U.S.C. 284(d); Pub. L. 95-617; Pub. L. 95-91; E.O. 12009, 42 FR 46267)

[44 FR 16372, Mar. 19, 1979; 44 FR 20077, Apr. 4, 1979, as amended by Order 714, 73 FR 57531, Oct. 3, 2008]


§ 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.


[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57531, 57533, Oct. 3, 2008]


§ 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.


[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 614, 65 FR 18227, Apr. 7, 2000; Order 699, 72 FR 45325, Aug. 14, 2007; Order 701, 72 FR 61054, Oct. 29, 2007]


§ 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.


[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57531, Oct. 3, 2008]


§ 35.7 Electronic filing of tariffs and related materials.

(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 on the Internet at http://www.ferc.gov and can be obtained at the Federal Energy Regulatory Commission, Public Reference Room, 888 First Street, NE., Washington, DC 20426.


(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.


[Order 714, 73 FR 57531, Oct. 3, 2008, as amended by Order 714-A, 79 FR 29076, May 21, 2014]


§ 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.


[Order 612, 64 FR 72537, Dec. 28, 1999; 65 FR 18229, Apr. 7, 2000, as amended by Order 647, 69 FR 32438, June 10, 2004; Order 714, 73 FR 57531, Oct. 3, 2008]


§ 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.


[Order 714, 73 FR 57531, Oct. 3, 2008]


§ 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.


[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 568, 59 FR 40240, Aug. 8, 1994; Order 714, 73 FR 57532, Oct. 3, 2008]


§ 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.


[Order 2001, 67 FR 31069, May 8, 2002, as amended by Order 714, 73 FR 57532, Oct. 3, 2008]


§ 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.


[Order 768, 77 FR 61924, Oct. 11, 2012, as amended by Order 770, 77 FR 71299, Nov. 30, 2012]


§ 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.


[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57532, 57533, Oct. 3, 2008]


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.).


(Federal Power Act, 16 U.S.C. 792-828c; Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267; Pub. L. 96-511, 94 Stat. 2812 (44 U.S.C. 3501 et seq.))

[Order 271, 28 FR 10573, Oct. 2, 1963, as amended at 28 FR 11404, Oct. 24, 1963; Order 537, 40 FR 48674, Oct. 17, 1975; Order 91, 45 FR 46363, July 10, 1980; Order 714, 73 FR 57532, Oct. 3, 2008]


§ 35.13 Filing of changes in rate schedules, tariffs or service agreements.


Contents

(a) General rule.

(1) Filing for any rate schedule change not otherwise excepted.

(2) Abbreviated filing requirements.

(3) Cost of service data required by letter.

(b) General information.

(c) Information relating to the effect of the rate schedule change.

(d) Cost of service information.

(1) Filing of Period I data.

(2) Filing of Period II data.

(3) Definitions.

(4) Test period.

(5) Work papers.

(6) Additional information.

(7) Attestation.

(e) Testimony and exhibits.

(1) Filing requirements.

(2) Case in chief.

(3) Burden of proof.

(f) Filing by parties concurring in coordination and interchange arrangements.

(g) Commission precedents and policy.

(h) Cost of service statements.

(1) AA – Balance sheets.

(2) AB – Income statements.

(3) AC – Retained earnings statements.

(4) AD – Cost of plant.

(5) AE – Accumulated depreciation and amortization.

(6) AF – Specified deferred credits.

(7) AG – Specified plant accounts (other than plant in service) and deferred debits.

(8) AH – Operation and maintenance expenses.

(9) AI – Wages and salaries.

(10) AJ – Depreciation and amortization expenses.

(11) AK – Taxes other than income taxes.

(12) AL – Working capital.

(13) AM – Construction work in progress.

(14) AN – Notes payable.

(15) AO – Rate for allowance for funds used during construction.

(16) AP – Federal income tax deductions – interest.

(17) AQ – Federal income tax deductions – other than interest.

(18) AR – Federal tax adjustments.

(19) AS – Additional state income tax deductions.

(20) AT – State tax adjustments.

(21) AU – Revenue credits.

(22) AV – Rate of return.

(23) AW – Cost of short-term debt.

(24) AX – Other recent and pending rate changes.

(25) AY – Income and revenue tax rate data.

(26) BA – Wholesale customer rate groups.

(27) BB – Allocation demand and capability data.

(28) BC – Reliability data.

(29) BD – Allocation energy and supporting data.

(30) BE – Specific assignment data.

(31) BF – Exclusive-use commitments of major power supply facilities.

(32) BG – Revenue data to reflect changed rates.

(33) BH – Revenue data to reflect present rates.

(34) BI – Fuel cost adjustment factors.

(35) BJ – Summary data tables.

(36) BK – Electric utility department cost of service, total and as allocated.

(37) BL – Rate design information.

(38) Statement BM – Construction program statement.

(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 AHOperation 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 AIWages 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


FR-1.

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 BLRate 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.


(Federal Power Act, 16 U.S.C. 791-828c; Dept. of Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 42 FR 46267, 3 CFR 142 (1978); Pub. L. 96-511, 94 Stat. 2812 (44 U.S.C. 3501 et seq.))

[Order 91, 45 FR 46363, July 10, 1980]


Editorial Note:For Federal Register citations affecting § 35.13, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

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:


Adjustment Factor = Fm/Sm-Fb/Sb


Where: F is the expense of fossil and nuclear fuel and purchased economic power in the base (b) and current (m) periods; and S is the kWh sales in the base and current periods, all as defined below.

(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 Fb or Fm;


(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
1
sources, that fact shall be noted and described as part of any filing. Where the utility purchases fuel from a company-owned or controlled source, the price of which is subject to the jurisdiction of a regulatory body, and where the price of such fuel has been approved by that regulatory body, such costs shall be presumed, subject to rebuttal, to be reasonable and includable in the adjustment clause. If the current price, however, is in litigation and is being collected subject to refund, the utility shall so advise the Commission and shall keep a separate account of such amounts paid which are subject to refund, and shall advise the Commission of the final disposition of such matter by the regulatory body having jurisdiction. With respect to the price of fuel purchases from company-owned or controlled sources pursuant to contracts which are not subject to regulatory authority, the utility company shall file such contracts and amendments thereto with the Commission for its acceptance at the time it files its fuel clause or modification thereof. Any subsequent amendment to such contracts shall likewise be filed with the Commission as a rate schedule change and may be subject to suspension under section 205 of the Federal Power Act. Fuel charges by affiliated companies which do not appear to be reasonable may result in the suspension of the fuel adjustment clause or cause an investigation thereof to be made by the Commission on its own motion under section 206 of the Federal Power Act.




1 As defined in the Commission’s Uniform System of Accounts 18 CFR part 101, Definitions 5B.


(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 Fm.


(iv) The purchasing utility shall make a credit to Fm after a purchase terminates if the total cost of the purchase exceeds the total avoided variable cost. The amount of the credit shall be the difference between the total cost of the purchase and the total avoided variable cost. This credit shall be made in the first adjustment period after the end of the purchase. If a utility fails to make the credit in the first adjustment period after the end of the purchase, it shall, when making the credit, also include in Fm interest on the amount of the credit. Interest shall be calculated at the rate required by § 35.19a(a)(2)(iii) of this chapter, and shall accrue from the date the credit should have been made under this paragraph until the date the credit is made.


(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.


(Approved by the Office of Management and Budget under control number 1902-0096)

(Federal Power Act, 16 U.S.C. 824d, 824e and 825h (1976 & Supp. IV 1980); Department of Energy Organization Act, 42 U.S.C. 7171, 7172 and 7173(c) (Supp. IV 1980); E.O. 12009, 3 CFR part 142 (1978); 5 U.S.C. 553 (1976))

[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 421, 36 FR 3047, Feb. 17, 1971; 39 FR 40583, Nov. 19, 1974; Order 225, 47 FR 19056, May 3, 1982; Order 352, 48 FR 55436, Dec. 13, 1983; 49 FR 5073, Feb. 10, 1984; Order 529, 55 FR 47321, Nov. 13, 1990; Order 600, 63 FR 53809, Oct. 7, 1998; Order 714, 73 FR 57532, Oct. 3, 2008; 73 FR 63886, Oct. 28, 2008]


§ 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.


[Order 888, 61 FR 21692, May 10, 1996, as amended by Order 714, 73 FR 57532, Oct. 3, 2008]


§ 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.


[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57533, Oct. 3, 2008]


§ 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.


[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57533, Oct. 3, 2008; 74 FR 55770, Oct. 29, 2009]


§ 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.


[Order 631, 68 FR 19619, Apr. 21, 2003, as amended by Order 714, 73 FR 57533, Oct. 3, 2008]


§ 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.


[44 FR 53503, Sept. 14, 1979, as amended at 45 FR 3889, Jan. 21, 1980; Order 545, 57 FR 53990, Nov. 16, 1992; 74 FR 54463, Oct. 22, 2009]


§ 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
5
or other writing. Any oral agreement or understanding forming a part of such statement shall be reduced to writing and made a part thereof.




5 See § 35.2.


[Order 271, 28 FR 10573, Oct. 2, 1963, as amended by Order 714, 73 FR 57533, Oct. 3, 2008]


§ 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.


(Federal Power Act, as amended, 16 U.S.C. 792-828c; Department of Energy Organization Act, 42 U.S.C. 7101-7352; E.O. 12009, 3 CFR 142 (1978))

[Order 84, 45 FR 31300, May 13, 1980. Redesignated by Order 545, 57 FR 53990, Nov. 16, 1992, as amended by Order 714, 73 FR 57533, Oct. 3, 2008]


§ 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.


[59 FR 65938, Dec. 22, 1994, as amended by Order 714, 73 FR 57533, Oct. 3, 2008]


§ 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.



(See Order 13, issued October 18, 1978; Order 203, issued May 29, 1958; Order 204, issued May 29, 1958; Order 404, issued May 15, 1970; Order 408, issued August 26, 1970; Order 432, issued April 23, 1971; Order 504, issued February 11, 1974; Order 505, issued February 11, 1974; Order 566, issued June 3, 1977; Opinion 578, issued June 3, 1970; and Opinion 801, issued May 31, 1977.)

(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.


[46 FR 26636, May 14, 1981. Redesignated and amended by Order 144-A, 47 FR 8342, Feb. 26, 1982; Redesignated by Order 545, 57 FR 53990, Nov. 16, 1992]


§ 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.


[Order 474, 52 FR 23965, June 26, 1987, as amended by Order 474-A, 52 FR 35702, Sept. 23, 1987; Order 474-B, 54 FR 32804, Aug. 10, 1989. Redesignated by Order 545, 57 FR 53990, Nov. 16, 1992, as amended by Order 626, 67 FR 36096, May 23, 2002]


§ 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.


[Order 888-A, 62 FR 12460, Mar. 14, 1997]


§ 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.


[Order 697, 72 FR 40038, July 20, 2007]


§ 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)-(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]


[Order 888, 61 FR 21693, May 10, 1996]


Editorial Note:For Federal Register citations affecting § 35.28, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.

§ 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.


[Order 557, 58 FR 51221, Oct. 1, 1993. Redesignated by Order 888, 61 FR 21692, May 10, 1996]


Subpart D – Procedures and Requirements for Public Utility Sales of Power to Bonneville Power Administration Under Northwest Power Act


Authority:Federal Power Act, 16 U.S.C. 792-828c (1976 and Supp. IV 1980) and Pacific Northwest Electric Power Planning and Conservation Act, 16 U.S.C. 830-839h (Supp. IV (1980)).

§ 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.


[Order 337, 48 FR 46976, Oct. 17, 1983, as amended by Order 400, 49 FR 39300, Oct. 5, 1984]


§ 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.


(Approved by the Office of Management and Budget under control number 1902-0096)

[Order 337, 48 FR 46976, Oct. 17, 1983, as amended at 49 FR 1177, Jan. 10, 1984]


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.


[Order 580-A, 62 FR 33348, June 19, 1997, as amended at 69 FR 18803, Apr. 9, 2004]


§ 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.


[Order 580-A, 62 FR 33348, June 19, 1997, as amended at 69 FR 18803, Apr. 9, 2004; Order 658, 70 FR 34343, June 14, 2005; Order 737, 75 FR 43404, July 26, 2010]


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.



Note to paragraph (f):

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.



Note to paragraph (j)(1)(iii):

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.


[Order 2000-A, 65 FR 12110, Mar. 8, 2000, as amended by Order 679, 71 FR 43338, July 31, 2006]


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).


[Order 679, 71 FR 43338, July 31, 2006, as amended by Order 679-A, 72 FR 1172, Jan. 10, 2007, Order 691, 72 FR 5174, Feb. 5, 2007]


Subpart H – Wholesale Sales of Electric Energy, Capacity and Ancillary Services at Market-Based Rates


Source:Order 697, 72 FR 40038, July 20, 2007, unless otherwise noted.

§ 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.


[Order 697, 72 FR 40038, July 20, 2007, as amended by Order 697-A, 73 FR 25912, May 7, 2008; Order 697-B, 73 FR 79627, Dec. 30, 2008; Order 816, 80 FR 67108, Oct. 30, 2015; Order 816-A, 81 FR 33383, May 26, 2016; Order 860, 84 FR 36428, July 26, 2019]


§ 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.


[Order 697, 72 FR 40038, July 20, 2007, as amended by Order 697-B, 73 FR 79627, Dec. 30, 2008; Order 769, 77 FR 65475, Oct. 29, 2012; Order 784, 78 FR 46209, July 30, 2013; Order 816, 80 FR 67108, Oct. 30, 2015; Order 819, 80 FR 73977, Nov. 27, 2015; Order 861, 84 FR 36386, July 26, 2019; Order 860, 84 FR 36428, July 26, 2019]


§ 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.


[Order 697, 72 FR 40038, July 20, 2007, as amended by Order 784, 78 FR 46210, July 30, 2013]


§ 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.


[Order 697, 72 FR 40038, July 20, 2007, as amended by Order 697-A, 73 FR 25912, May 7, 2008]


§ 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.


[Order 697, 72 FR 40038, July 20, 2007, as amended by Order 768, 77 FR 61924, Oct. 11, 2012]


§ 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.


[Order 697-D, 75 FR 14351, Mar. 25, 2010, as amended by Order 816, 80 FR 67108, Oct. 30, 2015; Order 816-A, 81 FR 33383, May 26, 2016; Order 860, 84 FR 36428, July 26, 2019]


Subpart I – Cross-Subsidization Restrictions on Affiliate Transactions


Source:73 FR 11025, Feb. 29, 2008, unless otherwise noted.

§ 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).


[73 FR 11025, Feb. 29, 2008, as amended by Order 707-A, 73 FR 43083, July 24, 2008]


Subpart J – Credit Practices In Organized Wholesale Electric Markets


Source:Order 741, 75 FR 65962, Oct. 27, 2010, unless otherwise noted.

§ 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.


[Order 741, 75 FR 65962, Oct. 27, 2010, as amended by Order 741-A, 76 FR 10498, Feb. 25, 2011]


PART 36 – RULES CONCERNING APPLICATIONS FOR TRANSMISSION SERVICES UNDER SECTION 211 OF THE FEDERAL POWER ACT


Authority:5 U.S.C. 551-557; 16 U.S.C. 791a-825r; 31 U.S.C. 9701; 42 U.S.C. 7107-7352.

§ 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 Federal Register in accordance with the specifications in § 385.203(d) of this chapter. The form of notice shall be on electronic media as specified by the Secretary.


(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.


[Order 560, 58 FR 57737, Oct. 27, 1993, as amended by Order 593, 62 FR 1283, Jan. 9, 1997; Order 647, 69 FR 32438, June 10, 2004]


PART 37 – OPEN ACCESS SAME-TIME INFORMATION SYSTEMS


Authority:16 U.S.C. 791-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.


Source:Order 889, 61 FR 21764, May 10, 1996, unless otherwise noted.

§ 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.


[Order 889, 61 FR 21764, May 10, 1996, as amended by Order 889-A, 62 FR 12503, Mar. 14, 1997]


§ 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.


[Order 889, 61 FR 21764, May 10, 1996, as amended by Order 605, 64 FR 34124, June 25, 1999; Order 638, 65 FR 17400, Mar. 31, 2000; Order 676, 71 FR 26212, May 4, 2006]


§ 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.


[Order 889, 61 FR 21764, May 10, 1996, as amended by Order 889-A, 62 FR 12503, Mar. 14, 1997; Order 605, 64 FR 34124, June 25, 1999; Order 2004, 68 FR 69157, Dec. 11, 2003; Order 890, 72 FR 12493, Mar. 15, 2007; Order 890-A, 73 FR 3111, Jan. 16, 2008; Order 784, 78 FR 46210, July 30, 2013; Order 676-J, 86 FR 29502, June 2, 2021]


§ 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.


[Order 889, 61 FR 21764, May 10, 1996, as amended by Order 889-A, 62 FR 12504, Mar. 14, 1997; Order 890, 72 FR 12496, Mar. 15, 2007]


§ 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.


[Order 605, 64 FR 34124, June 25, 1999]


PART 38 – STANDARDS FOR PUBLIC UTILITY BUSINESS OPERATIONS AND COMMUNICATIONS


Authority:16 U.S.C. 791-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352.


Source:Order 676, 71 FR 26212, May 4, 2006, unless otherwise noted.

§ 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 promulgated by the North American Energy Standards Board (NAESB) Wholesale Electric Quadrant (WEQ) that are incorporated by reference in paragraph (b) of this section.


(b)(1) The material incorporated by reference in this section was approved by the Director of the Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. All approved material may be inspected at the Federal Energy Regulatory Commission, Public Reference and Files Maintenance Branch, 888 First Street NE, Washington, DC 20426, Tel: (202) 502-8371, www.ferc.gov, and is available from the sources listed in paragraph (b)(2) of this section. It is also available for inspection at the National Archives and Records Administration (NARA). For information on the availability of this material at NARA, email [email protected], or go to: https://www.archives.gov/federal-register/cfr/ibr-locations.html .


(2) North American Energy Standards Board (NAESB), 801 Travis Street, Suite 1675, Houston, TX 77002, Tel: (713) 356-0060. NAESB’s website is at https://www.naesb.org/. The NAESB WEQ Business Practice Standards; Standards and Models the Commission incorporates by reference are as follows:


(i) 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);


(ii) WEQ-000, Abbreviations, Acronyms, and Definition of Terms (WEQ Version 003.3, March 30, 2020);


(iii) WEQ-001, Open Access Same-Time Information Systems (OASIS), (WEQ Version 003.3, March 30, 2020);


(iv) WEQ-002, Open Access Same-Time Information Systems (OASIS) Business Practice Standards and Communication Protocols (S&CP), (WEQ Version 003.3, March 30, 2020);


(v) WEQ-003, Open Access Same-Time Information Systems (OASIS) Data Dictionary, (WEQ Version 003.3, March 30, 2020);


(vi) WEQ-004, Coordinate Interchange (WEQ Version 003.3, March 30, 2020);


(vii) WEQ-005, Area Control Error (ACE) Equation Special Cases (WEQ Version 003.3, March 30, 2020);


(viii) WEQ-006, Manual Time Error Correction (WEQ Version 003.1, Sept. 30, 2015);


(ix) WEQ-007, Inadvertent Interchange Payback (WEQ Version 003.3, March 30, 2020);


(x) WEQ-008, Transmission Loading Relief (TLR) – Eastern Interconnection (WEQ Version 003.3, March 30, 2020);


(xi) WEQ-011, Gas/Electric Coordination (WEQ Version 003.3, March 30, 2020);


(xii) WEQ-012, Public Key Infrastructure (PKI) (WEQ Version 003.3, March 30, 2020);


(xiii) WEQ-013, Open Access Same-Time Information Systems (OASIS) Implementation Guide, (WEQ Version 003.3, March 30, 2020);


(xiv) WEQ-015, Measurement and Verification of Wholesale Electricity Demand Response (WEQ Version 003.3, March 30, 2020);


(xv) WEQ-021, Measurement and Verification of Energy Efficiency Products (WEQ Version 003.3, March 30, 2020);


(xvi) WEQ-022, Electric Industry Registry (WEQ Version 003.3, March 30, 2020); and


(xvii) WEQ-023, Modeling. (WEQ Version 003.3, March 30, 2020).


[Order 676-J, 86 FR 29502, June 2, 2021]


§ 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.


[78 FR 70187, Nov. 22, 2013]


PART 39 – RULES CONCERNING CERTIFICATION OF THE ELECTRIC RELIABILITY ORGANIZATION; AND PROCEDURES FOR THE ESTABLISHMENT, APPROVAL, AND ENFORCEMENT OF ELECTRIC RELIABILITY STANDARDS


Authority:16 U.S.C. 824o.


Source:Order 672, 71 FR 8736, Feb. 17, 2006, unless otherwise noted.

§ 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.


[Order 672, 71 FR 8736, Feb. 17, 2006, as amended at 71 FR 11505, Mar. 8, 2006; Order 672-A, 71 FR 19823, Apr. 18, 2006]


§ 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.


[Order 672, 71 FR 8736, Feb. 17, 2006, as amended by Order 737, 75 FR 43404, July 26, 2010]


§ 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.


[Order 672, 71 FR 8736, Feb. 17, 2006, as amended by Order 824, 81 FR 45008, July 12, 2016]


§ 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


Authority:16 U.S.C. 824o.


Source:Order 693, 72 FR 16598, Apr. 4, 2007, unless otherwise noted.

§ 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


Authority:16 U.S.C. 791a-825r, 2601-2645; 42 U.S.C. 7101-7352.


Source:Order 141, 12 FR 8500, Dec. 19, 1947, unless otherwise noted.


Cross Reference:

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.


[Order 675-A, 71 FR 29784, May 24, 2006]


§ 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.


[Order 675, 71 FR 9706, Feb. 27, 2006]


§ 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.


[Order 675, 71 FR 9706, Feb. 27, 2006]


§ 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.


[Order 141, 12 FR 8500, Dec. 19, 1947, as amended by Order 225, 47 FR 19056, May 3, 1982]


§ 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.


[Order 575, 60 FR 4854, Jan. 25, 1995]


§ 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.


[Order 462, 37 FR 26005, Dec. 7, 1972, as amended by Order 390, 49 FR 32505, Aug. 14, 1984]


§ 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.


[73 FR 58736, Oct. 7, 2008]


§ 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.


[Order 462, 37 FR 26006, Dec. 7, 1972]


PART 42 – LONG-TERM FIRM TRANSMISSION RIGHTS IN ORGANIZED ELECTRICITY MARKETS


Authority:16 U.S.C. 791a-825r and section 217 of the Federal Power Act, 16 U.S.C. 824q.


Source:Order 681, 71 FR 43619, Aug. 1, 2006, unless otherwise noted.

§ 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


Authority:16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352; 3 CFR 142.


Source:Order 141, 12 FR 8501, Dec. 19, 1947, unless otherwise noted.


Cross References:

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.


[Order 446, 51 FR 4904, Feb. 10, 1986, as amended by Order 856, 84 FR 7282, Mar. 4, 2019]


§ 45.2 Positions requiring authorization.

(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
1
within the purview of section 305(b) of the Act. With respect to positions not herein specifically mentioned which applicant holds and which are invested with executive authority, applicant shall state in the application the source of such executive authority, whether by bylaws, action of the board of directors, or otherwise.




1 Corporation means 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. It shall not include municipalities as defined in the Federal Power Act (sec. 3, 49 Stat. 838; 16 U.S.C. 796).


(b) Corporations
1 within the purview of section 305(b) of the Act include:


(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.


[Order 141, 12 FR 8501, Dec. 19, 1947, as amended by Order 856, 84 FR 7282, Mar. 4, 2019]


§ 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.


[Order 664, 70 FR 55723, Sept. 23, 2005, as amended by Order 856, 84 FR 7282, Mar. 4, 2019]


§ 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).


[Order 141, 12 FR 8501, Dec. 19, 1947, as amended by Order 856, 84 FR 7282, Mar. 4, 2019]


§ 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.


[Order 141, 12 FR 8501, Dec. 19, 1947, as amended by Order 856, 84 FR 7282, Mar. 4, 2019]


§ 45.6 Termination of authorization.

(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).


[Order 737, 75 FR 43404, July 26, 2010]


§ 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.


[Order 246, 27 FR 4912, May 25, 1962, as amended by Order 427, 36 FR 5598, Mar. 25, 1971; Order 374, 49 FR 20479, 20480, May 15, 1984; Order 435, 50 FR 40358, Oct. 3, 1985; Order 737, 75 FR 43404, July 26, 2010; Order 856, 84 FR 7282, Mar. 4, 2019]


Cross Reference:

For rules and regulations of the Securities and Exchange Commission, see 17 CFR, chap. II.


§ 45.9 Automatic authorization of certain interlocking positions.

(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.


[Order 446, 51 FR 4905, Feb. 10, 1986, as amended by Order 664, 70 FR 55723, Sept. 23, 2005; Order 856, 84 FR 7282, Mar. 4, 2019]


PART 46 – PUBLIC UTILITY FILING REQUIREMENTS AND FILING REQUIREMENTS FOR PERSONS HOLDING INTERLOCKING POSITIONS


Authority:16 U.S.C. 792-828c; 16 U.S.C. 2601-2645; 42 U.S.C. 7101-7352; E.O. 12009, 3 CFR 142.


Source:45 FR 23418, Apr. 7, 1980, unless otherwise noted.

§ 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.


[Order 67, 45 FR 3569, Jan. 18, 1980]


§ 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.
1




1 Guidance in applying the definition of electrical equipment may be obtained by examining the items within the following accounts described in part 101, title 18 of the Code of Federal Regulations: Boiler/Reactor plant equipment (Accounts 312 and 322); Engines and engine driven generators (313); Turbogenerator units (314 and 323); Accessory electrical equipment (315, 324, 334 and 345); Miscellaneous power plant equipment (316, 325, 335 and 346); Water wheels, turbines and generators (333); Fuel holders, producers, and accessories (342); Prime movers (343); Generators (344); Station equipment (353 and 362); Poles, towers and fixtures (354, 355 and 364); Overhead conductors and devices (356 and 365); Underground conduit (357 and 366); Underground conductors and devices (358 and 367); Storage battery equipment (363); Line transformers (368); Services (369); Meters (370); Installation on customers’ premises (371); Street lighting and signal systems (373); Leased property on customers’ premises (372); and Communication equipment (397). Excepted from these accounts, are vehicles, structures, foundations, settings, and services.


(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.


[45 FR 23418, Apr. 7, 1980, as amended by Order 856, 84 FR 7283, Mar. 4, 2019]


§ 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.


[Order 67, 45 FR 3569, Jan. 18, 1980; 45 FR 6377, Jan. 28, 1980, as amended by Order 737, 75 FR 43404, July 26, 2010; 80 FR 43624, July 23, 2015]


§ 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.


[45 FR 23418, Apr. 7, 1980, as amended by Order 140, 46 FR 22181, Apr. 16, 1981; Order 737, 75 FR 43404, July 26, 2010]


§ 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.


(Pub. L. 96-511, 94 Stat. 2812 (44 U.S.C. 3501 et seq.))

[45 FR 23418, Apr. 7, 1980, as amended by Order 601, 63 FR 72169, Dec. 31, 1998; Order 737, 75 FR 43404, July 26, 2010]


PART 50 – APPLICATIONS FOR PERMITS TO SITE INTERSTATE ELECTRIC TRANSMISSION FACILITIES


Authority:16 U.S.C. 824p, DOE Delegation Order No. 00-004.00A.


Source:71 FR 69465, Dec. 1, 2006, unless otherwise noted.

§ 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 Federal Register, as provided by § 50.9(a), which will briefly summarize the facts contained in the application in such a way as to acquaint the public with its scope and purpose. The form of notice also must include the name, address, and telephone number of an authorized contact person.


§ 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 Federal Register.


(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


Authority:16 U.S.C. 791a-825r, 2601-2645; 31 U.S.C. 9701; 42 U.S.C. 7101-7352, 7651-7651o.


Source:Order 218, 25 FR 5014, June 7, 1960, unless otherwise noted.


Editorial Note:For Federal Register citations affecting part 101, see the List of CFR Sections Affected, which appears in the Finding Aids section of the printed volume and at www.govinfo.gov.


Note:

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.



Cross References:

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.


Uniform System of Accounts Prescribed for Public Utilities and Licensees Subject to the Provisions of the Federal Power Act


Definitions

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.

General Instructions


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:



100-199 Assets and other debits.

200-299 Liabilities and other credits.

300-399 Plant accounts.

400-432, 434-435 Income accounts.

433, 436-439 Retained earnings accounts.

440-459 Revenue accounts.

500-599 Production, transmission and distribution expenses.

900-949 Customer accounts, customer service and informational, sales, and general and administrative expenses.

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.



Note:

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.

Electric Plant Instructions


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.



Note:

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:


Ai = s(S/W) + d(D/D + P + C)(1−S/W)

Ae = [1−S/W][p(P/D+P+C)+c(C/D+P+C)]


Ai = Gross allowance for borrowed funds used during construction rate.

Ae = Allowance for other funds used during construction rate.

S = Average short-term debt.

s = Short-term debt interest rate.

D = Long-term debt.

d = Long-term debt interest rate.

P = Preferred stock.

p = Preferred stock cost rate.

C = Common equity.

c = Common equity cost rate.

W = Average balance in construction work in progress plus nuclear fuel in process of refinement, conversion, enrichment and fabrication, less asset retirement costs (See General Instruction 25) related to plant under construction.

(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.



Note:

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.)



Note:

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)



Note:

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.



Note:

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.

Operating Expense Instructions


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.



Items

Labor

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.


Expenses

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.



Items

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.



Balance Sheet Chart of Accounts

ASSETS AND OTHER DEBITS

1. Utility Plant

101 Electric plant in service (Major only).

101.1 Property under capital leases.

102 Electric plant purchased or sold.

103 Experimental electric plant unclassified (Major only).

103.1 Electric plant in process of reclassification (Nonmajor only).

104 Electric plant leased to others.

105 Electric plant held for future use.

106 Completed construction not classified – Electric (Major only).

107 Construction work in progress – Electric.

108 Accumulated provision for depreciation of electric utility plant (Major only).

109 [Reserved]

110 Accumulated provision for depreciation and amortization of electric utility plant (Nonmajor only).

111 Accumulated provision for amortization of electric utility plant (Major only).

112-113 [Reserved]

114 Electric plant acquisition adjustments.

115 Accumulated provision for amortization of electric plant acquisition adjustments (Major only).

116 Other electric plant adjustments.

118 Other utility plant.

119 Accumulated provision for depreciation and amortization of other utility plant.

120.1 Nuclear fuel in process of refinement, conversion, enrichment and fabrication (Major only).

120.2 Nuclear fuel materials and assemblies – Stock account (Major only).

120.3 Nuclear fuel assemblies in reactor (Major only).

120.4 Spent nuclear fuel (Major only).

120.5 Accumulated provision for amortization of nuclear fuel assemblies (Major only).

120.6 Nuclear fuel under capital leases (Major only).

2. Other Property and Investments

121 Nonutility property.

122 Accumulated provision for depreciation and amortization of nonutility property.

123 Investment in associated companies (Major only).

123.1 Investment in subsidiary companies (Major only).

124 Other investments.

125 Sinking funds (Major only).

126 Depreciation fund (Major only).

127 Amortization fund – Federal (Major only).

128 Other special funds (Major only).

129 Special funds (Nonmajor only).

3. Current and Accrued Assets

130 Cash and working funds (Nonmajor only).

131 Cash (Major only).

132 Interest special deposits (Major only).

133 Dividend special deposits (Major only).

134 Other special deposits (Major only).

135 Working funds (Major only).

136 Temporary cash investments.

141 Notes receivable.

142 Customer accounts receivable.

143 Other accounts receivable.

144 Accumulated provision for uncollectible accounts – credit.

145 Notes receivable from associated companies.

146 Accounts receivable from associated companies.

151 Fuel stock (Major only).

152 Fuel stock expenses undistributed (Major only).

153 Residuals (Major only).

154 Plant materials and operating supplies.

155 Merchandise (Major only).

156 Other materials and supplies (Major only).

157 Nuclear materials held for sale (Major only).

158.1 Allowance inventory.

158.2 Allowances withheld.

163 Stores expense undistributed (Major only).

165 Prepayments.

171 Interest and dividends receivable (Major only).

172 Rents receivable (Major only).

173 Accrued utility revenues (Major only).

174 Miscellaneous current and accrued assets.

175 Derivative instrument assets.

176 Derivative instrument assets-Hedges.

4. Deferred Debits

181 Unamortized debt expense.

182.1 Extraordinary property losses.

182.2 Unrecovered plant and regulatory study costs.

182.3 Other regulatory assets.

183 Preliminary survey and investigation charges (Major only).

184 Clearing accounts (Major only).

185 Temporary facilities (Major only).

186 Miscellaneous deferred debits.

187 Deferred losses from disposition of utility plant.

188 Research, development, and demonstration expenditures (Major only).

189 Unamortized loss on reacquired debt.

190 Accumulated deferred income taxes.

LIABILITIES AND OTHER CREDITS

5. Proprietary Capital

201 Common stock issued.

202 Common stock subscribed (Major only).

203 Common stock liability for conversion (Major only).

204 Preferred stock issued.

205 Preferred stock subscribed (Major only).

206 Preferred stock liability for conversion (Major only).

207 Premium on capital stock (Major only).

208 Donations received from stockholders (Major only).

209 Reduction in par or stated value of capital stock (Major only).

210 Gain on resale or cancellation of reacquired capital stock (Major only).

211 Miscellaneous paid-in capital.

212 Installments received on capital stock.

213 Discount on capital stock.

214 Capital stock expense.

215 Appropriated retained earnings.

215.1 Appropriated retained earnings – Amortization reserve, Federal.

216 Unappropriated retained earnings.

216.1 Unappropriated undistributed subsidiary earnings (Major only).

217 Reacquired capital stock.

218 Noncorporate proprietorship (Nonmajor only).

219 Accumulated other comprehensive income.

6. Long-Term Debt

221 Bonds.

222 Reacquired bonds (Major only).

223 Advances from associated companies.

224 Other long-term debt.

225 Unamortized premium on long-term debt.

226 Unamortized discount on long-term debt – Debit.

7. Other Noncurrent Liabilities

227 Obligations under capital lease – noncurrent.

228.1 Accumulated provision for property insurance.

228.2 Accumulated provision for injuries and damages.

228.3 Accumulated provision for pensions and benefits.

228.4 Accumulated miscellaneous operating provisions.

229 Accumulated provision for rate refunds.

230 Asset retirement obligations.

8. Current and Accrued Liabilities

231 Notes payable.

232 Accounts payable.

233 Notes payable to associated companies.

234 Accounts payable to associated companies.

235 Customer deposits.

236 Taxes accrued.

237 Interest accrued.

238 Dividends declared (Major only).

239 Matured long-term debt (Major only).

240 Matured interest (Major only).

241 Tax collections payable (Major only).

242 Miscellaneous current and accrued liabilities.

243 Obligations under capital leases – current.

244 Derivatives instrument liabilities.

245 Derivative instrument liabilities-Hedges.

9. Deferred Credits

251 [Reserved]

252 Customer advances for construction.

253 Other deferred credits.

254 Other regulatory liabilities.

255 Accumulated deferred investment tax credits.

256 Deferred gains from disposition of utility plant.

257 Unamortized gain on reacquired debt.

281 Accumulated deferred income taxes – Accelerated amortization property.

282 Accumulated deferred income taxes – Other property.

283 Accumulated deferred income taxes – Other.

Balance Sheet Accounts

101 Electric plant in service (Major only).


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.)

101.1 Property under capital leases.


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.

102 Electric plant purchased or sold.


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.

103 Experimental electric plant unclassified (Major only).


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.

103.1 Electric plant in process of reclassification (Nonmajor only).


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.

104 Electric plant leased to others.


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.

105 Electric plant held for future use.


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.



Note:

Materials and supplies, meters and transformers held in reserve, and normal spare capacity of plant in service shall not be included in this account.


106 Completed construction not classified – Electric (Major only).

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.



Note:

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.


107 Construction work in progress – Electric.

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.

108 Accumulated provision for depreciation of electric utility plant (Major only).


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.

109 [Reserved]

110 Accumulated provision for depreciation and amortization of electric utility plant (Nonmajor only).


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.

111 Accumulated provision for amortization of electric utility plant (Major only).


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.

112-113 [Reserved]

114 Electric plant acquisition adjustments.


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.

115 Accumulated provision for amortization of electric plant acquisition adjustments (Major only).


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.

116 Other electric plant adjustments.


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.



Note:

The provisions of this account shall not be construed as approving or authorizing the recording of appreciation of electric plant.


118 Other utility plant.

This account shall include the balances in accounts for utility plant, other than electric plant, such as gas, railway, etc.

119 Accumulated provision for depreciation and amortization of other utility plant.


This account shall include the accumulated provision for depreciation and amortization applicable to utility property other than electric plant.

120.1 Nuclear fuel in process of refinement, conversion, enrichment and fabrication (Major only).


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.

items



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.


120.2 Nuclear fuel materials and assemblies – Stock account (Major only).

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.

120.3 Nuclear fuel assemblies in reactor (Major only).


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.

120.4 Spent nuclear fuel (Major only).


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.

120.5 Accumulated provision for amortization of nuclear fuel assemblies (Major only).


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.

120.6 Nuclear fuel under capital leases (Major only).


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.

121 Nonutility property.


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 operati