Last updated on March 15th, 2023 at 04:09 pm
Title 40 – Protection of Environment–Volume 23
CHAPTER I – ENVIRONMENTAL PROTECTION AGENCY (CONTINUED)
SUBCHAPTER C – AIR PROGRAMS (CONTINUED)
PART 97 – FEDERAL NOX BUDGET TRADING PROGRAM, CAIR NOX AND SO2 TRADING PROGRAMS, CSAPR NOX AND SO2 TRADING PROGRAMS, AND TEXAS SO2 TRADING PROGRAM
Subpart A – NOX Budget Trading Program General Provisions
§ 97.1 Purpose.
This part establishes general provisions and the applicability, permitting, allowance, excess emissions, monitoring, and opt-in provisions for the federal NO
§ 97.2 Definitions.
The terms used in this part shall have the meanings set forth in this section as follows:
Account number means the identification number given by the Administrator to each NO
Acid Rain emissions limitation means, as defined in § 72.2 of this chapter, a limitation on emissions of sulfur dioxide or nitrogen oxides under the Acid Rain Program under title IV of the Clean Air Act.
Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator’s duly authorized representative.
Allocate or allocation means, with regard to NO
Automated data acquisition and handling system or DAHS means that component of the CEMS, or other emissions monitoring system approved for use under subpart H of this part, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by subpart H of this part.
Boiler means an enclosed fossil or other fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401 et seq.
Combined cycle system means a system comprised of one or more combustion turbines, heat recovery steam generators, and steam turbines configured to improve overall efficiency of electricity generation or steam production.
Combustion turbine means an enclosed fossil or other fuel-fired device that is comprised of a compressor, a combustor, and a turbine, and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine.
Commence commercial operation means, with regard to a unit that serves a generator, to have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation. Except as provided in § 97.4(b), § 97.5, or subpart I of this part, for a unit that is a NO
Commence operation means to have begun any mechanical, chemical, or electronic process, including, with regard to a unit, start-up of a unit’s combustion chamber. Except as provided in § 97.4(b), § 97.5, or subpart I of this part for a unit that is a NO
Common stack means a single flue through which emissions from two or more units are exhausted.
Compliance account means a NO
Continuous emission monitoring system or CEMS means the equipment required under subpart H of this part to sample, analyze, measure, and provide, by means of readings taken at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of nitrogen oxides (NO
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated DAHS. A flow monitoring system provides a permanent, continuous record of stack gas volumetric flow rate, in units of standard cubic feet per hour (scfh);
(2) A nitrogen oxides concentration monitoring system, consisting of a NO
(3) A nitrogen oxides emission rate (or NO
(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter. A moisture monitoring system provides a permanent, continuous record of the stack gas moisture content, in units of percent H
Control period means the period beginning May 1 of a year and ending on September 30 of the same year, inclusive.
Electricity for sale under firm contract to the grid means electricity for sale where the capacity involved is intended to be available at all times during the period covered by a guaranteed commitment to deliver, even under adverse conditions.
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the NO
Energy Information Administration means the Energy Information Administration of the United States Department of Energy.
Excess emissions means any tonnage of nitrogen oxides emitted by a NO
Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.
Fossil fuel fired means, with regard to a unit:
(1) For units that commenced operation before January 1, 1996, the combustion of fossil fuel, alone or in combination with any other fuel, where fossil fuel actually combusted comprises more than 50 percent of the annual heat input on a Btu basis during 1995, or, if a unit had no heat input in 1995, during the last year of operation of the unit prior to 1995;
(2) For units that commenced operation on or after January 1, 1996 and before January 1, 1997, the combustion of fossil fuel, alone or in combination with any other fuel, where fossil fuel actually combusted comprises more than 50 percent of the annual heat input on a Btu basis during 1996; or
(3) For units that commence operation on or after January 1, 1997:
(i) The combination of fossil fuel, alone or in combustion with any other fuel, where fossil fuel actually combusted comprises more than 50 percent of the annual heat input on a Btu basis during any year; or
(ii) The combination of fossil fuel, alone or in combination with any other fuel, where fossil fuel is projected to comprise more than 50 percent of the annual heat input on a Btu basis during any year, provided that the unit shall be “fossil fuel-fired” as of the date, during such year, on which the unit begins combusting fossil fuel.
General account means a NO
Generator means a device that produces electricity.
Heat input means, with regard to a specified period to time, the product (in mmBtu/time) of the gross calorific value of the fuel (in Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the NO
Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy from any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period equal to or greater than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Maximum design heat input means the ability of a unit to combust a stated maximum amount of fuel per hour (in mmBtu/hr) on a steady state basis, as determined by the physical design and physical characteristics of the unit.
Maximum potential hourly heat input means an hourly heat input (in mmBtu/hr) used for reporting purposes when a unit lacks certified monitors to report heat input. If the unit intends to use appendix D of part 75 of this chapter to report heat input, this value should be calculated, in accordance with part 75 of this chapter, using the maximum fuel flow rate and the maximum gross calorific value. If the unit intends to use a flow monitor and a diluent gas monitor, this value should be reported, in accordance with part 75 of this chapter, using the maximum potential flowrate and either the maximum carbon dioxide concentration (in percent CO
Maximum potential NO
Maximum rated hourly heat input means a unit specific maximum hourly heat input (in mmBtu/hr) which is the higher of the manufacturer’s maximum rated hourly heat input or the highest observed hourly heat input.
Monitoring system means any monitoring system that meets the requirements of subpart H of this part, including a continuous emissions monitoring system, an excepted monitoring system, or an alternative monitoring system.
Most stringent State or Federal NO
Nameplate capacity means the maximum electrical generating output (in MWe) that a generator can sustain over a specified period of time when not restricted by seasonal or other deratings as measured in accordance with the United States Department of Energy standards.
Non-title V permit means a federally enforceable permit administered by the permitting authority pursuant to the Clean Air Act and regulatory authority under the Clean Air Act, other than title V of the Clean Air Act and part 70 or 71 of this chapter.
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
NO
Operating means, with regard to a unit under §§ 97.22(d)(2) and 97.80, having documented heat input for more than 876 hours in the 6 months immediately preceding the submission of an application for an initial NO
Operator means any person who operates, controls, or supervises a NO
Opt-in means to be elected to become a NO
Overdraft account means the NO
Owner means any of the following persons:
(1) Any holder of any portion of the legal or equitable title in a NO
(2) Any holder of a leasehold interest in a NO
(3) Any purchaser of power from a NO
(4) With respect to any general account, any person who has an ownership interest with respect to the NO
Percent monitor data availability means, for purposes of § 97.43 (a)(1) and § 97.84(b), total unit operating hours for which quality-assured data were recorded under subpart H of this part in a control period, divided by the total number of unit operating hours in the control period, and multiplied by 100 percent.
Permitting authority means the State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to issue or revise permits to meet the requirements of the NO
Potential electrical output capacity means 33 percent of a unit’s maximum design heat input.
Receive or receipt of means, when referring to the permitting authority or the Administrator, to come into possession of a document, information, or correspondence (whether sent in writing or by authorized electronic transmission), as indicated in an official correspondence log, or by a notation made on the document, information, or correspondence, by the permitting authority or the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to NO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in appendix A of part 60 of this chapter.
Serial number means, when referring to NO
Source means any governmental, institutional, commercial, or industrial structure, installation, plant, building, or facility that emits or has the potential to emit any regulated air pollutant under the Clean Air Act. For purposes of section 502(c) of the Clean Air Act, a “source,” including a “source” with multiple units, shall be considered a single “facility.”
State means one of the 48 contiguous States or a portion thereof or the District of Columbia that is specified in § 52.34 of this chapter and in which are located units for which the Administrator makes an effective finding under § 52.34 of this chapter.
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery. Compliance with any “submission,” “service,” or “mailing” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Title V operating permit means a permit issued under title V of the Clean Air Act and part 70 or part 71 of this chapter.
Title V operating permit regulations means the regulations that the Administrator has approved or issued as meeting the requirements of title V of the Clean Air Act and part 70 or 71 of this chapter.
Ton or tonnage means any “short ton” (i.e., 2,000 pounds). For the purpose of determining compliance with the NO
Unit means a fossil fuel-fired stationary boiler, combustion turbine, or combined cycle system.
Unit operating day means a calendar day in which a unit combusts any fuel.
Unit operating hour or hour of unit operation means any hour (or fraction of an hour) during which a unit combusts any fuel.
§ 97.3 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this part are defined as follows:
§ 97.4 Applicability.
(a) The following units in a State shall be a NO
(1)(i) For units other than cogeneration units –
(A) For units commencing operation before January 1, 1997, a unit serving during 1995 or 1996 a generator –
(1) With a nameplate capacity greater than 25 MWe and
(2) Producing electricity for sale under a firm contract to the electric grid.
(B) For units commencing operation in 1997 or 1998, a unit serving during 1997 or 1998 a generator –
(1) With a nameplate capacity greater than 25 MWe and
(2) Producing electricity for sale under a firm contract to the electric grid.
(C) For units commencing operation on or after January 1, 1999, a unit serving at any time a generator –
(1) With a nameplate capacity greater than 25 MWe and
(2) Producing electricity for sale.
(ii) For cogeneration units –
(A) For units commencing operation before January 1, 1997, a unit serving during 1995 or 1996 a generator with a nameplate capacity greater than 25 MWe and failing to qualify as an unaffected unit under § 72.6(b)(4) of this chapter for 1995 or 1996 under the Acid Rain Program.
(B) For units commencing operation in 1997 or 1998, a unit serving during 1997 or 1998 a generator with a nameplate capacity grater than 25 MWe and failing to qualify as an unaffected unit under § 72.6(b)(4) of this chapter for 1997 or 1998 under the Acid Rain Program.
(C) For units commencing operation on or after January 1, 1999, a unit serving at any time a generator with a nameplate capacity greater than 25 MWe and failing to qualify as an unaffected unit under § 72.6(b)(4) of this chapter under the Acid Rain Program for any year.
(2)(i) For units other than cogeneration units –
(A) For units commencing operation before January 1, 1997, a unit –
(1) With a maximum design heat input greater than 250 mmBtu/hr and
(2) Not serving during 1995 or 1996 a generator producing electricity for sale under a firm contract to the electric grid.
(B) For units commencing operation in 1997 or 1998, a unit –
(1) With a maximum design heat input greater than 250 mmBtu/hr and
(2) Not serving during 1997 or 1998 a generator producing electricity for sale under a firm contract to the electric grid.
(C) For units commencing on or after January 1, 1999, a unit with a maximum design heat input greater than 250 mmBtu/hr:
(1) At no time serving a generator producing electricity for sale; or
(2) At any time serving a generator with a nameplate capacity of 25 MWe or less producing electricity for sale and with the potential to use no more than 50 percent of the potential electrical output capacity of the unit.
(ii) For cogeneration units –
(A) For units commencing operation before January 1, 1997, a unit with a maximum design heat input greater than 250 mmBtu/hr and qualifying as an unaffected unit under § 72.6(b)(4) of this chapter under the Acid Rain Program for 1995 and 1996.
(B) For units commencing operation in 1997 or 1998, a unit with a maximum design heat input greater than 250 mmBtu/hr and qualifying as an unaffected unit under § 72.6(b)(4) under the Acid Rain Program for 1997 and 1998.
(C) For units commencing on or after January 1, 1999, a unit with a maximum design heat input greater than 250 mmBtu/hr and qualifying as an unaffected unit under § 72.6(b)(4) of this chapter under the Acid Rain Program for each year.
(b)(1) Notwithstanding paragraph (a) of this section, a unit under paragraph (a)(1) or (a)(2) of this section that has a federally enforceable permit that restricts the unit to combusting only natural gas or fuel oil (as defined in § 75.2 of this chapter) during a control period includes a NO
(2) The exemption under paragraph (b)(1) of this section shall become effective as follows:
(i) The exemption shall become effective on the date on which the NO
(ii) If the NO
(3) The permitting authority that issues a federally enforceable permit under paragraph (b)(1) of this section for a unit under paragraph (a)(1) or (a)(2) of this section will provide the Administrator written notice of the issuance of such permit and, upon request, a copy of the permit.
(4) Special provisions. (i) A unit exempt under paragraph (b)(1) of this section shall comply with the restriction on fuel use and unit operating hours described in paragraph (b)(1) of this section during the control period in each year.
(ii) The Administrator will allocate NO
(A) The owners and operators of the unit must specify a general account, in which the Administrator will record the NO
(B) After the Administrator records a NO
(iii) A unit exempt under this paragraph (b) shall report hours of unit operation during the control period in each year to the permitting authority by November 1 of that year.
(iv) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (b)(1) of this section shall retain, at the source that includes the unit, records demonstrating that the conditions of the federally enforceable permit under paragraph (b)(1) of this section were met, including the restriction on fuel use or unit operating hours. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit met the restriction on fuel use or unit operating hours.
(v) The owners and operators and, to the extent applicable, the NO
(vi) On the earlier of the following dates, a unit exempt under paragraph (b)(1) of this section shall lose its exemption:
(A) The date on which the restriction on fuel use or unit operating hours described in paragraph (b)(1) of this section is removed from the unit’s federally enforceable permit or otherwise becomes no longer applicable to any control period starting in 2004; or
(B) The first date on which the unit fails to comply, or with regard to which the owners and operators fail to meet their burden of proving that the unit is complying, with the restriction on fuel use or unit operating hours described in paragraph (b)(1) of this section during any control period starting in 2004.
(vii) A unit that loses its exemption in accordance with paragraph (b)(4)(vi) of this section shall be subject to the requirements of this part. For the purpose of applying permitting requirements under subpart C of this part, allocating allowances under subpart E of this part, and applying monitoring requirements under subpart H of this part, the unit shall be treated as commencing operation and, if the unit is covered by paragraph (a)(1) of this section, commencing commercial operation on the date the unit loses its exemption.
(viii) A unit that is exempt under paragraph (b)(1) of this section is not eligible to be a NO
§ 97.5 Retired unit exemption.
(a) This section applies to any NO
(b)(1) Any NO
(2) The exemption under paragraph (b)(1) of this section shall become effective the day on which the unit is permanently retired. Within 30 days of permanent retirement, the NO
(3) After receipt of the notice under paragraph (b)(2) of this section, the permitting authority will amend any permit covering the source at which the unit is located to add the provisions and requirements of the exemption under paragraphs (b)(1) and (c) of this section.
(c) Special provisions. (1) A unit exempt under this section shall not emit any nitrogen oxides, starting on the date that the exemption takes effect.
(2) The Administrator will allocate NO
(3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under this section shall retain at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time prior to the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(4) The owners and operators and, to the extent applicable, the NO
(5)(i) A unit exempt under this section and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the NO
(ii) A unit exempt under this section and located at a source that is required, or but for this exemption would be required, to have a non-title V permit shall not resume operation unless the NO
(6) On the earlier of the following dates, a unit exempt under paragraph (b) of this section shall lose its exemption:
(i) The date on which the NO
(ii) The date on which the NO
(iii) The date on which the unit resumes operation, if the unit is not required to submit a NO
(7) For the purpose of applying monitoring requirements under subpart H of this part, a unit that loses its exemption under this section shall be treated as a unit that commences operation or commercial operation on the first date on which the unit resumes operation.
(8) A unit that is exempt under this section is not eligible to be a NO
§ 97.6 Standard requirements.
(a) Permit requirements. (1) The NO
(i) Submit to the permitting authority a complete NO
(ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a NO
(2) The owners and operators of each NO
(3) The owners and operators of a NO
(b) Monitoring requirements. (1) The owners and operators and, to the extent applicable, the NO
(2) The emissions measurements recorded and reported in accordance with subpart H of this part shall be used to determine compliance by the unit with the NO
(c) Nitrogen oxides requirements. (1) The owners and operators of each NO
(2) Each ton of nitrogen oxides emitted in excess of the NO
(3) A NO
(4) NO
(5) A NO
(6) A NO
(7) A NO
(8) Upon recordation by the Administrator under subpart F or G of this part, every allocation, transfer, or deduction of a NO
(d) Excess emissions requirements. (1) The owners and operators of a NO
(i) Surrender the NO
(ii) Pay any fine, penalty, or assessment or comply with any other remedy imposed under § 97.54(d)(3).
(e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the NO
(i) The account certificate of representation under § 97.13 for the NO
(ii) All emissions monitoring information, in accordance with subpart H of this part; provided that to the extent that subpart H of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the NO
(iv) Copies of all documents used to complete a NO
(2) The NO
(f) Liability. (1) Any person who knowingly violates any requirement or prohibition of the NO
(2) Any person who knowingly makes a false material statement in any record, submission, or report under the NO
(3) No permit revision shall excuse any violation of the requirements of the NO
(4) Each NO
(5) Any provision of the NO
(6) Any provision of the NO
(g) Effect on other authorities. No provision of the NO
§ 97.7 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the NO
(b) Unless otherwise stated, any time period scheduled, under the NO
(c) Unless otherwise stated, if the final day of any time period, under the NO
Subpart B – NOX Authorized Account Representative for NOX Budget Sources
(a) Except as provided under § 97.11, each NO
(b) The NO
(c) Upon receipt by the Administrator of a complete account certificate of representation under § 97.13, the NO
(d) No NO
(e) (1) Each submission under the NO
(2) The permitting authority and the Administrator will accept or act on a submission made on behalf of owner or operators of a NO
(a) An account certificate of representation may designate one and only one alternate NO
(b) Upon receipt by the Administrator of a complete account certificate of representation under § 97.13, any representation, action, inaction, or submission by the alternate NO
(c) Except in this section and §§ 97.10(a), 97.12, 97.13, and 97.51, whenever the term “NO
(a) Changing NO
(b) Changing alternate NO
(c) Changes in owners and operators. (1) In the event a new owner or operator of a NO
(2) Within 30 days following any change in the owners and operators of a NO
§ 97.13 Account certificate of representation.
(a) A complete account certificate of representation for a NO
(1) Identification of the NO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the NO
(3) A list of the owners and operators of the NO
(4) The following certification statement by the NO
(5) The signature of the NO
(b) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the account certificate of representation shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(a) Once a complete account certificate of representation under § 97.13 has been submitted and received, the permitting authority and the Administrator will rely on the account certificate of representation unless and until a superseding complete account certificate of representation under § 97.13 is received by the Administrator.
(b) Except as provided in § 97.12 (a) or (b), no objection or other communication submitted to the permitting authority or the Administrator concerning the authorization, or any representation, action, inaction, or submission of the NO
(c) Neither the permitting authority nor the Administrator will adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any NO
Subpart C – Permits
§ 97.20 General NOX Budget Trading Program permit requirements.
(a) For each NO
(1) For NO
(2) For NO
(b) Each NO
§ 97.21 Submission of NOX Budget permit applications.
(a) Duty to apply. The NO
(b)(1) For NO
(i) For any source, with one or more NO
(ii) For any source, with any NO
(2) For NO
(i) For any source, with one or more NO
(ii) For any source, with any NO
(c) Duty to reapply. (1) For a NO
(2) For a NO
§ 97.22 Information requirements for NOX Budget permit applications.
A complete NO
(a) Identification of the NO
(b) Identification of each NO
(c) The standard requirements under § 97.6; and
(d) For each NO
(1) “I certify that each unit for which this permit application is submitted under subpart I of this part is not a NO
(2) If the application is for an initial NO
§ 97.23 NOX Budget permit contents.
(a) Each NO
(b) Each NO
§ 97.24 NOX Budget permit revisions.
(a) For a NO
(b) For a NO
Subpart D – Compliance Certification
§ 97.30 Compliance certification report.
(a) Applicability and deadline. For each control period in which one or more NO
(b) Contents of report. The NO
(1) Identification of each NO
(2) At the NO
(3) At the NO
(4) The compliance certification under paragraph (c) of this section.
(c) Compliance certification. In the compliance certification report under paragraph (a) of this section, the NO
(1) Whether the unit was operated in compliance with the NO
(2) Whether the monitoring plan that governs the unit has been maintained to reflect the actual operation and monitoring of the unit and contains all information necessary to attribute NO
(3) Whether all the NO
(4) Whether the facts that form the basis for certification under subpart H of this part of each monitor at the unit or a group of units (including the unit) using a common stack, or for using an excepted monitoring method or alternative monitoring method approved under subpart H of this part, if any, have changed; and
(5) If a change is required to be reported under paragraph (c)(4) of this section, specify the nature of the change, the reason for the change, when the change occurred, and how the unit’s compliance status was determined subsequent to the change, including what method was used to determine emissions when a change mandated the need for monitor recertification.
§ 97.31 Administrator’s action on compliance certifications.
(a) The Administrator may review and conduct independent audits concerning any compliance certification or any other submission under the NO
(b) The Administrator may deduct NO
Subpart E – NOX Allowance Allocations
§ 97.40 Trading program budget.
In accordance with §§ 97.41 and 97.42, the Administrator will allocate to the NO
§ 97.41 Timing requirements for NOX allowance allocations.
(a) The NO
(b) By April 1, 2005, the Administrator will determine by order the NO
(c) By April 1, 2010, by April 1 of 2015, and thereafter by April 1 of the year that is 5 years after the last year for which NO
(d) By April 1, 2004 and April 1 of each year thereafter, the Administrator will determine by order the NO
(e) The Administrator will make available to the public each determination of NO
§ 97.42 NOX allowance allocations.
(a)(1) The heat input (in mmBtu) used for calculating NO
(i) For a NO
(A) For a unit under § 97.4(a)(1), the average of the two highest amounts of the unit’s heat input for the control periods in 1995 through 1998; or
(B) For a unit under § 97.4(a)(2), the control period in 1995 or, if the Administrator determines that reasonably reliable data are available for control periods in 1996 through 1998, the average of the two highest amounts of the unit’s heat input for the control periods in 1995 through 1998.
(ii) For a NO
(iii) For a NO
(2) The unit’s heat input for the control period in each year specified under paragraph (a)(1) of this section will be determined in accordance with part 75 of this chapter. Notwithstanding the first sentence of this paragraph (a)(2):
(i) For a NO
(ii) For a NO
(b) For each group of control periods specified in § 97.41(a) through (c), the Administrator will allocate to all NO
(1) The Administrator will allocate NO
(2) If the initial total number of NO
(c) For each group of control periods specified in § 97.41(a) through (c), the Administrator will allocate to all NO
(1) The Administrator will allocate NO
(2) If the initial total number of NO
(d) For each control period specified in § 97.41(d), the Administrator will allocate NO
(1) The Administrator will establish one allocation set-aside for each control period. Each allocation set-aside will be allocated NO
(2) The NO
(3) In a NO
(i) 0.15 lb/mmBtu multiplied by the unit’s maximum design heat input, multiplied by the lesser of 3,672 hours or the number of hours remaining in the control period starting with the day in the control period on which the unit commences operation or is projected to commence operation, divided by 2,000 lb/ton, and rounded to the nearest whole number of NO
(ii) The unit’s most stringent State or Federal NO
(4) In a NO
(i) 0.17 lb/mmBtu multiplied by the unit’s maximum design heat input, multiplied by the lesser of 3,672 hours or the number of hours remaining in the control period starting with the day in the control period on which the unit commences operation or is projected to commence operation, divided by 2,000 lb/ton, and rounded to the nearest whole number of NO
(ii) The unit’s most stringent State or Federal NO
(5) The Administrator will review each NO
(i) Upon receipt of the NO
(ii) The Administrator will determine the following amounts:
(A) The sum of the NO
(B) For units exempt under § 97.4(b) in the State that commenced operation, or are projected to commence operation, on or after May 1, 1997 (for control periods under § 97.41(a)); May 1, 2003, (for control periods under § 97.41(b)); and May 1 of the year 5 years before beginning of the group of 5 years that includes the control period (for control periods under § 97.41(c)), the sum of the NO
(iii) If the number of NO
(iv) If the number of NO
(e)(1) For a NO
(2) The Administrator will transfer any NO
(f) After making the deductions for compliance under § 97.54(b), (e), or (f) for a control period, the Administrator will determine whether any NO
(g) If the Administrator determines that NO
(1)(i) The Administrator will not record such NO
(ii) If the Administrator already recorded such NO
(iii) If the Administrator already recorded such NO
(2) The Administrator will transfer the NO
§ 97.43 Compliance Supplement Pool.
(a) For any NO
(1) Each NO
(2) NO
(3) Each NO
(4) The NO
(i) In the early reduction credit request, the NO
(ii) The early reduction credit request must be submitted, in a format specified by the Administrator, by February 1, 2004.
(b) For any NO
(1) The NO
(2) The early reduction credit request under paragraph (b)(1) must be submitted, in a format specified by the Administrator, by February 1, 2004.
(3) The NO
(c) The Administrator will review each early reduction credit request submitted in accordance with paragraph (a) or (b) of this section and will allocate NO
(1) Upon receipt of each early reduction credit request, the Administrator will make any necessary adjustments to the request to ensure that the amount of the early reduction credits requested meets the requirements of paragraph (a) or (b) of this section.
(2) After February 1, 2004, the Administrator will make available to the public a statement of the total number of early reduction credits requested by NO
(3) If the State’s compliance supplement pool set forth in appendix D to this subpart has a number of NO
(4) If the State’s compliance supplement pool set forth in appendix D to this subpart has a smaller number of NO
(5) By April 1, 2004, the Administrator will determine by order the allocations under paragraph (c)(3) or (4) of this section. The Administrator will make available to the public each determination of NO
(6) By May 1, 2004, the Administrator will record the allocations under paragraph (c)(3) or (4) of this section.
(7) NO
Appendix A to Subpart E of Part 97 – Final Section 126 Rule: EGU Allocations, 2004-2007
ST | Plant | Plant_id | Point_id | NO |
---|---|---|---|---|
DC | BENNING | 603 | 15 | 80 |
DC | BENNING | 603 | 16 | 117 |
DE | CHRISTIANA SUB | 591 | 11 | 5 |
DE | CHRISTIANA SUB | 591 | 14 | 5 |
DE | DELAWARE CITY | 52193 | B4 | 141 |
DE | DELAWARE CITY | 52193 | ST_1 | 155 |
DE | DELAWARE CITY | 52193 | ST_2 | 159 |
DE | DELAWARE CITY | 52193 | ST_3 | 158 |
DE | EDGE MOOR | 593 | 3 | 234 |
DE | EDGE MOOR | 593 | 4 | 401 |
DE | EDGE MOOR | 593 | 5 | 602 |
DE | HAY ROAD | 7153 | **3 | 184 |
DE | HAY ROAD | 7153 | – 1 | 235 |
DE | HAY ROAD | 7153 | – 2 | 207 |
DE | INDIAN RIVER | 594 | 1 | 187 |
DE | INDIAN RIVER | 594 | 2 | 194 |
DE | INDIAN RIVER | 594 | 3 | 369 |
DE | INDIAN RIVER | 594 | 4 | 729 |
DE | MCKEE RUN | 599 | 3 | 119 |
DE | VAN SANT STATION | 7318 | **11 | 7 |
IN | ANDERSON | 7336 | – ACT1 | 5 |
IN | ANDERSON | 7336 | – ACT2 | 5 |
IN | CLIFTY CREEK | 983 | 1 | 558 |
IN | CLIFTY CREEK | 983 | 2 | 543 |
IN | CLIFTY CREEK | 983 | 3 | 564 |
IN | CLIFTY CREEK | 983 | 4 | 525 |
IN | CLIFTY CREEK | 983 | 5 | 561 |
IN | CLIFTY CREEK | 983 | 6 | 509 |
IN | CONNERSVILLE | 1002 | 1 | 1 |
IN | CONNERSVILLE | 1002 | 2 | 1 |
IN | GALLAGHER | 1008 | 1 | 290 |
IN | GALLAGHER | 1008 | 2 | 276 |
IN | GALLAGHER | 1008 | 3 | 347 |
IN | GALLAGHER | 1008 | 4 | 329 |
IN | NOBLESVILLE | 1007 | 1 | 48 |
IN | NOBLESVILLE | 1007 | 2 | 45 |
IN | NOBLESVILLE | 1007 | 3 | 45 |
IN | RICHMOND | 7335 | – RCT1 | 5 |
IN | RICHMOND | 7335 | – RCT2 | 5 |
IN | TANNERS CREEK | 988 | U1 | 297 |
IN | TANNERS CREEK | 988 | U2 | 235 |
IN | TANNERS CREEK | 988 | U3 | 387 |
IN | TANNERS CREEK | 988 | U4 | 906 |
IN | WHITEWATER VALLEY | 1040 | 1 | 74 |
IN | WHITEWATER VALLEY | 1040 | 2 | 173 |
KY | BIG SANDY | 1353 | BSU1 | 565 |
KY | BIG SANDY | 1353 | BSU2 | 1,741 |
KY | CANE RUN | 1363 | 4 | 397 |
KY | CANE RUN | 1363 | 5 | 332 |
KY | CANE RUN | 1363 | 6 | 430 |
KY | COOPER | 1384 | 1 | 183 |
KY | COOPER | 1384 | 2 | 367 |
KY | DALE | 1385 | 3 | 161 |
KY | DALE | 1385 | 4 | 158 |
KY | E W BROWN | 1355 | 1 | 193 |
KY | E W BROWN | 1355 | 10 | 37 |
KY | E W BROWN | 1355 | 2 | 317 |
KY | E W BROWN | 1355 | 3 | 863 |
KY | E W BROWN | 1355 | 8 | 34 |
KY | E W BROWN | 1355 | 9 | 34 |
KY | E.W. BROWN | 1355 | 11 | 21 |
KY | EAST BEND | 6018 | 2 | 1,413 |
KY | GHENT | 1356 | 1 | 1,232 |
KY | GHENT | 1356 | 2 | 1,081 |
KY | GHENT | 1356 | 3 | 1,104 |
KY | GHENT | 1356 | 4 | 1,132 |
KY | H L SPURLOCK | 6041 | 1 | 697 |
KY | H L SPURLOCK | 6041 | 2 | 1,589 |
KY | MILL CREEK | 1364 | 1 | 528 |
KY | MILL CREEK | 1364 | 2 | 600 |
KY | MILL CREEK | 1364 | 3 | 941 |
KY | MILL CREEK | 1364 | 4 | 1,096 |
KY | PADDY’S RUN | 1366 | 12 | 8 |
KY | PINEVILLE | 1360 | 3 | 67 |
KY | TRIMBLE COUNTY | 6071 | 1 | 1,221 |
KY | TYRONE | 1361 | 1 | 3 |
KY | TYRONE | 1361 | 2 | 3 |
KY | TYRONE | 1361 | 3 | 3 |
KY | TYRONE | 1361 | 4 | 3 |
KY | TYRONE | 1361 | 5 | 117 |
MD | BRANDON SHORES | 602 | 1 | 1,827 |
MD | BRANDON SHORES | 602 | 2 | 1,713 |
MD | C P CRANE | 1552 | 1 | 434 |
MD | C P CRANE | 1552 | 2 | 463 |
MD | CHALK POINT | 1571 | – GT2 | 1 |
MD | CHALK POINT | 1571 | – GT3 | 36 |
MD | CHALK POINT | 1571 | – GT4 | 39 |
MD | CHALK POINT | 1571 | – GT5 | 55 |
MD | CHALK POINT | 1571 | – GT6 | 60 |
MD | CHALK POINT | 1571 | – SGT1 | 24 |
MD | CHALK POINT | 1571 | 1 | 833 |
MD | CHALK POINT | 1571 | 2 | 861 |
MD | CHALK POINT | 1571 | 3 | 585 |
MD | CHALK POINT | 1571 | 4 | 522 |
MD | DICKERSON | 1572 | – GT2 | 36 |
MD | DICKERSON | 1572 | – GT3 | 66 |
MD | DICKERSON | 1572 | 1 | 447 |
MD | DICKERSON | 1572 | 2 | 441 |
MD | DICKERSON | 1572 | 3 | 481 |
MD | GOULD STREET | 1553 | 3 | 81 |
MD | HERBERT A WAGNER | 1554 | 1 | 134 |
MD | HERBERT A WAGNER | 1554 | 2 | 399 |
MD | HERBERT A WAGNER | 1554 | 3 | 723 |
MD | HERBERT A WAGNER | 1554 | 4 | 301 |
MD | MORGANTOWN | 1573 | – GT3 | 9 |
MD | MORGANTOWN | 1573 | – GT4 | 9 |
MD | MORGANTOWN | 1573 | – GT5 | 9 |
MD | MORGANTOWN | 1573 | – GT6 | 8 |
MD | MORGANTOWN | 1573 | 1 | 1,151 |
MD | MORGANTOWN | 1573 | 2 | 1,375 |
MD | PANDA BRANDYWINE | 54832 | 1 | 95 |
MD | PANDA BRANDYWINE | 54832 | 2 | 84 |
MD | PERRYMAN | 1556 | **51 | 56 |
MD | PERRYMAN | 1556 | – GT1 | 8 |
MD | PERRYMAN | 1556 | – GT2 | 9 |
MD | PERRYMAN | 1556 | – GT3 | 6 |
MD | PERRYMAN | 1556 | – GT4 | 10 |
MD | R P SMITH | 1570 | 11 | 143 |
MD | R P SMITH | 1570 | 9 | 11 |
MD | RIVERSIDE | 1559 | – GT6 | 11 |
MD | RIVERSIDE | 1559 | 4 | 40 |
MD | VIENNA | 1564 | 8 | 169 |
MD | WESTPORT | 1560 | – GT5 | 28 |
MI | ADA COGEN LTD | 10819 | CA_Ltd | 23 |
MI | BELLE RIVER | 6034 | 1 | 1,589 |
MI | BELLE RIVER | 6034 | 2 | 1,672 |
MI | DAN E KARN | 1702 | 1 | 552 |
MI | DAN E KARN | 1702 | 2 | 530 |
MI | DAN E KARN | 1702 | 3 | 288 |
MI | DAN E KARN | 1702 | 4 | 310 |
MI | ECKERT STATION | 1831 | 1 | 52 |
MI | ECKERT STATION | 1831 | 2 | 47 |
MI | ECKERT STATION | 1831 | 3 | 65 |
MI | ECKERT STATION | 1831 | 4 | 116 |
MI | ECKERT STATION | 1831 | 5 | 154 |
MI | ECKERT STATION | 1831 | 6 | 131 |
MI | ENDICOTT GENERATING STATION | 4259 | 1 | 98 |
MI | ERICKSON | 1832 | 1 | 381 |
MI | GREENWOOD | 6035 | 1 | 373 |
MI | HANCOCK | 1730 | 5 | 3 |
MI | HANCOCK | 1730 | 6 | 3 |
MI | HARBOR BEACH | 1731 | 1 | 97 |
MI | J C WEADOCK | 1720 | 7 | 346 |
MI | J C WEADOCK | 1720 | 8 | 342 |
MI | J R WHITING | 1723 | 1 | 225 |
MI | J R WHITING | 1723 | 2 | 204 |
MI | J R WHITING | 1723 | 3 | 249 |
MI | JAMES DE YOUNG | 1830 | 5 | 69 |
MI | MARYSVILLE | 1732 | 10 | 22 |
MI | MARYSVILLE | 1732 | 11 | 16 |
MI | MARYSVILLE | 1732 | 12 | 17 |
MI | MARYSVILLE | 1732 | 9 | 17 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 003 | 269 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 004 | 276 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 005 | 271 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 006 | 273 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 007 | 280 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 008 | 277 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 009 | 273 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 010 | 271 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 011 | 274 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 012 | 269 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 013 | 275 |
MI | MIDLAND COGENERATION VENTURE | 10745 | 014 | 269 |
MI | MISTERSKY | 1822 | 5 | 33 |
MI | MISTERSKY | 1822 | 6 | 155 |
MI | MISTERSKY | 1822 | 7 | 98 |
MI | MONROE | 1733 | 1 | 1,902 |
MI | MONROE | 1733 | 2 | 1,555 |
MI | MONROE | 1733 | 3 | 1,574 |
MI | MONROE | 1733 | 4 | 1,822 |
MI | RIVER ROUGE | 1740 | 1 | 0 |
MI | RIVER ROUGE | 1740 | 2 | 627 |
MI | RIVER ROUGE | 1740 | 3 | 652 |
MI | ROUGE POWERHOUSE #1 | 10272 | 1 | 232 |
MI | ST CLAIR | 1743 | 1 | 339 |
MI | ST CLAIR | 1743 | 2 | 304 |
MI | ST CLAIR | 1743 | 3 | 351 |
MI | ST CLAIR | 1743 | 4 | 349 |
MI | ST CLAIR | 1743 | 5 | 0 |
MI | ST CLAIR | 1743 | 6 | 646 |
MI | ST CLAIR | 1743 | 7 | 733 |
MI | TRENTON CHANNEL | 1745 | 16 | 132 |
MI | TRENTON CHANNEL | 1745 | 17 | 124 |
MI | TRENTON CHANNEL | 1745 | 18 | 130 |
MI | TRENTON CHANNEL | 1745 | 19 | 126 |
MI | TRENTON CHANNEL | 1745 | 9A | 968 |
MI | WYANDOTTE | 1866 | 5 | 8 |
MI | WYANDOTTE | 1866 | 7 | 81 |
MI | WYANDOTTE | 1866 | 8 | 36 |
NC | ASHEVILLE | 2706 | 1 | 491 |
NC | ASHEVILLE | 2706 | 2 | 479 |
NC | BELEWS CREEK | 8042 | 1 | 2,306 |
NC | BELEWS CREEK | 8042 | 2 | 2,688 |
NC | BUCK | 2720 | 5 | 59 |
NC | BUCK | 2720 | 6 | 65 |
NC | BUCK | 2720 | 7 | 69 |
NC | BUCK | 2720 | 8 | 284 |
NC | BUCK | 2720 | 9 | 300 |
NC | BUTLER WARNER GEN PL | 1016 | – 1 | 40 |
NC | BUTLER WARNER GEN PL | 1016 | – 2 | 40 |
NC | BUTLER WARNER GEN PL | 1016 | – 3 | 40 |
NC | BUTLER WARNER GEN PL | 1016 | – 6 | 42 |
NC | BUTLER WARNER GEN PL | 1016 | – 7 | 40 |
NC | BUTLER WARNER GEN PL | 1016 | – 8 | 40 |
NC | BUTLER WARNER GEN PL | 1016 | – 9 | 103 |
NC | CAPE FEAR | 2708 | 5 | 255 |
NC | CAPE FEAR | 2708 | 6 | 361 |
NC | CLIFFSIDE | 2721 | 1 | 67 |
NC | CLIFFSIDE | 2721 | 2 | 73 |
NC | CLIFFSIDE | 2721 | 3 | 95 |
NC | CLIFFSIDE | 2721 | 4 | 107 |
NC | CLIFFSIDE | 2721 | 5 | 1,180 |
NC | COGENTRIX-ROCKY MOUNT | 50468 | ST_unt | 303 |
NC | COGENTRIX ELIZABETHTOWN | 10380 | ST_OWN | 111 |
NC | COGENTRIX KENANSVILLE | 10381 | ST_LLE | 102 |
NC | COGENTRIX LUMBERTON | 10382 | ST_TON | 111 |
NC | COGENTRIX ROXBORO | 10379 | ST_ORO | 166 |
NC | COGENTRIX SOUTHPORT | 10378 | ST_ORT | 335 |
NC | DAN RIVER | 2723 | 1 | 117 |
NC | DAN RIVER | 2723 | 2 | 128 |
NC | DAN RIVER | 2723 | 3 | 271 |
NC | G G ALLEN | 2718 | 1 | 311 |
NC | G G ALLEN | 2718 | 2 | 316 |
NC | G G ALLEN | 2718 | 3 | 525 |
NC | G G ALLEN | 2718 | 4 | 470 |
NC | G G ALLEN | 2718 | 5 | 514 |
NC | L V SUTTON | 2713 | 1 | 162 |
NC | L V SUTTON | 2713 | 2 | 176 |
NC | L V SUTTON | 2713 | 3 | 717 |
NC | L V SUTTON | 2713 | CT2B | 2 |
NC | LEE | 2709 | 1 | 129 |
NC | LEE | 2709 | 2 | 142 |
NC | LEE | 2709 | 3 | 414 |
NC | LEE | 2709 | CT4 | 1 |
NC | LINCOLN | 7277 | 1 | 33 |
NC | LINCOLN | 7277 | 10 | 31 |
NC | LINCOLN | 7277 | 11 | 33 |
NC | LINCOLN | 7277 | 12 | 31 |
NC | LINCOLN | 7277 | 13 | 26 |
NC | LINCOLN | 7277 | 14 | 26 |
NC | LINCOLN | 7277 | 15 | 25 |
NC | LINCOLN | 7277 | 16 | 25 |
NC | LINCOLN | 7277 | 2 | 33 |
NC | LINCOLN | 7277 | 3 | 31 |
NC | LINCOLN | 7277 | 4 | 31 |
NC | LINCOLN | 7277 | 5 | 29 |
NC | LINCOLN | 7277 | 6 | 30 |
NC | LINCOLN | 7277 | 7 | 24 |
NC | LINCOLN | 7277 | 8 | 25 |
NC | LINCOLN | 7277 | 9 | 32 |
NC | MARSHALL | 2727 | 1 | 899 |
NC | MARSHALL | 2727 | 2 | 940 |
NC | MARSHALL | 2727 | 3 | 1,588 |
NC | MARSHALL | 2727 | 4 | 1,570 |
NC | MAYO | 6250 | 1A | 893 |
NC | MAYO | 6250 | 1B | 875 |
NC | PANDA-ROSEMARY | 50555 | CT_ary | 62 |
NC | PANDA-ROSEMARY | 50555 | CW_ary | 47 |
NC | RIVERBEND | 2732 | 10 | 266 |
NC | RIVERBEND | 2732 | 7 | 193 |
NC | RIVERBEND | 2732 | 8 | 200 |
NC | RIVERBEND | 2732 | 9 | 253 |
NC | ROANOKE VALLEY | 50254 | 1 | 440 |
NC | ROANOKE VALLEY | 50254 | 2 | 140 |
NC | ROXBORO | 2712 | 1 | 766 |
NC | ROXBORO | 2712 | 2 | 1,426 |
NC | ROXBORO | 2712 | 3A | 792 |
NC | ROXBORO | 2712 | 3B | 785 |
NC | ROXBORO | 2712 | 4A | 778 |
NC | ROXBORO | 2712 | 4B | 733 |
NC | TOBACCOVILLE | 50221 | 1 | 53 |
NC | TOBACCOVILLE | 50221 | 2 | 53 |
NC | TOBACCOVILLE | 50221 | 3 | 53 |
NC | TOBACCOVILLE | 50221 | 4 | 53 |
NC | UNC – CHAPEL HILL | 54276 | ST_ill | 14 |
NC | W H WEATHERSPOON | 2716 | 1 | 76 |
NC | W H WEATHERSPOON | 2716 | 2 | 86 |
NC | W H WEATHERSPOON | 2716 | 3 | 161 |
NC | W H WEATHERSPOON | 2716 | CT-1 | 4 |
NC | W H WEATHERSPOON | 2716 | CT-2 | 3 |
NC | W H WEATHERSPOON | 2716 | CT-3 | 2 |
NC | W H WEATHERSPOON | 2716 | CT-4 | 4 |
NJ | B L ENGLAND | 2378 | 1 | 353 |
NJ | B L ENGLAND | 2378 | 2 | 417 |
NJ | B L ENGLAND | 2378 | 3 | 114 |
NJ | BAYONNE | 50497 | 1 | 139 |
NJ | BAYONNE | 50497 | 2 | 143 |
NJ | BAYONNE | 50497 | 3 | 140 |
NJ | BERGEN | 2398 | 1101 | 152 |
NJ | BERGEN | 2398 | 1201 | 157 |
NJ | BERGEN | 2398 | 1301 | 155 |
NJ | BERGEN | 2398 | 1401 | 152 |
NJ | BURLINGTON | 2399 | 101 | 30 |
NJ | BURLINGTON | 2399 | 102 | 34 |
NJ | BURLINGTON | 2399 | 103 | 39 |
NJ | BURLINGTON | 2399 | 104 | 47 |
NJ | BURLINGTON | 2399 | 11-1 | 2 |
NJ | BURLINGTON | 2399 | 11-2 | 2 |
NJ | BURLINGTON | 2399 | 11-3 | 2 |
NJ | BURLINGTON | 2399 | 11-4 | 2 |
NJ | BURLINGTON | 2399 | 7 | 17 |
NJ | BURLINGTON | 2399 | 9-1 | 4 |
NJ | BURLINGTON | 2399 | 9-2 | 4 |
NJ | BURLINGTON | 2399 | 9-3 | 4 |
NJ | BURLINGTON | 2399 | 9-4 | 4 |
NJ | CAMDEN | 10751 | 1 | 378 |
NJ | CARLL’S CORNER STATION | 2379 | 1 | 2 |
NJ | CARLL’S CORNER STATION | 2379 | 2 | 16 |
NJ | CARNEYS POINT (CCLP) NUG | 10566 | ST_NUG | 527 |
NJ | CEDAR STATION | 2380 | 1E&W | 5 |
NJ | CUMBERLAND | 5083 | – GT1 | 40 |
NJ | DEEPWATER | 2384 | 1 | 49 |
NJ | DEEPWATER | 2384 | 4 | 5 |
NJ | DEEPWATER | 2384 | 6 | 42 |
NJ | DEEPWATER | 2384 | 8 | 195 |
NJ | EDISON | 2400 | 1-1A&B | 3 |
NJ | EDISON | 2400 | 1-2A&B | 3 |
NJ | EDISON | 2400 | 1-3A&B | 3 |
NJ | EDISON | 2400 | 1-4A&B | 3 |
NJ | EDISON | 2400 | 2-1A&B | 7 |
NJ | EDISON | 2400 | 2-2A&B | 7 |
NJ | EDISON | 2400 | 2-3A&B | 7 |
NJ | EDISON | 2400 | 2-4A&B | 7 |
NJ | EDISON | 2400 | 3-1A&B | 7 |
NJ | EDISON | 2400 | 3-2A&B | 7 |
NJ | EDISON | 2400 | 3-3A&B | 7 |
NJ | EDISON | 2400 | 3-4A&B | 7 |
NJ | ESSEX | 2401 | 10-1A&B | 10 |
NJ | ESSEX | 2401 | 10-2A&B | 10 |
NJ | ESSEX | 2401 | 10-3A&B | 10 |
NJ | ESSEX | 2401 | 10-4A&B | 10 |
NJ | ESSEX | 2401 | 11-1A&B | 11 |
NJ | ESSEX | 2401 | 11-2A&B | 11 |
NJ | ESSEX | 2401 | 11-3A&B | 11 |
NJ | ESSEX | 2401 | 11-4A&B | 11 |
NJ | ESSEX | 2401 | 12-1A&B | 13 |
NJ | ESSEX | 2401 | 12-2A&B | 13 |
NJ | ESSEX | 2401 | 12-3A&B | 13 |
NJ | ESSEX | 2401 | 12-4A&B | 13 |
NJ | ESSEX | 2401 | 9 | 66 |
NJ | FORKED RIVER | 7138 | – 1 | 17 |
NJ | FORKED RIVER | 7138 | – 2 | 17 |
NJ | GILBERT | 2393 | 03 | 47 |
NJ | GILBERT | 2393 | 04 | 64 |
NJ | GILBERT | 2393 | 05 | 63 |
NJ | GILBERT | 2393 | 06 | 61 |
NJ | GILBERT | 2393 | 07 | 63 |
NJ | GILBERT | 2393 | 1 | 4 |
NJ | GILBERT | 2393 | 2 | 4 |
NJ | GILBERT | 2393 | CT-9 | 61 |
NJ | HUDSON | 2403 | 1 | 175 |
NJ | HUDSON | 2403 | 2 | 884 |
NJ | HUDSON | 2403 | 3 | 3 |
NJ | KEARNY | 2404 | 10 | 26 |
NJ | KEARNY | 2404 | 11 | 34 |
NJ | KEARNY | 2404 | 12-1 | 8 |
NJ | KEARNY | 2404 | 12-2 | 8 |
NJ | KEARNY | 2404 | 12-3 | 8 |
NJ | KEARNY | 2404 | 12-4 | 8 |
NJ | KEARNY | 2404 | 7 | 35 |
NJ | KEARNY | 2404 | 8 | 16 |
NJ | LINDEN | 2406 | 11 | 16 |
NJ | LINDEN | 2406 | 12 | 11 |
NJ | LINDEN | 2406 | 13 | 20 |
NJ | LINDEN | 2406 | 2 | 52 |
NJ | LINDEN | 2406 | 6 | 2 |
NJ | LINDEN | 2406 | 7 | 60 |
NJ | LINDEN | 2406 | 8 | 70 |
NJ | LINDEN COGEN | 50006 | 100 | 276 |
NJ | LINDEN COGEN | 50006 | 200 | 280 |
NJ | LINDEN COGEN | 50006 | 300 | 274 |
NJ | LINDEN COGEN | 50006 | 400 | 272 |
NJ | LINDEN COGEN | 50006 | 500 | 278 |
NJ | LOGAN GENERATING PLANT | 10043 | 1 | 424 |
NJ | MERCER | 2408 | 1 | 489 |
NJ | MERCER | 2408 | 2 | 558 |
NJ | MICKELTON | 8008 | 1 | 28 |
NJ | MIDDLE ST | 2382 | 3 | 4 |
NJ | MILFORD POWER LP | 10616 | 1 | 44 |
NJ | MOBIL NUG | n114 | CT_NUG | 40 |
NJ | NEWARK BAY COGEN | 50385 | 1 | 9 |
NJ | NEWARK BAY COGEN | 50385 | 2 | 9 |
NJ | NORTH JERSEY ENERGY ASSOCIATES | 10308 | 1 | 19 |
NJ | NORTH JERSEY ENERGY ASSOCIATES | 10308 | 2 | 19 |
NJ | O’BRIEN (NEWARK) COGENERATION, INC. | 50797 | 1 | 8 |
NJ | O’BRIEN (PARLIN) COGENERATION, INC. | 50799 | 1 | 8 |
NJ | O’BRIEN (PARLIN) COGENERATION, INC. | 50799 | 2 | 8 |
NJ | PEDRICKTOWN COGEN | 10099 | 1 | 13 |
NJ | PRIME ENERGY LP | 50852 | 1 | 178 |
NJ | SALEM | 2410 | 3A&B | 3 |
NJ | SAYREVILLE | 2390 | 07 | 40 |
NJ | SAYREVILLE | 2390 | 08 | 51 |
NJ | SAYREVILLE | 2390 | C-1 | 16 |
NJ | SAYREVILLE | 2390 | C-2 | 13 |
NJ | SAYREVILLE | 2390 | C-3 | 11 |
NJ | SAYREVILLE | 2390 | C-4 | 13 |
NJ | SEWAREN | 2411 | 1 | 42 |
NJ | SEWAREN | 2411 | 2 | 45 |
NJ | SEWAREN | 2411 | 3 | 58 |
NJ | SEWAREN | 2411 | 4 | 91 |
NJ | SEWAREN | 2411 | 6 | 2 |
NJ | SHERMAN | 7288 | CT-1 | 37 |
NJ | VINELAND VCLP NUG | 54807 | GT_NUG | 40 |
NJ | WERNER | 2385 | 04 | 14 |
NJ | WERNER | 2385 | C-1 | 7 |
NJ | WERNER | 2385 | C-2 | 6 |
NJ | WERNER | 2385 | C-3 | 7 |
NJ | WERNER | 2385 | C-4 | 7 |
NJ | WEST STAT | 6776 | 1 | 10 |
NY | 59TH STREET | 2503 | 114 | 41 |
NY | 59TH STREET | 2503 | 115 | 32 |
NY | 74TH STREET | 2504 | 120 | 70 |
NY | 74TH STREET | 2504 | 121 | 80 |
NY | 74TH STREET | 2504 | 122 | 65 |
NY | ARTHUR KILL | 2490 | 20 | 524 |
NY | ARTHUR KILL | 2490 | 30 | 380 |
NY | ASTORIA | 8906 | 30 | 557 |
NY | ASTORIA | 8906 | 40 | 505 |
NY | ASTORIA | 8906 | 50 | 561 |
NY | ASTORIA | 8906 | GT2-1 | 9 |
NY | ASTORIA | 8906 | GT2-2 | 9 |
NY | ASTORIA | 8906 | GT2-3 | 9 |
NY | ASTORIA | 8906 | GT2-4 | 9 |
NY | ASTORIA | 8906 | GT3-1 | 9 |
NY | ASTORIA | 8906 | GT3-2 | 9 |
NY | ASTORIA | 8906 | GT3-3 | 9 |
NY | ASTORIA | 8906 | GT3-4 | 9 |
NY | ASTORIA | 8906 | GT4-1 | 9 |
NY | ASTORIA | 8906 | GT4-2 | 9 |
NY | ASTORIA | 8906 | GT4-3 | 9 |
NY | ASTORIA | 8906 | GT4-4 | 9 |
NY | BOWLINE POINT | 2625 | 1 | 749 |
NY | BOWLINE POINT | 2625 | 2 | 566 |
NY | BROOKLYN NAVY YARD | 54914 | 1 | 239 |
NY | BROOKLYN NAVY YARD | 54914 | 2 | 220 |
NY | CHARLES POLETTI | 2491 | 001 | 883 |
NY | DANSKAMMER | 2480 | 1 | 34 |
NY | DANSKAMMER | 2480 | 2 | 45 |
NY | DANSKAMMER | 2480 | 3 | 229 |
NY | DANSKAMMER | 2480 | 4 | 449 |
NY | EF BARRETT | 2511 | 10 | 285 |
NY | EF BARRETT | 2511 | 20 | 287 |
NY | EAST RIVER | 2493 | 50 | 33 |
NY | EAST RIVER | 2493 | 60 | 319 |
NY | EAST RIVER | 2493 | 70 | 113 |
NY | FAR ROCKAWAY | 2513 | 40 | 138 |
NY | GLENWOOD | 2514 | 40 | 151 |
NY | GLENWOOD | 2514 | 50 | 124 |
NY | GLENWOOD | 2514 | U00020 | 1 |
NY | GLENWOOD | 2514 | U00021 | 1 |
NY | HUDSON AVENUE | 2496 | 100 | 162 |
NY | LOVETT | 2629 | 3 | 74 |
NY | LOVETT | 2629 | 4 | 304 |
NY | LOVETT | 2629 | 5 | 380 |
NY | NISSEQUOGUE COGEN PARTNERS | 4931 | 1 | 86 |
NY | NORTHPORT | 2516 | 1 | 343 |
NY | NORTHPORT | 2516 | 2 | 533 |
NY | NORTHPORT | 2516 | 3 | 375 |
NY | NORTHPORT | 2516 | 4 | 582 |
NY | O&R HILLBURN GT | 2628 | 1 | 2 |
NY | O&R SHOEMAKER GT | 2632 | 1 | 10 |
NY | PORT JEFFERSON | 2517 | 3 | 270 |
NY | PORT JEFFERSON | 2517 | 4 | 253 |
NY | RAVENSWOOD | 2500 | 10 | 299 |
NY | RAVENSWOOD | 2500 | 20 | 363 |
NY | RAVENSWOOD | 2500 | 30 | 1,360 |
NY | RAVENSWOOD | 2500 | GT2-1 | 3 |
NY | RAVENSWOOD | 2500 | GT2-2 | 3 |
NY | RAVENSWOOD | 2500 | GT2-3 | 3 |
NY | RAVENSWOOD | 2500 | GT2-4 | 3 |
NY | RAVENSWOOD | 2500 | GT3-1 | 3 |
NY | RAVENSWOOD | 2500 | GT3-2 | 3 |
NY | RAVENSWOOD | 2500 | GT3-3 | 3 |
NY | RAVENSWOOD | 2500 | GT3-4 | 3 |
NY | RICHARD M FLYNN | 7314 | NA1 | 246 |
NY | RICHARD M FLYNN | 7314 | NA2 | 25 |
NY | ROSETON | 8006 | 1 | 479 |
NY | ROSETON | 8006 | 2 | 595 |
NY | TRIGEN-NDEC | 52056 | 4 | 105 |
NY | WADING RIVER | 7146 | 1 | 8 |
NY | WADING RIVER | 7146 | 2 | 8 |
NY | WADING RIVER | 7146 | 3 | 8 |
NY | WADING RIVER | 7146 | UGT013 | 1 |
NY | WATERSIDE | 2502 | 61 | 84 |
NY | WATERSIDE | 2502 | 62 | 91 |
NY | WATERSIDE | 2502 | 80 | 208 |
NY | WATERSIDE | 2502 | 90 | 208 |
NY | WEST BABYLON | 2521 | 1 | 2 |
OH | ASHTABULA | 2835 | 10 | 75 |
OH | ASHTABULA | 2835 | 11 | 80 |
OH | ASHTABULA | 2835 | 7 | 333 |
OH | ASHTABULA | 2835 | 8 | 70 |
OH | ASHTABULA | 2835 | 9 | 66 |
OH | AVON LAKE | 2836 | 10 | 139 |
OH | AVON LAKE | 2836 | 12 | 1,040 |
OH | AVON LAKE | 2836 | 9 | 41 |
OH | AVON LAKE | 2836 | CT10 | 3 |
OH | BAY SHORE | 2878 | 1 | 208 |
OH | BAY SHORE | 2878 | 2 | 229 |
OH | BAY SHORE | 2878 | 3 | 213 |
OH | BAY SHORE | 2878 | 4 | 330 |
OH | CARDINAL | 2828 | 1 | 1,030 |
OH | CARDINAL | 2828 | 2 | 1,083 |
OH | CARDINAL | 2828 | 3 | 1,079 |
OH | CONESVILLE | 2840 | 1 | 214 |
OH | CONESVILLE | 2840 | 2 | 203 |
OH | CONESVILLE | 2840 | 3 | 212 |
OH | CONESVILLE | 2840 | 4 | 1,119 |
OH | CONESVILLE | 2840 | 5 | 731 |
OH | CONESVILLE | 2840 | 6 | 736 |
OH | DICKS CREEK | 2831 | 1 | 7 |
OH | EASTLAKE | 2837 | 1 | 214 |
OH | EASTLAKE | 2837 | 2 | 230 |
OH | EASTLAKE | 2837 | 3 | 251 |
OH | EASTLAKE | 2837 | 4 | 371 |
OH | EASTLAKE | 2837 | 5 | 974 |
OH | EASTLAKE | 2837 | 6 | 1 |
OH | EDGEWATER | 2857 | 13 | 65 |
OH | EDGEWATER | 2857 | A | 1 |
OH | EDGEWATER | 2857 | B | 1 |
OH | FRANK M TAIT | 2847 | GT1 | 23 |
OH | FRANK M TAIT | 2847 | GT2 | 25 |
OH | GEN J M GAVIN | 8102 | 1 | 2,744 |
OH | GEN J M GAVIN | 8102 | 2 | 2,981 |
OH | HAMILTON | 2917 | 9 | 110 |
OH | J M STUART | 2850 | 1 | 1,054 |
OH | J M STUART | 2850 | 2 | 1,228 |
OH | J M STUART | 2850 | 3 | 1,074 |
OH | J M STUART | 2850 | 4 | 1,106 |
OH | KILLEN STATION | 6031 | 2 | 1,706 |
OH | KYGER CREEK | 2876 | 1 | 471 |
OH | KYGER CREEK | 2876 | 2 | 471 |
OH | KYGER CREEK | 2876 | 3 | 478 |
OH | KYGER CREEK | 2876 | 4 | 465 |
OH | KYGER CREEK | 2876 | 5 | 455 |
OH | LAKE SHORE | 2838 | 18 | 195 |
OH | MAD RIVER | 2860 | A | 2 |
OH | MAD RIVER | 2860 | B | 2 |
OH | MIAMI FORT | 2832 | 5-1 | 35 |
OH | MIAMI FORT | 2832 | 5-2 | 35 |
OH | MIAMI FORT | 2832 | 6 | 398 |
OH | MIAMI FORT | 2832 | 7 | 1,044 |
OH | MIAMI FORT | 2832 | 8 | 1,015 |
OH | MIAMI FORT | 2832 | CT2 | 1 |
OH | MUSKINGUM RIVER | 2872 | 1 | 309 |
OH | MUSKINGUM RIVER | 2872 | 2 | 316 |
OH | MUSKINGUM RIVER | 2872 | 3 | 347 |
OH | MUSKINGUM RIVER | 2872 | 4 | 349 |
OH | MUSKINGUM RIVER | 2872 | 5 | 1,105 |
OH | NILES | 2861 | 1 | 212 |
OH | NILES | 2861 | 2 | 160 |
OH | NILES | 2861 | A | 2 |
OH | O H HUTCHINGS | 2848 | H-1 | 24 |
OH | O H HUTCHING | 2848 | H-2 | 37 |
OH | O H HUTCHINGS | 2848 | H-3 | 64 |
OH | O H HUTCHINGS | 2848 | H-4 | 68 |
OH | O H HUTCHINGS | 2848 | H-5 | 62 |
OH | O H HUTCHINGS | 2848 | H-6 | 69 |
OH | O H HUTCHINGS | 2848 | H-7 | 1 |
OH | PICWAY | 2843 | 9 | 141 |
OH | R E BURGER | 2864 | 1 | 0 |
OH | R E BURGER | 2864 | 2 | 0 |
OH | R E BURGER | 2864 | 3 | 0 |
OH | R E BURGER | 2864 | 4 | 0 |
OH | R E BURGER | 2864 | 5 | 14 |
OH | R E BURGER | 2864 | 6 | 13 |
OH | R E BURGER | 2864 | 7 | 337 |
OH | R E BURGER | 2864 | 8 | 274 |
OH | RICHARD GORSUCH | 7286 | 1 | 146 |
OH | RICHARD GORSUCH | 7286 | 2 | 138 |
OH | RICHARD GORSUCH | 7286 | 3 | 144 |
OH | RICHARD GORSUCH | 7286 | 4 | 146 |
OH | W H SAMMIS | 2866 | 1 | 402 |
OH | W H SAMMIS | 2866 | 2 | 418 |
OH | W H SAMMIS | 2866 | 3 | 400 |
OH | W H SAMMIS | 2866 | 4 | 415 |
OH | W H SAMMIS | 2866 | 5 | 631 |
OH | W H SAMMIS | 2866 | 6 | 1,221 |
OH | W H SAMMIS | 2866 | 7 | 1,259 |
OH | W H ZIMMER | 6019 | 1 | 2,918 |
OH | WALTER C BECKJORD | 2830 | 1 | 167 |
OH | WALTER C BECKJORD | 2830 | 2 | 198 |
OH | WALTER C BECKJORD | 2830 | 3 | 281 |
OH | WALTER C BECKJORD | 2830 | 4 | 347 |
OH | WALTER C BECKJORD | 2830 | 5 | 481 |
OH | WALTER C BECKJORD | 2830 | 6 | 850 |
OH | WALTER C BECKJORD | 2830 | CT1 | 3 |
OH | WALTER C BECKJORD | 2830 | CT2 | 3 |
OH | WALTER C BECKJORD | 2830 | CT3 | 4 |
OH | WALTER C BECKJORD | 2830 | CT4 | 2 |
OH | WEST LORAIN | 2869 | 1A | 0 |
OH | WEST LORAIN | 2869 | 1B | 0 |
OH | WOODSDALE | 7158 | – GT1 | 30 |
OH | WOODSDALE | 7158 | – GT2 | 30 |
OH | WOODSDALE | 7158 | – GT3 | 39 |
OH | WOODSDALE | 7158 | – GT4 | 37 |
OH | WOODSDALE | 7158 | – GT5 | 40 |
OH | WOODSDALE | 7158 | – GT6 | 39 |
PA | AES BEAVER VALLEY | 10676 | 032 | 144 |
PA | AES BEAVER VALLEY | 10676 | 033 | 131 |
PA | AES BEAVER VALLEY | 10676 | 034 | 133 |
PA | AES BEAVER VALLEY | 10676 | 035 | 67 |
PA | ARMSTRONG | 3178 | 1 | 363 |
PA | ARMSTRONG | 3178 | 2 | 383 |
PA | BRUCE MANSFIELD | 6094 | 1 | 1,657 |
PA | BRUCE MANSFIELD | 6094 | 2 | 1,672 |
PA | BRUCE MANSFIELD | 6094 | 3 | 1,636 |
PA | BRUNNER ISLAND | 3140 | 1 | 568 |
PA | BRUNNER ISLAND | 3140 | 2 | 718 |
PA | BRUNNER ISLAND | 3140 | 3 | 1,539 |
PA | BRUNOT ISLAND | 3096 | 2A | 0 |
PA | BRUNOT ISLAND | 3096 | 2B | 0 |
PA | BRUNOT ISLAND | 3096 | 3 | 0 |
PA | CAMBRIA COGEN | 10641 | 1 | 155 |
PA | CAMBRIA COGEN | 10641 | 2 | 161 |
PA | CHESWICK | 8226 | 1 | 1,119 |
PA | COLVER POWER PROJECT | 10143 | 1 | 291 |
PA | CONEMAUGH | 3118 | 1 | 2,167 |
PA | CONEMAUGH | 3118 | 2 | 1,995 |
PA | CROMBY | 3159 | 1 | 377 |
PA | CROMBY | 3159 | 2 | 201 |
PA | DELAWARE | 3160 | 71 | 61 |
PA | DELAWARE | 3160 | 81 | 56 |
PA | EBENSBURG POWER | 10603 | 1 | 191 |
PA | EDDYSTONE | 3161 | 1 | 565 |
PA | EDDYSTONE | 3161 | 2 | 636 |
PA | EDDYSTONE | 3161 | 3 | 207 |
PA | EDDYSTONE | 3161 | 4 | 237 |
PA | ELRAMA | 3098 | 1 | 214 |
PA | ELRAMA | 3098 | 2 | 209 |
PA | ELRAMA | 3098 | 3 | 208 |
PA | ELRAMA | 3098 | 4 | 428 |
PA | FOSTER WHEELER MT. CARMEL | 10343 | AB_NUG | 152 |
PA | GILBERTON POWER NUG | 010113 | AB_NUG | 273 |
PA | GPU GENCO WAYNE | 3134 | 1 | 8 |
PA | HATFIELD’S FERRY | 3179 | 1 | 1,155 |
PA | HATFIELD’S FERRY | 3179 | 2 | 1,029 |
PA | HATFIELD’S FERRY | 3179 | 3 | 1,087 |
PA | HOLTWOOD | 3145 | 17 | 246 |
PA | HOMER CITY | 3122 | 1 | 1,471 |
PA | HOMER CITY | 3122 | 2 | 1,553 |
PA | HOMER CITY | 3122 | 3 | 1,437 |
PA | HUNLOCK PWR STATION | 3176 | 6 | 131 |
PA | KEYSTONE | 3136 | 1 | 2,154 |
PA | KEYSTONE | 3136 | 2 | 2,133 |
PA | KIMBERLY-CLARK | 3157 | 10 | 211 |
PA | MARTINS CREEK | 3148 | 1 | 314 |
PA | MARTINS CREEK | 3148 | 2 | 293 |
PA | MARTINS CREEK | 3148 | 3 | 543 |
PA | MARTINS CREEK | 3148 | 4 | 500 |
PA | MITCHELL | 3181 | 1 | 10 |
PA | MITCHELL | 3181 | 2 | 6 |
PA | MITCHELL | 3181 | 3 | 9 |
PA | MITCHELL | 3181 | 33 | 556 |
PA | MONTOUR | 3149 | 1 | 1,560 |
PA | MONTOUR | 3149 | 2 | 1,673 |
PA | MOUNTAIN | 3111 | 1 | 5 |
PA | MOUNTAIN | 3111 | 2 | 5 |
PA | NEW CASTLE | 3138 | 3 | 190 |
PA | NEW CASTLE | 3138 | 4 | 195 |
PA | NEW CASTLE | 3138 | 5 | 245 |
PA | NORCON POWER PARTNERS LP | 54571 | 1 | 103 |
PA | NORCON POWER PARTNERS LP | 54571 | 2 | 109 |
PA | NORTHAMPTION GENERATING | 50888 | 1 | 291 |
PA | NORTHEASTERN POWER | 50039 | 188 | |
PA | PANTHER CREEK | 50776 | 1 | 134 |
PA | PANTHER CREEK | 50776 | 2 | 130 |
PA | PECO ENERGY CROYDEN | 8012 | 11 | 11 |
PA | PECO ENERGY CROYDEN | 8012 | 12 | 9 |
PA | PECO ENERGY CROYDEN | 8012 | 21 | 5 |
PA | PECO ENERGY CROYDEN | 8012 | 22 | 11 |
PA | PECO ENERGY CROYDEN | 8012 | 31 | 13 |
PA | PECO ENERGY CROYDEN | 8012 | 32 | 6 |
PA | PECO ENERGY CROYDEN | 8012 | 41 | 11 |
PA | PECO ENERGY CROYDEN | 8012 | 42 | 9 |
PA | PECO ENERGY RICHMOND | 3168 | 91 | 10 |
PA | PECO ENERGY RICHMOND | 3168 | 92 | 9 |
PA | PHILLIPS POWER STATION | 3099 | 3 | 0 |
PA | PHILLIPS POWER STATION | 3099 | 4 | 0 |
PA | PHILLIPS POWER STATION | 3099 | 5 | 0 |
PA | PHILLIPS POWER STATION | 3099 | 6 | 0 |
PA | PINEY CREEK | 54144 | 1 | 102 |
PA | PORTLAND | 3113 | – 5 | 48 |
PA | PORTLAND | 3113 | 1 | 266 |
PA | PORTLAND | 3113 | 2 | 412 |
PA | SCHUYLKILL | 3169 | 1 | 84 |
PA | SCHUYLKILL ENERGY RESOURCES | 880010 | 1 | 289 |
PA | SCHUYLKILL STATION (TURBI | 50607 | AB_NUG | 701 |
PA | SCRUBGRASS GENERATING PLANT | 50974 | 1 | 124 |
PA | SCRUBGRASS GENERATING PLANT | 50974 | 2 | 123 |
PA | SEWARD | 3130 | 12 | 64 |
PA | SEWARD | 3130 | 14 | 72 |
PA | SEWARD | 3130 | 15 | 355 |
PA | SHAWVILLE | 3131 | 1 | 295 |
PA | SHAWVILLE | 3131 | 2 | 294 |
PA | SHAWVILLE | 3131 | 3 | 380 |
PA | SHAWVILLE | 3131 | 4 | 392 |
PA | SUNBURY | 3152 | 1A | 134 |
PA | SUNBURY | 3152 | 1B | 122 |
PA | SUNBURY | 3152 | 2A | 130 |
PA | SUNBURY | 3152 | 2B | 134 |
PA | SUNBURY | 3152 | 3 | 263 |
PA | SUNBURY | 3152 | 4 | 302 |
PA | TITUS | 3115 | 1 | 161 |
PA | TITUS | 3115 | 2 | 152 |
PA | TITUS | 3115 | 3 | 151 |
PA | TOLNA | 3116 | 1 | 3 |
PA | TOLNA | 3116 | 2 | 4 |
PA | TRIGEN ENERGY SANSOM | 880006 | 1 | 12 |
PA | TRIGEN ENERGY SANSOM | 880006 | 2 | 10 |
PA | TRIGEN ENERGY SANSOM | 880006 | 3 | 5 |
PA | TRIGEN ENERGY SANSOM | 880006 | 4 | 6 |
PA | WARREN | 3132 | 1 | 47 |
PA | WARREN | 3132 | 2 | 32 |
PA | WARREN | 3132 | 3 | 40 |
PA | WARREN | 3132 | 4 | 42 |
PA | WARREN | 3132 | CT1 | 14 |
PA | WESTWOOD ENERGY PROPERTIE | 50611 | 031 | 98 |
PA | WHEELABRATOR FRACKVILLE E | 50879 | GEN1 | 161 |
PA | WILLIAMS GEN – HAZELTON | 10870 | HRSG | 16 |
PA | WILLIAMS GEN – HAZELTON | 10870 | TURBN | 141 |
VA | BELLMEADE | 7696 | 1 | 76 |
VA | BELLMEADE | 7696 | 2 | 88 |
VA | BREMO BLUFF | 3796 | 3 | 137 |
VA | BREMO BLUFF | 3796 | 4 | 386 |
VA | CHESAPEAKE | 3803 | 1 | 298 |
VA | CHESAPEAKE | 3803 | 2 | 308 |
VA | CHESAPEAKE | 3803 | 3 | 370 |
VA | CHESAPEAKE | 3803 | 4 | 571 |
VA | CHESAPEAKE CORP. | 10017 | ST_rp. | 59 |
VA | CHESTERFIELD | 3797 | – 8 | 263 |
VA | CHESTERFIELD | 3797 | 3 | 232 |
VA | CHESTERFIELD | 3797 | 4 | 389 |
VA | CHESTERFIELD | 3797 | 5 | 769 |
VA | CHESTERFIELD | 3797 | 6 | 1,348 |
VA | CHESTERFIELD | 3797 | 7 | 316 |
VA | CLINCH RIVER | 3775 | 1 | 548 |
VA | CLINCH RIVER | 3775 | 2 | 520 |
VA | CLINCH RIVER | 3775 | 3 | 575 |
VA | CLOVER | 7213 | 1 | 1,033 |
VA | CLOVER | 7213 | 2 | 1,118 |
VA | COGENTRIX – HOPEWELL | 10377 | ST_ell | 327 |
VA | COGENTRIX – PORTSMOUTH | 10071 | ST_uth | 356 |
VA | COGENTRIX RICHMOND 1 | 54081 | ST_d 1 | 299 |
VA | COGENTRIX RICHMOND 2 | 54081 | ST_d 2 | 209 |
VA | COMMONWEALTH ATLANTIC LP | 52087 | GT_LP | 35 |
VA | DARBYTOWN | 7212 | – 1 | 29 |
VA | DARBYTOWN | 7212 | – 2 | 28 |
VA | DARBYTOWN | 7212 | – 3 | 30 |
VA | DARBYTOWN | 7212 | – 4 | 29 |
VA | DOSWELL #1 | 52019 | CA_#1 | 46 |
VA | DOSWELL #1 | 52019 | CT_#1 | 94 |
VA | DOSWELL #2 | 52019 | CA_#2 | 46 |
VA | DOSWELL #2 | 52019 | CT_#2 | 94 |
VA | GLEN LYN | 3776 | 51 | 101 |
VA | GLEN LYN | 3776 | 52 | 110 |
VA | GLEN LYN | 3776 | 6 | 487 |
VA | GORDONSVILLE 1 | 54844 | CA_e 1 | 16 |
VA | GORDONSVILLE 1 | 54844 | CT_e 1 | 33 |
VA | GORDONSVILLE 2 | 54844 | CA_Xe 2 | 17 |
VA | GORDONSVILLE 2 | 54844 | CT_e 2 | 34 |
VA | GRAVEL NECK | 7032 | – 3 | 21 |
VA | GRAVEL NECK | 7032 | – X4 | 24 |
VA | GRAVEL NECK | 7032 | – 5 | 14 |
VA | GRAVEL NECK | 7032 | – 6 | 18 |
VA | HOPEWELL COGEN, INC. | 10633 | CT_nc. | 102 |
VA | HOPEWELL COGEN, INC. | 10633 | CW_nc. | 53 |
VA | LG&E-WESTMORELAND ALTAVISTA | 10773 | 1 | 18 |
VA | LG&E-WESTMORELAND ALTAVISTA | 10773 | 2 | 18 |
VA | LG&E-WESTMORELAND HOPEWELL | 10771 | 1 | 17 |
VA | LG&E-WESTMORELAND HOPEWELL | 10771 | 2 | 16 |
VA | LG&E-WESTMORELAND SOUTHAMPTON | 10774 | 1 | 23 |
VA | LG&E-WESTMORELAND SOUTHAMPTON | 10774 | 2 | 29 |
VA | MECKLENBURG | 52007 | ST_urg | 234 |
VA | POSSUM POINT | 3804 | 3 | 221 |
VA | POSSUM POINT | 3804 | 4 | 528 |
VA | POSSUM POINT | 3804 | 5 | 322 |
VA | POTOMAC RIVER | 3788 | 1 | 203 |
VA | POTOMAC RIVER | 3788 | 2 | 139 |
VA | POTOMAC RIVER | 3788 | 3 | 232 |
VA | POTOMAC RIVER | 3788 | 4 | 223 |
VA | POTOMAC RIVER | 3788 | 5 | 222 |
VA | SEI BIRCHWOOD | 12 | 1 | 305 |
VA | TASLEY | 3785 | 10 | 6 |
VA | YORKTOWN | 3809 | 1 | 386 |
VA | YORKTOWN | 3809 | 2 | 419 |
VA | YORKTOWN | 3809 | 3 | 764 |
WV | ALBRIGHT | 3942 | 1 | 76 |
WV | ALBRIGHT | 3942 | 2 | 71 |
WV | ALBRIGHT | 3942 | 3 | 241 |
WV | FORT MARTIN | 3943 | 1 | 887 |
WV | FORT MARTIN | 3943 | 2 | 868 |
WV | GRANT TOWN | 10151 | ST_own | 156 |
WV | HARRISON | 3944 | 1 | 1,385 |
WV | HARRISON | 3944 | 2 | 1,444 |
WV | HARRISON | 3944 | 3 | 1,505 |
WV | JOHN E AMOS | 3935 | 1 | 1,254 |
WV | JOHN E AMOS | 3935 | 2 | 1,198 |
WV | JOHN E AMOS | 3935 | 3 | 1,859 |
WV | KAMMER | 3947 | 1 | 399 |
WV | KAMMER | 3947 | 2 | 418 |
WV | KAMMER | 3947 | 3 | 447 |
WV | KANAWHA RIVER | 3936 | 1 | 336 |
WV | KANAWHA RIVER | 3936 | 2 | 323 |
WV | MITCHELL | 3948 | 1 | 1,288 |
WV | MITCHELL | 3948 | 2 | 1,191 |
WV | MORGANTOWN ENERGY ASSOCIATES | 27 | 1 | 80 |
WV | MORGANTOWN ENERGY ASSOCIATES | 27 | 2 | 80 |
WV | MOUNTAINEER (1301) | 6264 | 1 | 1,952 |
WV | MT STORM | 3954 | 1 | 1,048 |
WV | MT STORM | 3954 | 2 | 1,127 |
WV | MT STORM | 3954 | 3 | 1,236 |
WV | NORTH BRANCH | 7537 | 1A | 51 |
WV | NORTH BRANCH | 7537 | 1B | 53 |
WV | PHIL SPORN | 3938 | 11 | 239 |
WV | PHIL SPORN | 3938 | 21 | 215 |
WV | PHIL SPORN | 3938 | 31 | 239 |
WV | PHIL SPORN | 3938 | 41 | 230 |
WV | PHIL SPORN | 3938 | 51 | 708 |
WV | PLEASANTS | 6004 | 1 | 1,296 |
WV | PLEASANTS | 6004 | 2 | 1,165 |
WV | RIVESVILLE | 3945 | 7 | 38 |
WV | RIVESVILLE | 3945 | 8 | 88 |
WV | WILLOW ISLAND | 3946 | 1 | 79 |
WV | WILLOW ISLAND | 3946 | 2 | 246 |
Appendix B to Subpart E of Part 97 – Final Section 126 Rule: Non-EGU Allocations, 2004-2007
State | County | Plant | Plant ID | Point ID | NO |
---|---|---|---|---|---|
DC | Washington | GSA CENTRAL HEATING PLANT | 0025 | 003 | 0 |
DC | Washington | GSA CENTRAL HEATING PLANT | 0025 | 004 | 0 |
DC | Washington | GSA CENTRAL HEATING PLANT | 0025 | 005 | 0 |
DC | Washington | GSA CENTRAL HEATING PLANT | 0025 | 006 | 0 |
DC | Washington | GSA WEST HEATING PLANT | 0024 | 003 | 13 |
DC | Washington | GSA WEST HEATING PLANT | 0024 | 005 | 12 |
DE | Kent | KRAFT FOODS INC | 0007 | 001 | 0 |
DE | New Castle | MOTIVA ENTERPRISES (FORMERLY STAR ENTERPRISE, DELAWARE CITY PLANT) | 0016 | 002 | 102 |
DE | New Castle | MOTIVA ENTERPRISES (FORMERLY STAR ENTERPRISE, DELAWARE CITY PLANT) | 0016 | 012 | 118 |
KY | Boyd | ASHLAND OIL INC | 0004 | 061 | 23 |
KY | Lawrence | KENTUCKY POWER CO | 0003 | 004 | 0 |
MD | Baltimore | BETHLEHEM STEEL | 0147 | 016 | 75 |
MD | Baltimore | BETHLEHEM STEEL | 0147 | 017 | 75 |
MD | Baltimore | BETHLEHEM STEEL | 0147 | 018 | 75 |
MD | Baltimore | BETHLEHEM STEEL | 0147 | 019 | 75 |
MD | Allegany | WESTVACO | 0011 | 001 | 289 |
MD | Allegany | WESTVACO | 0011 | 002 | 373 |
MI | Wayne | DETROIT EDISON CO | B2810 | 0003 | 31 |
MI | Midland | DOW CHEMICAL USA | A4033 | 0401 | 6 |
MI | Midland | DOW CHEMICAL USA | A4033 | 0402 | 0 |
MI | Wayne | DSC LTD | B3680 | 0006 | 30 |
MI | Genesee | GENERAL MOTORS CORP | A1178 | 0501 | 63 |
MI | Genesee | GENERAL MOTORS CORP | A1178 | 0502 | 47 |
MI | Oakland | GENERAL MOTORS CORP | B4031 | 0506 | 22 |
MI | Genesee | GENERAL MOTORS CORP | A1178 | 0507 | 20 |
MI | Oakland | GENERAL MOTORS CORP | B4032 | 0510 | 4 |
MI | Kalamazoo | GEORGIA PACIFIC CORP | B4209 | 0005 | 6 |
MI | Kalamazoo | JAMES RIVER PAPER CO INC | B1678 | 0003 | 90 |
MI | Wayne | MARATHON OIL COMPANY | A9831 | 0001 | 109 |
MI | Allegan | MENASHA CORP | A0023 | 0024 | 71 |
MI | Allegan | MENASHA CORP | A0023 | 0025 | 69 |
MI | Ingham | MICHIGAN STATE UNIVERSITY | K3249 | 0053 | 110 |
MI | Ingham | MICHIGAN STATE UNIVERSITY | K3249 | 0054 | 118 |
MI | Ingham | MICHIGAN STATE UNIVERSITY | K3249 | 0055 | 77 |
MI | Ingham | MICHIGAN STATE UNIVERSITY | K3249 | 0056 | 73 |
MI | Washtenaw | THE REGENTS OF THE UNIVERSITY OF MICHIGAN | M0675 | 0001 | 40 |
MI | Washtenaw | THE REGENTS OF THE UNIVERSITY OF MICHIGAN | M0675 | 0002 | 37 |
MI | Oakland | WILLIAM BEAUMONT HOSPITAL | G5067 | 0010 | 0 |
MI | Oakland | WILLIAM BEAUMONT HOSPITAL | G5067 | 0011 | 0 |
NC | Haywood | BLUE RIDGE PAPER PRODUCTS INC | 0159 | 005 | 129 |
NC | Haywood | CHAMPION INT CORP | 0159 | 001 | 98 |
NC | Haywood | CHAMPION INT CORP | 0159 | 002 | 88 |
NC | Haywood | CHAMPION INT CORP | 0159 | 003 | 200 |
NC | Haywood | CHAMPION INT CORP | 0159 | 004 | 176 |
NC | Halifax | CHAMPION INTERNATIONAL CORP. ROANOKE RAP | 0007 | 001 | 340 |
NC | Guilford | CONE MILLS CORP – WHITE OAK PLANT | 0863 | 004 | 50 |
NC | Cabarrus | FIELDCREST – CANNON PLT 1 KANNAPOLIS | 0006 | 001 | 77 |
NC | Columbus | INTERNATIONAL PAPER: RIEGELWOOD | 0036 | 003 | 90 |
NC | Columbus | INTERNATIONAL PAPER: RIEGELWOOD | 0036 | 004 | 228 |
NC | Martin | WEYERHAEUSER PAPER CO. PLYMOUTH | 0069 | 001 | 265 |
NC | Craven | WEYERHAUSER COMPANY NEW BERN MILL | 0104 | 005 | 205 |
NC | Craven | WEYERHAEUSER COMPANY NEW BERN MILL | 0104 | 006 | 72 |
NC | Martin | WEYERHAEUSER COMPANY PLYMOUTH | 0069 | 009 | 25 |
NJ | Middlesex | BALL – INCON GLASS PACKAGING | 15035 | 001 | 46 |
NJ | Hudson | BEST FOODS CPC INTERNATIONAL I | 10003 | 003 | 27 |
NJ | Middlesex | CHEVRON U.S.A., INC | 15023 | 001 | 17 |
NJ | Middlesex | CHEVRON U.S.A., INC | 15023 | 043 | 55 |
NJ | Gloucester | COASTAL EAGLE POINT OIL COMPAN | 55004 | 001 | 3 |
NJ | Gloucester | COASTAL EAGLE POINT OIL COMPAN | 55004 | 038 | 11 |
NJ | Gloucester | COASTAL EAGLE POINT OIL COMPAN | 55004 | 039 | 11 |
NJ | Gloucester | COASTAL EAGLE POINT OIL COMPAN | 55004 | 040 | 11 |
NJ | Gloucester | COASTAL EAGLE POINT OIL COMPAN | 55004 | 064 | 38 |
NJ | Gloucester | COASTAL EAGLE POINT OIL COMPAN | 55004 | 123 | 37 |
NJ | Middlesex | DEGUSSA CORPORATION-METZ DIVIS | 15305 | 009 | 15 |
NJ | Union | EXXON CORPORATION | 40003 | 001 | 57 |
NJ | Union | EXXON CORPORATION | 40003 | 007 | 22 |
NJ | Union | EXXON CORPORATION | 40003 | 014 | 98 |
NJ | Union | EXXON CORPORATION | 40003 | 015 | 14 |
NJ | Middlesex | HERCULES INCORPORATED | 15017 | 001 | 38 |
NJ | Middlesex | HERCULES INCORPORATED | 15017 | 002 | 37 |
NJ | Warren | HOFFMAN LAROCHE INC | 85010 | 034 | 45 |
NJ | Mercer | HOMASCTE COMPANY | 60018 | 001 | 290 |
NJ | Mercer | HOMASCTE COMPANY | 60018 | 002 | 312 |
NJ | Passaic | INTERNATIONAL VEILING CORPORAT | 30098 | 001 | 22 |
NJ | Bergen | MALT PRODUCTS CORPORATION | 00322 | 001 | 27 |
NJ | Atlantic | MARINA ASSOCIATES | 70009 | 001 | 330 |
NJ | Atlantic | MARINA ASSOCIATES | 70009 | 002 | 329 |
NJ | Atlantic | MARINA ASSOCIATES | 70009 | 003 | 990 |
NJ | Union | MERCK & CO., INC | 40009 | 001 | 66 |
NJ | Union | MERCK & CO., INC | 40009 | 002 | 61 |
NJ | Union | MERCK & CO., INC | 40009 | 003 | 56 |
NJ | Union | MERCK & CO., INC | 40009 | 004 | 75 |
NJ | Union | MERCK & CO., INC | 40009 | 005 | 89 |
NJ | Union | MERCK & CO., INC | 40009 | 006 | 103 |
NJ | Gloucester | MOBIL OIL CORPORATION | 55006 | 001 | 54 |
NJ | Gloucester | MOBIL OIL CORPORATION | 55006 | 002 | 54 |
NJ | Gloucester | MOBIL OIL CORPORATION | 55006 | 003 | 54 |
NJ | Gloucester | MOBIL OIL CORPORATION | 55006 | 004 | 49 |
NJ | Gloucester | MOBIL OIL CORPORATION | 55006 | 005 | 16 |
NJ | Gloucester | MOBIL OIL CORPORATION | 55006 | 006 | 105 |
NJ | Gloucester | MOBIL OIL CORPORATION | 55006 | 027 | 0 |
NJ | Gloucester | MOBIL OIL CORPORATION | 55006 | 270 | 14 |
NJ | Monmouth | NESTLE CO., INC., THE | 20004 | 006 | 13 |
NJ | Monmouth | NESTLE CO., INC., THE | 20004 | 007 | 13 |
NJ | Middlesex | NEW JERSEY STEEL CORPORATION | 15076 | 001 | 18 |
NJ | Gloucester | PETROLEUM RECYCLING, INC | 55180 | 020 | 169 |
NJ | Atlantic | SCOTT PAPER COMPANY | 70011 | 002 | 89 |
NJ | Atlantic | SCOTT PAPER COMPANY | 70011 | 003 | 75 |
NJ | Atlantic | SCOTT PAPER COMPANY | 70011 | 004 | 99 |
NJ | Mercer | STONY BROOK REGIONAL SEWERAGE | 60248 | 001 | 55 |
NJ | Mercer | STONY BROOK REGIONAL SEWERAGE | 60248 | 002 | 55 |
NY | Kings | HUDSON AVENUE | 2496 | B71 | 19 |
NY | Kings | HUDSON AVENUE | 2496 | B72 | 19 |
NY | Kings | HUDSON AVENUE | 2496 | B81 | 19 |
NY | Kings | HUDSON AVENUE | 2496 | B82 | 19 |
NY | Queens | RAVENSWOOD-A-HOUSE | CE03 | B01 | 15 |
NY | Queens | RAVENSWOOD-A-HOUSE | CE03 | B02 | 15 |
NY | Queens | RAVENSWOOD-A-HOUSE | CE03 | B03 | 21 |
NY | Queens | RAVENSWOOD-A-HOUSE | CE03 | B04 | 21 |
OH | Butler | AK STEEL (FORMERLY ARMCO STEEL CO.) | 1409010006 | P009 | 66 |
OH | Butler | AK STEEL (FORMERLY ARMCO STEEL CO.) | 1409010006 | P010 | 66 |
OH | Butler | AK STEEL (FORMERLY ARMCO STEEL CO.) | 1409010006 | P011 | 66 |
OH | Butler | AK STEEL (FORMERLY ARMCO STEEL CO.) | 1409010006 | P012 | 66 |
OH | Stark | ASHLAND PETROLEUM COMPANY | 1576000301 | B015 | 18 |
OH | Lucas | BP OIL COMPANY, TOLEDO REFINERY | 0448020007 | B004 | 39 |
OH | Lucas | BP OIL COMPANY, TOLEDO REFINERY | 0448020007 | B020 | 102 |
OH | Montgomery | CARGILL INCORPORATED | 0857041124 | B004 | 133 |
OH | Montgomery | CARGILL INCORPORATED | 0857041124 | B006 | 1 |
OH | Butler | CHAMPION INTERNATIONAL CORP | 1409040212 | B010 | 267 |
OH | Summit | GOODYEAR TIRE & RUBBER COMPANY | 1677010193 | B001 | 101 |
OH | Summit | GOODYEAR TIRE & RUBBER COMPANY | 1677010193 | B002 | 108 |
OH | Hamilton | HENKEL CORP. – EMERY GROUP | 1431070035 | B027 | 209 |
OH | Cuyahoga | LTV STEEL COMPANY, INC | 1318001613 | B001 | 139 |
OH | Cuyahoga | LTV STEEL COMPANY, INC | 1318001613 | B002 | 150 |
OH | Cuyahoga | LTV STEEL COMPANY, INC | 1318001613 | B003 | 159 |
OH | Cuyahoga | LTV STEEL COMPANY, INC | 1318001613 | B004 | 158 |
OH | Cuyahoga | LTV STEEL COMPANY, INC | 1318001613 | B007 | 155 |
OH | Cuyahoga | LTV STEEL COMPANY, INC | 1318001613 | B905 | 14 |
OH | Ross | MEAD CORPORATION | 0671010028 | B001 | 185 |
OH | Ross | MEAD CORPORATION | 0671010028 | B002 | 208 |
OH | Ross | MEAD CORPORATION | 0671010028 | B003 | 251 |
OH | Scioto | NEW BOSTON COKE CORP | 0773010004 | B008 | 20 |
OH | Scioto | NEW BOSTON COKE CORP | 0773010004 | B009 | 15 |
OH | Hamilton | PROCTER & GAMBLE CO | 1431390903 | B021 | 72 |
OH | Hamilton | PROCTER & GAMBLE CO | 1431390903 | B022 | 296 |
OH | Lorain | REPUBLIC ENGINEERED STEELS, INC. (FORMERLY USS/KOBE STEEL – LORAIN WORKS) | 0247080229 | B013 | 159 |
OH | Lawrence | SOUTH POINT ETHANOL | 0744000009 | B003 | 107 |
OH | Lawrence | SOUTH POINT ETHANOL | 0744000009 | B004 | 107 |
OH | Lawrence | SOUTH POINT ETHANOL | 0744000009 | B007 | 107 |
OH | Lucas | SUN REFINING & MARKETING CO, TOLEDO REF | 0448010246 | B044 | 47 |
OH | Lucas | SUN REFINING & MARKETING CO, TOLEDO REF | 0448010246 | B046 | 34 |
OH | Lucas | SUN REFINING & MARKETING CO, TOLEDO REF | 0448010246 | B047 | 18 |
OH | Trumbull | W C I STEEL, INC | 0278000463 | B001 | 113 |
OH | Trumbull | W C I STEEL, INC | 0278000463 | B004 | 142 |
PA | Northampton | BETHLEHEM STEEL CORP | 0048 | 041 | 100 |
PA | Northampton | BETHLEHEM STEEL CORP | 0048 | 042 | 66 |
PA | Northampton | BETHLEHEM STEEL CORP | 0048 | 067 | 165 |
PA | Armstrong | BMG ASPHALT CO | 0004 | 101 | 0 |
PA | Erie | GENERAL ELECTRIC | 0009 | 032 | 16 |
PA | York | GLATFELTER, P. H. CO | 0016 | 031 | 0 |
PA | York | GLATFELTER, P. H. CO | 0016 | 034 | 137 |
PA | York | GLATFELTER, P. H. CO | 0016 | 035 | 112 |
PA | York | GLATFELTER, P. H. CO | 0016 | 036 | 211 |
PA | Clinton | INTERNATIONAL PAPER: LOCKHAVEN | 0008 | 033 | 101 |
PA | Clinton | INTERNATIONAL PAPER: LOCKHAVEN | 0008 | 034 | 90 |
PA | Delaware | KIMBERLY CLARK (FORMERLY SCOTT PAPER CO.) | 0016 | 034 | 1 |
PA | Delaware | KIMBERLY CLARK (FORMERLY SCOTT PAPER CO.) | 0016 | 035 | 345 |
PA | Allegheny | LTV STEEL COMPANY – PITTSBURGH WORKS | 0022 | 015 | 25 |
PA | Allegheny | LTV STEEL COMPANY – PITTSBURGH WORKS | 0022 | 017 | 15 |
PA | Allegheny | LTV STEEL COMPANY – PITTSBURGH WORKS | 0022 | 019 | 29 |
PA | Allegheny | LTV STEEL COMPANY – PITTSBURGH WORKS | 0022 | 021 | 55 |
PA | Montgomery | MERCK SHARP & DOHME | 0028 | 039 | 126 |
PA | Westmoreland | MONESSEN INC | 0007 | 031 | 0 |
PA | Bucks | PECO | 0055 | 043 | 15 |
PA | Bucks | PECO | 0055 | 045 | 32 |
PA | Bucks | PECO | 0055 | 044 | 77 |
PA | Wyoming | PROCTER & GAMBLE CO | 0009 | 035 | 187 |
PA | Allegheny | SHENANGO IRON & COKE WORKS | 0050 | 006 | 18 |
PA | Allegheny | SHENANGO IRON & COKE WORKS | 0050 | 009 | 15 |
PA | Delaware | SUN REFINING & MARKETING CO | 0025 | 089 | 102 |
PA | Delaware | SUN REFINING & MARKETING CO | 0025 | 090 | 163 |
PA | Philadelphia | SUN REFINING AND MARKETING 1 O | 1501 | 020 | 49 |
PA | Philadelphia | SUN REFINING AND MARKETING 1 O | 1501 | 021 | 83 |
PA | Philadelphia | SUN REFINING AND MARKETING 1 O | 1501 | 022 | 105 |
PA | Philadelphia | SUN REFINING AND MARKETING 1 O | 1501 | 023 | 127 |
PA | Philadelphia | SUNOCO (FORMERLY ALLIED CHEMICAL CORP) | 1551 | 052 | 86 |
PA | Perry | TEXAS EASTERN GAS PIPELINE COMPANY | 0001 | 031 | 0 |
PA | Berks | TEXAS EASTERN GAS PIPELINE COMPANY | 0087 | 031 | 98 |
PA | Delaware | TOSCO REFINING (FORMERLY BP OIL, INC.) | 0030 | 032 | 71 |
PA | Delaware | TOSCO REFINING (FORMERLY BP OIL, INC.) | 0030 | 033 | 80 |
PA | Philadelphia | U.S. NAVAL BASE | 9702 | 016 | 0 |
PA | Philadelphia | U.S. NAVAL BASE | 9702 | 017 | 1 |
PA | Philadelphia | U.S. NAVAL BASE | 9702 | 098 | 0 |
PA | Philadelphia | U.S. NAVAL BASE | 9702 | 099 | 0 |
PA | Elk | WILLAMETTE INDUSTRIES (FORMERLY PENNTECH PAPERS, INC | 0005 | 040 | 90 |
PA | Elk | WILLAMETTE INDUSTRIES (FORMERLY PENNTECH PAPERS, INC | 0005 | 041 | 89 |
PA | Beaver | ZINC CORPORATION OF AMERICA | 0032 | 034 | 176 |
PA | Beaver | ZINC CORPORATION OF AMERICA | 0032 | 035 | 180 |
VA | Hopewell | ALLIED-SIGNAL INC | 0026 | 002 | 499 |
VA | York | AMOCO OIL CO | 0004 | 001 | 25 |
VA | Giles | CELANESE ACETATE LLC (FORMERLY HOECHST CELANESE CORP) | 0004 | 007 | 148 |
VA | Giles | CELANESE ACETATE LLC (FORMERLY HOECHST CELANESE CORP) | 0004 | 014 | 56 |
VA | Pittsylvania | DAN RIVER INC. (SCHOOLFIELD DIV) | 0002 | 003 | 49 |
VA | Bedford | GEORGIA-PACIFIC – BIG ISLAND MILL | 0003 | 002 | 86 |
VA | Isle Of Wight | INTERNATIONAL PAPER – FRANKLIN (FORMERLY UNION CAMP CORP/FINE PAPER DIV) | 0006 | 003 | 272 |
VA | Hopewell | JAMES RIVER COGENERATION (COGE | 0055 | 001 | 511 |
VA | Hopewell | JAMES RIVER COGENERATION (COGE | 0055 | 002 | 512 |
VA | King William | ST. LAURENT PAPER PRODUCTS CORP. | 0001 | 003 | 253 |
VA | Alleghany | WESTVACO CORP | 0003 | 001 | 253 |
VA | Alleghany | WESTVACO CORP | 0003 | 002 | 130 |
VA | Alleghany | WESTVACO CORP | 0003 | 003 | 195 |
VA | Alleghany | WESTVACO CORP | 0003 | 004 | 373 |
VA | Alleghany | WESTVACO CORP | 0003 | 005 | 170 |
VA | Alleghany | WESTVACO CORP | 0003 | 011 | 105 |
WV | Kanawha | AVENTIS CROPSCIENCE | 00007 | 010 | 113 |
WV | Kanawha | AVENTIS CROPSCIENCE | 00007 | 011 | 102 |
WV | Kanawha | AVENTIS CROPSCIENCE | 00007 | 012 | 105 |
WV | Kanawha | DUPONT – BELLE | 00001 | 612 | 54 |
WV | Fayette | ELKEM METALS COMPANY L.P. – ALLOY P PLANT | 00001 | 006 | 116 |
WV | Marshall | PPG INDUSTRIES, INC | 00002 | 001 | 195 |
WV | Marshall | PPG INDUSTRIES, INC | 00002 | 003 | 419 |
WV | Kanawha | RHONE-POLUENC | 00007 | 070 | 8 |
WV | Kanawha | RHONE-POLUENC | 00007 | 071 | 73 |
WV | Kanawha | RHONE-POLUENC | 00007 | 080 | 7 |
WV | Kanawha | RHONE-POLUENC | 00007 | 081 | 66 |
WV | Kanawha | RHONE-POLUENC | 00007 | 090 | 8 |
WV | Kanawha | RHONE-POLUENC | 00007 | 091 | 68 |
WV | Kanawha | UNION CARBIDE – SOUTH CHARLESTON PLANT | 00003 | 0B6 | 66 |
WV | Kanawha | UNION CARBIDE – SOUTH CHARLESTON PLANT | 0003 | 0B6 | 92 |
WV | Kanawha | UNION CARBIDE – SOUTH CHARLESTON PLANT | 0003 | 0B7 | 45 |
WV | Hancock | WEIRTON STEEL CORPORATION | 00001 | 030 | 31 |
WV | Hancock | WEIRTON STEEL CORPORATION | 00001 | 088 | 30 |
WV | Hancock | WEIRTON STEEL CORPORATION | 00001 | 089 | 2 |
WV | Hancock | WEIRTON STEEL CORPORATION | 00001 | 090 | 110 |
WV | Hancock | WEIRTON STEEL CORPORATION | 00001 | 091 | 253 |
WV | Hancock | WEIRTON STEEL CORPORATION | 00001 | 092 | 208 |
WV | Hancock | WEIRTON STEEL CORPORATION | 00001 | 093 | 200 |
Appendix C to Subpart E of Part 97 – Final Section 126 Rule: Trading Budget
ST | F126-EGU | F126-NEGU | Total |
---|---|---|---|
DC | 207 | 26 | 233 |
DE | 4,306 | 232 | 4,538 |
IN | 7,088 | 82 | 7,170 |
KY | 19,654 | 53 | 19,707 |
MD | 14,519 | 1,013 | 15,532 |
MI | 25,689 | 2,166 | 27,855 |
NC | 31,212 | 2,329 | 33,541 |
NJ | 9,716 | 4,838 | 14,554 |
NY | 16,081 | 156 | 16,237 |
OH | 45,432 | 4,103 | 49,535 |
PA | 47,224 | 3,619 | 50,843 |
VA | 17,091 | 4,104 | 21,195 |
WV | 26,859 | 2,184 | 29,043 |
Total | 265,078 | 24,905 | 289,983 |
Appendix D to Subpart E of Part 97 – Final Section 126 Rule: State Compliance supplement pools for the Section 126 Final Rule (Tons)
State | Compliance supplement pool |
---|---|
Delaware | 168 |
District of Columbia | 0 |
Indiana | 2,454 |
Kentucky | 7,314 |
Maryland | 3,882 |
Michigan | 9,398 |
New Jersey | 1,550 |
New York | 1,379 |
North Carolina | 10,737 |
Ohio | 22,301 |
Pennsylvania | 15,763 |
Virginia | 5,504 |
West Virginia | 16,709 |
Total | 97,159 |
Subpart F – NOX Allowance Tracking System
§ 97.50 NOX Allowance Tracking System accounts.
(a) Nature and function of compliance accounts and overdraft accounts. Consistent with § 97.51(a), the Administrator will establish one compliance account for each NO
(b) Nature and function of general accounts. Consistent with § 97.51(b), the Administrator will establish, upon request, a general account for any person. Allocations of NO
§ 97.51 Establishment of accounts.
(a) Compliance accounts and overdraft accounts. Upon receipt of a complete account certificate of representation under § 97.13, the Administrator will establish:
(1) A compliance account for each NO
(2) An overdraft account for each source for which the account certificate of representation was submitted and that has two or more NO
(b) General accounts – (1) Application for general account. (i) Any person may apply to open a general account for the purpose of holding and transferring allowances. An application for a general account may designate one and only one NO
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the NO
(B) At the option of the NO
(C) A list of all persons subject to a binding agreement for the NO
(D) The following certification statement by the NO
(E) The signature of the NO
(ii) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2) Authorization of NO
(i) The Administrator will establish a general account for the person or persons for whom the application is submitted.
(ii) The NO
(iii) Any representation, action, inaction, or submission by any alternate NO
(iv) Each submission concerning the general account shall be submitted, signed, and certified by the NO
(v) The Administrator will accept or act on a submission concerning the general account only if the submission has been made, signed, and certified in accordance with paragraph (b)(2)(iv) of this section.
(3) Changing NO
(ii) The alternate NO
(iii)(A) In the event a new person having an ownership interest with respect to NO
(B) Within 30 days following any change in the persons having an ownership interest with respect to NO
(4) Objections concerning NO
(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the NO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the NO
(c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of this section.
(a) Following the establishment of a NO
(b) Authorized account representative identification. The Administrator will assign a unique identifying number to each NO
§ 97.53 Recordation of NOX allowance allocations.
(a) The Administrator will record the NO
(b) By May 1, 2003, the Administrator will record the NO
(c) By May 1, 2003, the Administrator will record the NO
(d) By May 1, 2004, the Administrator will record the NO
(e) Each year starting with 2005, after the Administrator has made all deductions from a NO
(1) NO
(2) NO
(3) NO
(f) Serial numbers for allocated NO
§ 97.54 Compliance.
(a) NO
(1) Were allocated for a control period in a prior year or the same year; and
(2) Are held in the unit’s compliance account, or the overdraft account of the source where the unit is located, as of the NO
(b) Deductions for compliance. (1) Following the recordation, in accordance with § 97.61, of NO
(i) From the compliance account; and
(ii) Only if no more NO
(2) The Administrator will deduct NO
(i) Until the number of NO
(ii) Until no more NO
(c)(1) Identification of NO
(2) First-in, first-out. The Administrator will deduct NO
(i) Those NO
(ii) Those NO
(iii) Those NO
(iv) Those NO
(d) Deductions for excess emissions. (1) After making the deductions for compliance under paragraph (b) of this section, the Administrator will deduct from the unit’s compliance account or the overdraft account of the source where the unit is located a number of NO
(2) If the compliance account or overdraft account does not contain sufficient NO
(3) Any allowance deduction required under paragraph (d) of this section shall not affect the liability of the owners and operators of the NO
(i) For purposes of determining the number of days of violation, if a NO
(ii) Each ton of excess emissions is a separate violation.
(e) Deductions for units sharing a common stack. In the case of units sharing a common stack and having emissions that are not separately monitored or apportioned in accordance with subpart H of this part:
(1) The NO
(2) Notwithstanding paragraph (b)(2)(i) of this section, the Administrator will deduct NO
(f) Deduction of banked allowances. Each year starting in 2006, after the Administrator has completed the designation of banked NO
(1) The Administrator will determine the total number of banked NO
(2) If the total number of banked NO
(3) If the total number of banked NO
(i) The Administrator will determine the following ratio: 0.10 multiplied by the sum of the trading program budgets under § 97.40 for all States for the control period and divided by the total number of banked NO
(ii) The Administrator will multiply the number of banked NO
(g) Recordation of deductions. The Administrator will record in the appropriate compliance account or overdraft account all deductions from such an account pursuant to paragraph (b), (d), (e), or (f) of this section.
§ 97.55 Banking.
NO
(a) Any NO
(b) The Administrator will designate, as a “banked” NO
§ 97.56 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any NO
§ 97.57 Closing of general accounts.
(a) The NO
(b) If a general account shows no activity for a period of a year or more and does not contain any NO
Subpart G – NOX Allowance Transfers
§ 97.60 Submission of NOX allowance transfers.
The NO
(a) The numbers identifying both the transferor and transferee accounts;
(b) A specification by serial number of each NO
(c) The printed name and signature of the NO
§ 97.61 EPA recordation.
(a) Within 5 business days of receiving a NO
(1) The transfer is correctly submitted under § 97.60; and
(2) The transferor account includes each NO
(b) A NO
(c) Where a NO
§ 97.62 Notification.
(a) Notification of recordation. Within 5 business days of recordation of a NO
(b) Notification of non-recordation. Within 10 business days of receipt of a NO
(1) A decision not to record the transfer; and
(2) The reasons for such non-recordation.
(c) Nothing in this section shall preclude the submission of a NO
Subpart H – Monitoring and Reporting
§ 97.70 General requirements.
The owners and operators, and to the extent applicable, the NO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each NO
(1) Install all monitoring systems required under this subpart for monitoring NO
(2) Install all monitoring systems for monitoring heat input rate.
(3) Successfully complete all certification tests required under § 97.71 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraphs (a)(1) and (2) of this section.
(4) Record, report, and quality-assure the data from the monitoring systems under paragraphs (a)(1) and (2) of this section.
(b) Compliance deadlines. The owner or operator shall meet the certification and other requirements of paragraphs (a)(1) through (a)(3) of this section on or before the following dates. The owner or operator shall record, report and quality-assure the data from the monitoring systems under paragraphs (a)(1) and (a)(2) of this section on and after the following dates.
(1) For the owner or operator of a NO
(2) For the owner or operator of a NO
(3) For the owner or operator of a NO
(i) The earlier of 90 unit operating days after the date on which the unit commences commercial operation or 180 calendar days after the date on which the unit commences commercial operation; or
(ii) May 1, 2003, if the compliance date under paragraph (b)(3)(i) of this section is before May 1, 2003.
(4) For the owner or operator of a NO
(i) The earlier of 90 unit operating days or 180 calendar days after the date on which the unit commences commercial operation, if this compliance date is during a control period; or
(ii) May 1 immediately following the compliance date under paragraph (b)(4)(i) of this section, if such compliance date is not during a control period.
(5) For the owner or operator of a NO
(6) For the owner or operator of a NO
(i) The earlier of 90 unit operating days or 180 calendar days after the date on which emissions first exit to the atmosphere through the new stack or flue or add-on NO
(ii) May 1 immediately following the compliance date under paragraph (b)(6)(i) of this section, if such compliance date is not during a control period.
(7) For the owner or operator of a unit for which an application for a NO
(c) Commencement of data reporting. (1) The owner or operator of NO
(2) The owner or operator of a NO
(i) The date and hour on which the unit commences operation, if the date and hour on which the unit commences operation is during a control period; or
(ii) The first hour on May 1 of the first control period after the date and hour on which the unit commences operation, if the date and hour on which the unit commences operation is not during a control period.
(3) Notwithstanding paragraphs (c)(2)(i) and (c)(2)(ii) of this section, the owner or operator may begin reporting NO
(d) Prohibitions. (1) No owner or operator of a NO
(2) No owner or operator of a NO
(3) No owner or operator of a NO
(4) No owner or operator of a NO
(i) During the period that the unit is covered by an exemption under § 97.4(b) or § 97.5 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the permitting authority for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The NO
§ 97.71 Initial certification and recertification procedures.
(a) The owner or operator of a NO
(1) If, prior to January 1, 1998, the Administrator approved a petition under § 75.17(a) or (b) of this chapter for apportioning the NO
(2) For any additional CEMS required under the common stack provisions in § 75.72 of this chapter or for any NO
(b) The owner or operator of a NO
(1) Requirements for initial certification. The owner or operator shall ensure that each emission monitoring system required by subpart H of part 75 of this chapter (which includes the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.70(b). In addition, whenever the owner or operator installs an emission monitoring system in order to meet the requirements of this part in a location where no such emission monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in a certified emission monitoring system that may significantly affect the ability of the system to accurately measure or record NO
(3) Certification approval process for initial certification and recertification – (i) Notification of certification. The NO
(ii) Certification application. The NO
(iii) Except for units using the low mass emission excepted methodology under § 75.19 of this chapter, the provisional certification date for a monitor shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitor may be used under the NO
(iv) Certification application formal approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (b)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the NO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. A certification application will be considered complete when all of the applicable information required to be submitted under paragraph (b)(3)(ii) of this section has been received by the Administrator. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the NO
(C) Disapproval notice. If the certification application shows that any monitoring system or component thereof does not meet the performance requirements of this part, or if the certification application is incomplete and the requirement for disapproval under paragraph (b)(3)(iv)(B) of this section has been met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter). The owner or operator shall follow the procedures for loss of certification in paragraph (b)(3)(v) of this section for each monitoring system that is disapproved for initial certification.
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.72(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (b)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (b)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(b)(5), § 75.20(h)(4), or § 75.21(e) and continuing until the date and hour specified under § 75.20(a)(5)(i) of this chapter:
(1) For units that the owner or operator intends to monitor or monitors for NO
(2) For units that the owner or operator intends to monitor or monitors for NO
(B) The NO
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(c) Initial certification and recertification procedures for low mass emission units using the excepted methodologies under § 75.19 of this chapter. The owner or operator of a gas-fired or oil-fired unit using the low mass emissions excepted methodology under § 75.19 of this chapter and not subject to an Acid Rain emissions limitation shall meet the applicable general operating requirements of § 75.10 of this chapter and the applicable requirements of § 75.19 of this chapter. The owner or operator of such a unit shall also meet the applicable certification and recertification procedures of paragraph (b) of this section, except that the excepted methodology shall be deemed provisionally certified for use under the NO
(d) Certification/recertification procedures for alternative monitoring systems. The NO
§ 97.72 Out of control periods.
(a) Whenever any emission monitoring system fails to meet the quality assurance or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable procedures in subpart D, subpart H, appendix D, or appendix E of part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of an emission monitoring system and a review of the initial certification or recertification application reveal that any system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.71 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the permitting authority or the Administrator. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the system. The data measured and recorded by the system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the system. The owner or operator shall follow the initial certification or recertification procedures in § 97.71 for each disapproved system.
§ 97.73 Notifications.
(a) The NO
(b) For any unit that does not have an Acid Rain emissions limitation, the permitting authority may waive the requirement to notify the permitting authority in paragraph (a) of this section.
§ 97.74 Recordkeeping and reporting.
(a) General provisions. (1) The NO
(2) If the NO
(b) Monitoring plans. (1) The owner or operator of a unit subject to an Acid Rain emissions limitation shall comply with requirements of § 75.62 of this chapter, except that the monitoring plan shall also include all of the information required by subpart H of part 75 of this chapter.
(2) The owner or operator of a unit that is not subject to an Acid Rain emissions limitation shall comply with requirements of § 75.62 of this chapter, except that the monitoring plan is only required to include the information required by subpart H of part 75 of this chapter.
(c) Certification applications. The NO
(d) Quarterly reports. The NO
(1) If a unit is subject to an Acid Rain emission limitation or if the owner or operator of the NO
(i) For a unit for which the owner or operator intends to apply or applies for the early reduction credits under § 97.43, the calendar quarter that covers May 1, 2000 through June 30, 2000. The NO
(ii) For a unit that commences operation before January 1, 2003 and that is not subject to paragraph (d)(1)(i) of this section, the calendar quarter covering May 1, 2003 through June 30, 2003. The NO
(iii) For a unit that commences operation on or after January 1, 2003:
(A) The calendar quarter in which the unit commences operation, if unit operation commences during a control period. The NO
(B) The calendar quarter which includes May 1 through June 30 of the first control period following the date on which the unit commences operation, if the unit does not commence operation during a control period. The NO
(iv) A calendar quarter before the quarter specified in paragraph (d)(1)(i), (d)(1)(ii), or (d)(1)(iii)(B) of this section, if the owner or operator elects to begin reporting early under § 97.70(c)(3).
(2) If a NO
(i) Meet all of the requirements of part 75 related to monitoring and reporting NO
(ii) Submit quarterly reports, documenting NO
(A) For a unit for which the owner or operator intends to apply or applies for the early reduction credits under § 97.43, the calendar quarter that covers May 1, 2000 through June 30, 2000. The NO
(B) For a unit that commences operation before January 1, 2003 and that is not subject to paragraph (d)(2)(ii)(A) of this section, the calendar quarter covering May 1, 2003 through June 30, 2003. The NO
(C) For a unit that commences operation on or after January 1, 2003 and during a control period, the calendar quarter in which the unit commences operation. The NO
(D) For a unit that commences operation on or after January 1, 2003 and not during a control period, the calendar quarter which includes May 1 through June 30 of the first control period following the date on which the unit commences operation. The NO
(3) The NO
(i) For units subject to an Acid Rain emissions limitation, quarterly reports shall include all of the data and information required in subpart H of part 75 of this chapter for each NO
(ii) For units not subject to an Acid Rain emissions limitation, quarterly reports are only required to include all of the data and information required in subpart H of part 75 of this chapter for each NO
(4) Compliance certification. The NO
(i) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications;
(ii) For a unit with add-on NO
(iii) For a unit that is reporting on a control period basis under paragraph (d)(2)(ii) of this section, the NO
§ 97.75 Petitions.
(a) The NO
(b) Application of an alternative to any requirement of this subpart is in accordance with this subpart only to the extent that the petition is approved by the Administrator under § 75.66 of this chapter.
§ 97.76 Additional requirements to provide heat input data.
The owner or operator of a NO
Subpart I – Individual Unit Opt-ins
§ 97.80 Applicability.
A unit that is in a State (as defined in § 97.2), is not a NO
§ 97.81 General.
Except otherwise as provided in this part, a NO
A unit for which an application for a NO
§ 97.83 Applying for NOX Budget opt-in permit.
(a) Applying for initial NO
(1) A complete NO
(2) A monitoring plan submitted in accordance with subpart H of this part; and
(3) A complete account certificate of representation under § 97.13, if no NO
(b) Duty to reapply. Unless the NO
§ 97.84 Opt-in process.
The permitting authority will issue or deny an initial NO
(a) Interim review of monitoring plan. The Administrator will determine, on an interim basis, the sufficiency of the monitoring plan accompanying the initial application for a NO
(b) If the Administrator determines that the unit’s monitoring plan is sufficient under paragraph (a) of this section and after completion of monitoring system certification under subpart H of this part, the NO
(c) Based on the information monitored and reported under paragraph (b) of this section, the Administrator will calculate the unit’s baseline heat input, which will equal the unit’s total heat input (in mmBtu) for the control period, and the unit’s baseline NO
(d) Issuance of draft NO
(e) Not withstanding paragraphs (a) through (d) of this section, if at any time before issuance of a draft NO
(f) Withdrawal of application for NO
(g) The unit shall be a NO
§ 97.85 NOX Budget opt-in permit contents.
(a) Each NO
(b) Each NO
§ 97.86 Withdrawal from NOX Budget Trading Program.
(a) Requesting withdrawal. To withdraw from the NO
(b) Conditions for withdrawal. Before a NO
(1) For the control period immediately before the withdrawal is to be effective, the NO
(2) If the NO
(3) After the requirements for withdrawal under paragraphs (b)(1) and (2) of this section are met, the Administrator will deduct from the NO
(c) A NO
(d) Notification. (1) After the requirements for withdrawal under paragraphs (a) and (b) of this section are met (including deduction of the full amount of NO
(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the Administrator will issue a notification to the permitting authority and the NO
(e) Permit revision. After the Administrator issues a notification under paragraph (d)(1) of this section that the requirements for withdrawal have been met, the permitting authority will revise the NO
(f) Reapplication upon failure to meet conditions of withdrawal. If the Administrator denies the request to withdraw the NO
(g) Ability to return to the NO
§ 97.87 Change in regulatory status.
(a) Notification. When a NO
(b) Permitting authority’s and Administrator’s action. (1)(i) When the NO
(ii)(A) The Administrator will deduct from the compliance account for the NO
(1) Any NO
(2) If the effective date of the NO
(B) The NO
(iii)(A) For every control period during which the NO
(B) Notwithstanding paragraph (b)(1)(iii)(A) of this section, if the effective date of the NO
(2)(i) When the NO
(ii) After the deduction under paragraph (b)(2)(i) of this section is completed, the Administrator will close the NO
§ 97.88 NOX allowance allocations to opt-in units.
(a) NO
(2) By no later than April 1, after the first control period for which the NO
(3) The Administrator will make available to the public each determination of NO
(b) For each control period for which the NO
(1) The heat input (in mmBtu) used for calculating NO
(i) The unit’s baseline heat input determined pursuant to § 97.84(c); or
(ii) The unit’s heat input, as determined in accordance with subpart H of this part, for the control period in the year prior to the year of the control period for which the NO
(2) The Administrator will allocate NO
Subpart J – Appeal Procedures
§ 97.90 Appeal procedures.
The appeal procedures for the NO
Subpart AA – CAIR NOX Annual Trading Program General Provisions
§ 97.101 Purpose.
This subpart and subparts BB through II set forth the general provisions and the designated representative, permitting, allowance, monitoring, and opt-in provisions for the Federal Clean Air Interstate Rule (CAIR) NO
§ 97.102 Definitions.
The terms used in this subpart and subparts BB through II shall have the meanings set forth in this section as follows:
Account number means the identification number given by the Administrator to each CAIR NO
Acid Rain emissions limitation means a limitation on emissions of sulfur dioxide or nitrogen oxides under the Acid Rain Program.
Acid Rain Program means a multi-state sulfur dioxide and nitrogen oxides air pollution control and emission reduction program established by the Administrator under title IV of the CAA and parts 72 through 78 of this chapter.
Actual weighted average NO
(1) The sum of the products of the actual annual average NO
(2) The sum of the actual annual heat input (as determined in accordance with part 75 of this chapter) for all units in the NO
Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator’s duly authorized representative.
Allocate or allocation means, with regard to CAIR NO
Allowance transfer deadline means, for a control period, midnight of March 1 (if it is a business day), or midnight of the first business day thereafter (if March 1 is not a business day), immediately following the control period and is the deadline by which a CAIR NO
Alternate CAIR designated representative means, for a CAIR NO
Automated data acquisition and handling system or DAHS means that component of the continuous emission monitoring system, or other emissions monitoring system approved for use under subpart HH of this part, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by subpart HH of this part.
Biomass means –
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other nonmerchantable material, and that is;
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
Bottoming-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.
CAIR authorized account representative means, with regard to a general account, a responsible natural person who is authorized, in accordance with subparts BB, FF, and II of this part, to transfer and otherwise dispose of CAIR NO
CAIR designated representative means, for a CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR permit means the legally binding and federally enforceable written document, or portion of such document, issued by the permitting authority under subpart CC of this part, including any permit revisions, specifying the CAIR NO
CAIR SO
CAIR SO
Certifying official means:
(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, Federal, or other public agency, a principal executive officer or ranking elected official.
Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite.
Coal-derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.
Coal-fired means:
(1) Except for purposes of subpart EE of this part, combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during any year; or
(2) For purposes of subpart EE of this part, combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during a specified year.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine:
(1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after the calendar year in which the unit first produces electricity –
(i) For a topping-cycle cogeneration unit, (A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input;
(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel except biomass if the unit is a boiler.
Combustion turbine means:
(1) An enclosed device comprising a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the enclosed device under paragraph (1) of this definition is combined cycle, any associated duct burner, heat recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.105 and § 97.184(h).
(i) For a unit that is a CAIR NO
(ii) For a unit that is a CAIR NO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.105, for a unit that is not a CAIR NO
(i) For a unit with a date for commencement of commercial operation as defined in paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in paragraph (2) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
Commence operation means:
(1) To have begun any mechanical, chemical, or electronic process, including, with regard to a unit, start-up of a unit’s combustion chamber, except as provided in § 97.184(h).
(2) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source) after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the date of commencement of operation of the unit, which shall continue to be treated as the same unit.
(3) For a unit that is replaced by a unit at the same source (e.g., repowered) after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit’s date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1), (2), or (3) of this definition as appropriate, except as provided in § 97.184(h).
Common stack means a single flue through which emissions from 2 or more units are exhausted.
Compliance account means a CAIR NO
Continuous emission monitoring system or CEMS means the equipment required under subpart HH of this part to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of nitrogen oxides emissions, stack gas volumetric flow rate, stack gas moisture content, and oxygen or carbon dioxide concentration (as applicable), in a manner consistent with part 75 of this chapter. The following systems are the principal types of continuous emission monitoring systems required under subpart HH of this part:
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A nitrogen oxides concentration monitoring system, consisting of a NO
(3) A nitrogen oxides emission rate (or NO
(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(5) A carbon dioxide monitoring system, consisting of a CO
(6) An oxygen monitoring system, consisting of an O
Control period means the period beginning January 1 of a calendar year, except as provided in § 97.106(c)(2), and ending on December 31 of the same year, inclusive.
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the CAIR designated representative and as determined by the Administrator in accordance with subpart HH of this part.
Excess emissions means any ton of nitrogen oxides emitted by the CAIR NO
Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.
Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in any calendar year.
Fuel oil means any petroleum-based fuel (including diesel fuel or petroleum derivatives such as oil tar) and any recycled or blended petroleum products or petroleum by-products used as a fuel whether in a liquid, solid, or gaseous state.
General account means a CAIR NO
Generator means a device that produces electricity.
Gross electrical output means, with regard to a cogeneration unit, electricity made available for use, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Heat input means, with regard to a specified period of time, the product (in mmBtu/time) of the gross calorific value of the fuel (in Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the CAIR designated representative and determined by the Administrator in accordance with subpart HH of this part and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources.
Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Hg Budget Trading Program means a multi-state Hg air pollution control and emission reduction program approved and administered by the Administrator in accordance subpart HHHH of part 60 of this chapter and § 60.24(h)(6), or established by the Administrator under section 111 of the Clean Air Act, as a means of reducing national Hg emissions.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis as of the initial installation of the unit as specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the requirements of subpart HH of this part, including a continuous emissions monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.
Most stringent State or Federal NO
Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount as of such completion as specified by the person conducting the physical change.
Oil-fired means, for purposes of subpart EE of this part, combusting fuel oil for more than 15.0 percent of the annual heat input in a specified year and not qualifying as coal-fired.
Operator means any person who operates, controls, or supervises a CAIR NO
Owner means any of the following persons:
(1) With regard to a CAIR NO
(i) Any holder of any portion of the legal or equitable title in a CAIR NO
(ii) Any holder of a leasehold interest in a CAIR NO
(iii) Any purchaser of power from a CAIR NO
(2) With regard to any general account, any person who has an ownership interest with respect to the CAIR NO
Permitting authority means the State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to issue or revise permits to meet the requirements of the CAIR NO
Potential electrical output capacity means 33 percent of a unit’s maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the permitting authority or the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the permitting authority or the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to CAIR NO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.
Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent shutdown and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or shutdown unit (the replaced unit).
Repowered means, with regard to a unit, replacement of a coal-fired boiler with one of the following coal-fired technologies at the same source as the coal-fired boiler:
(1) Atmospheric or pressurized fluidized bed combustion;
(2) Integrated gasification combined cycle;
(3) Magnetohydrodynamics;
(4) Direct and indirect coal-fired turbines;
(5) Integrated gasification fuel cells; or
(6) As determined by the Administrator in consultation with the Secretary of Energy, a derivative of one or more of the technologies under paragraphs (1) through (5) of this definition and any other coal-fired technology capable of controlling multiple combustion emissions simultaneously with improved boiler or generation efficiency and with significantly greater waste reduction relative to the performance of technology in widespread commercial use as of January 1, 2005.
Sequential use of energy means:
(1) For a topping-cycle cogeneration unit, the use of reject heat from electricity production in a useful thermal energy application or process; or
(2) For a bottoming-cycle cogeneration unit, the use of reject heat from useful thermal energy application or process in electricity production.
Serial number means, for a CAIR NO
Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act.
Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. For purposes of section 502(c) of the Clean Air Act, a “source,” including a “source” with multiple units, shall be considered a single “facility.”
State means one of the States or the District of Columbia that is subject to the CAIR NO
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery. Compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Title V operating permit means a permit issued under title V of the Clean Air Act and part 70 or part 71 of this chapter.
Title V operating permit regulations means the regulations that the Administrator has approved or issued as meeting the requirements of title V of the Clean Air Act and part 70 or 71 of this chapter.
Ton means 2,000 pounds. For the purpose of determining compliance with the CAIR NO
Topping-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful power, including electricity, and at least some of the reject heat from the electricity production is then used to provide useful thermal energy.
Total energy input means, with regard to a cogeneration unit, total energy of all forms supplied to the cogeneration unit, excluding energy produced by the cogeneration unit itself. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:
Total energy output means, with regard to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.
Unit means a stationary, fossil-fuel-fired boiler or combustion turbine or other stationary, fossil-fuel-fired combustion device.
Unit operating day means a calendar day in which a unit combusts any fuel.
Unit operating hour or hour of unit operation means an hour in which a unit combusts any fuel.
Useful power means, with regard to a cogeneration unit, electricity or mechanical energy made available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means, with regard to a cogeneration unit, thermal energy that is:
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., thermal energy used by an absorption chiller).
Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.
§ 97.103 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart and subparts BB through II are defined as follows:
§ 97.104 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State shall be CAIR NO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a CAIR NO
(b) The units in a State that meet the requirements set forth in paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) of this section shall not be CAIR NO
(1)(i) Any unit that is a CAIR NO
(A) Qualifying as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and
(B) Not serving at any time, since the later of November 15, 1990 or the start-up of the unit’s combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit’s potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i) of this section for at least one calendar year, but subsequently no longer meets all such requirements, the unit shall become a CAIR NO
(2)(i) Any unit that is a CAIR NO
(A) Qualifying as a solid waste incineration unit; and
(B) With an average annual fuel consumption of non-fossil fuel for 1985-1987 exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any 3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).
(ii) Any unit that is a CAIR NO
(A) Qualifying as a solid waste incineration unit; and
(B) With an average annual fuel consumption of non-fossil fuel for the first 3 calendar years of operation exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any 3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste incineration unit and meets the requirements of paragraph (b)(2)(i) or (ii) of this section for at least 3 consecutive calendar years, but subsequently no longer meets all such requirements, the unit shall become a CAIR NO
(c) A certifying official of an owner or operator of any unit may petition the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CAIR NO
(1) Petition content. The petition shall be in writing and include the identification of the unit and the relevant facts about the unit. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying official: “I am authorized to make this submission on behalf of the owners and operators of the unit for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) Submission. The petition and any other documents provided in connection with the petition shall be submitted to the Director of the Clean Air Markets Division (or its successor), U.S. Environmental Protection Agency, who will act on the petition as the Administrator’s duly authorized representative.
(3) Response. The Administrator will issue a written response to the petition and may request supplemental information relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CAIR NO
§ 97.105 Retired unit exemption.
(a)(1) Any CAIR NO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the CAIR NO
(3) After receipt of the statement under paragraph (a)(2) of this section, the permitting authority will amend any permit under subpart CC of this part covering the source at which the unit is located to add the provisions and requirements of the exemption under paragraphs (a)(1) and (b) of this section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of this section shall not emit any nitrogen oxides, starting on the date that the exemption takes effect.
(2) The Administrator or the permitting authority will allocate CAIR NO
(3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(4) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the CAIR NO
(5) A unit exempt under paragraph (a) of this section and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under § 97.122 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2009 or the date on which the unit resumes operation.
(6) On the earlier of the following dates, a unit exempt under paragraph (a) of this section shall lose its exemption:
(i) The date on which the CAIR designated representative submits a CAIR permit application for the unit under paragraph (b)(5) of this section;
(ii) The date on which the CAIR designated representative is required under paragraph (b)(5) of this section to submit a CAIR permit application for the unit; or
(iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAIR permit application for the unit.
(7) For the purpose of applying monitoring, reporting, and recordkeeping requirements under subpart HH of this part, a unit that loses its exemption under paragraph (a) of this section shall be treated as a unit that commences commercial operation on the first date on which the unit resumes operation.
§ 97.106 Standard requirements.
(a) Permit requirements. (1) The CAIR designated representative of each CAIR NO
(i) Submit to the permitting authority a complete CAIR permit application under § 97.122 in accordance with the deadlines specified in § 97.121; and
(ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit.
(2) The owners and operators of each CAIR NO
(3) Except as provided in subpart II of this part, the owners and operators of a CAIR NO
(b) Monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the CAIR designated representative, of each CAIR NO
(2) The emissions measurements recorded and reported in accordance with subpart HH of this part shall be used to determine compliance by each CAIR NO
(c) Nitrogen oxides emission requirements. (1) As of the allowance transfer deadline for a control period, the owners and operators of each CAIR NO
(2) A CAIR NO
(3) A CAIR NO
(4) CAIR NO
(5) A CAIR NO
(6) A CAIR NO
(7) Upon recordation by the Administrator under subpart EE, FF, GG, or II of this part, every allocation, transfer, or deduction of a CAIR NO
(d) Excess emissions requirements. If a CAIR NO
(1) The owners and operators of the source and each CAIR NO
(2) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law.
(e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the CAIR NO
(i) The certificate of representation under § 97.113 for the CAIR designated representative for the source and each CAIR NO
(ii) All emissions monitoring information, in accordance with subpart HH of this part, provided that to the extent that subpart HH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR NO
(iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR NO
(2) The CAIR designated representative of a CAIR NO
(f) Liability. (1) Each CAIR NO
(2) Any provision of the CAIR NO
(3) Any provision of the CAIR NO
(g) Effect on other authorities. No provision of the CAIR NO
§ 97.107 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the CAIR NO
(b) Unless otherwise stated, any time period scheduled, under the CAIR NO
(c) Unless otherwise stated, if the final day of any time period, under the CAIR NO
§ 97.108 Appeal procedures.
The appeal procedures for decisions of the Administrator under the CAIR NO
Subpart BB – CAIR Designated Representative for CAIR NOX Sources
§ 97.110 Authorization and responsibilities of CAIR designated representative.
(a) Except as provided under § 97.111, each CAIR NO
(b) The CAIR designated representative of the CAIR NO
(c) Upon receipt by the Administrator of a complete certificate of representation under § 97.113, the CAIR designated representative of the source shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the CAIR NO
(d) No CAIR permit will be issued, no emissions data reports will be accepted, and no CAIR NO
(e)(1) Each submission under the CAIR NO
(2) The permitting authority and the Administrator will accept or act on a submission made on behalf of owner or operators of a CAIR NO
§ 97.111 Alternate CAIR designated representative.
(a) A certificate of representation under § 97.113 may designate one and only one alternate CAIR designated representative, who may act on behalf of the CAIR designated representative. The agreement by which the alternate CAIR designated representative is selected shall include a procedure for authorizing the alternate CAIR designated representative to act in lieu of the CAIR designated representative.
(b) Upon receipt by the Administrator of a complete certificate of representation under § 97.113, any representation, action, inaction, or submission by the alternate CAIR designated representative shall be deemed to be a representation, action, inaction, or submission by the CAIR designated representative.
(c) Except in this section and §§ 97.102, 97.110(a) and (d), 97.112, 97.113, 97.115, 97.151 and 97.182, whenever the term “CAIR designated representative” is used in subparts AA through II of this part, the term shall be construed to include the CAIR designated representative or any alternate CAIR designated representative.
§ 97.112 Changing CAIR designated representative and alternate CAIR designated representative; changes in owners and operators.
(a) Changing CAIR designated representative. The CAIR designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.113. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous CAIR designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new CAIR designated representative and the owners and operators of the CAIR NO
(b) Changing alternate CAIR designated representative. The alternate CAIR designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.113. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate CAIR designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate CAIR designated representative and the owners and operators of the CAIR NO
(c) Changes in owners and operators. (1) In the event an owner or operator of a CAIR NO
(2) Within 30 days following any change in the owners and operators of a CAIR NO
§ 97.113 Certificate of representation.
(a) A complete certificate of representation for a CAIR designated representative or an alternate CAIR designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the CAIR NO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the CAIR designated representative and any alternate CAIR designated representative.
(3) A list of the owners and operators of the CAIR NO
(4) The following certification statements by the CAIR designated representative and any alternate CAIR designated representative –
(i) “I certify that I was selected as the CAIR designated representative or alternate CAIR designated representative, as applicable, by an agreement binding on the owners and operators of the source and each CAIR NO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CAIR NO
(iii) “I certify that the owners and operators of the source and of each CAIR NO
(iv) Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a CAIR NO
(5) The signature of the CAIR designated representative and any alternate CAIR designated representative and the dates signed.
(b) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
§ 97.114 Objections concerning CAIR designated representative.
(a) Once a complete certificate of representation under § 97.113 has been submitted and received, the permitting authority and the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.113 is received by the Administrator.
(b) Except as provided in § 97.112(a) or (b), no objection or other communication submitted to the permitting authority or the Administrator concerning the authorization, or any representation, action, inaction, or submission, of the CAIR designated representative shall affect any representation, action, inaction, or submission of the CAIR designated representative or the finality of any decision or order by the permitting authority or the Administrator under the CAIR NO
(c) Neither the permitting authority nor the Administrator will adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any CAIR designated representative, including private legal disputes concerning the proceeds of CAIR NO
§ 97.115 Delegation by CAIR designated representative and alternate CAIR designated representative.
(a) A CAIR designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this part.
(b) An alternate CAIR designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this part.
(c) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the CAIR designated representative or alternate CAIR designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such CAIR designated representative or alternate CAIR designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such CAIR designated representative or alternate CAIR designated representative:
(i) “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a CAIR designated representative or alternate CAIR designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.115(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.115(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.115 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the CAIR designated representative or alternate CAIR designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such CAIR designated representative or alternate CAIR designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the CAIR designated representative or alternate CAIR designated representative submitting such notice of delegation.
Subpart CC – Permits
§ 97.120 General CAIR NOX Annual Trading Program permit requirements.
(a) For each CAIR NO
(b) Each CAIR permit shall contain, with regard to the CAIR NO
§ 97.121 Submission of CAIR permit applications.
(a) Duty to apply. The CAIR designated representative of any CAIR NO
(b) Duty to reapply. For a CAIR NO
§ 97.122 Information requirements for CAIR permit applications.
A complete CAIR permit application shall include the following elements concerning the CAIR NO
(a) Identification of the CAIR NO
(b) Identification of each CAIR NO
(c) The standard requirements under § 97.106.
§ 97.123 CAIR permit contents and term.
(a) Each CAIR permit will contain, in a format prescribed by the permitting authority, all elements required for a complete CAIR permit application under § 97.122.
(b) Each CAIR permit is deemed to incorporate automatically the definitions of terms under § 97.102 and, upon recordation by the Administrator under subpart EE, FF, GG, or II of this part, every allocation, transfer, or deduction of a CAIR NO
(c) The term of the CAIR permit will be set by the permitting authority, as necessary to facilitate coordination of the renewal of the CAIR permit with issuance, revision, or renewal of the CAIR NO
§ 97.124 CAIR permit revisions.
Except as provided in § 97.123(b), the permitting authority will revise the CAIR permit, as necessary, in accordance with the permitting authority’s title V operating permits regulations or the permitting authority’s regulations for other federally enforceable permits as applicable addressing permit revisions.
Subpart DD [Reserved]
Subpart EE – CAIR NOX Allowance Allocations
§ 97.140 State trading budgets.
The State trading budgets for annual allocations of CAIR NO
State | State trading budget for 2009-2014 (tons) | State trading budget for 2015 and thereafter (tons) |
---|---|---|
Alabama | 69,020 | 57,517 |
Delaware | 4,166 | 3,472 |
District of Columbia | 144 | 120 |
Florida | 99,445 | 82,871 |
Georgia | 66,321 | 55,268 |
Illinois | 76,230 | 63,525 |
Indiana | 108,935 | 90,779 |
Iowa | 32,692 | 27,243 |
Kentucky | 83,205 | 69,337 |
Louisiana | 35,512 | 29,593 |
Maryland | 27,724 | 23,104 |
Michigan | 65,304 | 54,420 |
Minnesota | 31,443 | 26,203 |
Mississippi | 17,807 | 14,839 |
Missouri | 59,871 | 49,892 |
New Jersey | 12,670 | 10,558 |
New York | 45,617 | 38,014 |
North Carolina | 62,183 | 51,819 |
Ohio | 108,667 | 90,556 |
Pennsylvania | 99,049 | 82,541 |
South Carolina | 32,662 | 27,219 |
Tennessee | 50,973 | 42,478 |
Texas | 181,014 | 150,845 |
Virginia | 36,074 | 30,062 |
West Virginia | 74,220 | 61,850 |
Wisconsin | 40,759 | 33,966 |
Total | 1,521,707 | 1,268,091 |
§ 97.141 Timing requirements for CAIR NOX allowance allocations.
(a) The Administrator will determine by order the CAIR NO
(b) By July 31, 2011 and July 31 of each year thereafter, the Administrator will determine by order the CAIR NO
(c) By July 31, 2009 and July 31 of each year thereafter, the Administrator will determine by order the CAIR NO
(d) The Administrator will make available to the public each determination of CAIR NO
§ 97.142 CAIR NOX allowance allocations.
(a)(1) The baseline heat input (in mmBtu) used with respect to CAIR NO
(i) For units commencing operation before January 1, 2001 the average of the 3 highest amounts of the unit’s adjusted control period heat input for 2000 through 2004, with the adjusted control period heat input for each year calculated as follows:
(A) If the unit is coal-fired during the year, the unit’s control period heat input for such year is multiplied by 100 percent;
(B) If the unit is oil-fired during the year, the unit’s control period heat input for such year is multiplied by 60 percent; and
(C) If the unit is not subject to paragraph (a)(1)(i)(A) or (B) of this section, the unit’s control period heat input for such year is multiplied by 40 percent.
(ii) For units commencing operation on or after January 1, 2001 and operating each calendar year during a period of 5 or more consecutive calendar years, the average of the 3 highest amounts of the unit’s total converted control period heat input over the first such 5 years.
(2)(i) A unit’s control period heat input, and a unit’s status as coal-fired or oil-fired, for a calendar year under paragraph (a)(1)(i) of this section, and a unit’s total tons of NO
(ii) A unit’s converted control period heat input for a calendar year specified under paragraph (a)(1)(ii) of this section equals:
(A) Except as provided in paragraph (a)(2)(ii)(B) or (C) of this section, the control period gross electrical output of the generator or generators served by the unit multiplied by 7,900 Btu/kWh, if the unit is coal-fired for the year, or 6,675 Btu/kWh, if the unit is not coal-fired for the year, and divided by 1,000,000 Btu/mmBtu, provided that if a generator is served by 2 or more units, then the gross electrical output of the generator will be attributed to each unit in proportion to the unit’s share of the total control period heat input of such units for the year;
(B) For a unit that is a boiler and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the total heat energy (in Btu) of the steam produced by the boiler during the control period, divided by 0.8 and by 1,000,000 Btu/mmBtu; or
(C) For a unit that is a combustion turbine and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the control period gross electrical output of the enclosed device comprising the compressor, combustor, and turbine multiplied by 3,413 Btu/kWh, plus the total heat energy (in Btu) of the steam produced by any associated heat recovery steam generator during the control period divided by 0.8, and with the sum divided by 1,000,000 Btu/mmBtu.
(iii) Gross electrical output and total heat energy under paragraph (a)(2)(ii) of this section will be determined based on the best available data reported to the Administrator for the unit (in a format prescribed by the Administrator).
(3) The Administrator will determine what data are the best available data under paragraph (a)(2) of this section by weighing the likelihood that data are accurate and reliable and giving greater weight to data submitted to a governmental entity in compliance with legal requirements or substantiated by an independent entity.
(b)(1) For each control period in 2009 and thereafter, the Administrator will allocate to all CAIR NO
(2) The Administrator will allocate CAIR NO
(c) For each control period in 2009 and thereafter, the Administrator will allocate CAIR NO
(1) The Administrator will establish a separate new unit set-aside for each control period. Each new unit set-aside will be allocated CAIR NO
(2) The CAIR designated representative of such a CAIR NO
(3) In a CAIR NO
(4) The Administrator will review each CAIR NO
(i) The Administrator will accept an allowance allocation request only if the request meets, or is adjusted by the Administrator as necessary to meet, the requirements of paragraphs (c)(2) and (3) of this section.
(ii) On or after May 1 of the control period, the Administrator will determine the sum of the CAIR NO
(iii) If the amount of CAIR NO
(iv) If the amount of CAIR NO
(v) The Administrator will notify each CAIR designated representative that submitted an allowance allocation request of the amount of CAIR NO
(d) If, after completion of the procedures under paragraph (c)(4) of this section for a control period, any unallocated CAIR NO
(e) If the Administrator determines that CAIR NO
(1) Except as provided in paragraph (e)(2) or (3) of this section, the Administrator will not record such CAIR NO
(2) If the Administrator already recorded such CAIR NO
(3) If the Administrator already recorded such CAIR NO
(4) The Administrator will transfer the CAIR NO
§ 97.143 Compliance supplement pool.
(a) In addition to the CAIR NO
State | Compliance supplement pool |
---|---|
Alabama | 10,166 |
Delaware | 843 |
District of Columbia | 0 |
Florida | 8,335 |
Georgia | 12,397 |
Illinois | 11,299 |
Indiana | 20,155 |
Iowa | 6,978 |
Kentucky | 14,935 |
Louisiana | 2,251 |
Maryland | 4,670 |
Michigan | 8,347 |
Minnesota | 6,528 |
Mississippi | 3,066 |
Missouri | 9,044 |
New Jersey | 660 |
New York | 0 |
North Carolina | 0 |
Ohio | 25,037 |
Pennsylvania | 16,009 |
South Carolina | 2,600 |
Tennessee | 8,944 |
Texas | 772 |
Virginia | 5,134 |
West Virginia | 16,929 |
Wisconsin | 4,898 |
Total | 199,997 |
(b) For any CAIR NO
(1) The owners and operators of such CAIR NO
(2) The CAIR designated representative of such CAIR NO
(c) For any CAIR NO
(1) The CAIR designated representative of such CAIR NO
(2) In the request under paragraph (c)(1) of this section, the CAIR designated representative of such CAIR NO
(i) Obtain a sufficient amount of electricity from other electricity generation facilities, during the installation of control technology at the unit for compliance with the CAIR NO
(ii) Obtain under paragraphs (b) and (d) of this section, or otherwise obtain, a sufficient amount of CAIR NO
(d) The Administrator will review each request under paragraph (b) or (c) of this section submitted by May 1, 2009 and will allocate CAIR NO
(1) Upon receipt of each such request, the Administrator will make any necessary adjustments to the request to ensure that the amount of the CAIR NO
(2) If the State’s compliance supplement pool under paragraph (a) of this section has an amount of CAIR NO
(3) If the State’s compliance supplement pool under paragraph (a) of this section has a smaller amount of CAIR NO
(4) By July 31, 2009, the Administrator will determine by order the allocations under paragraph (d)(2) or (3) of this section. The Administrator will make available to the public each determination of CAIR NO
(5) By January 1, 2010, the Administrator will record the allocations under paragraph (d)(4) of this section.
(a) Notwithstanding §§ 97.141, 97.142, and 97.153 if a State submits, and the Administrator approves, a State implementation plan revision in accordance with § 51.123(p)(1) of this chapter providing for allocation of CAIR NO
(b) Notwithstanding § 97.143, if a State submits, and the Administrator approves, a State implementation plan revision in accordance with § 51.123(p)(2) of this chapter providing for allocation of the State’s compliance supplement pool by the permitting authority, then the permitting authority shall make such allocations in accordance with such approved State implementation plan revision, the Administrator will not make allocations under § 97.143(d)(4) for the CAIR NO
(c)(1) In implementing paragraph (a) of this section and §§ 97.141, 97.142, and 97.153, the Administrator will ensure that the total amount of CAIR NO
(2) In implementing paragraph (b) of this section and § 97.143, the Administrator will ensure that the total amount of CAIR NO
Appendix A to Subpart EE of Part 97 – States With Approved State Implementation Plan Revisions Concerning Allocations
1. The following States have State Implementation Plan revisions under § 51.123(p)(1) of this chapter approved by the Administrator and providing for allocation of CAIR NO
2. The following States have State Implementation Plan revisions under § 51.123(p)(2) of this chapter approved by the Administrator and providing for allocation of the Compliance Supplement Pool by the permitting authority under § 97.144(b):
Subpart FF – CAIR NOX Allowance Tracking System
§ 97.150 [Reserved]
§ 97.151 Establishment of accounts.
(a) Compliance accounts. Except as provided in § 97.184(e), upon receipt of a complete certificate of representation under § 97.113, the Administrator will establish a compliance account for the CAIR NO
(b) General accounts – (1) Application for general account. (i) Any person may apply to open a general account for the purpose of holding and transferring CAIR NO
(ii) A complete application for a general account shall be submitted to the Administrator and shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the CAIR authorized account representative and any alternate CAIR authorized account representative;
(B) Organization name and type of organization, if applicable;
(C) A list of all persons subject to a binding agreement for the CAIR authorized account representative and any alternate CAIR authorized account representative to represent their ownership interest with respect to the CAIR NO
(D) The following certification statement by the CAIR authorized account representative and any alternate CAIR authorized account representative: “I certify that I was selected as the CAIR authorized account representative or the alternate CAIR authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to CAIR NO
(E) The signature of the CAIR authorized account representative and any alternate CAIR authorized account representative and the dates signed.
(iii) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2) Authorization of CAIR authorized account representative and alternate CAIR authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section:
(A) The Administrator will establish a general account for the person or persons for whom the application is submitted.
(B) The CAIR authorized account representative and any alternate CAIR authorized account representative for the general account shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CAIR NO
(C) Any representation, action, inaction, or submission by any alternate CAIR authorized account representative shall be deemed to be a representation, action, inaction, or submission by the CAIR authorized account representative.
(ii) Each submission concerning the general account shall be submitted, signed, and certified by the CAIR authorized account representative or any alternate CAIR authorized account representative for the persons having an ownership interest with respect to CAIR NO
(iii) The Administrator will accept or act on a submission concerning the general account only if the submission has been made, signed, and certified in accordance with paragraph (b)(2)(ii) of this section.
(3) Changing CAIR authorized account representative and alternate CAIR authorized account representative; changes in persons with ownership interest. (i) The CAIR authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous CAIR authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new CAIR authorized account representative and the persons with an ownership interest with respect to the CAIR NO
(ii) The alternate CAIR authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate CAIR authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate CAIR authorized account representative and the persons with an ownership interest with respect to the CAIR NO
(iii)(A) In the event a person having an ownership interest with respect to CAIR NO
(B) Within 30 days following any change in the persons having an ownership interest with respect to CAIR NO
(4) Objections concerning CAIR authorized account representative and alternate CAIR authorized account representative. (i) Once a complete application for a general account under paragraph (b)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (b)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the CAIR authorized account representative or any alternate CAIR authorized account representative for a general account shall affect any representation, action, inaction, or submission of the CAIR authorized account representative or any alternate CAIR authorized account representative or the finality of any decision or order by the Administrator under the CAIR NO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the CAIR authorized account representative or any alternate CAIR authorized account representative for a general account, including private legal disputes concerning the proceeds of CAIR NO
(5) Delegation by CAIR authorized account representative and alternate CAIR authorized account representative. (i) A CAIR authorized account representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under subparts FF and GG of this part.
(ii) An alternate CAIR authorized account representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under subparts FF and GG of this part.
(iii) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the CAIR authorized account representative or alternate CAIR authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such CAIR authorized account representative or alternate CAIR authorized account representative;
(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such CAIR authorized account representative or alternate CAIR authorized account representative: “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a CAIR authorized account representative or alternate CAIR authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.151(b)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such CAIR authorized account representative or alternate CAIR authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.151(b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.151(b)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the CAIR authorized account representative or alternate CAIR authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such CAIR authorized account representative or alternate CAIR authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of this section shall be deemed to be an electronic submission by the CAIR designated representative or alternate CAIR designated representative submitting such notice of delegation.
(c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of this section.
Following the establishment of a CAIR NO
§ 97.153 Recordation of CAIR NOX allowance allocations.
(a) By September 30, 2007, the Administrator will record in the CAIR NO
(b) By September 30, 2008, the Administrator will record in the CAIR NO
(c) By September 30, 2009, the Administrator will record in the CAIR NO
(d) By December 1, 2010 and December 1 of each year thereafter, the Administrator will record in the CAIR NO
(e) By December 1, 2009 and December 1 of each year thereafter, the Administrator will record in the CAIR NO
(f) Serial numbers for allocated CAIR NO
§ 97.154 Compliance with CAIR NOX emissions limitation.
(a) Allowance transfer deadline. The CAIR NO
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in the compliance account as of the allowance transfer deadline for the control period or are transferred into the compliance account by a CAIR NO
(b) Deductions for compliance. Following the recordation, in accordance with § 97.161, of CAIR NO
(1) Until the amount of CAIR NO
(2) If there are insufficient CAIR NO
(c)(1) Identification of CAIR NO
(2) First-in, first-out. The Administrator will deduct CAIR NO
(i) Any CAIR NO
(ii) Any CAIR NO
(d) Deductions for excess emissions. (1) After making the deductions for compliance under paragraph (b) of this section for a control period in a calendar year in which the CAIR NO
(2) Any allowance deduction required under paragraph (d)(1) of this section shall not affect the liability of the owners and operators of the CAIR NO
(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and (d) of this section and subpart II.
(f) Administrator’s action on submissions. (1) The Administrator may review and conduct independent audits concerning any submission under the CAIR NO
(2) The Administrator may deduct CAIR NO
§ 97.155 Banking.
(a) CAIR NO
(b) Any CAIR NO
§ 97.156 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any CAIR NO
§ 97.157 Closing of general accounts.
(a) The CAIR authorized account representative of a general account may submit to the Administrator a request to close the account, which shall include a correctly submitted allowance transfer under §§ 97.160 and 97.161 for any CAIR NO
(b) If a general account has no allowance transfers in or out of the account for a 12-month period or longer and does not contain any CAIR NO
Subpart GG – CAIR NOX Allowance Transfers
§ 97.160 Submission of CAIR NOX allowance transfers.
A CAIR authorized account representative seeking recordation of a CAIR NO
(a) The account numbers for both the transferor and transferee accounts;
(b) The serial number of each CAIR NO
(c) The name and signature of the CAIR authorized account representative of the transferor account and the date signed.
§ 97.161 EPA recordation.
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a CAIR NO
(1) The transfer is correctly submitted under § 97.160; and
(2) The transferor account includes each CAIR NO
(b) A CAIR NO
(c) Where a CAIR NO
§ 97.162 Notification.
(a) Notification of recordation. Within 5 business days of recordation of a CAIR NO
(b) Notification of non-recordation. Within 10 business days of receipt of a CAIR NO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
(c) Nothing in this section shall preclude the submission of a CAIR NO
Subpart HH – Monitoring and Reporting
§ 97.170 General requirements.
The owners and operators, and to the extent applicable, the CAIR designated representative, of a CAIR NO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each CAIR NO
(1) Install all monitoring systems required under this subpart for monitoring NO
(2) Successfully complete all certification tests required under § 97.171 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator shall meet the monitoring system certification and other requirements of paragraphs (a)(1) and (2) of this section on or before the following dates. The owner or operator shall record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section on and after the following dates.
(1) For the owner or operator of a CAIR NO
(2) For the owner or operator of a CAIR NO
(i) January 1, 2008; or
(ii) 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation.
(3) For the owner or operator of a CAIR NO
(4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a unit for which a CAIR opt-in permit application is submitted and not withdrawn and a CAIR opt-in permit is not yet issued or denied under subpart II of this part, by the date specified in § 97.184(b).
(5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a CAIR NO
(c) Reporting data. The owner or operator of a CAIR NO
(d) Prohibitions. (1) No owner or operator of a CAIR NO
(2) No owner or operator of a CAIR NO
(3) No owner or operator of a CAIR NO
(4) No owner or operator of a CAIR NO
(i) During the period that the unit is covered by an exemption under § 97.105 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The CAIR designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.171(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a CAIR NO
§ 97.171 Initial certification and recertification procedures.
(a) The owner or operator of a CAIR NO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendix B, appendix D, and appendix E to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.170(a)(1) exempt from initial certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the NO
(d) Except as provided in paragraph (a) of this section, the owner or operator of a CAIR NO
(1) Requirements for initial certification. The owner or operator shall ensure that each continuous monitoring system under § 97.170(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.170(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.170(a)(1) that may significantly affect the ability of the system to accurately measure or record NO
(3) Approval process for initial certification and recertification. Paragraphs (d)(3)(i) through (iv) of this section apply to both initial certification and recertification of a continuous monitoring system under § 97.170(a)(1). For recertifications, replace the words “certification” and “initial certification” with the word “recertification”, replace the word “certified” with the word “recertified”, and follow the procedures in §§ 75.20(b)(5) and (g)(7) of this chapter in lieu of the procedures in paragraph (d)(3)(v) of this section.
(i) Notification of certification. The CAIR designated representative shall submit to the appropriate EPA Regional Office and the Administrator written notice of the dates of certification testing, in accordance with § 97.173.
(ii) Certification application. The CAIR designated representative shall submit to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the CAIR NO
(iv) Certification application approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the CAIR NO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the CAIR designated representative must submit the additional information required to complete the certification application. If the CAIR designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 120-day review period shall not begin before receipt of a complete certification application.
(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter). The owner or operator shall follow the procedures for loss of certification in paragraph (d)(3)(v) of this section for each monitoring system that is disapproved for initial certification.
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.172(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NO
(2) For a disapproved NO
(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(5) For a disapproved excepted NO
(B) The CAIR designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) Initial certification and recertification procedures for units using the low mass emission excepted methodology under § 75.19 of this chapter. The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) Certification/recertification procedures for alternative monitoring systems. The CAIR designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
§ 97.172 Out of control periods.
(a) Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D or subpart H of, or appendix D or appendix E to, part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.171 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the permitting authority or the Administrator. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 97.171 for each disapproved monitoring system.
§ 97.173 Notifications.
The CAIR designated representative for a CAIR NO
§ 97.174 Recordkeeping and reporting.
(a) General provisions. The CAIR designated representative shall comply with all recordkeeping and reporting requirements in this section, the applicable recordkeeping and reporting requirements under § 75.73 of this chapter, and the requirements of § 97.110(e)(1).
(b) Monitoring plans. The owner or operator of a CAIR NO
(c) Certification applications. The CAIR designated representative shall submit an application to the Administrator within 45 days after completing all initial certification or recertification tests required under § 97.171, including the information required under § 75.63 of this chapter.
(d) Quarterly reports. The CAIR designated representative shall submit quarterly reports, as follows:
(1) The CAIR designated representative shall report the NO
(i) For a unit that commences commercial operation before July 1, 2007, the calendar quarter covering January 1, 2008 through March 31, 2008;
(ii) For a unit that commences commercial operation on or after July 1, 2007, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.170(b), unless that quarter is the third or fourth quarter of 2007, in which case reporting shall commence in the quarter covering January 1, 2008 through March 31, 2008;
(iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a unit for which a CAIR opt-in permit application is submitted and not withdrawn and a CAIR opt-in permit is not yet issued or denied under subpart II of this part, the calendar quarter corresponding to the date specified in § 97.184(b); and
(iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a CAIR NO
(2) The CAIR designated representative shall submit each quarterly report to the Administrator within 30 days following the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.
(3) For CAIR NO
(e) Compliance certification. The CAIR designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and
(2) For a unit with add-on NO
§ 97.175 Petitions.
The CAIR designated representative of a CAIR NO
Subpart II – CAIR NOX Opt-In Units
§ 97.180 Applicability.
A CAIR NO
(a) Is located in a State that submits, and for which the Administrator approves, a State implementation plan revision in accordance with § 51.123(p)(3)(i), (ii), or (iii) of this chapter establishing procedures concerning CAIR opt-in units;
(b) Is not a CAIR NO
(c) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;
(d) Has or is required or qualified to have a title V operating permit or other federally enforceable permit; and
(e) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of subpart HH of this part.
§ 97.181 General.
(a) Except as otherwise provided in §§ 97.101 through 97.104, §§ 97.106 through 97.108, and subparts BB and CC and subparts FF through HH of this part, a CAIR NO
(b) Solely for purposes of applying, as provided in this subpart, the requirements of subpart HH of this part to a unit for which a CAIR opt-in permit application is submitted and not withdrawn and a CAIR opt-in permit is not yet issued or denied under this subpart, such unit shall be treated as a CAIR NO
§ 97.182 CAIR designated representative.
Any CAIR NO
§ 97.183 Applying for CAIR opt-in permit.
(a) Applying for initial CAIR opt-in permit. The CAIR designated representative of a unit meeting the requirements for a CAIR NO
(1) A complete CAIR permit application under § 97.122;
(2) A certification, in a format specified by the permitting authority, that the unit:
(i) Is not a CAIR NO
(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;
(iii) Vents all of its emissions to a stack; and
(iv) Has documented heat input for more than 876 hours during the 6 months immediately preceding submission of the CAIR permit application under § 97.122;
(3) A monitoring plan in accordance with subpart HH of this part;
(4) A complete certificate of representation under § 97.113 consistent with § 97.182, if no CAIR designated representative has been previously designated for the source that includes the unit; and
(5) A statement, in a format specified by the permitting authority, whether the CAIR designated representative requests that the unit be allocated CAIR NO
(b) Duty to reapply. (1) The CAIR designated representative of a CAIR NO
(2) Unless the permitting authority issues a notification of acceptance of withdrawal of the CAIR NO
§ 97.184 Opt-in process.
The permitting authority will issue or deny a CAIR opt-in permit for a unit for which an initial application for a CAIR opt-in permit under § 97.183 is submitted in accordance with the following, to the extent provided in a State implementation plan revision submitted in accordance with § 51.123(p)(3)(i), (ii), or (iii) of this chapter and approved by the Administrator:
(a) Interim review of monitoring plan. The permitting authority and the Administrator will determine, on an interim basis, the sufficiency of the monitoring plan accompanying the initial application for a CAIR opt-in permit under § 97.183. A monitoring plan is sufficient, for purposes of interim review, if the plan appears to contain information demonstrating that the NO
(b) Monitoring and reporting. (1)(i) If the permitting authority and the Administrator determine that the monitoring plan is sufficient under paragraph (a) of this section, the owner or operator shall monitor and report the NO
(ii) The monitoring and reporting under paragraph (b)(1)(i) of this section shall include the entire control period immediately before the date on which the unit enters the CAIR NO
(2) To the extent the NO
(c) Baseline heat input. The unit’s baseline heat input shall equal:
(1) If the unit’s NO
(2) If the unit’s NO
(d) Baseline NO
(1) If the unit’s NO
(2) If the unit’s NO
(3) If the unit’s NO
(e) Issuance of CAIR opt-in permit. After calculating the baseline heat input and the baseline NO
(f) Issuance of denial of CAIR opt-in permit. Notwithstanding paragraphs (a) through (e) of this section, if at any time before issuance of a CAIR opt-in permit for the unit, the permitting authority determines that the CAIR designated representative fails to show that the unit meets the requirements for a CAIR NO
(g) Date of entry into CAIR NO
(h) Repowered CAIR NO
(2) Notwithstanding paragraphs (c) and (d) of this section, as of the date of start-up under paragraph (h)(1) of this section, the repowered unit shall be deemed to have the same date of commencement of operation, date of commencement of commercial operation, baseline heat input, and baseline NO
§ 97.185 CAIR opt-in permit contents.
(a) Each CAIR opt-in permit will contain:
(1) All elements required for a complete CAIR permit application under § 97.122;
(2) The certification in § 97.183(a)(2);
(3) The unit’s baseline heat input under § 97.184(c);
(4) The unit’s baseline NO
(5) A statement whether the unit is to be allocated CAIR NO
(6) A statement that the unit may withdraw from the CAIR NO
(7) A statement that the unit is subject to, and the owners and operators of the unit must comply with, the requirements of § 97.187.
(b) Each CAIR opt-in permit is deemed to incorporate automatically the definitions of terms under § 97.102 and, upon recordation by the Administrator under subpart FF or GG of this part or this subpart, every allocation, transfer, or deduction of CAIR NO
(c) The CAIR opt-in permit shall be included, in a format specified by the permitting authority, in the CAIR permit for the source where the CAIR NO
§ 97.186 Withdrawal from CAIR NOX Annual Trading Program.
Except as provided under paragraph (g) of this section, a CAIR NO
(a) Requesting withdrawal. In order to withdraw a CAIR NO
(b) Conditions for withdrawal. Before a CAIR NO
(1) For the control period ending on the date on which the withdrawal is to be effective, the source that includes the CAIR NO
(2) After the requirement for withdrawal under paragraph (b)(1) of this section is met, the Administrator will deduct from the compliance account of the source that includes the CAIR NO
(c) Notification. (1) After the requirements for withdrawal under paragraphs (a) and (b) of this section are met (including deduction of the full amount of CAIR NO
(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the permitting authority will issue a notification to the CAIR designated representative of the CAIR NO
(d) Permit amendment. After the permitting authority issues a notification under paragraph (c)(1) of this section that the requirements for withdrawal have been met, the permitting authority will revise the CAIR permit covering the CAIR NO
(e) Reapplication upon failure to meet conditions of withdrawal. If the permitting authority denies the CAIR NO
(f) Ability to reapply to the CAIR NO
(g) Inability to withdraw. Notwithstanding paragraphs (a) through (f) of this section, a CAIR NO
§ 97.187 Change in regulatory status.
(a) Notification. If a CAIR NO
(b) Permitting authority’s and Administrator’s actions. (1) If a CAIR NO
(2)(i) The Administrator will deduct from the compliance account of the source that includes the CAIR NO
(A) Any CAIR NO
(B) If the date on which the CAIR NO
(ii) The CAIR designated representative shall ensure that the compliance account of the source that includes the CAIR NO
(3)(i) For every control period after the date on which the CAIR NO
(ii) If the date on which the CAIR NO
(A) The amount of CAIR NO
(B) The ratio of the number of days, in the control period, starting with the date on which the CAIR NO
(C) Rounded to the nearest whole allowance as appropriate.
§ 97.188 CAIR NOX allowance allocations to CAIR NOX opt-in units.
(a) Timing requirements. (1) When the CAIR opt-in permit is issued under § 97.184(e), the permitting authority will allocate CAIR NO
(2) By no later than October 31 of the control period after the control period in which a CAIR NO
(b) Calculation of allocation. For each control period for which a CAIR NO
(1) The heat input (in mmBtu) used for calculating the CAIR NO
(i) The CAIR NO
(ii) The CAIR NO
(2) The NO
(i) The CAIR NO
(ii) The most stringent State or Federal NO
(3) The permitting authority will allocate CAIR NO
(c) Notwithstanding paragraph (b) of this section and if the CAIR designated representative requests, and the permitting authority issues a CAIR opt-in permit (based on a demonstration of the intent to repower stated under § 97.183(a)(5)) providing for, allocation to a CAIR NO
(1) For each control period in 2009 through 2014 for which the CAIR NO
(i) The heat input (in mmBtu) used for calculating CAIR NO
(ii) The NO
(A) The CAIR NO
(B) The most stringent State or Federal NO
(iii) The permitting authority will allocate CAIR NO
(2) For each control period in 2015 and thereafter for which the CAIR NO
(i) The heat input (in mmBtu) used for calculating the CAIR NO
(ii) The NO
(A) 0.15 lb/mmBtu;
(B) The CAIR NO
(C) The most stringent State or Federal NO
(iii) The permitting authority will allocate CAIR NO
(d) Recordation. If provided in a State implementation plan revision submitted in accordance with § 51.123(p)(3)(i), (ii), or (iii) of this chapter and approved by the Administrator:
(1) The Administrator will record, in the compliance account of the source that includes the CAIR NO
(2) By December 1 of the control period in which a CAIR NO
Appendix A to Subpart II of Part 97 – States With Approved State Implementation Plan Revisions Concerning CAIR NOX Opt-In Units
1. The following States have State Implementation Plan revisions under § 51.123(p)(3) of this chapter approved by the Administrator and establishing procedures providing for CAIR NO
2. The following States have State Implementation Plan revisions under § 51.123(p)(3) of this chapter approved by the Administrator and establishing procedures providing for CAIR NO
Subpart AAA – CAIR SO2 Trading Program General Provisions
§ 97.201 Purpose.
This subpart and subparts BBB through III set forth the general provisions and the designated representative, permitting, allowance, monitoring, and opt-in provisions for the Federal Clean Air Interstate Rule (CAIR) SO
§ 97.202 Definitions.
The terms used in this subpart and subparts BBB through III shall have the meanings set forth in this section as follows:
Account number means the identification number given by the Administrator to each CAIR SO
Acid Rain emissions limitation means a limitation on emissions of sulfur dioxide or nitrogen oxides under the Acid Rain Program.
Acid Rain Program means a multi-state sulfur dioxide and nitrogen oxides air pollution control and emission reduction program established by the Administrator under title IV of the CAA and parts 72 through 78 of this chapter.
Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator’s duly authorized representative.
Allocate or allocation means, with regard to CAIR SO
Allowance transfer deadline means, for a control period, midnight of March 1 (if it is a business day), or midnight of the first business day thereafter (if March 1 is not a business day), immediately following the control period and is the deadline by which a CAIR SO
Alternate CAIR designated representative means, for a CAIR SO
Automated data acquisition and handling system or DAHS means that component of the continuous emission monitoring system, or other emissions monitoring system approved for use under subpart HHH of this part, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by subpart HHH of this part.
Biomass means –
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other nonmerchantable material, and that is;
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
Bottoming-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.
CAIR authorized account representative means, with regard to a general account, a responsible natural person who is authorized, in accordance with subparts BBB, FFF, and III of this part, to transfer and otherwise dispose of CAIR SO
CAIR designated representative means, for a CAIR SO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR permit means the legally binding and federally enforceable written document, or portion of such document, issued by the permitting authority under subpart CCC of this part, including any permit revisions, specifying the CAIR SO
CAIR SO
(1) For one CAIR SO
(2) For one CAIR SO
(3) For one CAIR SO
(4) An authorization to emit sulfur dioxide that is not issued under the Acid Rain Program, § 97.288, or provisions of a State implementation plan that are approved under § 51.124(o)(1) or (2) or (r) of this chapter shall not be a CAIR SO
CAIR SO
CAIR SO
CAIR SO
CAIR SO
CAIR SO
CAIR SO
CAIR SO
CAIR SO
Certifying official means:
(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, Federal, or other public agency, a principal executive officer or ranking elected official.
Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite.
Coal-derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.
Coal-fired means combusting any amount of coal or coal-derived fuel, alone, or in combination with any amount of any other fuel.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine:
(1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after the calendar year in which the unit first produces electricity –
(i) For a topping-cycle cogeneration unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input;
(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel except biomass if the unit is a boiler.
Combustion turbine means:
(1) An enclosed device comprising a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the enclosed device under paragraph (1) of this definition is combined cycle, any associated duct burner, heat recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.205 and § 97.284(h).
(i) For a unit that is a CAIR SO
(ii) For a unit that is a CAIR SO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.205, for a unit that is not a CAIR SO
(i) For a unit with a date for commencement of commercial operation as defined in paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in paragraph (2) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
Commence operation means:
(1) To have begun any mechanical, chemical, or electronic process, including, with regard to a unit, start-up of a unit’s combustion chamber, except as provided in § 97.284(h).
(2) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source) after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the date of commencement of operation of the unit, which shall continue to be treated as the same unit.
(3) For a unit that is replaced by a unit at the same source (e.g., repowered) after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit’s date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1), (2), or (3) of this definition as appropriate, except as provided in § 97.284(h).
Common stack means a single flue through which emissions from 2 or more units are exhausted.
Compliance account means a CAIR SO
Continuous emission monitoring system or CEMS means the equipment required under subpart HHH of this part to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of sulfur dioxide emissions, stack gas volumetric flow rate, stack gas moisture content, and oxygen or carbon dioxide concentration (as applicable), in a manner consistent with part 75 of this chapter. The following systems are the principal types of continuous emission monitoring systems required under subpart HHH of this part:
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A sulfur dioxide monitoring system, consisting of a SO
(3) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(4) A carbon dioxide monitoring system, consisting of a CO
(5) An oxygen monitoring system, consisting of an O
Control period means the period beginning January 1 of a calendar year, except as provided in § 97.206(c)(2), and ending on December 31 of the same year, inclusive.
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the CAIR designated representative and as determined by the Administrator in accordance with subpart HHH of this part.
Excess emissions means any ton, or portion of a ton, of sulfur dioxide emitted by the CAIR SO
Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.
Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in any calendar year.
General account means a CAIR SO
Generator means a device that produces electricity.
Heat input means, with regard to a specified period of time, the product (in mmBtu/time) of the gross calorific value of the fuel (in Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the CAIR designated representative and determined by the Administrator in accordance with subpart HHH of this part and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources.
Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Hg Budget Trading Program means a multi-state Hg air pollution control and emission reduction program approved and administered by the Administrator in accordance subpart HHHH of part 60 of this chapter and § 60.24(h)(6), or established by the Administrator under section 111 of the Clean Air Act, as a means of reducing national Hg emissions.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis as of the initial installation of the unit as specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the requirements of subpart HHH of this part, including a continuous emissions monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.
Most stringent State or Federal SO
Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount as of such completion as specified by the person conducting the physical change.
Operator means any person who operates, controls, or supervises a CAIR SO
Owner means any of the following persons:
(1) With regard to a CAIR SO
(i) Any holder of any portion of the legal or equitable title in a CAIR SO
(ii) Any holder of a leasehold interest in a CAIR SO
(iii) Any purchaser of power from a CAIR SO
(2) With regard to any general account, any person who has an ownership interest with respect to the CAIR SO
Permitting authority means the State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to issue or revise permits to meet the requirements of the CAIR SO
Potential electrical output capacity means 33 percent of a unit’s maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the permitting authority or the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the permitting authority or the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to CAIR SO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.
Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent shutdown and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or shutdown unit (the replaced unit).
Repowered means, with regard to a unit, replacement of a coal-fired boiler with one of the following coal-fired technologies at the same source as the coal-fired boiler:
(1) Atmospheric or pressurized fluidized bed combustion;
(2) Integrated gasification combined cycle;
(3) Magnetohydrodynamics;
(4) Direct and indirect coal-fired turbines;
(5) Integrated gasification fuel cells; or
(6) As determined by the Administrator in consultation with the Secretary of Energy, a derivative of one or more of the technologies under paragraphs (1) through (5) of this definition and any other coal-fired technology capable of controlling multiple combustion emissions simultaneously with improved boiler or generation efficiency and with significantly greater waste reduction relative to the performance of technology in widespread commercial use as of January 1, 2005.
Sequential use of energy means:
(1) For a topping-cycle cogeneration unit, the use of reject heat from electricity production in a useful thermal energy application or process; or
(2) For a bottoming-cycle cogeneration unit, the use of reject heat from useful thermal energy application or process in electricity production.
Serial number means, for a CAIR SO
Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act.
Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. For purposes of section 502(c) of the Clean Air Act, a “source,” including a “source” with multiple units, shall be considered a single “facility.”
State means one of the States or the District of Columbia that is subject to the CAIR SO
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery. Compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Title V operating permit means a permit issued under title V of the Clean Air Act and part 70 or part 71 of this chapter.
Title V operating permit regulations means the regulations that the Administrator has approved or issued as meeting the requirements of title V of the Clean Air Act and part 70 or 71 of this chapter.
Ton means 2,000 pounds. For the purpose of determining compliance with the CAIR SO
Topping-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful power, including electricity, and at least some of the reject heat from the electricity production is then used to provide useful thermal energy.
Total energy input means, with regard to a cogeneration unit, total energy of all forms supplied to the cogeneration unit, excluding energy produced by the cogeneration unit itself. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:
Total energy output means, with regard to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.
Unit means a stationary, fossil-fuel-fired boiler or combustion turbine or other stationary, fossil-fuel-fired combustion device. Unit operating day means a calendar day in which a unit combusts any fuel.
Unit operating hour or hour of unit operation means an hour in which a unit combusts any fuel.
Useful power means, with regard to a cogeneration unit, electricity or mechanical energy made available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means, with regard to a cogeneration unit, thermal energy that is:
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., thermal energy used by an absorption chiller).
Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.
§ 97.203 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart and subparts BBB through III are defined as follows:
§ 97.204 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State shall be CAIR SO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a CAIR SO
(b) The units in a State that meet the requirements set forth in paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) of this section shall not be CAIR SO
(1)(i) Any unit that is a CAIR SO
(A) Qualifying as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and
(B) Not serving at any time, since the later of November 15, 1990 or the start-up of the unit’s combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit’s potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i) of this section for at least one calendar year, but subsequently no longer meets all such requirements, the unit shall become a CAIR SO
(2)(i) Any unit that is a CAIR SO
(A) Qualifying as a solid waste incineration unit; and
(B) With an average annual fuel consumption of non-fossil fuel for 1985-1987 exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any 3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).
(ii) Any unit that is a CAIR SO
(A) Qualifying as a solid waste incineration unit; and
(B) With an average annual fuel consumption of non-fossil fuel for the first 3 calendar years of operation exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any 3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste incineration unit and meets the requirements of paragraph (b)(2)(i) or (ii) of this section for at least 3 consecutive calendar years, but subsequently no longer meets all such requirements, the unit shall become a CAIR SO
(c) A certifying official of an owner or operator of any unit may petition the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CAIR SO
(1) Petition content. The petition shall be in writing and include the identification of the unit and the relevant facts about the unit. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying official: “I am authorized to make this submission on behalf of the owners and operators of the unit for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) Submission. The petition and any other documents provided in connection with the petition shall be submitted to the Director of the Clean Air Markets Division (or its successor), U.S. Environmental Protection Agency, who will act on the petition as the Administrator’s duly authorized representative.
(3) Response. The Administrator will issue a written response to the petition and may request supplemental information relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CAIR SO
§ 97.205 Retired unit exemption.
(a)(1) Any CAIR SO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the CAIR SO
(3) After receipt of the statement under paragraph (a)(2) of this section, the permitting authority will amend any permit under subpart CCC of this part covering the source at which the unit is located to add the provisions and requirements of the exemption under paragraphs (a)(1) and (b) of this section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of this section shall not emit any sulfur dioxide, starting on the date that the exemption takes effect.
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the CAIR SO
(4) A unit exempt under paragraph (a) of this section and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under § 97.222 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2010 or the date on which the unit resumes operation.
(5) On the earlier of the following dates, a unit exempt under paragraph (a) of this section shall lose its exemption:
(i) The date on which the CAIR designated representative submits a CAIR permit application for the unit under paragraph (b)(4) of this section;
(ii) The date on which the CAIR designated representative is required under paragraph (b)(4) of this section to submit a CAIR permit application for the unit; or
(iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAIR permit application for the unit.
(6) For the purpose of applying monitoring, reporting, and recordkeeping requirements under subpart HHH of this part, a unit that loses its exemption under paragraph (a) of this section shall be treated as a unit that commences commercial operation on the first date on which the unit resumes operation.
§ 97.206 Standard requirements.
(a) Permit requirements. (1) The CAIR designated representative of each CAIR SO
(i) Submit to the permitting authority a complete CAIR permit application under § 97.222 in accordance with the deadlines specified in § 97.221; and
(ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit.
(2) The owners and operators of each CAIR SO
(3) Except as provided in subpart III of this part, the owners and operators of a CAIR SO
(b) Monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the CAIR designated representative, of each CAIR SO
(2) The emissions measurements recorded and reported in accordance with subpart HHH of this part shall be used to determine compliance by each CAIR SO
(c) Sulfur dioxide emission requirements. (1) As of the allowance transfer deadline for a control period, the owners and operators of each CAIR SO
(2) A CAIR SO
(3) A CAIR SO
(4) CAIR SO
(5) A CAIR SO
(6) A CAIR SO
(7) Upon recordation by the Administrator under subpart FFF, GGG, or III of this part, every allocation, transfer, or deduction of a CAIR SO
(d) Excess emissions requirements. If a CAIR SO
(1) The owners and operators of the source and each CAIR SO
(2) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law.
(e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the CAIR SO
(i) The certificate of representation under § 97.213 for the CAIR designated representative for the source and each CAIR SO
(ii) All emissions monitoring information, in accordance with subpart HHH of this part, provided that to the extent that subpart HHH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR SO
(iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR SO
(2) The CAIR designated representative of a CAIR SO
(f) Liability. (1) Each CAIR SO
(2) Any provision of the CAIR SO
(3) Any provision of the CAIR SO
(g) Effect on other authorities. No provision of the CAIR SO
§ 97.207 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the CAIR SO
(b) Unless otherwise stated, any time period scheduled, under the CAIR SO
(c) Unless otherwise stated, if the final day of any time period, under the CAIR SO
§ 97.208 Appeal procedures.
The appeal procedures for decisions of the Administrator under the CAIR SO
Subpart BBB – CAIR Designated Representative for CAIR SO2 Sources
§ 97.210 Authorization and responsibilities of CAIR designated representative.
(a) Except as provided under § 97.211, each CAIR SO
(b) The CAIR designated representative of the CAIR SO
(c) Upon receipt by the Administrator of a complete certificate of representation under § 97.213, the CAIR designated representative of the source shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the CAIR SO
(d) No CAIR permit will be issued, no emissions data reports will be accepted, and no CAIR SO
(e)(1) Each submission under the CAIR SO
(2) The permitting authority and the Administrator will accept or act on a submission made on behalf of owner or operators of a CAIR SO
§ 97.211 Alternate CAIR designated representative.
(a) A certificate of representation under § 97.213 may designate one and only one alternate CAIR designated representative, who may act on behalf of the CAIR designated representative. The agreement by which the alternate CAIR designated representative is selected shall include a procedure for authorizing the alternate CAIR designated representative to act in lieu of the CAIR designated representative.
(b) Upon receipt by the Administrator of a complete certificate of representation under § 97.213, any representation, action, inaction, or submission by the alternate CAIR designated representative shall be deemed to be a representation, action, inaction, or submission by the CAIR designated representative.
(c) Except in this section and §§ 97.202, 97.210(a) and (d), 97.212, 97.213, 97.215, 97.251 and 97.282, whenever the term “CAIR designated representative” is used in subparts AAA through III of this part, the term shall be construed to include the CAIR designated representative or any alternate CAIR designated representative.
§ 97.212 Changing CAIR designated representative and alternate CAIR designated representative; changes in owners and operators.
(a) Changing CAIR designated representative. The CAIR designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.213. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous CAIR designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new CAIR designated representative and the owners and operators of the CAIR SO
(b) Changing alternate CAIR designated representative. The alternate CAIR designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.213. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate CAIR designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate CAIR designated representative and the owners and operators of the CAIR SO
(c) Changes in owners and operators. (1) In the event an owner or operator of a CAIR SO
(2) Within 30 days following any change in the owners and operators of a CAIR SO
§ 97.213 Certificate of representation.
(a) A complete certificate of representation for a CAIR designated representative or an alternate CAIR designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the CAIR SO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the CAIR designated representative and any alternate CAIR designated representative.
(3) A list of the owners and operators of the CAIR SO
(4) The following certification statements by the CAIR designated representative and any alternate CAIR designated representative –
(i) “I certify that I was selected as the CAIR designated representative or alternate CAIR designated representative, as applicable, by an agreement binding on the owners and operators of the source and each CAIR SO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CAIR SO
(iii) “I certify that the owners and operators of the source and of each CAIR SO
(iv) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a CAIR SO
(5) The signature of the CAIR designated representative and any alternate CAIR designated representative and the dates signed.
(b) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
§ 97.214 Objections concerning CAIR designated representative.
(a) Once a complete certificate of representation under § 97.213 has been submitted and received, the permitting authority and the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.213 is received by the Administrator.
(b) Except as provided in § 97.212(a) or (b), no objection or other communication submitted to the permitting authority or the Administrator concerning the authorization, or any representation, action, inaction, or submission, of the CAIR designated representative shall affect any representation, action, inaction, or submission of the CAIR designated representative or the finality of any decision or order by the permitting authority or the Administrator under the CAIR SO
(c) Neither the permitting authority nor the Administrator will adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any CAIR designated representative, including private legal disputes concerning the proceeds of CAIR SO
§ 97.215 Delegation by CAIR designated representative and alternate CAIR designated representative.
(a) A CAIR designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this part.
(b) An alternate CAIR designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this part.
(c) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the CAIR designated representative or alternate CAIR designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such CAIR designated representative or alternate CAIR designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such CAIR designated representative or alternate CAIR designated representative:
(i) “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a CAIR designated representative or alternate CAIR designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.215(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.215(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.215 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the CAIR designated representative or alternate CAIR designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such CAIR designated representative or alternate CAIR designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the CAIR designated representative or alternate CAIR designated representative submitting such notice of delegation.
Subpart CCC – Permits
§ 97.220 General CAIR SO2 Trading Program permit requirements.
(a) For each CAIR SO
(b) Each CAIR permit shall contain, with regard to the CAIR SO
§ 97.221 Submission of CAIR permit applications.
(a) Duty to apply. The CAIR designated representative of any CAIR SO
(b) Duty to reapply. For a CAIR SO
§ 97.222 Information requirements for CAIR permit applications.
A complete CAIR permit application shall include the following elements concerning the CAIR SO
(a) Identification of the CAIR SO
(b) Identification of each CAIR SO
(c) The standard requirements under § 97.206.
§ 97.223 CAIR permit contents and term.
(a) Each CAIR permit will contain, in a format prescribed by the permitting authority, all lements required for a complete CAIR permit application under § 97.222.
(b) Each CAIR permit is deemed to incorporate automatically the definitions of terms under § 97.202 and, upon recordation by the Administrator under subpart FFF, GGG, or III of this part, every allocation, transfer, or deduction of a CAIR SO
(c) The term of the CAIR permit will be set by the permitting authority, as necessary to facilitate coordination of the renewal of the CAIR permit with issuance, revision, or renewal of the CAIR SO
§ 97.224 CAIR permit revisions.
Except as provided in § 97.223(b), the permitting authority will revise the CAIR permit, as necessary, in accordance with the permitting authority’s title V operating permits regulations or the permitting authority’s regulations for other federally enforceable permits as applicable addressing permit revisions.
Subparts DDD-EEE [Reserved]
Subpart FFF – CAIR SO2 Allowance Tracking System
§ 97.250 [Reserved]
§ 97.251 Establishment of accounts.
(a) Compliance accounts. Except as provided in § 97.284(e), upon receipt of a complete certificate of representation under § 97.213, the Administrator will establish a compliance account for the CAIR SO
(b) General accounts – (1) Application for general account. (i) Any person may apply to open a general account for the purpose of holding and transferring CAIR SO
(ii) A complete application for a general account shall be submitted to the Administrator and shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the CAIR authorized account representative and any alternate CAIR authorized account representative;
(B) Organization name and type of organization, if applicable;
(C) A list of all persons subject to a binding agreement for the CAIR authorized account representative and any alternate CAIR authorized account representative to represent their ownership interest with respect to the CAIR SO
(D) The following certification statement by the CAIR authorized account representative and any alternate CAIR authorized account representative: “I certify that I was selected as the CAIR authorized account representative or the alternate CAIR authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to CAIR SO
(E) The signature of the CAIR authorized account representative and any alternate CAIR authorized account representative and the dates signed.
(iii) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2) Authorization of CAIR authorized account representative and alternate CAIR authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section:
(A) The Administrator will establish a general account for the person or persons for whom the application is submitted.
(B) The CAIR authorized account representative and any alternate CAIR authorized account representative for the general account shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CAIR SO
(C) Any representation, action, inaction, or submission by any alternate CAIR authorized account representative shall be deemed to be a representation, action, inaction, or submission by the CAIR authorized account representative.
(ii) Each submission concerning the general account shall be submitted, signed, and certified by the CAIR authorized account representative or any alternate CAIR authorized account representative for the persons having an ownership interest with respect to CAIR SO
(iii) The Administrator will accept or act on a submission concerning the general account only if the submission has been made, signed, and certified in accordance with paragraph (b)(2)(ii) of this section.
(3) Changing CAIR authorized account representative and alternate CAIR authorized account representative; changes in persons with ownership interest. (i) The CAIR authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous CAIR authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new CAIR authorized account representative and the persons with an ownership interest with respect to the CAIR SO
(ii) The alternate CAIR authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate CAIR authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate CAIR authorized account representative and the persons with an ownership interest with respect to the CAIR SO
(iii)(A) In the event a person having an ownership interest with respect to CAIR SO
(B) Within 30 days following any change in the persons having an ownership interest with respect to CAIR SO
(4) Objections concerning CAIR authorized account representative and alternate CAIR authorized account representative. (i) Once a complete application for a general account under paragraph (b)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (b)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the CAIR authorized account representative or any alternate CAIR authorized account representative for a general account shall affect any representation, action, inaction, or submission of the CAIR authorized account representative or any alternate CAIR authorized account representative or the finality of any decision or order by the Administrator under the CAIR SO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the CAIR authorized account representative or any alternate CAIR authorized account representative for a general account, including private legal disputes concerning the proceeds of CAIR SO
(5) Delegation by CAIR authorized account representative and alternate CAIR authorized account representative. (i) A CAIR authorized account representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under subparts FFF and GGG of this part.
(ii) An alternate CAIR authorized account representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under subparts FFF and GGG of this part.
(iii) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the CAIR authorized account representative or alternate CAIR authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such CAIR authorized account representative or alternate CAIR authorized account representative;
(B) The name, address, e-mail address, telephone number, and, facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such CAIR authorized account representative or alternate CAIR authorized account representative: “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a CAIR authorized account representative or alternate CAIR authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.251(b)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such CAIR authorized account representative or alternate CAIR authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.251 (b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address, unless all delegation of authority by me under 40 CFR 97.251 (b)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the CAIR authorized account representative or alternate CAIR authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such CAIR authorized account representative or alternate CAIR authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of this section shall be deemed to be an electronic submission by the CAIR designated representative or alternate CAIR designated representative submitting such notice of delegation.
(c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of this section.
Following the establishment of a CAIR SO
§ 97.253 Recordation of CAIR SO2 allowances.
(a)(1) After a compliance account is established under § 97.251(a) or § 73.31(a) or (b) of this chapter, the Administrator will record in the compliance account any CAIR SO
(2) In 2011 and each year thereafter, after Administrator has completed all deductions under § 97.254(b), the Administrator will record in the compliance account any CAIR SO
(b)(1) After a general account is established under § 97.251(b) or § 73.31(c) of this chapter, the Administrator will record in the general account any CAIR SO
(2) In 2011 and each year thereafter, after Administrator has completed all deductions under § 97.254(b), the Administrator will record in the general account any CAIR SO
(c) Serial numbers for allocated CAIR SO
§ 97.254 Compliance with CAIR SO2 emissions limitation.
(a) Allowance transfer deadline. The CAIR SO
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in the compliance account as of the allowance transfer deadline for the control period or are transferred into the compliance account by a CAIR SO
(b) Deductions for compliance. Following the recordation, in accordance with § 97.261, of CAIR SO
(1) For a CAIR SO
(i) Deduct the amount of CAIR SO
(ii) Deduct the amount of CAIR SO
(iii) Treating the CAIR SO
(A) Until the tonnage equivalent of the CAIR SO
(B) If there are insufficient CAIR SO
(2) For a CAIR SO
(i) Until the tonnage equivalent of the CAIR SO
(ii) If there are insufficient CAIR SO
(c)(1) Identification of CAIR SO
(2) First-in, first-out. The Administrator will deduct CAIR SO
(i) Any CAIR SO
(ii) Any CAIR SO
(iii) Any CAIR SO
(iv) Any CAIR SO
(v) Any CAIR SO
(vi) Any CAIR SO
(d) Deductions for excess emissions. (1) After making the deductions for compliance under paragraph (b) of this section for a control period in a calendar year in which the CAIR SO
(2) Any allowance deduction required under paragraph (d)(1) of this section shall not affect the liability of the owners and operators of the CAIR SO
(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and (d) of this section and subpart III.
(f) Administrator’s action on submissions. (1) The Administrator may review and conduct independent audits concerning any submission under the CAIR SO
(2) The Administrator may deduct CAIR SO
§ 97.255 Banking.
(a) CAIR SO
(b) Any CAIR SO
§ 97.256 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any CAIR SO
§ 97.257 Closing of general accounts.
(a) The CAIR authorized account representative of a general account may submit to the Administrator a request to close the account, which shall include a correctly submitted allowance transfer under §§ 97.260 and 97.261 for any CAIR SO
(b) If a general account has no allowance transfers in or out of the account for a 12-month period or longer and does not contain any CAIR SO
Subpart GGG – CAIR SO2 Allowance Transfers
§ 97.260 Submission of CAIR SO2 allowance transfers.
(a) A CAIR authorized account representative seeking recordation of a CAIR SO
(1) The account numbers of both the transferor and transferee accounts;
(2) The serial number of each CAIR SO
(3) The name and signature of the CAIR authorized account representatives of the transferor and transferee accounts and the dates signed.
(b)(1) The CAIR authorized account representative for the transferee account can meet the requirements in paragraph (a)(3) of this section by submitting, in a format prescribed by the Administrator, a statement signed by the CAIR authorized account representative and identifying each account into which any transfer of allowances, submitted on or after the date on which the Administrator receives such statement, is authorized. Such authorization shall be binding on any CAIR authorized account representative for such account and shall apply to all transfers into the account that are submitted on or after such date of receipt, unless and until the Administrator receives a statement signed by the CAIR authorized account representative retracting the authorization for the account.
(2) The statement under paragraph (b)(1) of this section shall include the following: “By this signature I authorize any transfer of allowances into each account listed herein, except that I do not waive any remedies under State or Federal law to obtain correction of any erroneous transfers into such accounts. This authorization shall be binding on any CAIR authorized account representative for such account unless and until a statement signed by the CAIR authorized account representative retracting this authorization for the account is received by the Administrator.”
§ 97.261 EPA recordation.
(a) Within 5 business days (except as necessary to perform a transfer in perpetuity of CAIR SO
(1) The transfer is correctly submitted under § 97.260;
(2) The transferor account includes each CAIR SO
(3) The transfer is in accordance with the limitation on transfer under § 74.42 of this chapter and § 74.47(c) of this chapter, as applicable.
(b) A CAIR SO
(c) Where a CAIR SO
§ 97.262 Notification.
(a) Notification of recordation. Within 5 business days of recordation of a CAIR SO
(b) Notification of non-recordation. Within 10 business days of receipt of a CAIR SO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
(c) Nothing in this section shall preclude the submission of a CAIR SO
Subpart HHH – Monitoring and Reporting
§ 97.270 General requirements.
The owners and operators, and to the extent applicable, the CAIR designated representative, of a CAIR SO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each CAIR SO
(1) Install all monitoring systems required under this subpart for monitoring SO
(2) Successfully complete all certification tests required under § 97.271 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator shall meet the monitoring system certification and other requirements of paragraphs (a)(1) and (2) of this section on or before the following dates. The owner or operator shall record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section on and after the following dates.
(1) For the owner or operator of a CAIR SO
(2) For the owner or operator of a CAIR SO
(i) January 1, 2009; or
(ii) 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation.
(3) For the owner or operator of a CAIR SO
(4) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a unit for which a CAIR opt-in permit application is submitted and not withdrawn and a CAIR opt-in permit is not yet issued or denied under subpart III of this part, by the date specified in § 97.284(b).
(5) Notwithstanding the dates in paragraphs (b)(1) and (2) of this section, for the owner or operator of a CAIR SO
(c) Reporting data. The owner or operator of a CAIR SO
(d) Prohibitions. (1) No owner or operator of a CAIR SO
(2) No owner or operator of a CAIR SO
(3) No owner or operator of a CAIR SO
(4) No owner or operator of a CAIR SO
(i) During the period that the unit is covered by an exemption under § 97.205 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The CAIR designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.271(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a CAIR SO
§ 97.271 Initial certification and recertification procedures.
(a) The owner or operator of a CAIR SO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendix B and appendix D to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.270(a)(1) exempt from initial certification requirements under paragraph (a) of this section.
(c) [Reserved]
(d) Except as provided in paragraph (a) of this section, the owner or operator of a CAIR SO
(1) Requirements for initial certification. The owner or operator shall ensure that each continuous monitoring system under § 97.270(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.270(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.270(a)(1) that may significantly affect the ability of the system to accurately measure or record SO
(3) Approval process for initial certification and recertification. Paragraphs (d)(3)(i) through (iv) of this section apply to both initial certification and recertification of a continuous monitoring system under § 97.270(a)(1). For recertifications, replace the words “certification” and “initial certification” with the word “recertification”, replace the word “certified” with the word “recertified,” and follow the procedures in §§ 75.20(b)(5) and (g)(7) of this chapter in lieu of the procedures in paragraph (d)(3)(v) of this section.
(i) Notification of certification. The CAIR designated representative shall submit to the appropriate EPA Regional Office and the Administrator written notice of the dates of certification testing, in accordance with § 97.273.
(ii) Certification application. The CAIR designated representative shall submit to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the CAIR SO
(iv) Certification application approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the CAIR SO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the CAIR designated representative must submit the additional information required to complete the certification application. If the CAIR designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 120-day review period shall not begin before receipt of a complete certification application.
(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter). The owner or operator shall follow the procedures for loss of certification in paragraph (d)(3)(v) of this section for each monitoring system that is disapproved for initial certification.
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.272(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved SO
(2) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(3) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(B) The CAIR designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) Initial certification and recertification procedures for units using the low mass emission excepted methodology under § 75.19 of this chapter. The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) Certification/recertification procedures for alternative monitoring systems. The CAIR designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
§ 97.272 Out of control periods.
(a) Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D of appendix D to part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.271 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the permitting authority or the Administrator. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 97.271 for each disapproved monitoring system.
§ 97.273 Notifications.
The CAIR designated representative for a CAIR SO
(a) General provisions. The CAIR designated representative shall comply with all recordkeeping and reporting requirements in this section, the applicable recordkeeping and reporting requirements in subparts F and G of part 75 of this chapter, and the requirements of § 97.210(e)(1).
(b) Monitoring Plans. The owner or operator of a CAIR SO
(c) Certification Applications. The CAIR designated representative shall submit an application to the Administrator within 45 days after completing all initial certification or recertification tests required under § 97.271, including the information required under § 75.63 of this chapter.
(d) Quarterly reports. The CAIR designated representative shall submit quarterly reports, as follows:
(1) The CAIR designated representative shall report the SO
(i) For a unit that commences commercial operation before July 1, 2008, the calendar quarter covering January 1, 2009 through March 31, 2009;
(ii) For a unit that commences commercial operation on or after July 1, 2008, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.270(b), unless that quarter is the third or fourth quarter of 2008, in which case reporting shall commence in the quarter covering January 1, 2009 through March 31, 2009;
(iii) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a unit for which a CAIR opt-in permit application is submitted and not withdrawn and a CAIR opt-in permit is not yet issued or denied under subpart III of this part, the calendar quarter corresponding to the date specified in § 97.284(b); and
(iv) Notwithstanding paragraphs (d)(1)(i) and (ii) of this section, for a CAIR SO
(2) The CAIR designated representative shall submit each quarterly report to the Administrator within 30 days following the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.64 of this chapter.
(3) For CAIR SO
(e) Compliance certification. The CAIR designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and
(2) For a unit with add-on SO
§ 97.275 Petitions.
The CAIR designated representative of a CAIR SO
Subpart III – CAIR SO2 Opt-in Units
§ 97.280 Applicability.
A CAIR SO
(a) Is located in a State that submits, and for which the Administrator approves, a State implementation plan revision in accordance with § 51.124(r)(1), (2), or (3) of this chapter establishing procedures concerning CAIR opt-in units;
(b) Is not a CAIR SO
(c) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect and is not an opt-in source under part 74 of this chapter;
(d) Has or is required or qualified to have a title V operating permit or other federally enforceable permit; and
(e) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of subpart HH of this part.
§ 97.281 General.
(a) Except as otherwise provided in §§ 97.201 through 97.204, §§ 97.206 through 97.208, and subparts BBB and CCC and subparts FFF through HHH of this part, a CAIR SO
(b) Solely for purposes of applying, as provided in this subpart, the requirements of subpart HHH of this part to a unit for which a CAIR opt-in permit application is submitted and not withdrawn and a CAIR opt-in permit is not yet issued or denied under this subpart, such unit shall be treated as a CAIR SO
§ 97.282 CAIR designated representative.
Any CAIR SO
§ 97.283 Applying for CAIR opt-in permit.
(a) Applying for initial CAIR opt-in permit. The CAIR designated representative of a unit meeting the requirements for a CAIR SO
(1) A complete CAIR permit application under § 97.222;
(2) A certification, in a format specified by the permitting authority, that the unit:
(i) Is not a CAIR SO
(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;
(iii) Is not and, so long as the unit is a CAIR SO
(iv) Vents all of its emissions to a stack; and
(v) Has documented heat input for more than 876 hours during the 6 months immediately preceding submission of the CAIR permit application under § 97.222;
(3) A monitoring plan in accordance with subpart HHH of this part;
(4) A complete certificate of representation under § 97.213 consistent with § 97.282, if no CAIR designated representative has been previously designated for the source that includes the unit; and
(5) A statement, in a format specified by the permitting authority, whether the CAIR designated representative requests that the unit be allocated CAIR SO
(b) Duty to reapply. (1) The CAIR designated representative of a CAIR SO
(2) Unless the permitting authority issues a notification of acceptance of withdrawal of the CAIR SO
§ 97.284 Opt-in process.
The permitting authority will issue or deny a CAIR opt-in permit for a unit for which an initial application for a CAIR opt-in permit under § 97.183 is submitted in accordance with the following, to the extent provided in a State implementation plan revision submitted in accordance with § 51.124(r)(1), (2), or (3) of this chapter and approved by the Administrator:
(a) Interim review of monitoring plan. The permitting authority and the Administrator will determine, on an interim basis, the sufficiency of the monitoring plan accompanying the initial application for a CAIR opt-in permit under § 97.283. A monitoring plan is sufficient, for purposes of interim review, if the plan appears to contain information demonstrating that the SO
(b) Monitoring and reporting. (1)(i) If the permitting authority and the Administrator determine that the monitoring plan is sufficient under paragraph (a) of this section, the owner or operator shall monitor and report the SO
(ii) The monitoring and reporting under paragraph (b)(1)(i) of this section shall include the entire control period immediately before the date on which the unit enters the CAIR SO
(2) To the extent the SO
(c) Baseline heat input. The unit’s baseline heat input shall equal:
(1) If the unit’s SO
(2) If the unit’s SO
(d) Baseline SO
(1) If the unit’s SO
(2) If the unit’s SO
(3) If the unit’s SO
(e) Issuance of CAIR opt-in permit. After calculating the baseline heat input and the baseline SO
(f) Issuance of denial of CAIR opt-in permit. Notwithstanding paragraphs (a) through (e) of this section, if at any time before issuance of a CAIR opt-in permit for the unit, the permitting authority determines that the CAIR designated representative fails to show that the unit meets the requirements for a CAIR SO
(g) Date of entry into CAIR SO
(h) Repowered CAIR SO
(2) Notwithstanding paragraphs (c) and (d) of this section, as of the date of start-up under paragraph (h)(1) of this section, the repowered unit shall be deemed to have the same date of commencement of operation, date of commencement of commercial operation, baseline heat input, and baseline SO
§ 97.285 CAIR opt-in permit contents.
(a) Each CAIR opt-in permit will contain:
(1) All elements required for a complete CAIR permit application under § 97.222;
(2) The certification in § 97.283(a)(2);
(3) The unit’s baseline heat input under § 97.284(c);
(4) The unit’s baseline SO
(5) A statement whether the unit is to be allocated CAIR SO
(6) A statement that the unit may withdraw from the CAIR SO
(7) A statement that the unit is subject to, and the owners and operators of the unit must comply with, the requirements of § 97.287.
(b) Each CAIR opt-in permit is deemed to incorporate automatically the definitions of terms under § 97.202 and, upon recordation by the Administrator under subpart FFF or GGG of this part or this subpart, every allocation, transfer, or deduction of CAIR SO
(c) The CAIR opt-in permit shall be included, in a format specified by the permitting authority, in the CAIR permit for the source where the CAIR SO
§ 97.286 Withdrawal from CAIR SO2 Trading Program.
Except as provided under paragraph (g) of this section, a CAIR SO
(a) Requesting withdrawal. In order to withdraw a CAIR SO
(b) Conditions for withdrawal. Before a CAIR SO
(1) For the control period ending on the date on which the withdrawal is to be effective, the source that includes the CAIR SO
(2) After the requirement for withdrawal under paragraph (b)(1) of this section is met, the Administrator will deduct from the compliance account of the source that includes the CAIR SO
(c) Notification. (1) After the requirements for withdrawal under paragraphs (a) and (b) of this section are met (including deduction of the full amount of CAIR SO
(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the permitting authority will issue a notification to the CAIR designated representative of the CAIR SO
(d) Permit amendment. After the permitting authority issues a notification under paragraph (c)(1) of this section that the requirements for withdrawal have been met, the permitting authority will revise the CAIR permit covering the CAIR SO
(e) Reapplication upon failure to meet conditions of withdrawal. If the permitting authority denies the CAIR SO
(f) Ability to reapply to the CAIR SO
(g) Inability to withdraw. Notwithstanding paragraphs (a) through (f) of this section, a CAIR SO
§ 97.287 Change in regulatory status.
(a) Notification. If a CAIR SO
(b) Permitting authority’s and Administrator’s actions. (1) If a CAIR SO
(2)(i) The Administrator will deduct from the compliance account of the source that includes the CAIR SO
(A) Any CAIR SO
(B) If the date on which the CAIR SO
(ii) The CAIR designated representative shall ensure that the compliance account of the source that includes the CAIR SO
§ 97.288 CAIR SO2 allowance allocations to CAIR SO2 opt-in units.
(a) Timing requirements. (1) When the CAIR opt-in permit is issued under § 97.284(e), the permitting authority will allocate CAIR SO
(2) By no later than October 31 of the control period after the control period in which a CAIR SO
(b) Calculation of allocation. For each control period for which a CAIR SO
(1) The heat input (in mmBtu) used for calculating the CAIR SO
(i) The CAIR SO
(ii) The CAIR SO
(2) The SO
(i) The CAIR SO
(ii) The most stringent State or Federal SO
(3) The permitting authority will allocate CAIR SO
(c) Notwithstanding paragraph (b) of this section and if the CAIR designated representative requests, and the permitting authority issues a CAIR opt-in permit (based on a demonstration of the intent to repower stated under § 97.283(a)(5)) providing for, allocation to a CAIR SO
(1) For each control period in 2010 through 2014 for which the CAIR SO
(i) The heat input (in mmBtu) used for calculating CAIR SO
(ii) The SO
(A) The CAIR SO
(B) The most stringent State or Federal SO
(iii) The permitting authority will allocate CAIR SO
(2) For each control period in 2015 and thereafter for which the CAIR SO
(i) The heat input (in mmBtu) used for calculating the CAIR SO
(ii) The SO
(A) The CAIR SO
(B) The most stringent State or Federal SO
(iii) The permitting authority will allocate CAIR SO
(d) Recordation. If provided in a State implementation plan revision submitted in accordance with § 51.124(r)(1), (2), or (3) of this chapter and approved by the Administrator:
(1) The Administrator will record, in the compliance account of the source that includes the CAIR SO
(2) By December 1 of the control period in which a CAIR SO
Appendix A to Subpart III of Part 97 – States With Approved State Implementation Plan Revisions Concerning CAIR SO2 Opt-In Units
1. The following States have State Implementation Plan revisions under § 51.124(r) of this chapter approved by the Administrator and establishing procedures providing for CAIR SO
2. The following States have State Implementation Plan revisions under § 51.124(r) of this chapter approved by the Administrator and establishing procedures providing for CAIR SO
Subpart AAAA – CAIR NOX Ozone Season Trading Program General Provisions
§ 97.301 Purpose.
§ 97.302 Definitions.
The terms used in this subpart and subparts BBBB through IIII shall have the meanings set forth in this section as follows:
Account number means the identification number given by the Administrator to each CAIR NO
Acid Rain emissions limitation means a limitation on emissions of sulfur dioxide or nitrogen oxides under the Acid Rain Program.
Acid Rain Program means a multi-state sulfur dioxide and nitrogen oxides air pollution control and emission reduction program established by the Administrator under title IV of the CAA and parts 72 through 78 of this chapter.
Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator’s duly authorized representative.
Allocate or allocation means, with regard to CAIR NO
Allowance transfer deadline means, for a control period, midnight of November 30 (if it is a business day), or midnight of the first business day thereafter (if November 30 is not a business day), immediately following the control period and is the deadline by which a CAIR NO
Alternate CAIR designated representative means, for a CAIR NO
Automated data acquisition and handling system or DAHS means that component of the continuous emission monitoring system, or other emissions monitoring system approved for use under subpart HHHH of this part, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by subpart HHHH of this part.
Biomass means –
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other nonmerchantable material, and that is;
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
Boiler means an enclosed fossil-or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
Bottoming-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.
CAIR authorized account representative means, with regard to a general account, a responsible natural person who is authorized, in accordance with subparts BBBB, FFFF, and IIII of this part, to transfer and otherwise dispose of CAIR NO
CAIR designated representative means, for a CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR NO
CAIR permit means the legally binding and federally enforceable written document, or portion of such document, issued by the permitting authority under subpart CCCC of this part, including any permit revisions, specifying the CAIR NO
CAIR SO
CAIR SO
Certifying official means:
(1) For a corporation, a president, secretary, treasurer, or vice-president or the corporation in charge of a principal business function or any other person who performs similar policy or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, Federal, or other public agency, a principal executive officer or ranking elected official.
Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means any solid fuel classified as anthracite, bituminous, subbituminous, or lignite.
Coal-derived fuel means any fuel (whether in a solid, liquid, or gaseous state) produced by the mechanical, thermal, or chemical processing of coal.
Coal-fired means:
(1) Except for purposes of subpart EEEE of this part, combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during any year; or
(2) For purposes of subpart EEEE of this part, combusting any amount of coal or coal-derived fuel, alone or in combination with any amount of any other fuel, during a specified year.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine:
(1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and
(2) Producing during the 12-month period starting on the date the unit first produces electricity and during any calendar year after the calendar year in which the unit first produces electricity –
(i) For a topping-cycle cogeneration unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less then 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output.
(ii) For a bottoming-cycle cogeneration unit, useful power not less than 45 percent of total energy input;
(3) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel except biomass if the unit is a boiler.
Combustion turbine means:
(1) An enclosed device comprising a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the enclosed device under paragraph (1) of this definition is combined cycle, any associated duct burner, heat recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.305 and § 97.384(h).
(i) For a unit that is a CAIR NO
(ii) For a unit that is a CAIR NO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.305, for a unit that is not a CAIR NO
(i) For a unit with a date for commencement of commercial operation as defined in paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in paragraph (2) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1), (2), or (3) of this definition as appropriate.
(3) Notwithstanding paragraphs (1) and (2) of this definition, for a unit not serving a generator producing electricity for sale, the unit’s date of commencement of operation shall also be the unit’s date of commencement of commercial operation.
Commence operation means:
(1) To have begun any mechanical, chemical, or electronic process, including, with regard to a unit, start-up of a unit’s combustion chamber, except as provided in § 97.384(h).
(i) For a unit that undergoes a physical change (other than replacement of the unit by a unit at the same source) after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the date of commencement of operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit that is replaced by a unit at the same source (e.g., repowered) after the date the unit commences operation as defined in paragraph (1) of this definition, such date shall remain the replaced unit’s date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1) or (2) of this definition as appropriate, except as provided in § 97.384(h).
(2) Notwithstanding paragraph (1) of this definition and solely for purposes of subpart HHHH of this part, for a unit that is not a CAIR NO
(i) For a unit with a date for commencement of operation as defined in paragraph (2) of this definition and that subsequently undergoes a physical change (other than replacement of the unit by a unit at the same source), such date shall remain the date of commencement of operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of operation as defined in paragraph (2) of this definition and that is subsequently replaced by a unit at the same source (e.g., repowered), such date shall remain the replaced unit’s date of commencement of operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of operation as defined in paragraph (1) or (2) of this definition as appropriate.
Common stack means a single flue through which emissions from 2 or more units are exhausted.
Compliance account means a CAIR NO
Continuous emission monitoring system or CEMS means the equipment required under subpart HHHH of this part to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes (using an automated data acquisition and handling system (DAHS)), a permanent record of nitrogen oxides emissions, stack gas volumetric flow rate, stack gas moisture content, and oxygen or carbon dioxide concentration (as applicable), in a manner consistent with part 75 of this chapter. The following systems are the principal types of continuous emission monitoring systems required under subpart HHHH of this part:
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A nitrogen oxides concentration monitoring system, consisting of a NO
(3) A nitrogen oxides emission rate (or NO
(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(5) A carbon dioxide monitoring system, consisting of a CO
(6) An oxygen monitoring system, consisting of an O
Control period or ozone season means the period beginning May 1 of a calendar year, except as provided in § 97.306(c)(2) and ending on September 30 of the same year, inclusive.
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the CAIR designated representative and as determined by the Administrator in accordance with subpart HHHH of this part.
Excess emissions means any ton of nitrogen oxides emitted by the CAIR NO
Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.
Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in any calendar year.
Fuel oil means any petroleum-based fuel (including diesel fuel or petroleum derivatives such as oil tar) and any recycled or blended petroleum products or petroleum by-products used as a fuel whether in a liquid, solid, or gaseous state.
General account means a CAIR NO
Generator means a device that produces electricity.
Gross electrical output means, with regard to a cogeneration unit, electricity made available for use, including any such electricity used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Heat input means, with regard to a specified period of time, the product (in mmBtu/time) of the gross calorific value of the fuel (in Btu/lb) divided by 1,000,000 Btu/mmBtu and multiplied by the fuel feed rate into a combustion device (in lb of fuel/time), as measured, recorded, and reported to the Administrator by the CAIR designated representative and determined by the Administrator in accordance with subpart HHHH of this part and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust from other sources.
Heat input rate means the amount of heat input (in mmBtu) divided by unit operating time (in hr) or, with regard to a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Hg Budget Trading Program means a multi-state Hg air pollution control and emission reduction program approved and administered by the Administrator in accordance subpart HHHH of part 60 of this chapter and § 60.24(h)(6), or established by the Administrator under section 111 of the Clean Air Act, as a means of reducing national Hg emissions.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Maximum design heat input means the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis as of the initial installation of the unit as specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the requirements of subpart HHHH of this part, including a continuous emissions monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.
Most stringent State or Federal NO
Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output (in MWe) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount as of such completion as specified by the person conducting the physical change.
Oil-fired means, for purposes of subpart EEEE of this part, combusting fuel oil for more than 15.0 percent of the annual heat input in a specified year and not qualifying as coal-fired.
Operator means any person who operates, controls, or supervises a CAIR NO
Owner means any of the following persons:
(1) With regard to a CAIR NO
(i) Any holder of any portion of the legal or equitable title in a CAIR NO
(ii) Any holder of a leasehold interest in a CAIR NO
(iii) Any purchaser of power from a CAIR NO
(2) With regard to any general account, any person who has an ownership interest with respect to the CAIR NO
Permitting authority means the State air pollution control agency, local agency, other State agency, or other agency authorized by the Administrator to issue or revise permits to meet the requirements of the CAIR NO
Potential electrical output capacity means 33 percent of a unit(s maximum design heat input, divided by 3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the permitting authority or the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the permitting authority or the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to CAIR NO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.
Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent shutdown and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or shutdown unit (the replaced unit).
Repowered means, with regard to a unit, replacement of a coal-fired boiler with one of the following coal-fired technologies at the same source as the coal-fired boiler:
(1) Atmospheric or pressurized fluidized bed combustion;
(2) Integrated gasification combined cycle;
(3) Magnetohydrodynamics;
(4) Direct and indirect coal-fired turbines;
(5) Integrated gasification fuel cells; or
(6) As determined by the Administrator in consultation with the Secretary of Energy, a derivative of one or more of the technologies under paragraphs (1) through (5) of this definition and any other coal-fired technology capable of controlling multiple combustion emissions simultaneously with improved boiler or generation efficiency and with significantly greater waste reduction relative to the performance of technology in widespread commercial use as of January 1, 2005.
Sequential use of energy means:
(1) For a topping-cycle cogeneration unit, the use of reject heat from electricity production in a useful thermal energy application or process; or
(2) For a bottoming-cycle cogeneration unit, the use of reject heat from useful thermal energy application or process in electricity production.
Serial number means, for a CAIR NO
Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act.
Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. For purposes of section 502(c) of the Clean Air Act, a “source,” including a “source” with multiple units, shall be considered a single “facility.”
State means one of the States or the District of Columbia that is subject to the CAIR NO
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery. Compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Title V operating permit means a permit issued under title V of the Clean Air Act and part 70 or part 71 of this chapter.
Title V operating permit regulations means the regulations that the Administrator has approved or issued as meeting the requirements of title V of the Clean Air Act and part 70 or 71 of this chapter.
Ton means 2,000 pounds. For the purpose of determining compliance with the CAIR NO
Topping-cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful power, including electricity, and at least some of the reject heat from the electricity production is then used to provide useful thermal energy.
Total energy input means, with regard to a cogeneration unit, total energy of all forms supplied to the cogeneration unit, excluding energy produced by the cogeneration unit itself. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:
Total energy output means, with regard to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.
Unit means a stationary, fossil-fuel-fired boiler or combustion turbine or other stationary, fossil-fuel-fired combustion device.
Unit operating day means a calendar day in which a unit combusts any fuel.
Unit operating hour or hour of unit operation means an hour in which a unit combusts any fuel.
Useful power means, with regard to a cogeneration unit, electricity or mechanical energy made available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means, with regard to a cogeneration unit, thermal energy that is:
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., thermal energy used by an absorption chiller).
Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.
§ 97.303 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart and subparts BBBB through IIII are defined as follows:
§ 97.304 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State shall be CAIR NO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a CAIR NO
(b) The units in a State that meet the requirements set forth in paragraph (b)(1)(i), (b)(2)(i), or (b)(2)(ii) of this section shall not be CAIR NO
(1)(i) Any unit that is a CAIR NO
(A) Qualifying as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit; and
(B) Not serving at any time, since the later of November 15, 1990 or the start-up of the unit’s combustion chamber, a generator with nameplate capacity of more than 25 MWe supplying in any calendar year more than one-third of the unit(s potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and meets the requirements of paragraphs (b)(1)(i) of this section for at least one calendar year, but subsequently no longer meets all such requirements, the unit shall become a CAIR NO
(2)(i) Any unit that is a CAIR NO
(A) Qualifying as a solid waste incineration unit; and
(B) With an average annual fuel consumption of non-fossil fuel for 1985-1987 exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any 3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).
(ii) Any unit that is a CAIR NO
(A) Qualifying as a solid waste incineration unit; and
(B) With an average annual fuel consumption of non-fossil fuel for the first 3 calendar years of operation exceeding 80 percent (on a Btu basis) and an average annual fuel consumption of non-fossil fuel for any 3 consecutive calendar years after 1990 exceeding 80 percent (on a Btu basis).
(iii) If a unit qualifies as a solid waste incineration unit and meets the requirements of paragraph (b)(2)(i) or (ii) of this section for at least 3 consecutive calendar years, but subsequently no longer meets all such requirements, the unit shall become a CAIR NO
(c) A certifying official of an owner or operator of any unit may petition the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CAIR NO
(1) Petition content. The petition shall be in writing and include the identification of the unit and the relevant facts about the unit. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying official: “I am authorized to make this submission on behalf of the owners and operators of the unit for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) Submission. The petition and any other documents provided in connection with the petition shall be submitted to the Director of the Clean Air Markets Division (or its successor), U.S. Environmental Protection Agency, who will act on the petition as the Administrator’s duly authorized representative.
(3) Response. The Administrator will issue a written response to the petition and may request supplemental information relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CAIR NO
(d) Notwithstanding paragraphs (a) and (b) of this section, if a State submits, and the Administrator approves, a State implementation plan revision in accordance with § 51.123(ee)(1) of this chapter providing for the inclusion in the CAIR NO
§ 97.305 Retired unit exemption.
(a)(1) Any CAIR NO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the CAIR NO
(3) After receipt of the statement under paragraph (a)(2) of this section, the permitting authority will amend any permit under subpart CCCC of this part covering the source at which the unit is located to add the provisions and requirements of the exemption under paragraphs (a)(1) and (b) of this section.
(b) Special provisions. (1) A unit exempt under paragraph (a) of this section shall not emit any nitrogen oxides, starting on the date that the exemption takes effect.
(2) The Administrator or the permitting authority will allocate CAIR NO
(3) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the permitting authority or the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(4) The owners and operators and, to the extent applicable, the CAIR designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the CAIR NO
(5) A unit exempt under paragraph (a) of this section and located at a source that is required, or but for this exemption would be required, to have a title V operating permit shall not resume operation unless the CAIR designated representative of the source submits a complete CAIR permit application under § 97.322 for the unit not less than 18 months (or such lesser time provided by the permitting authority) before the later of January 1, 2009 or the date on which the unit resumes operation.
(6) On the earlier of the following dates, a unit exempt under paragraph (a) of this section shall lose its exemption:
(i) The date on which the CAIR designated representative submits a CAIR permit application for the unit under paragraph (b)(5) of this section;
(ii) The date on which the CAIR designated representative is required under paragraph (b)(5) of this section to submit a CAIR permit application for the unit; or
(iii) The date on which the unit resumes operation, if the CAIR designated representative is not required to submit a CAIR permit application for the unit.
(7) For the purpose of applying monitoring, reporting, and recordkeeping requirements under subpart HHHH of this part, a unit that loses its exemption under paragraph (a) of this section shall be treated as a unit that commences commercial operation on the first date on which the unit resumes operation.
§ 97.306 Standard requirements.
(a) Permit requirements. (1) The CAIR designated representative of each CAIR NO
(i) Submit to the permitting authority a complete CAIR permit application under § 97.322 in accordance with the deadlines specified in § 97.321; and
(ii) Submit in a timely manner any supplemental information that the permitting authority determines is necessary in order to review a CAIR permit application and issue or deny a CAIR permit.
(2) The owners and operators of each CAIR NO
(3) Except as provided in subpart IIII of this part, the owners and operators of a CAIR NO
(b) Monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the CAIR designated representative, of each CAIR NO
(2) The emissions measurements recorded and reported in accordance with subpart HHHH of this part shall be used to determine compliance by each CAIR NO
(c) Nitrogen oxides ozone season emission requirements. (1) As of the allowance transfer deadline for a control period, the owners and operators of each CAIR NO
(2) A CAIR NO
(3) A CAIR NO
(4) CAIR NO
(5) A CAIR NO
(6) A CAIR NO
(7) Upon recordation by the Administrator under subpart EEEE, FFFF, GGGG, or IIII of this part, every allocation, transfer, or deduction of a CAIR NO
(d) Excess emissions requirements. If a CAIR NO
(1) The owners and operators of the source and each CAIR NO
(2) Each ton of such excess emissions and each day of such control period shall constitute a separate violation of this subpart, the Clean Air Act, and applicable State law.
(e) Recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of the CAIR NO
(i) The certificate of representation under § 97.313 for the CAIR designated representative for the source and each CAIR NO
(ii) All emissions monitoring information, in accordance with subpart HHHH of this part, provided that to the extent that subpart HHHH of this part provides for a 3-year period for recordkeeping, the 3-year period shall apply.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under the CAIR NO
(iv) Copies of all documents used to complete a CAIR permit application and any other submission under the CAIR NO
(2) The CAIR designated representative of a CAIR NO
(f) Liability. (1) Each CAIR NO
(2) Any provision of the CAIR NO
(3) Any provision of the CAIR NO
(g) Effect on other authorities. No provision of the CAIR NO
§ 97.307 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the CAIR NO
(b) Unless otherwise stated, any time period scheduled, under the CAIR NO
(c) Unless otherwise stated, if the final day of any time period, under the CAIR NO
§ 97.308 Appeal procedures.
The appeal procedures for decisions of the Administrator under the CAIR NO
Appendix A to Subpart AAAA of Part 97 – States With Approved State Implementation Plan Revisions Concerning Applicability
The following States have State Implementation Plan revisions under § 51.123(ee)(1) of this chapter approved by the Administrator and providing for expansion of the applicability provisions to include all non-EGUs subject to the respective State’s emission trading program approved under § 51.121(p) of this chapter:
Subpart BBBB – CAIR Designated Representative for CAIR NOX Ozone Season Sources
§ 97.310 Authorization and responsibilities of CAIR designated representative.
(a) Except as provided under § 97.311, each CAIR NO
(b) The CAIR designated representative of the CAIR NO
(c) Upon receipt by the Administrator of a complete certificate of representation under § 97.313, the CAIR designated representative of the source shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the CAIR NO
(d) No CAIR permit will be issued, no emissions data reports will be accepted, and no CAIR NO
(e)(1) Each submission under the CAIR NO
(2) The permitting authority and the Administrator will accept or act on a submission made on behalf of owner or operators of a CAIR NO
§ 97.311 Alternate CAIR designated representative.
(a) A certificate of representation under § 97.313 may designate one and only one alternate CAIR designated representative, who may act on behalf of the CAIR designated representative. The agreement by which the alternate CAIR designated representative is selected shall include a procedure for authorizing the alternate CAIR designated representative to act in lieu of the CAIR designated representative.
(b) Upon receipt by the Administrator of a complete certificate of representation under § 97.313, any representation, action, inaction, or submission by the alternate CAIR designated representative shall be deemed to be a representation, action, inaction, or submission by the CAIR designated representative.
(c) Except in this section and §§ 97.302, 97.310(a) and (d), 97.312, 97.313, 97.315, 97.351, and 97.382, whenever the term “CAIR designated representative” is used in subparts AAAA through IIII of this part, the term shall be construed to include the CAIR designated representative or any alternate CAIR designated representative.
§ 97.312 Changing CAIR designated representative and alternate CAIR designated representative; changes in owners and operators.
(a) Changing CAIR designated representative. The CAIR designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.313. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous CAIR designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new CAIR designated representative and the owners and operators of the CAIR NO
(b) Changing alternate CAIR designated representative. The alternate CAIR designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.313. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate CAIR designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate CAIR designated representative and the owners and operators of the CAIR NO
(c) Changes in owners and operators. (1) In the event an owner or operator of a CAIR NO
(2) Within 30 days following any change in the owners and operators of a CAIR NO
§ 97.313 Certificate of representation.
(a) A complete certificate of representation for a CAIR designated representative or an alternate CAIR designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the CAIR NO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the CAIR designated representative and any alternate CAIR designated representative.
(3) A list of the owners and operators of the CAIR NO
(4) The following certification statements by the CAIR designated representative and any alternate CAIR designated representative –
(i) “I certify that I was selected as the CAIR designated representative or alternate CAIR designated representative, as applicable, by an agreement binding on the owners and operators of the source and each CAIR NO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CAIR NO
(iii) “I certify that the owners and operators of the source and of each CAIR NO
(iv) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a CAIR NO
(5) The signature of the CAIR designated representative and any alternate CAIR designated representative and the dates signed.
(b) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
§ 97.314 Objections concerning CAIR designated representative.
(a) Once a complete certificate of representation under § 97.313 has been submitted and received, the permitting authority and the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.313 is received by the Administrator.
(b) Except as provided in § 97.312(a) or (b), no objection or other communication submitted to the permitting authority or the Administrator concerning the authorization, or any representation, action, inaction, or submission, of the CAIR designated representative shall affect any representation, action, inaction, or submission of the CAIR designated representative or the finality of any decision or order by the permitting authority or the Administrator under the CAIR NO
(c) Neither the permitting authority nor the Administrator will adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any CAIR designated representative, including private legal disputes concerning the proceeds of CAIR NO
§ 97.315 Delegation by CAIR designated representative and alternate CAIR designated representative.
(a) A CAIR designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this part.
(b) An alternate CAIR designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this part.
(c) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the CAIR designated representative or alternate CAIR designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such CAIR designated representative or alternate CAIR designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such CAIR designated representative or alternate CAIR designated representative:
(i) “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a CAIR designated representative or alternate CAIR designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.315(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.315(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.315 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the CAIR designated representative or alternate CAIR designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such CAIR designated representative or alternate CAIR designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the CAIR designated representative or alternate CAIR designated representative submitting such notice of delegation.
Subpart CCCC – Permits
§ 97.320 General CAIR NOX Ozone Season Trading Program permit requirements.
(a) For each CAIR NO
(b) Each CAIR permit shall contain, with regard to the CAIR NO
§ 97.321 Submission of CAIR permit applications.
(a) Duty to apply. The CAIR designated representative of any CAIR NO
(b) Duty to reapply. For a CAIR NO
§ 97.322 Information requirements for CAIR permit applications.
A complete CAIR permit application shall include the following elements concerning the CAIR NO
(a) Identification of the CAIR NO
(b) Identification of each CAIR NO
(c) The standard requirements under § 97.306.
§ 97.323 CAIR permit contents and term.
(a) Each CAIR permit will contain, in a format prescribed by the permitting authority, all elements required for a complete CAIR permit application under § 97.322.
(b) Each CAIR permit is deemed to incorporate automatically the definitions of terms under § 97.302 and, upon recordation by the Administrator under subpart EEEE, FFFF, GGGG, or IIII of this part, every allocation, transfer, or deduction of a CAIR NO
(c) The term of the CAIR permit will be set by the permitting authority, as necessary to facilitate coordination of the renewal of the CAIR permit with issuance, revision, or renewal of the CAIR NO
§ 97.324 CAIR permit revisions.
Except as provided in § 97.323(b), the permitting authority will revise the CAIR permit, as necessary, in accordance with the permitting authority’s title V operating permits regulations or the permitting authority’s regulations for other federally enforceable permits as applicable addressing permit revisions.
Subpart DDDD [Reserved]
Subpart EEEE – CAIR NOX Ozone Season Allowance Allocations
§ 97.340 State trading budgets.
(a) Except as provided in paragraph (b) of this section, the State trading budgets for annual allocations of CAIR NO
State | State trading budget for 2009-2014 (tons) | State trading budget for 2015 and thereafter (tons) |
---|---|---|
Alabama | 32,182 | 26,818 |
Arkansas | 11,515 | 9,597 |
Connecticut | 2,559 | 2,559 |
Delaware | 2,226 | 1,855 |
District of Columbia | 112 | 94 |
Florida | 47,912 | 39,926 |
Illinois | 30,701 | 28,981 |
Indiana | 45,952 | 39,273 |
Iowa | 14,263 | 11,886 |
Kentucky | 36,045 | 30,587 |
Louisiana | 17,085 | 14,238 |
Maryland | 12,834 | 10,695 |
Massachusetts | 7,551 | 6,293 |
Michigan | 28,971 | 24,142 |
Mississippi | 8,714 | 7,262 |
Missouri | 26,678 | 22,231 |
New Jersey | 6,654 | 5,545 |
New York | 20,632 | 17,193 |
North Carolina | 28,392 | 23,660 |
Ohio | 45,664 | 39,945 |
Pennsylvania | 42,171 | 35,143 |
South Carolina | 15,249 | 12,707 |
Tennessee | 22,842 | 19,035 |
Virginia | 15,994 | 13,328 |
West Virginia | 26,859 | 26,525 |
Wisconsin | 17,987 | 14,989 |
(b) Upon approval by the Administrator of a State’s State implementation plan revision under § 51.123(ee)(1) of this chapter providing for the inclusion in the CAIR NO
§ 97.341 Timing requirements for CAIR NOX Ozone Season allowance allocations.
(a) The Administrator will determine by order the CAIR NO
(b) By July 31, 2011 and July 31 of each year thereafter, the Administrator will determine by order the CAIR NO
(c) By April 30, 2009 and April 30 of each year thereafter, the Administrator will determine by order the CAIR NO
(d) The Administrator will make available to the public each determination of CAIR NO
§ 97.342 CAIR NOX Ozone Season allowance allocations.
(a)(1) The baseline heat input (in mmBtu) used with respect to CAIR NO
(i) For units commencing operation before January 1, 2001 the average of the 3 highest amounts of the unit’s adjusted control period heat input for 2000 through 2004, with the adjusted control period heat input for each year calculated as follows:
(A) If the unit is coal-fired during the year, the unit’s control period heat input for such year is multiplied by 100 percent;
(B) If the unit is oil-fired during the year, the unit’s control period heat input for such year is multiplied by 60 percent; and
(C) If the unit is not subject to paragraph (a)(1)(i)(A) or (B) of this section, the unit’s control period heat input for such year is multiplied by 40 percent.
(ii) For units commencing operation on or after January 1, 2001 and operating each calendar year during a period of 5 or more consecutive calendar years, the average of the 3 highest amounts of the unit’s total converted control period heat input over the first such 5 years.
(2)(i) A unit’s control period heat input, and a unit’s status as coal-fired or oil-fired, for a calendar year under paragraph (a)(1)(i) of this section, and a unit’s total tons of NO
(ii) A unit’s converted control period heat input for a calendar year specified under paragraph (a)(1)(ii) of this section equals:
(A) Except as provided in paragraph (a)(2)(ii)(B) or (C) of this section, the control period gross electrical output of the generator or generators served by the unit multiplied by 7,900 Btu/kWh, if the unit is coal-fired for the year, or 6,675 Btu/kWh, if the unit is not coal-fired for the year, and divided by 1,000,000 Btu/mmBtu, provided that if a generator is served by 2 or more units, then the gross electrical output of the generator will be attributed to each unit in proportion to the unit’s share of the total control period heat input of such units for the year;
(B) For a unit that is a boiler and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the total heat energy (in Btu) of the steam produced by the boiler during the control period, divided by 0.8 and by 1,000,000 Btu/mmBtu; or
(C) For a unit that is a combustion turbine and has equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy, the control period gross electrical output of the enclosed device comprising the compressor, combustor, and turbine multiplied by 3,413 Btu/kWh, plus the total heat energy (in Btu) of the steam produced by any associated heat recovery steam generator during the control period divided by 0.8, and with the sum divided by 1,000,000 Btu/mmBtu.
(iii) Gross electrical output and total heat energy under paragraph (a)(2)(ii) of this section will be determined based on the best available data reported to the Administrator for the unit (in a format prescribed by the Administrator).
(3) The Administrator will determine what data are the best available data under paragraph (a)(2) of this section by weighing the likelihood that data are accurate and reliable and giving greater weight to data submitted to a governmental entity in compliance with legal requirements or substantiated by an independent entity.
(b)(1) For each control period in 2009 and thereafter, the Administrator will allocate to all CAIR NO
(2) The Administrator will allocate CAIR NO
(c) For each control period in 2009 and thereafter, the Administrator will allocate CAIR NO
(1) The Administrator will establish a separate new unit set-aside for each control period. Each new unit set-aside will be allocated CAIR NO
(2) The CAIR designated representative of such a CAIR NO
(3) In a CAIR NO
(4) The Administrator will review each CAIR NO
(i) The Administrator will accept an allowance allocation request only if the request meets, or is adjusted by the Administrator as necessary to meet, the requirements of paragraphs (c)(2) and (3) of this section.
(ii) On or after February 1 before the control period, the Administrator will determine the sum of the CAIR NO
(iii) If the amount of CAIR NO
(iv) If the amount of CAIR NO
(v) The Administrator will notify each CAIR designated representative that submitted an allowance allocation request of the amount of CAIR NO
(d) If, after completion of the procedures under paragraph (c)(4) of this section for a control period, any unallocated CAIR NO
(e) If the Administrator determines that CAIR NO
(1) Except as provided in paragraph (e)(2) or (3) of this section, the Administrator will not record such CAIR NO
(2) If the Administrator already recorded such CAIR NO
(3) If the Administrator already recorded such CAIR NO
(4) The Administrator will transfer the CAIR NO
(a) Notwithstanding §§ 97.341, 97.342, and 97.353 if a State submits, and the Administrator approves, a State implementation plan revision in accordance with § 51.123(ee)(2) of this chapter providing for allocation of CAIR NO
(b) In implementing paragraph (a) of this section and §§ 97.341, 97.342, and 97.353, the Administrator will ensure that the total amount of CAIR NO
Appendix A to Subpart EEEE of Part 97 – States With Approved State Implementation Plan Revisions Concerning Allocations
The following States have State Implementation Plan revisions under § 51.123(ee)(2) of this chapter approved by the Administrator and providing for allocation of CAIR NO
Subpart FFFF – CAIR NOX Ozone Season Allowance Tracking System
§ 97.350 [Reserved]
§ 97.351 Establishment of accounts.
(a) Compliance accounts. Except as provided in § 97.384(e), upon receipt of a complete certificate of representation under § 97.313, the Administrator will establish a compliance account for the CAIR NO
(b) General accounts – (1) Application for general account. (i) Any person may apply to open a general account for the purpose of holding and transferring CAIR NO
(ii) A complete application for a general account shall be submitted to the Administrator and shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the CAIR authorized account representative and any alternate CAIR authorized account representative;
(B) Organization name and type of organization, if applicable;
(C) A list of all persons subject to a binding agreement for the CAIR authorized account representative and any alternate CAIR authorized account representative to represent their ownership interest with respect to the CAIR NO
(D) The following certification statement by the CAIR authorized account representative and any alternate CAIR authorized account representative: “I certify that I was selected as the CAIR authorized account representative or the alternate CAIR authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to CAIR NO
(E) The signature of the CAIR authorized account representative and any alternate CAIR authorized account representative and the dates signed.
(iii) Unless otherwise required by the permitting authority or the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the permitting authority or the Administrator. Neither the permitting authority nor the Administrator shall be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2) Authorization of CAIR authorized account representative and alternate CAIR authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (b)(1) of this section:
(A) The Administrator will establish a general account for the person or persons for whom the application is submitted.
(B) The CAIR authorized account representative and any alternate CAIR authorized account representative for the general account shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CAIR NO
(C) Any representation, action, inaction, or submission by any alternate CAIR authorized account representative shall be deemed to be a representation, action, inaction, or submission by the CAIR authorized account representative.
(ii) Each submission concerning the general account shall be submitted, signed, and certified by the CAIR authorized account representative or any alternate CAIR authorized account representative for the persons having an ownership interest with respect to CAIR NO
(iii) The Administrator will accept or act on a submission concerning the general account only if the submission has been made, signed, and certified in accordance with paragraph (b)(2)(ii) of this section.
(3) Changing CAIR authorized account representative and alternate CAIR authorized account representative; changes in persons with ownership interest. (i) The CAIR authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous CAIR authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new CAIR authorized account representative and the persons with an ownership interest with respect to the CAIR NO
(ii) The alternate CAIR authorized account representative for a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (b)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate CAIR authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate CAIR authorized account representative and the persons with an ownership interest with respect to the CAIR NO
(iii)(A) In the event a person having an ownership interest with respect to CAIR NO
(B) Within 30 days following any change in the persons having an ownership interest with respect to CAIR NO
(4) Objections concerning CAIR authorized account representative and alternate CAIR authorized account representative. (i) Once a complete application for a general account under paragraph (b)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (b)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (b)(3)(i) or (ii) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the CAIR authorized account representative or any alternate CAIR authorized account representative for a general account shall affect any representation, action, inaction, or submission of the CAIR authorized account representative or any alternate CAIR authorized account representative or the finality of any decision or order by the Administrator under the CAIR NO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the CAIR authorized account representative or any alternate CAIR authorized account representative for a general account, including private legal disputes concerning the proceeds of CAIR NO
(5) Delegation by CAIR authorized account representative and alternate CAIR authorized account representative. (i) A CAIR authorized account representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under subparts FFFF and GGGG of this part.
(ii) An alternate CAIR authorized account representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under subparts FFFF and GGGG of this part.
(iii) In order to delegate authority to make an electronic submission to the Administrator in accordance with paragraph (b)(5)(i) or (ii) of this section, the CAIR authorized account representative or alternate CAIR authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such CAIR authorized account representative or alternate CAIR authorized account representative;
(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (b)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such CAIR authorized account representative or alternate CAIR authorized account representative: “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a CAIR authorized account representative or alternate CAIR authorized representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.351(b)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such CAIR authorized account representative or alternate CAIR authorized account representative: Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.351(b)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.351(b)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (b)(5)(iii) of this section shall be effective, with regard to the CAIR authorized account representative or alternate CAIR authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such CAIR authorized account representative or alternate CAIR authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (b)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (b)(5)(iv) of this section shall be deemed to be an electronic submission by the CAIR designated representative or alternate CAIR designated representative submitting such notice of delegation.
(c) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a) or (b) of this section.
Following the establishment of a CAIR NO
§ 97.353 Recordation of CAIR NOX Ozone Season allowance allocations.
(a) By September 30, 2007, the Administrator will record in the CAIR NO
(b) By September 30, 2008, the Administrator will record in the CAIR NO
(c) By September 30, 2009, the Administrator will record in the CAIR NO
(d) By December 1, 2010 and December 1 of each year thereafter, the Administrator will record in the CAIR NO
(e) By September 1, 2009 and September 1 of each year thereafter, the Administrator will record in the CAIR NO
(f) Serial numbers for allocated CAIR NO
§ 97.354 Compliance with CAIR NOX emissions limitation.
(a) Allowance transfer deadline. The CAIR NO
(1) Were allocated for the control period in the year or a prior year; and
(2) Are held in the compliance account as of the allowance transfer deadline for the control period or are transferred into the compliance account by a CAIR NO
(b) Deductions for compliance. Following the recordation, in accordance with § 97.361, of CAIR NO
(1) Until the amount of CAIR NO
(2) If there are insufficient CAIR NO
(c)(1) Identification of CAIR NO
(2) First-in, first-out. The Administrator will deduct CAIR NO
(i) Any CAIR NO
(ii) Any CAIR NO
(d) Deductions for excess emissions. (1) After making the deductions for compliance under paragraph (b) of this section for a control period in a calendar year in which the CAIR NO
(2) Any allowance deduction required under paragraph (d)(1) of this section shall not affect the liability of the owners and operators of the CAIR NO
(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and (d) of this section and subpart IIII.
(f) Administrator(s action on submissions. (1) The Administrator may review and conduct independent audits concerning any submission under the CAIR NO
(2) The Administrator may deduct CAIR NO
§ 97.355 Banking.
(a) CAIR NO
(b) Any CAIR NO
§ 97.356 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any CAIR NO
§ 97.357 Closing of general accounts.
(a) The CAIR authorized account representative of a general account may submit to the Administrator a request to close the account, which shall include a correctly submitted allowance transfer under §§ 97.360 and 97.361 for any CAIR NO
(b) If a general account has no allowance transfers in or out of the account for a 12-month period or longer and does not contain any CAIR NO
Subpart GGGG – CAIR NOX Ozone Season Allowance Transfers
§ 97.360 Submission of CAIR NOX Ozone Season allowance transfers.
A CAIR authorized account representative seeking recordation of a CAIR NO
(a) The account numbers for both the transferor and transferee accounts;
(b) The serial number of each CAIR NO
(c) The name and signature of the CAIR authorized account representative of the transferor account and the date signed.
§ 97.361 EPA recordation.
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a CAIR NO
(1) The transfer is correctly submitted under § 97.360; and
(2) The transferor account includes each CAIR NO
(b) A CAIR NO
(c) Where a CAIR NO
§ 97.362 Notification.
(a) Notification of recordation. Within 5 business days of recordation of a CAIR NO
(b) Notification of non-recordation. Within 10 business days of receipt of a CAIR NO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
(c) Nothing in this section shall preclude the submission of a CAIR NO
Subpart HHHH – Monitoring and Reporting
§ 97.370 General requirements.
The owners and operators, and to the extent applicable, the CAIR designated representative, of a CAIR NO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each CAIR NO
(1) Install all monitoring systems required under this subpart for monitoring NO
(2) Successfully complete all certification tests required under § 97.371 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator shall meet the monitoring system certification and other requirements of paragraphs (a)(1) and (2) of this section on or before the following dates. The owner or operator shall record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section on and after the following dates.
(1) For the owner or operator of a CAIR NO
(2) For the owner or operator of a CAIR NO
(i) 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation; or
(ii) May 1, 2008.
(3) For the owner or operator of a CAIR NO
(i) 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which the unit commences commercial operation; or
(ii) If the compliance date under paragraph (b)(3)(i) of this section is not during a control period, May 1 immediately following the compliance date under paragraph (b)(3)(i) of this section.
(4) For the owner or operator of a CAIR NO
(5) For the owner or operator of a CAIR NO
(i) 90 unit operating days or 180 calendar days, whichever occurs first, after the date on which emissions first exit to the atmosphere through the new stack or flue or add-on NO
(ii) If the compliance date under paragraph (b)(5)(i) of this section is not during a control period, May 1 immediately following the compliance date under paragraph (b)(5)(i) of this section.
(6) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of this section, for the owner or operator of a unit for which a CAIR NO
(7) Notwithstanding the dates in paragraphs (b)(1), (2), and (3) of this section, for the owner or operator of a CAIR NO
(c) Reporting data. The owner or operator of a CAIR NO
(d) Prohibitions. (1) No owner or operator of a CAIR NO
(2) No owner or operator of a CAIR NO
(3) No owner or operator of a CAIR NO
(4) No owner or operator of a CAIR NO
(i) During the period that the unit is covered by an exemption under § 97.305 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The CAIR designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.371(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a CAIR NO
§ 97.371 Initial certification and recertification procedures.
(a) The owner or operator of a CAIR NO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendix B, appendix D, and appendix E to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.370(a)(1) exempt from initial certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the NO
(d) Except as provided in paragraph (a) of this section, the owner or operator of a CAIR NO
(1) Requirements for initial certification. The owner or operator shall ensure that each continuous monitoring system under § 97.370(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.370(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.370(a)(1) that may significantly affect the ability of the system to accurately measure or record NO
(3) Approval process for initial certification and recertification. Paragraphs (d)(3)(i) through (iv) of this section apply to both initial certification and recertification of a continuous monitoring system under § 97.370(a)(1). For recertifications, replace the words “certification” and “initial certification” with the word “recertification”, replace the word “certified” with the word “recertified,” and follow the procedures in §§ 75.20(b)(5) and (g)(7) of this chapter in lieu of the procedures in paragraph (d)(3)(v) of this section.
(i) Notification of certification. The CAIR designated representative shall submit to the appropriate EPA Regional Office and the Administrator written notice of the dates of certification testing, in accordance with § 97.373.
(ii) Certification application. The CAIR designated representative shall submit to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the CAIR NO
(iv) Certification application approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the CAIR NO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the CAIR designated representative must submit the additional information required to complete the certification application. If the CAIR designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section. The 120-day review period shall not begin before receipt of a complete certification application.
(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter). The owner or operator shall follow the procedures for loss of certification in paragraph (d)(3)(v) of this section for each monitoring system that is disapproved for initial certification.
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.372(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NO
(2) For a disapproved NO
(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(5) For a disapproved excepted NO
(B) The CAIR designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) Initial certification and recertification procedures for units using the low mass emission excepted methodology under § 75.19 of this chapter. The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) Certification/recertification procedures for alternative monitoring systems. The CAIR designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
§ 97.372 Out of control periods.
(a) Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D or subpart H of, or appendix D or appendix E to, part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.371 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the permitting authority or the Administrator. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 97.371 for each disapproved monitoring system.
§ 97.373 Notifications.
The CAIR designated representative for a CAIR NO
§ 97.374 Recordkeeping and reporting.
(a) General provisions. The CAIR designated representative shall comply with all recordkeeping and reporting requirements in this section, the applicable recordkeeping and reporting requirements under § 75.73 of this chapter, and the requirements of § 97.310(e)(1).
(b) Monitoring Plans. The owner or operator of a CAIR NO
(c) Certification Applications. The CAIR designated representative shall submit an application to the Administrator within 45 days after completing all initial certification or recertification tests required under § 97.371, including the information required under § 75.63 of this chapter.
(d) Quarterly reports. The CAIR designated representative shall submit quarterly reports, as follows:
(1) If the CAIR NO
(i) For a unit that commences commercial operation before July 1, 2007, the calendar quarter covering May 1, 2008 through June 30, 2008;
(ii) For a unit that commences commercial operation on or after July 1, 2007, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.370(b), unless that quarter is the third or fourth quarter of 2007 or the first quarter of 2008, in which case reporting shall commence in the quarter covering May 1, 2008 through June 30, 2008;
(iii) Notwithstanding paragraphs (d)(1) (i) and (ii) of this section, for a unit for which a CAIR opt-in permit application is submitted and not withdrawn and a CAIR opt-in permit is not yet issued or denied under subpart IIII of this part, the calendar quarter corresponding to the date specified in § 97.384(b); and
(iv) Notwithstanding paragraphs (d)(1) (i) and (ii) of this section, for a CAIR NO
(2) If the CAIR NO
(i) Meet the requirements of subpart H of part 75 (concerning monitoring of NO
(ii) Meet the requirements of subpart H of part 75 for the control period (including the requirements in § 75.74(c) of this chapter) and report NO
(A) For a unit that commences commercial operation before July 1, 2007, the calendar quarter covering May 1, 2008 through June 30, 2008;
(B) For a unit that commences commercial operation on or after July 1, 2007, the calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.370(b), unless that date is not during a control period, in which case reporting shall commence in the quarter that includes May 1 through June 30 of the first control period after such date;
(C) Notwithstanding paragraphs (d)(2)(ii)(A) and (2)(ii)(B) of this section, for a unit for which a CAIR opt-in permit application is submitted and not withdrawn and a CAIR opt-in permit is not yet issued or denied under subpart IIII of this part, the calendar quarter corresponding to the date specified in § 97.384(b); and
(D) Notwithstanding paragraphs (d)(2)(ii)(A) and (2)(ii)(B) of this section, for a CAIR NO
(3) The CAIR designated representative shall submit each quarterly report to the Administrator within 30 days following the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.
(4) For CAIR NO
(e) Compliance certification. The CAIR designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications;
(2) For a unit with add-on NO
(3) For a unit that is reporting on a control period basis under paragraph (d)(2)(ii) of this section, the NO
§ 97.375 Petitions.
The CAIR designated representative of a CAIR NO
Subpart IIII – CAIR NOX Ozone Season Opt-in Units
§ 97.380 Applicability.
A CAIR NO
(a) Is located in a State that submits, and for which the Administrator approves, a State implementation plan revision in accordance with § 51.123(ee)(3) (i), (ii), or (iii) of this chapter establishing procedures concerning CAIR Ozone Season opt-in units;
(b) Is not a CAIR NO
(c) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;
(d) Has or is required or qualified to have a title V operating permit or other federally enforceable permit; and
(e) Vents all of its emissions to a stack and can meet the monitoring, recordkeeping, and reporting requirements of subpart HHHH of this part.
§ 97.381 General.
(a) Except as otherwise provided in §§ 97.301 through 97.304, §§ 97.306 through 97.308, and subparts BBBB and CCCC and subparts FFFF through HHHH of this part, a CAIR NO
(b) Solely for purposes of applying, as provided in this subpart, the requirements of subpart HHHH of this part to a unit for which a CAIR opt-in permit application is submitted and not withdrawn and a CAIR opt-in permit is not yet issued or denied under this subpart, such unit shall be treated as a CAIR NO
§ 97.382 CAIR designated representative.
Any CAIR NO
§ 97.383 Applying for CAIR opt-in permit.
(a) Applying for initial CAIR opt-in permit. The CAIR designated representative of a unit meeting the requirements for a CAIR NO
(1) A complete CAIR permit application under § 97.322;
(2) A certification, in a format specified by the permitting authority, that the unit:
(i) Is not a CAIR NO
(ii) Is not covered by a retired unit exemption under § 72.8 of this chapter that is in effect;
(iii) Vents all of its emissions to a stack; and
(iv) Has documented heat input for more than 876 hours during the 6 months immediately preceding submission of the CAIR permit application under § 97.322;
(3) A monitoring plan in accordance with subpart HHHH of this part;
(4) A complete certificate of representation under § 97.313 consistent with § 97.382, if no CAIR designated representative has been previously designated for the source that includes the unit; and
(5) A statement, in a format specified by the permitting authority, whether the CAIR designated representative requests that the unit be allocated CAIR NO
(b) Duty to reapply. (1) The CAIR designated representative of a CAIR NO
(2) Unless the permitting authority issues a notification of acceptance of withdrawal of the CAIR NO
§ 97.384 Opt-in process.
The permitting authority will issue or deny a CAIR opt-in permit for a unit for which an initial application for a CAIR opt-in permit under § 97.383 is submitted in accordance with the following, to the extent provided in a State implementation plan revision submitted in accordance with § 51.123(ee)(3)(i), (ii), or (iii) of this chapter and approved by the Administrator:
(a) Interim review of monitoring plan. The permitting authority and the Administrator will determine, on an interim basis, the sufficiency of the monitoring plan accompanying the initial application for a CAIR opt-in permit under § 97.383. A monitoring plan is sufficient, for purposes of interim review, if the plan appears to contain information demonstrating that the NO
(b) Monitoring and reporting. (1)(i) If the permitting authority and the Administrator determine that the monitoring plan is sufficient under paragraph (a) of this section, the owner or operator shall monitor and report the NO
(ii) The monitoring and reporting under paragraph (b)(1)(i) of this section shall include the entire control period immediately before the date on which the unit enters the CAIR NO
(2) To the extent the NO
(c) Baseline heat input. The unit’s baseline heat input shall equal:
(1) If the unit’s NO
(2) If the unit’s NO
(d) Baseline NO
(1) If the unit’s NO
(2) If the unit’s NO
(3) If the unit’s NO
(e) Issuance of CAIR opt-in permit. After calculating the baseline heat input and the baseline NO
(f) Issuance of denial of CAIR opt-in permit. Notwithstanding paragraphs (a) through (e) of this section, if at any time before issuance of a CAIR opt-in permit for the unit, the permitting authority determines that the CAIR designated representative fails to show that the unit meets the requirements for a CAIR NO
(g) Date of entry into CAIR NO
(h) Repowered CAIR NO
(2) Notwithstanding paragraphs (c) and (d) of this section, as of the date of start-up under paragraph (h)(1) of this section, the repowered unit shall be deemed to have the same date of commencement of operation, date of commencement of commercial operation, baseline heat input, and baseline NO
§ 97.385 CAIR opt-in permit contents.
(a) Each CAIR opt-in permit will contain:
(1) All elements required for a complete CAIR permit application under § 97.322;
(2) The certification in § 97.383(a)(2);
(3) The unit’s baseline heat input under § 97.384(c);
(4) The unit’s baseline NO
(5) A statement whether the unit is to be allocated CAIR NO
(6) A statement that the unit may withdraw from the CAIR NO
(7) A statement that the unit is subject to, and the owners and operators of the unit must comply with, the requirements of § 97.387.
(b) Each CAIR opt-in permit is deemed to incorporate automatically the definitions of terms under § 97.302 and, upon recordation by the Administrator under subpart FFFF or GGGG of this part or this subpart, every allocation, transfer, or deduction of CAIR NO
(c) The CAIR opt-in permit shall be included, in a format specified by the permitting authority, in the CAIR permit for the source where the CAIR NO
§ 97.386 Withdrawal from CAIR NOX Ozone Season Trading Program.
Except as provided under paragraph (g) of this section, a CAIR NO
(a) Requesting withdrawal. In order to withdraw a CAIR NO
(b) Conditions for withdrawal. Before a CAIR NO
(1) For the control period ending on the date on which the withdrawal is to be effective, the source that includes the CAIR NO
(2) After the requirement for withdrawal under paragraph (b)(1) of this section is met, the Administrator will deduct from the compliance account of the source that includes the CAIR NO
(c) Notification. (1) After the requirements for withdrawal under paragraphs (a) and (b) of this section are met (including deduction of the full amount of CAIR NO
(2) If the requirements for withdrawal under paragraphs (a) and (b) of this section are not met, the permitting authority will issue a notification to the CAIR designated representative of the CAIR NO
(d) Permit amendment. After the permitting authority issues a notification under paragraph (c)(1) of this section that the requirements for withdrawal have been met, the permitting authority will revise the CAIR permit covering the CAIR NO
(e) Reapplication upon failure to meet conditions of withdrawal. If the permitting authority denies the CAIR NO
(f) Ability to reapply to the CAIR NO
(g) Inability to withdraw. Notwithstanding paragraphs (a) through (f) of this section, a CAIR NO
§ 97.387 Change in regulatory status.
(a) Notification. If a CAIR NO
(b) Permitting authority’s and Administrator’s actions. (1) If a CAIR NO
(2)(i) The Administrator will deduct from the compliance account of the source that includes the CAIR NO
(A) Any CAIR NO
(B) If the date on which the CAIR NO
(ii) The CAIR designated representative shall ensure that the compliance account of the source that includes the CAIR NO
(3)(i) For every control period after the date on which the CAIR NO
(ii) If the date on which the CAIR NO
(A) The amount of CAIR NO
(B) The ratio of the number of days, in the control period, starting with the date on which the CAIR NO
(C) Rounded to the nearest whole allowance as appropriate.
§ 97.388 CAIR NOX Ozone Season allowance allocations to CAIR NOX Ozone Season opt-in units.
(a) Timing requirements. (1) When the CAIR opt-in permit is issued under § 97.384(e), the permitting authority will allocate CAIR NO
(2) By no later than July 31 of the control period after the control period in which a CAIR NO
(b) Calculation of allocation. For each control period for which a CAIR NO
(1) The heat input (in mmBtu) used for calculating the CAIR NO
(i) The CAIR NO
(ii) The CAIR NO
(2) The NO
(i) The CAIR NO
(ii) The most stringent State or Federal NO
(3) The permitting authority will allocate CAIR NO
(c) Notwithstanding paragraph (b) of this section and if the CAIR designated representative requests, and the permitting authority issues a CAIR opt-in permit (based on a demonstration of the intent to repower stated under § 97.383 (a)(5)) providing for, allocation to a CAIR NO
(1) For each control period in 2009 through 2014 for which the CAIR NO
(i) The heat input (in mmBtu) used for calculating CAIR NO
(ii) The NO
(A) The CAIR NO
(B) The most stringent State or Federal NO
(iii) The permitting authority will allocate CAIR NO
(2) For each control period in 2015 and thereafter for which the CAIR NO
(i) The heat input (in mmBtu) used for calculating the CAIR NO
(ii) The NO
(A) 0.15 lb/mmBtu;
(B) The CAIR NO
(C) The most stringent State or Federal NO
(iii) The permitting authority will allocate CAIR NO
(d) Recordation. If provided in a State implementation plan revision submitted in accordance with § 51.123(ee)(3)(i), (ii), or (iii) of this chapter and approved by the Administrator:
(1) The Administrator will record, in the compliance account of the source that includes the CAIR NO
(2) By September 1 of the control period in which a CAIR NO
Appendix A to Subpart IIII of Part 97 – States With Approved State Implementation Plan Revisions Concerning CAIR NOX Ozone Season Opt-in Units
1. The following States have State Implementation Plan revisions under § 51.123(ee)(3) of this chapter approved by the Administrator and establishing procedures providing for CAIR NO
2. The following States have State Implementation Plan revisions under § 51.123(ee)(3) of this chapter approved by the Administrator and establishing procedures providing for CAIR NO
Subpart AAAAA – CSAPR NOX Annual Trading Program
§ 97.401 Purpose.
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Cross-State Air Pollution Rule (CSAPR) NO
§ 97.402 Definitions.
The terms used in this subpart shall have the meanings set forth in this section as follows, provided that any term that includes the acronym “CSAPR” shall be considered synonymous with a term that is used in a SIP revision approved by the Administrator under § 52.38 or § 52.39 of this chapter and that is substantively identical except for the inclusion of the acronym “TR” in place of the acronym “CSAPR”:
Acid Rain Program means a multi-state SO
Administrator means the Administrator of the United States Environmental Protection Agency or the Director of the Clean Air Markets Division (or its successor determined by the Administrator) of the United States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.
Allocate or allocation means, with regard to CSAPR NO
(1) A CSAPR NO
(2) A new unit set-aside;
(3) An Indian country new unit set-aside; or
(4) An entity not listed in paragraphs (1) through (3) of this definition;
(5) Provided that, if the Administrator, State, or permitting authority initially credits, to a CSAPR NO
Allowance Management System means the system by which the Administrator records allocations, auctions, transfers, and deductions of CSAPR NO
Allowance Management System account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, auction, holding, transfer, or deduction of CSAPR NO
Allowance transfer deadline means, for a control period before 2021, midnight of March 1 immediately after such control period or, for a control period in 2021 or thereafter, midnight of June 1 immediately after such control period (or if such March 1 or June 1 is not a business day, midnight of the first business day thereafter) and is the deadline by which a CSAPR NO
Alternate designated representative means, for a CSAPR NO
Assurance account means an Allowance Management System account, established by the Administrator under § 97.425(b)(3) for certain owners and operators of a group of one or more CSAPR NO
Auction means, with regard to CSAPR NO
Authorized account representative means, for a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of CSAPR NO
Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by this subpart.
Biomass means –
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other material that is nonmerchantable for other purposes, and that is:
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
Bottoming-cycle unit means a unit in which the energy input to the unit is first used to produce useful thermal energy, where at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.
Business day means a day that does not fall on a weekend or a federal holiday.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function or any other person who performs similar policy- or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means “coal” as defined in § 72.2 of this chapter.
Cogeneration system means an integrated group, at a source, of equipment (including a boiler, or combustion turbine, and a generator) designed to produce useful thermal energy for industrial, commercial, heating, or cooling purposes and electricity through the sequential use of energy.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a topping-cycle unit or a bottoming-cycle unit:
(1) Operating as part of a cogeneration system; and
(2) Producing on an annual average basis –
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output; or
(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;
(3) Provided that the requirements in paragraph (2) of this definition shall not apply to a calendar year referenced in paragraph (2) of this definition during which the unit did not operate at all;
(4) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel, except biomass if the unit is a boiler; and
(5) Provided that, if, throughout its operation during the 12-month period or a calendar year referenced in paragraph (2) of this definition, a unit is operated as part of a cogeneration system and the cogeneration system meets on a system-wide basis the requirement in paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be deemed to meet such requirement during that 12-month period or calendar year.
Combustion turbine means an enclosed device comprising:
(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.405.
(i) For a unit that is a CSAPR NO
(ii) For a unit that is a CSAPR NO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.405, for a unit that is not a CSAPR NO
(i) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change or is moved to a different location or source, such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same or a different source, such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
Common designated representative means, with regard to a control period in a given year, a designated representative where, as of April 1 immediately after the allowance transfer deadline for such a control period before 2021, or as of July 1 immediately after such deadline for such a control period in 2021 or thereafter, the same natural person is authorized under §§ 97.413(a) and 97.415(a) as the designated representative for a group of one or more CSAPR NO
Common designated representative’s assurance level means, with regard to a specific common designated representative and a State (and Indian country within the borders of such State) and control period in a given year for which the State assurance level is exceeded as described in § 97.406(c)(2)(iii), the amount (rounded to the nearest allowance) equal to the sum of the total amount of CSAPR NO
Common designated representative’s share means, with regard to a specific common designated representative for a control period in a given year and a total amount of NO
Common stack means a single flue through which emissions from 2 or more units are exhausted.
Compliance account means an Allowance Management System account, established by the Administrator for a CSAPR NO
Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent record of NO
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A NO
(3) A NO
(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(5) A CO
(6) An O
Control period means the period starting January 1 of a calendar year, except as provided in § 97.406(c)(3), and ending on December 31 of the same year, inclusive.
CSAPR NO
CSAPR NO
CSAPR NO
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, CSAPR NO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR SO
CSAPR SO
Designated representative means, for a CSAPR NO
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative, and as modified by the Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required to measure, record, and report such air pollutants in accordance with this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the CSAPR NO
Fossil fuel means –
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or
(2) For purposes of applying the limitation on “average annual fuel consumption of fossil fuel” in § 97.404(b)(2)(i)(B) and (b)(2)(ii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account, established under this subpart, that is not a compliance account or an assurance account.
Generator means a device that produces electricity.
Heat input means, for a unit for a specified period of unit operating time, the product (in mmBtu) of the gross calorific value of the fuel (in mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of fuel/time) and unit operating time, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the quotient (in mmBtu/hr) of the amount of heat input for a specified period of unit operating time (in mmBtu) divided by unit operating time (in hr) or, for a unit and a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Indian country means “Indian country” as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Maximum design heat input rate means, for a unit, the maximum amount of fuel per hour (in Btu/hr) that the unit is capable of combusting on a steady state basis as of the initial installation of the unit as specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe, rounded to the nearest tenth) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount (in MWe, rounded to the nearest tenth) as of such completion as specified by the person conducting the physical change.
Natural gas means “natural gas” as defined in § 72.2 of this chapter.
Newly affected CSAPR NO
Nitrogen oxides means all oxides of nitrogen except nitrous oxide (N
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a CSAPR NO
Owner means, for a CSAPR NO
(1) Any holder of any portion of the legal or equitable title in a CSAPR NO
(2) Any holder of a leasehold interest in a CSAPR NO
(3) Any purchaser of power from a CSAPR NO
Permanently retired means, with regard to a unit, a unit that is unavailable for service and that the unit’s owners and operators do not expect to return to service in the future.
Permitting authority means “permitting authority” as defined in §§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity means, for a unit (in MWh/yr), 33 percent of the unit’s maximum design heat input rate (in Btu/hr), divided by 3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to CSAPR NO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.
Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or retired unit (the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from electricity production in a useful thermal energy application or process; or
(2) The use of reject heat from a useful thermal energy application or process in electricity production.
Serial number means, for a CSAPR NO
Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act.
Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the definition of “major source”, “stationary source”, or “source” as set forth and implemented in a title V operating permit program or any other program under the Clean Air Act.
State means one of the States that is subject to the CSAPR NO
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Topping-cycle unit means a unit in which the energy input to the unit is first used to produce useful power, including electricity, where at least some of the reject heat from the electricity production is then used to provide useful thermal energy.
Total energy input means, for a unit, total energy of all forms supplied to the unit, excluding energy produced by the unit. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:
Total energy output means, for a unit, the sum of useful power and useful thermal energy produced by the unit.
Unit means a stationary, fossil-fuel-fired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-fired combustion device. A unit that undergoes a physical change or is moved to a different location or source shall continue to be treated as the same unit. A unit (the replaced unit) that is replaced by another unit (the replacement unit) at the same or a different source shall continue to be treated as the same unit, and the replacement unit shall be treated as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to a unit, an hour in which the unit combusts any fuel.
Useful power means, with regard to a unit, electricity or mechanical energy that the unit makes available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means thermal energy that is:
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption chiller).
Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.
§ 97.403 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
§ 97.404 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State (and Indian country within the borders of such State) shall be CSAPR NO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a CSAPR NO
(b) Any unit in a State (and Indian country within the borders of such State) that otherwise is a CSAPR NO
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) Not supplying in 2005 or any calendar year thereafter more than one-third of the unit’s potential electrical output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If, after qualifying under paragraph (b)(1)(i) of this section as not being a CSAPR NO
(2)(i) Any unit:
(A) Qualifying as a solid waste incineration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) With an average annual fuel consumption of fossil fuel for the first 3 consecutive calendar years of operation starting no earlier than 2005 of less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years thereafter of less than 20 percent (on a Btu basis).
(ii) If, after qualifying under paragraph (b)(2)(i) of this section as not being a CSAPR NO
(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section or a SIP revision approved under § 52.38(a)(4) or (5) of this chapter, of the CSAPR NO
(1) Petition content. The petition shall be in writing and include the identification of the unit or other equipment and the relevant facts about the unit or other equipment. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying official: “I am authorized to make this submission on behalf of the owners and operators of the unit or other equipment for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) Response. The Administrator will issue a written response to the petition and may request supplemental information determined by the Administrator to be relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CSAPR NO
§ 97.405 Retired unit exemption.
(a)(1) Any CSAPR NO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the CSAPR NO
(b)(1) A unit exempt under paragraph (a) of this section shall not emit any NO
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the CSAPR NO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.
§ 97.406 Standard requirements.
(a) Designated representative requirements. The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.413 through 97.418.
(b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each CSAPR NO
(2) The emissions data determined in accordance with §§ 97.430 through 97.435 shall be used to calculate allocations of CSAPR NO
(c) NO
(ii) If total NO
(A) The owners and operators of the source and each CSAPR NO
(B) The owners and operators of the source and each CSAPR NO
(2) CSAPR NO
(A) The quotient of the amount by which the common designated representative’s share of such NO
(B) The amount by which total NO
(ii) The owners and operators shall hold the CSAPR NO
(iii) Total NO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if total NO
(v) To the extent the owners and operators fail to hold CSAPR NO
(A) The owners and operators shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each CSAPR NO
(3) Compliance periods. (i) A CSAPR NO
(ii) A CSAPR NO
(4) Vintage of CSAPR NO
(ii) A CSAPR NO
(5) Allowance Management System requirements. Each CSAPR NO
(6) Limited authorization. A CSAPR NO
(i) Such authorization shall only be used in accordance with the CSAPR NO
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7) Property right. A CSAPR NO
(d) Title V permit requirements. (1) No title V permit revision shall be required for any allocation, holding, deduction, or transfer of CSAPR NO
(2) A description of whether a unit is required to monitor and report NO
(e) Additional recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of each CSAPR NO
(i) The certificate of representation under § 97.416 for the designated representative for the source and each CSAPR NO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the CSAPR NO
(2) The designated representative of a CSAPR NO
(f) Liability. (1) Any provision of the CSAPR NO
(2) Any provision of the CSAPR NO
(g) Effect on other authorities. No provision of the CSAPR NO
§ 97.407 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the CSAPR NO
(b) Unless otherwise stated, any time period scheduled, under the CSAPR NO
(c) Unless otherwise stated, if the final day of any time period, under the CSAPR NO
§ 97.408 Administrative appeal procedures.
The administrative appeal procedures for decisions of the Administrator under the CSAPR NO
§ 97.409 [Reserved]
§ 97.410 State NOX Annual trading budgets, new unit set-asides, Indian country new unit set-asides, and variability limits.
(a) The State NO
(1) Alabama. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,454 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 1,441 tons.
(vi) [Reserved]
(2) Georgia. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,240 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 1,074 tons.
(vi) [Reserved]
(3) Illinois. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 3,830 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 3,831 tons.
(vi) [Reserved]
(4) Indiana. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 3,292 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 3,256 tons.
(vi) [Reserved]
(5) Iowa. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 729 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 38 tons.
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 715 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 38 tons.
(6) Kansas. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 596 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 31 tons.
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 596 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 31 tons.
(7) Kentucky. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 3,403 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 3,090 tons.
(vi) [Reserved]
(8) Maryland. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 333 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 333 tons.
(vi) [Reserved]
(9) Michigan. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,243 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 65 tons.
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 1,201 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 63 tons.
(10) Minnesota. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 561 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 30 tons.
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 565 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 30 tons.
(11) Missouri. (i) The NO
(ii) The new unit set-aside for 2015 is 1,572 tons and for 2016 is 3,144 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 2,929 tons.
(vi) [Reserved]
(12) Nebraska. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,772 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 30 tons.
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 1,771 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 30 tons.
(13) New Jersey. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 164 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 155 tons.
(vi) [Reserved]
(14) New York. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 412 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 22 tons.
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 410 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 22 tons.
(15) North Carolina. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 2,984 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 51 tons.
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 2,451 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 42 tons.
(16) Ohio. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,909 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 1,805 tons.
(vi) [Reserved]
(17) Pennsylvania. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 2,400 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 2,383 tons.
(vi) [Reserved]
(18) South Carolina. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 617 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 33 tons.
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 620 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 33 tons.
(19) Tennessee. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 714 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 381 tons.
(vi) [Reserved]
(20) Texas. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 5,370 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 138 tons.
(iv)-(vi) [Reserved]
(21) Virginia. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,662 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 1,663 tons.
(vi) [Reserved]
(22) West Virginia. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 2,974 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 2,730 tons.
(vi) [Reserved]
(23) Wisconsin. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 2,012 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 34 tons.
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 1,939 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 33 tons.
(b) The States’ variability limits for the State NO
(1) The variability limit for Alabama is 12,953 tons.
(2) The variability limit for Georgia is 9,673 tons.
(3) The variability limit for Illinois is 8,617 tons.
(4) The variability limit for Indiana is 19,516 tons.
(5) The variability limit for Iowa is 6,750 tons.
(6) The variability limit for Kansas is 5,644 tons.
(7) The variability limit for Kentucky is 13,903 tons.
(8) The variability limit for Maryland is 2,983 tons.
(9) The variability limit for Michigan is 11,347 tons.
(10) The variability limit for Minnesota is 5,323 tons.
(11) The variability limit for Missouri is 8,774 tons.
(12) The variability limit for Nebraska is 5,407 tons.
(13) The variability limit for New Jersey is 1,430 tons.
(14) The variability limit for New York is 3,910 tons.
(15) The variability limit for North Carolina is 7,480 tons.
(16) The variability limit for Ohio is 16,246 tons.
(17) The variability limit for Pennsylvania is 21,455 tons.
(18) The variability limit for South Carolina is 5,850 tons.
(19) The variability limit for Tennessee is 3,481 tons.
(20) [Reserved]
(21) The variability limit for Virginia is 5,984 tons.
(22) The variability limit for West Virginia is 9,825 tons.
(23) The variability limit for Wisconsin is 5,917 tons.
(c) Each State NO
§ 97.411 Timing requirements for CSAPR NOX Annual allowance allocations.
(a) Existing units. (1) CSAPR NO
(2) Notwithstanding paragraph (a)(1) of this section, if a unit provided an allocation in the notice of data availability issued under paragraph (a)(1) of this section does not operate, starting after 2014, during the control period in two consecutive years, such unit will not be allocated the CSAPR NO
(b) New units – (1) New unit set-asides. (i)(A) By June 1 of each year from 2015 through 2020, the Administrator will calculate the CSAPR NO
(B) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR NO
(ii) For each notice of data availability required in paragraph (b)(1)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR NO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(1)(i)(A) or (B) of this section, as applicable. By August 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i)(A) of this section, or by May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i)(B) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(1)(ii)(A) of this section.
(iii) If the new unit set-aside for a control period before 2021 contains any CSAPR NO
(iv) For each notice of data availability required in paragraph (b)(1)(iii) of this section, the Administrator will provide an opportunity for submission of objections to the identification of CSAPR NO
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(iii) of this section and shall be limited to addressing whether the identification of CSAPR NO
(B) The Administrator will adjust the identification of CSAPR NO
(v) To the extent any CSAPR NO
(2) Indian country new unit set-asides. (i)(A) By June 1 of each year from 2015 through 2020, the Administrator will calculate the CSAPR NO
(B) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR NO
(ii) For each notice of data availability required in paragraph (b)(2)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR NO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i)(A) or (B) of this section, as applicable. By August 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i)(A) of this section, or by May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i)(B) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(ii)(A) of this section.
(iii) If the Indian country new unit set-aside for a control period before 2021 contains any CSAPR NO
(iv) For each notice of data availability required in paragraph (b)(2)(iii) of this section, the Administrator will provide an opportunity for submission of objections to the identification of CSAPR NO
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(iii) of this section and shall be limited to addressing whether the identification of CSAPR NO
(B) The Administrator will adjust the identification of CSAPR NO
(v) To the extent any CSAPR NO
(c) Units incorrectly allocated CSAPR NO
(i)(A) The recipient is not actually a CSAPR NO
(B) The recipient is not located as of January 1 of the control period in the State from whose NO
(ii) The recipient is not actually a CSAPR NO
(2) Except as provided in paragraph (c)(3) or (4) of this section, the Administrator will not record such CSAPR NO
(3) If the Administrator already recorded such CSAPR NO
(4) If the Administrator already recorded such CSAPR NO
(5)(i) With regard to the CSAPR NO
(A) Transfer such CSAPR NO
(B) If the State has a SIP revision approved under § 52.38(a)(4) or (5) of this chapter covering such control period, include such CSAPR NO
(ii) With regard to the CSAPR NO
(A) Transfer such CSAPR NO
(B) If the State has a SIP revision approved under § 52.38(a)(4) or (5) of this chapter covering such control period, include such CSAPR NO
(iii) With regard to the CSAPR NO
§ 97.412 CSAPR NOX Annual allowance allocations to new units.
(a) Allocations from new unit set-asides. For each control period in 2015 and thereafter and for the CSAPR NO
(1) The CSAPR NO
(i) CSAPR NO
(ii) CSAPR NO
(iii) CSAPR NO
(iv) For purposes of paragraph (a)(9) of this section, CSAPR NO
(2) The Administrator will establish a separate new unit set-aside for the State for each such control period. Each such new unit set-aside will be allocated CSAPR NO
(3) The Administrator will determine, for each CSAPR NO
(i) The control period in 2015;
(ii)(A) The first control period after the control period in which the CSAPR NO
(B) The control period containing the deadline for certification of the CSAPR NO
(iii) For a unit described in paragraph (a)(1)(ii) of this section, the first control period in which the CSAPR NO
(iv) For a unit described in paragraph (a)(1)(iii) of this section, the first control period after the control period in which the unit resumes operation, for allocations for a control period before 2021, or the control period in which the unit resumes operation, for allocations for a control period in 2021 or thereafter.
(4)(i) The allocation to each CSAPR NO
(ii) The Administrator will adjust the allocation amount in paragraph (a)(4)(i) of this section in accordance with paragraphs (a)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR NO
(6) If the amount of CSAPR NO
(7) If the amount of CSAPR NO
(8) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.411(b)(1)(i) and (ii), of the amount of CSAPR NO
(9) For a control period before 2021, if, after completion of the procedures under paragraphs (a)(5) through (8) of this section for such control period, any unallocated CSAPR NO
(i) The Administrator will determine, for each unit described in paragraph (a)(1) of this section that commenced commercial operation during the period starting January 1 of the year before the year of such control period and ending November 30 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR NO
(ii) The Administrator will determine the sum of the positive differences determined under paragraph (a)(9)(i) of this section;
(iii) If the amount of unallocated CSAPR NO
(iv) If the amount of unallocated CSAPR NO
(10) If, after completion of the procedures under paragraphs (a)(9) and (12) of this section for a control period before 2021, or under paragraphs (a)(2) through (7) and (12) of this section for a control period in 2021 or thereafter, any unallocated CSAPR NO
(11)(i) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.411(b)(1)(iii), (iv), and (v), of the amount of CSAPR NO
(ii) For a control period in 2021 or thereafter, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.411(b)(1)(i), (ii), and (v), of the amount of CSAPR NO
(12) Notwithstanding the requirements of paragraphs (a)(2) through (11) of this section, if the calculations of allocations from a new unit set-aside for a control period before 2021 under paragraph (a)(7) of this section, paragraphs (a)(6) and (a)(9)(iv) of this section, or paragraphs (a)(6), (a)(9)(iii), and (a)(10) of this section, or for a control period in 2021 or thereafter under paragraph (a)(7) of this section or paragraphs (a)(6) and (10) of this section, would otherwise result in total allocations from such new unit set-aside unequal to the total amount of such new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR NO
(b) Allocations from Indian country new unit set-asides. For each control period in 2015 and thereafter and for the CSAPR NO
(1) The CSAPR NO
(i) CSAPR NO
(ii) For purposes of paragraph (b)(9) of this section, CSAPR NO
(2) The Administrator will establish a separate Indian country new unit set-aside for the State for each such control period. Each such Indian country new unit set-aside will be allocated CSAPR NO
(3) The Administrator will determine, for each CSAPR NO
(i) The control period in 2015; and
(ii)(A) The first control period after the control period in which the CSAPR NO
(B) The control period containing the deadline for certification of the CSAPR NO
(4)(i) The allocation to each CSAPR NO
(ii) The Administrator will adjust the allocation amount in paragraph (b)(4)(i) of this section in accordance with paragraphs (b)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR NO
(6) If the amount of CSAPR NO
(7) If the amount of CSAPR NO
(8) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.411(b)(2)(i) and (ii), of the amount of CSAPR NO
(9) For a control period before 2021, if, after completion of the procedures under paragraphs (b)(5) through (8) of this section for such control period, any unallocated CSAPR NO
(i) The Administrator will determine, for each unit described in paragraph (b)(1) of this section that commenced commercial operation during the period starting January 1 of the year before the year of such control period and ending November 30 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR NO
(ii) The Administrator will determine the sum of the positive differences determined under paragraph (b)(9)(i) of this section;
(iii) If the amount of unallocated CSAPR NO
(iv) If the amount of unallocated CSAPR NO
(10) If, after completion of the procedures under paragraphs (b)(9) and (12) of this section for a control period before 2021, or under paragraphs (b)(2) through (7) and (12) of this section for a control period in 2021 or thereafter, any unallocated CSAPR NO
(i) Transfer such unallocated CSAPR NO
(ii) If the State has a SIP revision approved under § 52.38(a)(4) or (5) of this chapter covering such control period, include such unallocated CSAPR NO
(11)(i) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.411(b)(2)(iii), (iv), and (v), of the amount of CSAPR NO
(ii) For a control period in 2021 or thereafter, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.411(b)(2)(i), (ii), and (v), of the amount of CSAPR NO
(12) Notwithstanding the requirements of paragraphs (b)(2) through (11) of this section, if the calculations of allocations from an Indian country new unit set-aside for a control period before 2021 under paragraph (b)(7) of this section or paragraphs (b)(6) and (b)(9)(iv) of this section, or for a control period in 2021 or thereafter under paragraph (b)(7) of this section, would otherwise result in total allocations from such Indian country new unit set-aside unequal to the total amount of such Indian country new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR NO
§ 97.413 Authorization of designated representative and alternate designated representative.
(a) Except as provided under § 97.415, each CSAPR NO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.416:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each CSAPR NO
(ii) The owners and operators of the source and each CSAPR NO
(b) Except as provided under § 97.415, each CSAPR NO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.416,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each CSAPR NO
(c) Except in this section, § 97.402, and §§ 97.414 through 97.418, whenever the term “designated representative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
§ 97.414 Responsibilities of designated representative and alternate designated representative.
(a) Except as provided under § 97.418 concerning delegation of authority to make submissions, each submission under the CSAPR NO
(b) The Administrator will accept or act on a submission made for a CSAPR NO
§ 97.415 Changing designated representative and alternate designated representative; changes in owners and operators; changes in units at the source.
(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.416. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the CSAPR NO
(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.416. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the CSAPR NO
(c) Changes in owners and operators. (1) In the event an owner or operator of a CSAPR NO
(2) Within 30 days after any change in the owners and operators of a CSAPR NO
(d) Changes in units at the source. Within 30 days of any change in which units are located at a CSAPR NO
(1) If the change is the addition of a unit that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the source, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity from whom the unit was purchased or otherwise obtained (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was purchased or otherwise obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity to which the unit was sold or that otherwise obtained the unit (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was sold or otherwise obtained, and the date on which the unit became no longer located at the source.
§ 97.416 Certificate of representation.
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the CSAPR NO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the CSAPR NO
(4) The following certification statements by the designated representative and any alternate designated representative –
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each CSAPR NO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CSAPR NO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a CSAPR NO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(c) A certificate of representation under this section that complies with the provisions of paragraph (a) of this section except that it contains the acronym “TR” in place of the acronym “CSAPR” in the required certification statements will be considered a complete certificate of representation under this section, and the certification statements included in such certificate of representation will be interpreted as if the acronym “CSAPR” appeared in place of the acronym “TR”.
§ 97.417 Objections concerning designated representative and alternate designated representative.
(a) Once a complete certificate of representation under § 97.416 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.416 is received by the Administrator.
(b) Except as provided in paragraph (a) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CSAPR NO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of CSAPR NO
§ 97.418 Delegation by designated representative and alternate designated representative.
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.418(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.418(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.418 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
§ 97.419 [Reserved]
§ 97.420 Establishment of compliance accounts, assurance accounts, and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.416, the Administrator will establish a compliance account for the CSAPR NO
(b) Assurance accounts. The Administrator will establish assurance accounts for certain owners and operators and States in accordance with § 97.425(b)(3).
(c) General accounts – (1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring CSAPR NO
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to CSAPR NO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the CSAPR NO
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to CSAPR NO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(iv) An application for a general account under paragraph (c)(1) of this section that complies with the provisions of such paragraph except that it contains the acronym “TR” in place of the acronym “CSAPR” in the required certification statement will be considered a complete application for a general account under such paragraph, and the certification statement included in such application for a general account will be interpreted as if the acronym “CSAPR” appeared in place of the acronym “TR”.
(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (c)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CSAPR NO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to CSAPR NO
(ii) Except as provided in paragraph (c)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to CSAPR NO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(iv) A certification statement submitted in accordance with paragraph (c)(2)(ii) of this section that contains the acronym “TR” will be interpreted as if the acronym “CSAPR” appeared in place of the acronym “TR”.
(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the CSAPR NO
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the CSAPR NO
(iii)(A) In the event a person having an ownership interest with respect to CSAPR NO
(B) Within 30 days after any change in the persons having an ownership interest with respect to CSAPR NO
(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the CSAPR NO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of CSAPR NO
(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (c)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (c)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized account representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.420(c)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.420(c)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.420(c)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (c)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (c)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this section shall be deemed to be an electronic submission by the authorized account representative or alternate authorized account representative submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted CSAPR NO
(ii) If a general account has no CSAPR NO
(d) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a), (b), or (c) of this section.
(e) Responsibilities of authorized account representative and alternate authorized account representative. After the establishment of a compliance account or general account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of CSAPR NO
§ 97.421 Recordation of CSAPR NOX Annual allowance allocations and auction results.
(a) By November 7, 2011, the Administrator will record in each CSAPR NO
(b) By November 7, 2011, the Administrator will record in each CSAPR NO
(1) If, by April 1, 2015, the State does not submit to the Administrator such complete SIP revision, the Administrator will record by April 15, 2015 in each CSAPR NO
(2) If the State submits to the Administrator by April 1, 2015, and the Administrator approves by October 1, 2015, such complete SIP revision, the Administrator will record by October 1, 2015 in each CSAPR NO
(3) If the State submits to the Administrator by April 1, 2015, and the Administrator does not approve by October 1, 2015, such complete SIP revision, the Administrator will record by October 1, 2015 in each CSAPR NO
(c) By July 1, 2016, the Administrator will record in each CSAPR NO
(d) By July 1, 2017, the Administrator will record in each CSAPR NO
(e) By July 1, 2018, the Administrator will record in each CSAPR NO
(f)(1) By July 1, 2019 and July 1, 2020, the Administrator will record in each CSAPR NO
(2) By July 1, 2024 and July 1 of each year thereafter, the Administrator will record in each CSAPR NO
(g)(1) By August 1 of each year from 2015 through 2020, the Administrator will record in each CSAPR NO
(2) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR NO
(h)(1) By August 1 of each year from 2015 through 2020, the Administrator will record in each CSAPR NO
(2) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR NO
(i) By February 15 of each year from 2016 through 2021, the Administrator will record in each CSAPR NO
(j) By February 15 of each year from 2016 through 2021, the Administrator will record in each CSAPR NO
(k) By the date 15 days after the date on which any allocation or auction results, other than an allocation or auction results described in paragraphs (a) through (j) of this section, of CSAPR NO
(l) When recording the allocation or auction of CSAPR NO
§ 97.422 Submission of CSAPR NOX Annual allowance transfers.
(a) An authorized account representative seeking recordation of a CSAPR NO
(b) A CSAPR NO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each CSAPR NO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each CSAPR NO
§ 97.423 Recordation of CSAPR NOX Annual allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a CSAPR NO
(b) A CSAPR NO
(c) Where a CSAPR NO
(d) Within 5 business days of recordation of a CSAPR NO
(e) Within 10 business days of receipt of a CSAPR NO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
§ 97.424 Compliance with CSAPR NOX Annual emissions limitation.
(a) Availability for deduction for compliance. CSAPR NO
(1) Were allocated or auctioned for such control period or a control period in a prior year; and
(2) Are held in the source’s compliance account as of the allowance transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance with § 97.423, of CSAPR NO
(1) Until the amount of CSAPR NO
(2) If there are insufficient CSAPR NO
(c) Selection of CSAPR NO
(2) First-in, first-out. The Administrator will deduct CSAPR NO
(i) Any CSAPR NO
(ii) Any other CSAPR NO
(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in which the CSAPR NO
(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and (d) of this section.
§ 97.425 Compliance with CSAPR NOX Annual assurance provisions.
(a) Availability for deduction. CSAPR NO
(1) Were allocated or auctioned for a control period in a prior year or the control period in the given year or in the immediately following year; and
(2) Are held in the assurance account, established by the Administrator for such owners and operators of such group of CSAPR NO
(b) Deductions for compliance. The Administrator will deduct CSAPR NO
(1) By June 1 of each year from 2018 through 2021 and August 1 of each year thereafter, the Administrator will:
(i) Calculate, for each State (and Indian country within the borders of such State), the total NO
(ii) For the set of any States (and Indian country within the borders of such States) for which the results of the calculations required in paragraph (b)(1)(i) of this section indicate that total NO
(A) Calculate, for each such State (and Indian country within the borders of such State) and such control period and each common designated representative for such control period for a group of one or more CSAPR NO
(B) Promulgate a notice of data availability of the results of the calculations required in paragraphs (b)(1)(i) and (b)(1)(ii)(A) of this section, including separate calculations of the NO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice of data availability required in paragraph (b)(1)(ii) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations referenced in such notice are in accordance with § 97.406(c)(2)(iii), §§ 97.406(b) and 97.430 through 97.435, the definitions of “common designated representative”, “common designated representative’s assurance level”, and “common designated representative’s share” in § 97.402, and the calculation formula in § 97.406(c)(2)(i).
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By October 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) For any State (and Indian country within the borders of such State) referenced in each notice of data availability required in paragraph (b)(2)(ii) of this section as having CSAPR NO
(4)(i) As of midnight of November 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section, the owners and operators described in paragraph (b)(3) of this section shall hold in the assurance account established for them and for the appropriate CSAPR NO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(4)(i) of this section, if November 1 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section and after the recordation, in accordance with § 97.423, of CSAPR NO
(6) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notice of data availability required in paragraph (b)(2)(ii) of this section for a control period in a given year, of any data used in making the calculations referenced in such notice, the amounts of CSAPR NO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of CSAPR NO
(ii) [Reserved]
(iii) If the revised data are used to recalculate, in accordance with paragraph (b)(6)(i) of this section, the amount of CSAPR NO
(A) Where the amount of CSAPR NO
(B) For the owners and operators for which the amount of CSAPR NO
(C) Each CSAPR NO
§ 97.426 Banking.
(a) A CSAPR NO
(b) Any CSAPR NO
(c) At any time after the allowance transfer deadline for the last control period for which a State NO
§ 97.427 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
§ 97.428 Administrator’s action on submissions.
(a) The Administrator may review and conduct independent audits concerning any submission under the CSAPR NO
(b) The Administrator may deduct CSAPR NO
§ 97.429 [Reserved]
§ 97.430 General monitoring, recordkeeping, and reporting requirements.
The owners and operators, and to the extent applicable, the designated representative, of a CSAPR NO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each CSAPR NO
(1) Install all monitoring systems required under this subpart for monitoring NO
(2) Successfully complete all certification tests required under § 97.431 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator of a CSAPR NO
(1) January 1, 2015; or
(2) 180 calendar days after the date on which the unit commences commercial operation.
(3) The owner or operator of a CSAPR NO
(i) Such requirements shall apply to the monitoring systems required under § 97.430 through § 97.435, rather than the monitoring systems required under part 75 of this chapter;
(ii) NO
(iii) Any petition for another procedure under § 75.4(e)(2) of this chapter shall be submitted under § 97.435, rather than § 75.66 of this chapter.
(c) Reporting data. The owner or operator of a CSAPR NO
(d) Prohibitions. (1) No owner or operator of a CSAPR NO
(2) No owner or operator of a CSAPR NO
(3) No owner or operator of a CSAPR NO
(4) No owner or operator of a CSAPR NO
(i) During the period that the unit is covered by an exemption under § 97.405 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.431(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a CSAPR NO
§ 97.431 Initial monitoring system certification and recertification procedures.
(a) The owner or operator of a CSAPR NO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B, D, and E to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.430(a)(1) that is exempt from initial certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the NO
(d) Except as provided in paragraph (a) of this section, the owner or operator of a CSAPR NO
(1) Requirements for initial certification. The owner or operator shall ensure that each continuous monitoring system under § 97.430(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.430(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.430(a)(1) that may significantly affect the ability of the system to accurately measure or record NO
(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.430(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in § 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words “certification” and “initial certification” are replaced by the word “recertification” and the word “certified” is replaced by the word “recertified”.
(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office and the Administrator written notice of the dates of certification testing, in accordance with § 97.433.
(ii) Certification application. The designated representative shall submit to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the CSAPR NO
(iv) Certification application approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the CSAPR NO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.432(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NO
(2) For a disapproved NO
(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(5) For a disapproved excepted NO
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
§ 97.432 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D or subpart H of, or appendix D or appendix E to, part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.431 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the Administrator or any State or permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 97.431 for each disapproved monitoring system.
§ 97.433 Notifications concerning monitoring.
The designated representative of a CSAPR NO
§ 97.434 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply with all recordkeeping and reporting requirements in paragraphs (b) through (e) of this section, the applicable recordkeeping and reporting requirements under § 75.73 of this chapter, and the requirements of § 97.414(a).
(b) Monitoring plans. The owner or operator of a CSAPR NO
(c) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all initial certification or recertification tests required under § 97.431, including the information required under § 75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit quarterly reports, as follows:
(1) The designated representative shall report the NO
(i) The calendar quarter covering January 1, 2015 through March 31, 2015; or
(ii) The calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.430(b).
(2) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.
(3) For CSAPR NO
(4) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(2) of this section.
(e) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and
(2) For a unit with add-on NO
§ 97.435 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements.
(a) The designated representative of a CSAPR NO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(1) Identification of each unit and source covered by the petition;
(2) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used in the proposed alternative;
(4) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be de minimis; and
(5) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
Subpart BBBBB – CSAPR NOX Ozone Season Group 1 Trading Program
§ 97.501 Purpose.
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Cross-State Air Pollution Rule (CSAPR) NO
§ 97.502 Definitions.
The terms used in this subpart shall have the meanings set forth in this section as follows, provided that any term that includes the acronym “CSAPR” shall be considered synonymous with a term that is used in a SIP revision approved by the Administrator under § 52.38 or § 52.39 of this chapter and that is substantively identical except for the inclusion of the acronym “TR” in place of the acronym “CSAPR”:
Acid Rain Program means a multi-state SO
Administrator means the Administrator of the United States Environmental Protection Agency or the Director of the Clean Air Markets Division (or its successor determined by the Administrator) of the United States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.
Allocate or allocation means, with regard to CSAPR NO
(1) A CSAPR NO
(2) A new unit set-aside;
(3) An Indian country new unit set-aside; or
(4) An entity not listed in paragraphs (1) through (3) of this definition;
(5) Provided that, if the Administrator, State, or permitting authority initially credits, to a CSAPR NO
Allowance Management System means the system by which the Administrator records allocations, auctions, transfers, and deductions of CSAPR NO
Allowance Management System account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, auction, holding, transfer, or deduction of CSAPR NO
Allowance transfer deadline means, for a control period in 2015 or 2016, midnight of December 1 immediately after such control period or, for a control period in a year from 2017 through 2020, midnight of March 1 immediately after such control period or, for a control period in 2021 or thereafter, midnight of June 1 immediately after such control period (or if such December 1, March 1, or June 1 is not a business day, midnight of the first business day thereafter) and is the deadline by which a CSAPR NO
Alternate designated representative means, for a CSAPR NO
Assurance account means an Allowance Management System account, established by the Administrator under § 97.525(b)(3) for certain owners and operators of a group of one or more CSAPR NO
Auction means, with regard to CSAPR NO
Authorized account representative means, for a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of CSAPR NO
Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by this subpart.
Biomass means –
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other material that is nonmerchantable for other purposes, and that is:
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
Bottoming-cycle unit means a unit in which the energy input to the unit is first used to produce useful thermal energy, where at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.
Business day means a day that does not fall on a weekend or a federal holiday.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function or any other person who performs similar policy- or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means “coal” as defined in § 72.2 of this chapter.
Cogeneration system means an integrated group, at a source, of equipment (including a boiler, or combustion turbine, and a generator) designed to produce useful thermal energy for industrial, commercial, heating, or cooling purposes and electricity through the sequential use of energy.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a topping-cycle unit or a bottoming-cycle unit:
(1) Operating as part of a cogeneration system; and
(2) Producing on an annual average basis –
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output; or
(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;
(3) Provided that the requirements in paragraph (2) of this definition shall not apply to a calendar year referenced in paragraph (2) of this definition during which the unit did not operate at all;
(4) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel, except biomass if the unit is a boiler; and
(5) Provided that, if, throughout its operation during the 12-month period or a calendar year referenced in paragraph (2) of this definition, a unit is operated as part of a cogeneration system and the cogeneration system meets on a system-wide basis the requirement in paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be deemed to meet such requirement during that 12-month period or calendar year.
Combustion turbine means an enclosed device comprising:
(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.505.
(i) For a unit that is a CSAPR NO
(ii) For a unit that is a CSAPR NO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.505, for a unit that is not a CSAPR NO
(i) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change or is moved to a different location or source, such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same or a different source, such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
Common designated representative means, with regard to a control period in a given year, a designated representative where, as of April 1 immediately after the allowance transfer deadline for such a control period before 2021, or as of July 1 immediately after such deadline for such a control period in 2021 or thereafter, the same natural person is authorized under §§ 97.513(a) and 97.515(a) as the designated representative for a group of one or more CSAPR NO
Common designated representative’s assurance level means, with regard to a specific common designated representative and a State (and Indian country within the borders of such State) and control period in a given year for which the State assurance level is exceeded as described in § 97.506(c)(2)(iii), the amount (rounded to the nearest allowance) equal to the sum of the total amount of CSAPR NO
Common designated representative’s share means, with regard to a specific common designated representative for a control period in a given year and a total amount of NO
Common stack means a single flue through which emissions from 2 or more units are exhausted.
Compliance account means an Allowance Management System account, established by the Administrator for a CSAPR NO
Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent record of NO
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A NO
(3) A NO
(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(5) A CO
(6) An O
Control period means the period starting May 1 of a calendar year, except as provided in § 97.506(c)(3), and ending on September 30 of the same year, inclusive.
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, CSAPR NO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR SO
CSAPR SO
Designated representative means, for a CSAPR NO
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative, and as modified by the Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required to measure, record, and report such air pollutants in accordance with this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the CSAPR NO
Fossil fuel means –
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or
(2) For purposes of applying the limitation on “average annual fuel consumption of fossil fuel” in § 97.504(b)(2)(i)(B) and (b)(2)(ii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account, established under this subpart, that is not a compliance account or an assurance account.
Generator means a device that produces electricity.
Heat input means, for a unit for a specified period of unit operating time, the product (in mmBtu) of the gross calorific value of the fuel (in mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of fuel/time) and unit operating time, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the quotient (in mmBtu/hr) of the amount of heat input for a specified period of unit operating time (in mmBtu) divided by unit operating time (in hr) or, for a unit and a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Indian country means “Indian country” as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Maximum design heat input rate means, for a unit, the maximum amount of fuel per hour (in Btu/hr) that the unit is capable of combusting on a steady state basis as of the initial installation of the unit as specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe, rounded to the nearest tenth) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount (in MWe, rounded to the nearest tenth) as of such completion as specified by the person conducting the physical change.
Natural gas means “natural gas” as defined in § 72.2 of this chapter.
Newly affected CSAPR NO
Nitrogen oxides means all oxides of nitrogen except nitrous oxide (N
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a CSAPR NO
Owner means, for a CSAPR NO
(1) Any holder of any portion of the legal or equitable title in a CSAPR NO
(2) Any holder of a leasehold interest in a CSAPR NO
(3) Any purchaser of power from a CSAPR NO
Permanently retired means, with regard to a unit, a unit that is unavailable for service and that the unit’s owners and operators do not expect to return to service in the future.
Permitting authority means “permitting authority” as defined in §§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity means, for a unit (in MWh/yr), 33 percent of the unit’s maximum design heat input rate (in Btu/hr), divided by 3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to CSAPR NO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.
Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or retired unit (the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from electricity production in a useful thermal energy application or process; or
(2) The use of reject heat from a useful thermal energy application or process in electricity production.
Serial number means, for a CSAPR NO
Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act.
Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the definition of “major source”, “stationary source”, or “source” as set forth and implemented in a title V operating permit program or any other program under the Clean Air Act.
State means one of the States that is subject to the CSAPR NO
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Topping-cycle unit means a unit in which the energy input to the unit is first used to produce useful power, including electricity, where at least some of the reject heat from the electricity production is then used to provide useful thermal energy.
Total energy input means, for a unit, total energy of all forms supplied to the unit, excluding energy produced by the unit. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:
Total energy output means, for a unit, the sum of useful power and useful thermal energy produced by the unit.
Unit means a stationary, fossil-fuel-fired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-fired combustion device. A unit that undergoes a physical change or is moved to a different location or source shall continue to be treated as the same unit. A unit (the replaced unit) that is replaced by another unit (the replacement unit) at the same or a different source shall continue to be treated as the same unit, and the replacement unit shall be treated as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to a unit, an hour in which the unit combusts any fuel.
Useful power means, with regard to a unit, electricity or mechanical energy that the unit makes available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means thermal energy that is:
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption chiller).
Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.
§ 97.503 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
§ 97.504 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State (and Indian country within the borders of such State) shall be CSAPR NO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a CSAPR NO
(b) Any unit in a State (and Indian country within the borders of such State) that otherwise is a CSAPR NO
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) Not supplying in 2005 or any calendar year thereafter more than one-third of the unit’s potential electrical output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If, after qualifying under paragraph (b)(1)(i) of this section as not being a CSAPR NO
(2)(i) Any unit:
(A) Qualifying as a solid waste incineration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) With an average annual fuel consumption of fossil fuel for the first 3 consecutive calendar years of operation starting no earlier than 2005 of less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years thereafter of less than 20 percent (on a Btu basis).
(ii) If, after qualifying under paragraph (b)(2)(i) of this section as not being a CSAPR NO
(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section or a SIP revision approved under § 52.38(b)(4) or (5) of this chapter, of the CSAPR NO
(1) Petition content. The petition shall be in writing and include the identification of the unit or other equipment and the relevant facts about the unit or other equipment. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying official: “I am authorized to make this submission on behalf of the owners and operators of the unit or other equipment for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) Response. The Administrator will issue a written response to the petition and may request supplemental information determined by the Administrator to be relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CSAPR NO
§ 97.505 Retired unit exemption.
(a)(1) Any CSAPR NO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the CSAPR NO
(b)(1) A unit exempt under paragraph (a) of this section shall not emit any NO
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the CSAPR NO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.
§ 97.506 Standard requirements.
(a) Designated representative requirements. The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.513 through 97.518.
(b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each CSAPR NO
(2) The emissions data determined in accordance with §§ 97.530 through 97.535 shall be used to calculate allocations of CSAPR NO
(c) NO
(ii) If total NO
(A) The owners and operators of the source and each CSAPR NO
(B) The owners and operators of the source and each CSAPR NO
(2) CSAPR NO
(A) The quotient of the amount by which the common designated representative’s share of such NO
(B) The amount by which total NO
(ii) The owners and operators shall hold the CSAPR NO
(iii) Total NO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if total NO
(v) To the extent the owners and operators fail to hold CSAPR NO
(A) The owners and operators shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each CSAPR NO
(3) Compliance periods. (i) A CSAPR NO
(ii) A CSAPR NO
(4) Vintage of CSAPR NO
(ii) A CSAPR NO
(5) Allowance Management System requirements. Each CSAPR NO
(6) Limited authorization. A CSAPR NO
(i) Such authorization shall only be used in accordance with the CSAPR NO
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7) Property right. A CSAPR NO
(d) Title V permit requirements. (1) No title V permit revision shall be required for any allocation, holding, deduction, or transfer of CSAPR NO
(2) A description of whether a unit is required to monitor and report NO
(e) Additional recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of each CSAPR NO
(i) The certificate of representation under § 97.516 for the designated representative for the source and each CSAPR NO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the CSAPR NO
(2) The designated representative of a CSAPR NO
(f) Liability. (1) Any provision of the CSAPR NO
(2) Any provision of the CSAPR NO
(g) Effect on other authorities. No provision of the CSAPR NO
§ 97.507 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the CSAPR NO
(b) Unless otherwise stated, any time period scheduled, under the CSAPR NO
(c) Unless otherwise stated, if the final day of any time period, under the CSAPR NO
§ 97.508 Administrative appeal procedures.
The administrative appeal procedures for decisions of the Administrator under the CSAPR NO
§ 97.509 [Reserved]
§ 97.510 State NOX Ozone Season Group 1 trading budgets, new unit set-asides, Indian country new unit set-asides, and variability limits.
(a) The State NO
(1) Alabama. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 635 tons.
(iii)-(vi) [Reserved]
(2) Arkansas. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 756 tons.
(iii)-(vi) [Reserved]
(3) Florida. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 544 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 29 tons.
(iv)-(vi) [Reserved]
(4) Georgia. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 559 tons.
(iii) [Reserved]
(iv) The NO
(v) The new unit set-aside for 2017 and thereafter is 485 tons.
(vi) [Reserved]
(5) Illinois. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,697 tons.
(iii)-
(vi) [Reserved]
(6) Indiana. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,406 tons.
(iii)-(vi) [Reserved]
(7) Iowa. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 314 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 17 tons.
(iv)-(vi) [Reserved]
(8) Kentucky. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,447 tons.
(iii)-(vi) [Reserved]
(9) Louisiana. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 344 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 18 tons.
(iv)-(vi) [Reserved]
(10) Maryland. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 144 tons.
(iii)-(vi) [Reserved]
(11) Michigan. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 533 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 28 tons.
(iv)-(vi) [Reserved]
(12) Mississippi. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 237 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 12 tons.
(iv)-(vi) [Reserved]
(13) Missouri. (i) The NO
(ii) The new unit set-aside for 2015 is 684 tons and for 2016 is 1,367 tons.
(iii)-(vi) [Reserved]
(14) New Jersey. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 83 tons.
(iii)-(vi) [Reserved]
(15) New York. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 197 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 10 tons.
(iv)-(vi) [Reserved]
(16) North Carolina. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,308 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 22 tons.
(iv)-(vi) [Reserved]
(17) Ohio. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 826 tons.
(iii)-(vi) [Reserved]
(18) Oklahoma. (i) The NO
(ii) The new unit set-aside for 2015 is 731 tons and for 2016 is 454 tons.
(iii)-(vi) [Reserved]
(19) Pennsylvania. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,044 tons.
(iii)-(vi) [Reserved]
(20) South Carolina. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 264 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 14 tons.
(iv)-(vi) [Reserved]
(21) Tennessee. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 298 tons.
(iii)-(vi) [Reserved]
(22) Texas. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 2,556 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 66 tons.
(iv)-(vi) [Reserved]
(23) Virginia. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 723 tons.
(iii)-(vi) [Reserved]
(24) West Virginia. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 1,264 tons.
(iii)-(vi) [Reserved]
(25) Wisconsin. (i) The NO
(ii) The new unit set-aside for 2015 and 2016 is 872 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 15 tons.
(iv)-(vi) [Reserved]
(b) The States’ variability limits for the State NO
(1)-(3) [Reserved]
(4) The variability limit for Georgia is 5,049 tons.
(5)-(25) [Reserved]
(c) Each State NO
§ 97.511 Timing requirements for CSAPR NOX Ozone Season Group 1 allowance allocations.
(a) Existing units. (1) CSAPR NO
(2) Notwithstanding paragraph (a)(1) of this section, if a unit provided an allocation in the notice of data availability issued under paragraph (a)(1) of this section does not operate, starting after 2014, during the control period in two consecutive years, such unit will not be allocated the CSAPR NO
(b) New units – (1) New unit set-asides. (i)(A) By June 1 of each year from 2015 through 2020, the Administrator will calculate the CSAPR NO
(B) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR NO
(ii) For each notice of data availability required in paragraph (b)(1)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR NO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(1)(i)(A) or (B) of this section, as applicable. By August 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i)(A) of this section, or by May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i)(B) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(1)(ii)(A) of this section.
(iii)(A) If the new unit set-aside for the control period in 2015 or 2016 contains any CSAPR NO
(B) If the new unit set-aside for the control period in a year from 2017 through 2020 contains any CSAPR NO
(iv) For each notice of data availability required in paragraph (b)(1)(iii) of this section, the Administrator will provide an opportunity for submission of objections to the identification of CSAPR NO
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(iii) of this section and shall be limited to addressing whether the identification of CSAPR NO
(B) The Administrator will adjust the identification of CSAPR NO
(v) To the extent any CSAPR NO
(2) Indian country new unit set-asides. (i)(A) By June 1 of each year from 2015 through 2020, the Administrator will calculate the CSAPR NO
(B) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR NO
(ii) For each notice of data availability required in paragraph (b)(2)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR NO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i)(A) or (B) of this section, as applicable. By August 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i)(A) of this section, or by May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i)(B) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(ii)(A) of this section.
(iii)(A) If the Indian country new unit set-aside for the control period in 2015 or 2016 contains any CSAPR NO
(B) If the Indian country new unit set-aside for the control period in a year from 2017 through 2020 contains any CSAPR NO
(iv) For each notice of data availability required in paragraph (b)(2)(iii) of this section, the Administrator will provide an opportunity for submission of objections to the identification of CSAPR NO
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(iii) of this section and shall be limited to addressing whether the identification of CSAPR NO
(B) The Administrator will adjust the identification of CSAPR NO
(v) To the extent any CSAPR NO
(c) Units incorrectly allocated CSAPR NO
(i)(A) The recipient is not actually a CSAPR NO
(B) The recipient is not located as of May 1 of the control period in the State from whose NO
(ii) The recipient is not actually a CSAPR NO
(2) Except as provided in paragraph (c)(3) or (4) of this section, the Administrator will not record such CSAPR NO
(3) If the Administrator already recorded such CSAPR NO
(4) If the Administrator already recorded such CSAPR NO
(5)(i) With regard to the CSAPR NO
(A) Transfer such CSAPR NO
(B) If the State has a SIP revision approved under § 52.38(b)(4) or (5) of this chapter covering such control period, include such CSAPR NO
(ii) With regard to the CSAPR NO
(A) Transfer such CSAPR NO
(B) If the State has a SIP revision approved under § 52.38(b)(4) or (5) of this chapter covering such control period, include such CSAPR NO
(iii) With regard to the CSAPR NO
§ 97.512 CSAPR NOX Ozone Season Group 1 allowance allocations to new units.
(a) Allocations from new unit set-asides. For each control period in 2015 and thereafter and for the CSAPR NO
(1) The CSAPR NO
(i) CSAPR NO
(ii) CSAPR NO
(iii) CSAPR NO
(iv) For purposes of paragraph (a)(9) of this section, CSAPR NO
(2) The Administrator will establish a separate new unit set-aside for the State for each such control period. Each such new unit set-aside will be allocated CSAPR NO
(3) The Administrator will determine, for each CSAPR NO
(i) The control period in 2015;
(ii)(A) The first control period after the control period in which the CSAPR NO
(B) The control period containing the deadline for certification of the CSAPR NO
(iii) For a unit described in paragraph (a)(1)(ii) of this section, the first control period in which the CSAPR NO
(iv) For a unit described in paragraph (a)(1)(iii) of this section, the first control period after the control period in which the unit resumes operation, for allocations for a control period before 2021, or the control period in which the unit resumes operation, for allocations for a control period in 2021 or thereafter.
(4)(i) The allocation to each CSAPR NO
(ii) The Administrator will adjust the allocation amount in paragraph (a)(4)(i) of this section in accordance with paragraphs (a)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR NO
(6) If the amount of CSAPR NO
(7) If the amount of CSAPR NO
(8) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.511(b)(1)(i) and (ii), of the amount of CSAPR NO
(9) For a control period before 2021, if, after completion of the procedures under paragraphs (a)(5) through (8) of this section for such control period, any unallocated CSAPR NO
(i)(A) For the control period in 2015 or 2016, the Administrator will determine, for each unit described in paragraph (a)(1) of this section that commenced commercial operation during the period starting May 1 of the year before the year of such control period and ending August 31 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR NO
(B) For the control period in 2017, 2018, 2019, or 2020
, the Administrator will determine, for each unit described in paragraph (a)(1) of this section that commenced commercial operation during the period starting January 1 of the year before the year of such control period and ending November 30 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR NO
(ii) The Administrator will determine the sum of the positive differences determined under paragraph (a)(9)(i) of this section;
(iii) If the amount of unallocated CSAPR NO
(iv) If the amount of unallocated CSAPR NO
(10) If, after completion of the procedures under paragraphs (a)(9) and (12) of this section for a control period before 2021, or under paragraphs (a)(2) through (7) and (12) of this section for a control period in 2021 or thereafter, any unallocated CSAPR NO
(11)(i) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.511(b)(1)(iii), (iv), and (v), of the amount of CSAPR NO
(ii) For a control period in 2021 or thereafter, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.511(b)(1)(i), (ii), and (v), of the amount of CSAPR NO
(12) Notwithstanding the requirements of paragraphs (a)(2) through (11) of this section, if the calculations of allocations from a new unit set-aside for a control period before 2021 under paragraph (a)(7) of this section, paragraphs (a)(6) and (a)(9)(iv) of this section, or paragraphs (a)(6), (a)(9)(iii), and (a)(10) of this section, or for a control period in 2021 or thereafter under paragraph (a)(7) of this section or paragraphs (a)(6) and (10) of this section, would otherwise result in total allocations from such new unit set-aside unequal to the total amount of such new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR NO
(b) Allocations from Indian country new unit set-asides. For each control period in 2015 and thereafter and for the CSAPR NO
(1) The CSAPR NO
(i) CSAPR NO
(ii) For purposes of paragraph (b)(9) of this section, CSAPR NO
(2) The Administrator will establish a separate Indian country new unit set-aside for the State for each such control period. Each such Indian country new unit set-aside will be allocated CSAPR NO
(3) The Administrator will determine, for each CSAPR NO
(i) The control period in 2015; and
(ii)(A) The first control period after the control period in which the CSAPR NO
(B) The control period containing the deadline for certification of the CSAPR NO
(4)(i) The allocation to each CSAPR NO
(ii) The Administrator will adjust the allocation amount in paragraph (b)(4)(i) of this section in accordance with paragraphs (b)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR NO
(6) If the amount of CSAPR NO
(7) If the amount of CSAPR NO
(8) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.511(b)(2)(i) and (ii), of the amount of CSAPR NO
(9) For a control period before 2021, if, after completion of the procedures under paragraphs (b)(5) through (8) of this section for such control period, any unallocated CSAPR NO
(i)(A) For the control period in 2015 or 2016, the Administrator will determine, for each unit described in paragraph (b)(1) of this section that commenced commercial operation during the period starting May 1 of the year before the year of such control period and ending August 31 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR NO
(B) For the control period in 2017, 2018, 2019, or 2020, the Administrator will determine, for each unit described in paragraph (b)(1) of this section that commenced commercial operation during the period starting January 1 of the year before the year of such control period and ending November 30 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR NO
(ii) The Administrator will determine the sum of the positive differences determined under paragraph (b)(9)(i) of this section;
(iii) If the amount of unallocated CSAPR NO
(iv) If the amount of unallocated CSAPR NO
(10) If, after completion of the procedures under paragraphs (b)(9) and (12) of this section for a control period before 2021, or under paragraphs (b)(2) through (7) and (12) of this section for a control period in 2021 or thereafter, any unallocated CSAPR NO
(i) Transfer such unallocated CSAPR NO
(ii) If the State has a SIP revision approved under § 52.38(b)(4) or (5) of this chapter covering such control period, include such unallocated CSAPR NO
(11)(i) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.511(b)(2)(iii), (iv), and (v), of the amount of CSAPR NO
(ii) For a control period in 2021 or thereafter, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.511(b)(2)(i), (ii), and (v), of the amount of CSAPR NO
(12) Notwithstanding the requirements of paragraphs (b)(2) through (11) of this section, if the calculations of allocations from an Indian country new unit set-aside for a control period before 2021 under paragraph (b)(7) of this section or paragraphs (b)(6) and (b)(9)(iv) of this section, or for a control period in 2021 or thereafter under paragraph (b)(7) of this section, would otherwise result in total allocations from such Indian country new unit set-aside unequal to the total amount of such Indian country new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR NO
§ 97.513 Authorization of designated representative and alternate designated representative.
(a) Except as provided under § 97.515, each CSAPR NO
Ozone Season Group 1 Trading Program.
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.516:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each CSAPR NO
(ii) The owners and operators of the source and each CSAPR NO
(b) Except as provided under § 97.515, each CSAPR NO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.516,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each CSAPR NO
(c) Except in this section, § 97.502, and §§ 97.514 through 97.518, whenever the term “designated representative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
§ 97.514 Responsibilities of designated representative and alternate designated representative.
(a) Except as provided under § 97.518 concerning delegation of authority to make submissions, each submission under the CSAPR NO
(b) The Administrator will accept or act on a submission made for a CSAPR NO
§ 97.515 Changing designated representative and alternate designated representative; changes in owners and operators; changes in units at the source.
(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.516. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the CSAPR NO
(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.516. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the CSAPR NO
(c) Changes in owners and operators. (1) In the event an owner or operator of a CSAPR NO
(2) Within 30 days after any change in the owners and operators of a CSAPR NO
(d) Changes in units at the source. Within 30 days of any change in which units are located at a CSAPR NO
(1) If the change is the addition of a unit that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the source, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity from whom the unit was purchased or otherwise obtained (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was purchased or otherwise obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity to which the unit was sold or that otherwise obtained the unit (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was sold or otherwise obtained, and the date on which the unit became no longer located at the source.
§ 97.516 Certificate of representation.
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the CSAPR NO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the CSAPR NO
(4) The following certification statements by the designated representative and any alternate designated representative –
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each CSAPR NO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CSAPR NO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a CSAPR NO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(c) A certificate of representation under this section that complies with the provisions of paragraph (a) of this section except that it contains the phrase “TR NO
§ 97.517 Objections concerning designated representative and alternate designated representative.
(a) Once a complete certificate of representation under § 97.516 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.516 is received by the Administrator.
(b) Except as provided in paragraph (a) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CSAPR NO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of CSAPR NO
§ 97.518 Delegation by designated representative and alternate designated representative.
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.518(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.518(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.518 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
§ 97.519 [Reserved]
§ 97.520 Establishment of compliance accounts, assurance accounts, and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.516, the Administrator will establish a compliance account for the CSAPR NO
(b) Assurance accounts. The Administrator will establish assurance accounts for certain owners and operators and States in accordance with § 97.525(b)(3).
(c) General accounts – (1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring CSAPR NO
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to CSAPR NO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the CSAPR NO
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to CSAPR NO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(iv) An application for a general account under paragraph (c)(1) of this section that complies with the provisions of such paragraph except that it contains the phrase “TR NO
(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (c)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CSAPR NO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to CSAPR NO
(ii) Except as provided in paragraph (c)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to CSAPR NO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(iv) A certification statement submitted in accordance with paragraph (c)(2)(ii) of this section that contains the phrase “TR NO
(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the CSAPR NO
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the CSAPR NO
(iii)(A) In the event a person having an ownership interest with respect to CSAPR NO
(B) Within 30 days after any change in the persons having an ownership interest with respect to CSAPR NO
(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the CSAPR NO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of CSAPR NO
(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (c)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (c)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized account representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.520(c)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.520(c)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.520(c)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (c)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (c)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this section shall be deemed to be an electronic submission by the authorized account representative or alternate authorized account representative submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted CSAPR NO
(ii) If a general account has no CSAPR NO
(d) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a), (b), or (c) of this section.
(e) Responsibilities of authorized account representative and alternate authorized account representative. After the establishment of a compliance account or general account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of CSAPR NO
§ 97.521 Recordation of CSAPR NOX Ozone Season Group 1 allowance allocations and auction results.
(a) By November 7, 2011 or, with regard to units in Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, March 26, 2015, the Administrator will record in each CSAPR NO
(b) By November 7, 2011 or, with regard to units in Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, March 26, 2015, the Administrator will record in each CSAPR NO
(1) If, by April 1, 2015 or, with regard to CSAPR NO
(2) If the State submits to the Administrator by April 1, 2015 or, with regard to units in Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, October 1, 2015, and the Administrator approves by October 1, 2015 or, with regard to units in Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, April 1, 2016, such complete SIP revision, the Administrator will record by October 1, 2015 or, with regard to units in Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, April 1, 2016 in each CSAPR NO
(3) If the State submits to the Administrator by April 1, 2015 or, with regard to units in Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, October 1, 2015, and the Administrator does not approve by October 1, 2015 or, with regard to units in Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, April 1, 2016, such complete SIP revision, the Administrator will record by October 1, 2015 or, with regard to units in Iowa, Michigan, Missouri, Oklahoma, and Wisconsin, April 1, 2016 in each CSAPR NO
(c) By January 9, 2017, the Administrator will record in each CSAPR NO
(d) By July 1, 2017, the Administrator will record in each CSAPR NO
(e) By July 1, 2018, the Administrator will record in each CSAPR NO
(f)(1) By July 1, 2019 and July 1, 2020, the Administrator will record in each CSAPR NO
(2) By July 1, 2024 and July 1 of each year thereafter, the Administrator will record in each CSAPR NO
(g)(1) By August 1 of each year from 2015 through 2020, the Administrator will record in each CSAPR NO
(2) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR NO
(h)(1) By August 1 of each year from 2015 through 2020, the Administrator will record in each CSAPR NO
(2) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR NO
(i)(1) By November 15, 2015 and November 15, 2016, the Administrator will record in each CSAPR NO
(2) By February 15 of each year from 2018 through 2021, the Administrator will record in each CSAPR NO
(j)(1) By November 15, 2015 and November 15, 2016, the Administrator will record in each CSAPR NO
(2) By February 15 of each year from 2018 through 2021, the Administrator will record in each CSAPR NO
(k) By the date 15 days after the date on which any allocation or auction results, other than an allocation or auction results described in paragraphs (a) through (j) of this section, of CSAPR NO
(l) When recording the allocation or auction of CSAPR NO
§ 97.522 Submission of CSAPR NOX Ozone Season Group 1 allowance transfers.
(a) An authorized account representative seeking recordation of a CSAPR NO
(b) A CSAPR NO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each CSAPR NO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each CSAPR NO
§ 97.523 Recordation of CSAPR NOX Ozone Season Group 1 allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a CSAPR NO
(b) A CSAPR NO
(c) Where a CSAPR NO
(d) Within 5 business days of recordation of a CSAPR NO
(e) Within 10 business days of receipt of a CSAPR NO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
§ 97.524 Compliance with CSAPR NOX Ozone Season Group 1 emissions limitation.
(a) Availability for deduction for compliance. CSAPR NO
(1) Were allocated or auctioned for such control period or a control period in a prior year; and
(2) Are held in the source’s compliance account as of the allowance transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance with § 97.523, of CSAPR NO
(1) Until the amount of CSAPR NO
(2) If there are insufficient CSAPR NO
(c) Selection of CSAPR NO
(2) First-in, first-out. The Administrator will deduct CSAPR NO
(i) Any CSAPR NO
(ii) Any other CSAPR NO
(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in which the CSAPR NO
(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and (d) of this section.
§ 97.525 Compliance with CSAPR NOX Ozone Season Group 1 assurance provisions.
(a) Availability for deduction. CSAPR NO
(1) Were allocated or auctioned for a control period in a prior year or the control period in the given year or in the immediately following year; and
(2) Are held in the assurance account, established by the Administrator for such owners and operators of such group of CSAPR NO
(b) Deductions for compliance. The Administrator will deduct CSAPR NO
(1) By June 1 of each year from 2018 through 2021 and August 1 of each year thereafter, the Administrator will:
(i) Calculate, for each State (and Indian country within the borders of such State), the total NO
(ii) For the set of any States (and Indian country within the borders of such States) for which the results of the calculations required in paragraph (b)(1)(i) of this section indicate that total NO
(A) Calculate, for each such State (and Indian country within the borders of such State) and such control period and each common designated representative for such control period for a group of one or more CSAPR NO
(B) Promulgate a notice of data availability of the results of the calculations required in paragraphs (b)(1)(i) and (b)(1)(ii)(A) of this section, including separate calculations of the NO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice of data availability required in paragraph (b)(1)(ii) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations referenced in such notice are in accordance with § 97.506(c)(2)(iii), §§ 97.506(b) and 97.530 through 97.535, the definitions of “common designated representative”, “common designated representative’s assurance level”, and “common designated representative’s share” in § 97.502, and the calculation formula in § 97.506(c)(2)(i).
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By October 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) For any State (and Indian country within the borders of such State) referenced in each notice of data availability required in paragraph (b)(2)(ii) of this section as having CSAPR NO
(4)(i) As of midnight of November 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section, the owners and operators described in paragraph (b)(3) of this section shall hold in the assurance account established for them and for the appropriate CSAPR NO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(4)(i) of this section, if November 1 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section and after the recordation, in accordance with § 97.523, of CSAPR NO
(6) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notice of data availability required in paragraph (b)(2)(ii) of this section for a control period in a given year, of any data used in making the calculations referenced in such notice, the amounts of CSAPR NO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of CSAPR NO
(ii) [Reserved]
(iii) If the revised data are used to recalculate, in accordance with paragraph (b)(6)(i) of this section, the amount of CSAPR NO
(A) Where the amount of CSAPR NO
(B) For the owners and operators for which the amount of CSAPR NO
(C) Each CSAPR NO
§ 97.526 Banking and conversion.
(a) A CSAPR NO
(b) Any CSAPR NO
of this section.
(c) At any time after the allowance transfer deadline for the last control period for which a State NO
(d) Notwithstanding any other provision of this subpart, part 52 of this chapter, or any SIP revision approved under § 52.38(b)(4) or (5) of this chapter:
(1) As soon as practicable after the completion of deductions under § 97.524 for the control period in 2016, but not later than March 1, 2018, the Administrator will temporarily suspend acceptance of CSAPR NO
(i) The Administrator will deduct all CSAPR NO
(ii) The Administrator will determine a conversion factor equal to the greater of 1.0000 or the quotient, expressed to four decimal places, of the sum of all CSAPR NO
(iii) The Administrator will allocate and record in each such account an amount of CSAPR NO
(iv) Where, pursuant to paragraph (d)(1)(i) of this section, the Administrator deducts CSAPR NO
(2)(i) After the Administrator has carried out the procedures set forth in paragraph (d)(1) of this section, upon any determination that would otherwise result in the initial recordation of a given number of CSAPR NO
(ii) After the Administrator has carried out the procedures set forth in paragraph (d)(1) of this section and § 97.826(d)(1), upon any determination that would otherwise result in the initial recordation of a given number of CSAPR NO
(e) Notwithstanding any other provision of this subpart or any SIP revision approved under § 52.38(b)(4) or (5) of this chapter, CSAPR NO
(1) After the Administrator has carried out the procedures set forth in paragraph (d)(1) of this section, the owner or operator of a CSAPR NO
(2) After the Administrator has carried out the procedures set forth in paragraph (d)(1) of this section and § 97.826(d)(1), the owner or operator of a CSAPR NO
§ 97.527 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
§ 97.528 Administrator’s action on submissions.
(a) The Administrator may review and conduct independent audits concerning any submission under the CSAPR NO
(b) The Administrator may deduct CSAPR NO
§ 97.529 [Reserved]
§ 97.530 General monitoring, recordkeeping, and reporting requirements.
The owners and operators, and to the extent applicable, the designated representative, of a CSAPR NO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each CSAPR NO
(1) Install all monitoring systems required under this subpart for monitoring NO
(2) Successfully complete all certification tests required under § 97.531 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator of a CSAPR NO
(1) May 1, 2015;
(2) 180 calendar days after the date on which the unit commences commercial operation; or
(3) Where data for the unit are reported on a control period basis under § 97.534(d)(1)(ii)(B), and where the compliance date under paragraph (b)(2) of this section is not in a month from May through September, May 1 immediately after the compliance date under paragraph (b)(2) of this section.
(4) The owner or operator of a CSAPR NO
(i) Such requirements shall apply to the monitoring systems required under § 97.530 through § 97.535, rather than the monitoring systems required under part 75 of this chapter;
(ii) NO
(iii) Any petition for another procedure under § 75.4(e)(2) of this chapter shall be submitted under § 97.535, rather than § 75.66 of this chapter.
(c) Reporting data. The owner or operator of a CSAPR NO
(d) Prohibitions. (1) No owner or operator of a CSAPR NO
(2) No owner or operator of a CSAPR NO
(3) No owner or operator of a CSAPR NO
(4) No owner or operator of a CSAPR NO
(i) During the period that the unit is covered by an exemption under § 97.505 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.531(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a CSAPR NO
§ 97.531 Initial monitoring system certification and recertification procedures.
(a) The owner or operator of a CSAPR NO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B, D, and E to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.530(a)(1) that is exempt from initial certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the NO
(d) Except as provided in paragraph (a) of this section, the owner or operator of a CSAPR NO
(1) Requirements for initial certification. The owner or operator shall ensure that each continuous monitoring system under § 97.530(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.530(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.530(a)(1) that may significantly affect the ability of the system to accurately measure or record NO
(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.530(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in § 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words “certification” and “initial certification” are replaced by the word “recertification” and the word “certified” is replaced by the word “recertified”.
(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office and the Administrator written notice of the dates of certification testing, in accordance with § 97.533.
(ii) Certification application. The designated representative shall submit to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the CSAPR NO
(iv) Certification application approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the CSAPR NO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.532(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NO
(2) For a disapproved NO
(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(5) For a disapproved excepted NO
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
§ 97.532 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D or subpart H of, or appendix D or appendix E to, part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.531 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the Administrator or any State or permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 97.531 for each disapproved monitoring system.
§ 97.533 Notifications concerning monitoring.
The designated representative of a CSAPR NO
§ 97.534 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply with all recordkeeping and reporting requirements in paragraphs (b) through (e) of this section, the applicable recordkeeping and reporting requirements under § 75.73 of this chapter, and the requirements of § 97.514(a).
(b) Monitoring plans. The owner or operator of a CSAPR NO
(c) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all initial certification or recertification tests required under § 97.531, including the information required under § 75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit quarterly reports, as follows:
(1)(i) If a CSAPR NO
(ii) If a CSAPR NO
(A) Meet the requirements of subpart H of part 75 of this chapter for such unit for the entire year and report the NO
(B) Meet the requirements of subpart H of part 75 of this chapter (including the requirements in § 75.74(c) of this chapter) for such unit for the control period and report the NO
(2) The designated representative shall report the NO
(i) The calendar quarter covering May 1, 2015 through June 30, 2015;
(ii) The calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.530(b); or
(iii) For a unit that reports on a control period basis under paragraph (d)(1)(ii)(B) of this section, if the calendar quarter under paragraph (d)(2)(ii) of this section does not include a month from May through September, the calendar quarter covering May 1 through June 30 immediately after the calendar quarter under paragraph (d)(2)(ii) of this section.
(3) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.
(4) For CSAPR NO
(5) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(3) of this section.
(e) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications;
(2) For a unit with add-on NO
(3) For a unit that is reporting on a control period basis under paragraph (d)(1)(ii)(B) of this section, the NO
§ 97.535 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements.
(a) The designated representative of a CSAPR NO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(1) Identification of each unit and source covered by the petition;
(2) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used in the proposed alternative;
(4) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be de minimis; and
(5) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
Subpart CCCCC – CSAPR SO2 Group 1 Trading Program
§ 97.601 Purpose.
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Cross-State Air Pollution Rule (CSAPR) SO
§ 97.602 Definitions.
The terms used in this subpart shall have the meanings set forth in this section as follows, provided that any term that includes the acronym “CSAPR” shall be considered synonymous with a term that is used in a SIP revision approved by the Administrator under § 52.38 or § 52.39 of this chapter and that is substantively identical except for the inclusion of the acronym “TR” in place of the acronym “CSAPR”:
Acid Rain Program means a multi-state SO
Administrator means the Administrator of the United States Environmental Protection Agency or the Director of the Clean Air Markets Division (or its successor determined by the Administrator) of the United States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.
Allocate or allocation means, with regard to CSAPR SO
(1) A CSAPR SO
(2) A new unit set-aside;
(3) An Indian country new unit set-aside; or
(4) An entity not listed in paragraphs (1) through (3) of this definition;
(5) Provided that, if the Administrator, State, or permitting authority initially credits, to a CSAPR SO
Allowance Management System means the system by which the Administrator records allocations, auctions, transfers, and deductions of CSAPR SO
Allowance Management System account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, auction, holding, transfer, or deduction of CSAPR SO
Allowance transfer deadline means, for a control period before 2021, midnight of March 1 immediately after such control period or, for a control period in 2021 or thereafter, midnight of June 1 immediately after such control period (or if such March 1 or June 1 is not a business day, midnight of the first business day thereafter) and is the deadline by which a CSAPR SO
Alternate designated representative means, for a CSAPR SO
Assurance account means an Allowance Management System account, established by the Administrator under § 97.625(b)(3) for certain owners and operators of a group of one or more CSAPR SO
Auction means, with regard to CSAPR SO
Authorized account representative means, for a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of CSAPR SO
Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by this subpart.
Biomass means –
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other material that is nonmerchantable for other purposes, and that is:
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
Bottoming-cycle unit means a unit in which the energy input to the unit is first used to produce useful thermal energy, where at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.
Business day means a day that does not fall on a weekend or a federal holiday.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function or any other person who performs similar policy- or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means “coal” as defined in § 72.2 of this chapter.
Cogeneration system means an integrated group, at a source, of equipment (including a boiler, or combustion turbine, and a generator) designed to produce useful thermal energy for industrial, commercial, heating, or cooling purposes and electricity through the sequential use of energy.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a topping-cycle unit or a bottoming-cycle unit:
(1) Operating as part of a cogeneration system; and
(2) Producing on an annual average basis –
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output; or
(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;
(3) Provided that the requirements in paragraph (2) of this definition shall not apply to a calendar year referenced in paragraph (2) of this definition during which the unit did not operate at all;
(4) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel, except biomass if the unit is a boiler; and
(5) Provided that, if, throughout its operation during the 12-month period or a calendar year referenced in paragraph (2) of this definition, a unit is operated as part of a cogeneration system and the cogeneration system meets on a system-wide basis the requirement in paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be deemed to meet such requirement during that 12-month period or calendar year.
Combustion turbine means an enclosed device comprising:
(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.605.
(i) For a unit that is a CSAPR SO
(ii) For a unit that is a CSAPR SO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.605, for a unit that is not a CSAPR SO
(i) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change or is moved to a different location or source, such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same or a different source, such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
Common designated representative means, with regard to a control period in a given year, a designated representative where, as of April 1 immediately after the allowance transfer deadline for such a control period before 2021, or as of July 1 immediately after such deadline for such a control period in 2021 or thereafter, the same natural person is authorized under §§ 97.613(a) and 97.615(a) as the designated representative for a group of one or more CSAPR SO
Common designated representative’s assurance level means, with regard to a specific common designated representative and a State (and Indian country within the borders of such State) and control period in a given year for which the State assurance level is exceeded as described in § 97.606(c)(2)(iii), the amount (rounded to the nearest allowance) equal to the sum of the total amount of CSAPR SO
Common designated representative’s share means, with regard to a specific common designated representative for a control period in a given year and a total amount of SO
Common stack means a single flue through which emissions from 2 or more units are exhausted.
Compliance account means an Allowance Management System account, established by the Administrator for a CSAPR SO
Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent record of SO
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A SO
(3) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(4) A CO
(5) An O
Control period means the period starting January 1 of a calendar year, except as provided in § 97.606(c)(3), and ending on December 31 of the same year, inclusive.
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR SO
CSAPR SO
CSAPR SO
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, CSAPR SO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, CSAPR SO
CSAPR SO
CSAPR SO
CSAPR SO
CSAPR SO
Designated representative means, for a CSAPR SO
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative, and as modified by the Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required to measure, record, and report such air pollutants in accordance with this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the CSAPR SO
Fossil fuel means –
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or
(2) For purposes of applying the limitation on “average annual fuel consumption of fossil fuel” in § 97.604(b)(2)(i)(B) and (b)(2)(ii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account, established under this subpart, that is not a compliance account or an assurance account.
Generator means a device that produces electricity.
Heat input means, for a unit for a specified period of unit operating time, the product (in mmBtu) of the gross calorific value of the fuel (in mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of fuel/time) and unit operating time, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the quotient (in mmBtu/hr) of the amount of heat input for a specified period of unit operating time (in mmBtu) divided by unit operating time (in hr) or, for a unit and a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Indian country means “Indian country” as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Maximum design heat input rate means, for a unit, the maximum amount of fuel per hour (in Btu/hr) that the unit is capable of combusting on a steady state basis as of the initial installation of the unit as specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe, rounded to the nearest tenth) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount (in MWe, rounded to the nearest tenth) as of such completion as specified by the person conducting the physical change.
Natural gas means “natural gas” as defined in § 72.2 of this chapter.
Newly affected CSAPR SO
Nitrogen oxides means all oxides of nitrogen except nitrous oxide (N
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a CSAPR SO
Owner means, for a CSAPR SO
(1) Any holder of any portion of the legal or equitable title in a CSAPR SO
(2) Any holder of a leasehold interest in a CSAPR SO
(3) Any purchaser of power from a CSAPR SO
Permanently retired means, with regard to a unit, a unit that is unavailable for service and that the unit’s owners and operators do not expect to return to service in the future.
Permitting authority means “permitting authority” as defined in §§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity means, for a unit (in MWh/yr), 33 percent of the unit’s maximum design heat input rate (in Btu/hr), divided by 3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to CSAPR SO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.
Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or retired unit (the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from electricity production in a useful thermal energy application or process; or
(2) The use of reject heat from a useful thermal energy application or process in electricity production.
Serial number means, for a CSAPR SO
Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act.
Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the definition of “major source”, “stationary source”, or “source” as set forth and implemented in a title V operating permit program or any other program under the Clean Air Act.
State means one of the States that is subject to the CSAPR SO
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Topping-cycle unit means a unit in which the energy input to the unit is first used to produce useful power, including electricity, where at least some of the reject heat from the electricity production is then used to provide useful thermal energy.
Total energy input means, for a unit, total energy of all forms supplied to the unit, excluding energy produced by the unit. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:
Total energy output means, for a unit, the sum of useful power and useful thermal energy produced by the unit.
Unit means a stationary, fossil-fuel-fired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-fired combustion device. A unit that undergoes a physical change or is moved to a different location or source shall continue to be treated as the same unit. A unit (the replaced unit) that is replaced by another unit (the replacement unit) at the same or a different source shall continue to be treated as the same unit, and the replacement unit shall be treated as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to a unit, an hour in which the unit combusts any fuel.
Useful power means, with regard to a unit, electricity or mechanical energy that the unit makes available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means thermal energy that is:
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption chiller).
Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.
§ 97.603 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
§ 97.604 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State (and Indian country within the borders of such State) shall be CSAPR SO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a CSAPR SO
(b) Any unit in a State (and Indian country within the borders of such State) that otherwise is a CSAPR SO
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) Not supplying in 2005 or any calendar year thereafter more than one-third of the unit’s potential electrical output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If, after qualifying under paragraph (b)(1)(i) of this section as not being a CSAPR SO
(2)(i) Any unit:
(A) Qualifying as a solid waste incineration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) With an average annual fuel consumption of fossil fuel for the first 3 consecutive calendar years of operation starting no earlier than 2005 of less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years thereafter of less than 20 percent (on a Btu basis).
(ii) If, after qualifying under paragraph (b)(2)(i) of this section as not being a CSAPR SO
(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section or a SIP revision approved under § 52.39(e) or (f) of this chapter, of the CSAPR SO
(1) Petition content. The petition shall be in writing and include the identification of the unit or other equipment and the relevant facts about the unit or other equipment. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying official: “I am authorized to make this submission on behalf of the owners and operators of the unit or other equipment for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) Response. The Administrator will issue a written response to the petition and may request supplemental information determined by the Administrator to be relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CSAPR SO
§ 97.605 Retired unit exemption.
(a)(1) Any CSAPR SO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the CSAPR SO
(b)(1) A unit exempt under paragraph (a) of this section shall not emit any SO
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the CSAPR SO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.
§ 97.606 Standard requirements.
(a) Designated representative requirements. The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.613 through 97.618.
(b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each CSAPR SO
(2) The emissions data determined in accordance with §§ 97.630 through 97.635 shall be used to calculate allocations of CSAPR SO
(c) SO
(ii) If total SO
(A) The owners and operators of the source and each CSAPR SO
(B) The owners and operators of the source and each CSAPR SO
(2) CSAPR SO
(A) The quotient of the amount by which the common designated representative’s share of such SO
(B) The amount by which total SO
(ii) The owners and operators shall hold the CSAPR SO
(iii) Total SO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if total SO
(v) To the extent the owners and operators fail to hold CSAPR SO
(A) The owners and operators shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each CSAPR SO
(3) Compliance periods. (i) A CSAPR SO
(ii) A CSAPR SO
(4) Vintage of CSAPR SO
(ii) A CSAPR SO
(5) Allowance Management System requirements. Each CSAPR SO
(6) Limited authorization. A CSAPR SO
(i) Such authorization shall only be used in accordance with the CSAPR SO
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7) Property right. A CSAPR SO
(d) Title V permit requirements. (1) No title V permit revision shall be required for any allocation, holding, deduction, or transfer of CSAPR SO
(2) A description of whether a unit is required to monitor and report SO
(e) Additional recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of each CSAPR SO
(i) The certificate of representation under § 97.616 for the designated representative for the source and each CSAPR SO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the CSAPR SO
(2) The designated representative of a CSAPR SO
(f) Liability. (1) Any provision of the CSAPR SO
(2) Any provision of the CSAPR SO
(g) Effect on other authorities. No provision of the CSAPR SO
§ 97.607 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the CSAPR SO
(b) Unless otherwise stated, any time period scheduled, under the CSAPR SO
(c) Unless otherwise stated, if the final day of any time period, under the CSAPR SO
§ 97.608 Administrative appeal procedures.
The administrative appeal procedures for decisions of the Administrator under the CSAPR SO
§ 97.609 [Reserved]
§ 97.610 State SO2 Group 1 trading budgets, new unit set-asides, Indian country new unit set-asides, and variability limits.
(a) The State SO
(1) Illinois. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 11,744 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 6,223 tons.
(vi) [Reserved]
(2) Indiana. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 8,723 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 4,993 tons.
(vi) [Reserved]
(3) Iowa. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 2,035 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 107 tons.
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 1,426 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 75 tons.
(4) Kentucky. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 13,960 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 6,381 tons.
(vi) [Reserved]
(5) Maryland. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 602 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 568 tons.
(vi) [Reserved]
(6) Michigan. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 4,357 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 229 tons.
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 2,743 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 144 tons.
(7) Missouri. (i) The SO
(ii) The new unit set-aside for 2015 is 4,149 tons and for 2016 is 6,224 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 4,982 tons.
(vi) [Reserved]
(8) New Jersey. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 153 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 110 tons.
(vi) [Reserved]
(9) New York. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 690 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 36 tons.
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 535 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 28 tons.
(10) North Carolina. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 10,813 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 137 tons.
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 4,559 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 58 tons.
(11) Ohio. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 6,308 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 2,850 tons.
(vi) [Reserved]
(12) Pennsylvania. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 5,573 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 2,242 tons.
(vi) [Reserved]
(13) Tennessee. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 2,963 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 1,181 tons.
(vi) [Reserved]
(14) Virginia. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 2,833 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 1,401 tons.
(vi) [Reserved]
(15) West Virginia. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 10,232 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 5,299 tons.
(vi) [Reserved]
(16) Wisconsin. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 3,099 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 80 tons.
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 1,870 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 48 tons.
(b) The States’ variability limits for the State SO
(1) The variability limit for Illinois is 22,342 tons.
(2) The variability limit for Indiana is 29,961 tons.
(3) The variability limit for Iowa is 13,533 tons.
(4) The variability limit for Kentucky is 19,131 tons.
(5) The variability limit for Maryland is 5,077 tons.
(6) The variability limit for Michigan is 25,919 tons.
(7) The variability limit for Missouri is 29,869 tons.
(8) The variability limit for New Jersey is 1,003 tons.
(9) The variability limit for New York is 4,960 tons.
(10) The variability limit for North Carolina is 10,372 tons.
(11) The variability limit for Ohio is 25,603 tons.
(12) The variability limit for Pennsylvania is 20,164 tons.
(13) The variability limit for Tennessee is 10,590 tons.
(14) The variability limit for Virginia is 6,310 tons.
(15) The variability limit for West Virginia is 13,620 tons.
(16) The variability limit for Wisconsin is 8,619 tons.
(c) Each State SO
§ 97.611 Timing requirements for CSAPR SO2 Group 1 allowance allocations.
(a) Existing units. (1) CSAPR SO
(2) Notwithstanding paragraph (a)(1) of this section, if a unit provided an allocation in the notice of data availability issued under paragraph (a)(1) of this section does not operate, starting after 2014, during the control period in two consecutive years, such unit will not be allocated the CSAPR SO
(b) New units – (1) New unit set-asides. (i)(A) By June 1 of each year from 2015 through 2020, the Administrator will calculate the CSAPR SO
(B) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR SO
(ii) For each notice of data availability required in paragraph (b)(1)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR SO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(1)(i)(A) or (B) of this section, as applicable. By August 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i)(A) of this section, or by May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i)(B) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(1)(ii)(A) of this section.
(iii) If the new unit set-aside for a control period before 2021 contains any CSAPR SO
(iv) For each notice of data availability required in paragraph (b)(1)(iii) of this section, the Administrator will provide an opportunity for submission of objections to the identification of CSAPR SO
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(iii) of this section and shall be limited to addressing whether the identification of CSAPR SO
(B) The Administrator will adjust the identification of CSAPR SO
(v) To the extent any CSAPR SO
(2) Indian country new unit set-asides. (i)(A) By June 1 of each year from 2015 through 2020, the Administrator will calculate the CSAPR SO
(B) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR SO
(ii) For each notice of data availability required in paragraph (b)(2)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR SO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i)(A) or (B) of this section, as applicable. By August 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i)(A) of this section, or by May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i)(B) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(ii)(A) of this section.
(iii) If the Indian country new unit set-aside for a control period before 2021 contains any CSAPR SO
(iv) For each notice of data availability required in paragraph (b)(2)(iii) of this section, the Administrator will provide an opportunity for submission of objections to the identification of CSAPR SO
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(iii) of this section and shall be limited to addressing whether the identification of CSAPR SO
(B) The Administrator will adjust the identification of CSAPR SO
(v) To the extent any CSAPR SO
(c) Units incorrectly allocated CSAPR SO
(i)(A) The recipient is not actually a CSAPR SO
(B) The recipient is not located as of January 1 of the control period in the State from whose SO
(ii) The recipient is not actually a CSAPR SO
(2) Except as provided in paragraph (c)(3) or (4) of this section, the Administrator will not record such CSAPR SO
(3) If the Administrator already recorded such CSAPR SO
(4) If the Administrator already recorded such CSAPR SO
(5)(i) With regard to the CSAPR SO
(A) Transfer such CSAPR SO
(B) If the State has a SIP revision approved under § 52.39(e) or (f) of this chapter covering such control period, include such CSAPR SO
(ii) With regard to the CSAPR SO
(A) Transfer such CSAPR SO
(B) If the State has a SIP revision approved under § 52.39(e) or (f) of this chapter covering such control period, include such CSAPR SO
(iii) With regard to the CSAPR SO
§ 97.612 CSAPR SO2 Group 1 allowance allocations to new units.
(a) Allocations from new unit set-asides. For each control period in 2015 and thereafter and for the CSAPR SO
(1) The CSAPR SO
(i) CSAPR SO
(ii) CSAPR SO
(iii) CSAPR SO
(iv) For purposes of paragraph (a)(9) of this section, CSAPR SO
(2) The Administrator will establish a separate new unit set-aside for the State for each such control period. Each such new unit set-aside will be allocated CSAPR SO
(3) The Administrator will determine, for each CSAPR SO
(i) The control period in 2015;
(ii)(A) The first control period after the control period in which the CSAPR SO
(B) The control period containing the deadline for certification of the CSAPR SO
(iii) For a unit described in paragraph (a)(1)(ii) of this section, the first control period in which the CSAPR SO
(iv) For a unit described in paragraph (a)(1)(iii) of this section, the first control period after the control period in which the unit resumes operation, for allocations for a control period before 2021, or the control period in which the unit resumes operation, for allocations for a control period in 2021 or thereafter.
(4)(i) The allocation to each CSAPR SO
(ii) The Administrator will adjust the allocation amount in paragraph (a)(4)(i) of this section in accordance with paragraphs (a)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR SO
(6) If the amount of CSAPR SO
(7) If the amount of CSAPR SO
(8) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.611(b)(1)(i) and (ii), of the amount of CSAPR SO
(9) For a control period before 2021, if, after completion of the procedures under paragraphs (a)(5) through (8) of this section for such control period, any unallocated CSAPR SO
(i) The Administrator will determine, for each unit described in paragraph (a)(1) of this section that commenced commercial operation during the period starting January 1 of the year before the year of such control period and ending November 30 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR SO
(ii) The Administrator will determine the sum of the positive differences determined under paragraph (a)(9)(i) of this section;
(iii) If the amount of unallocated CSAPR SO
(iv) If the amount of unallocated CSAPR SO
(10) If, after completion of the procedures under paragraphs (a)(9) and (12) of this section for a control period before 2021, or under paragraphs (a)(2) through (7) and (12) of this section for a control period in 2021 or thereafter, any unallocated CSAPR SO
(11)(i) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.611(b)(1)(iii), (iv), and (v), of the amount of CSAPR SO
(ii) For a control period in 2021 or thereafter, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.611(b)(1)(i), (ii), and (v), of the amount of CSAPR SO
(12) Notwithstanding the requirements of paragraphs (a)(2) through (11) of this section, if the calculations of allocations from a new unit set-aside for a control period before 2021 under paragraph (a)(7) of this section, paragraphs (a)(6) and (a)(9)(iv) of this section, or paragraphs (a)(6), (a)(9)(iii), and (a)(10) of this section, or for a control period in 2021 or thereafter under paragraph (a)(7) of this section or paragraphs (a)(6) and (10) of this section, would otherwise result in total allocations from such new unit set-aside unequal to the total amount of such new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR SO
(b) Allocations from Indian country new unit set-asides. For each control period in 2015 and thereafter and for the CSAPR SO
(1) The CSAPR SO
(i) CSAPR SO
(ii) For purposes of paragraph (b)(9) of this section, CSAPR SO
(2) The Administrator will establish a separate Indian country new unit set-aside for the State for each such control period. Each such Indian country new unit set-aside will be allocated CSAPR SO
(3) The Administrator will determine, for each CSAPR SO
(i) The control period in 2015; and
(ii)(A) The first control period after the control period in which the CSAPR SO
(B) The control period containing the deadline for certification of the CSAPR SO
(4)(i) The allocation to each CSAPR SO
(ii) The Administrator will adjust the allocation amount in paragraph (b)(4)(i) of this section in accordance with paragraphs (b)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR SO
(6) If the amount of CSAPR SO
(7) If the amount of CSAPR SO
(8) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.611(b)(2)(i) and (ii), of the amount of CSAPR SO
(9) For a control period before 2021, if, after completion of the procedures under paragraphs (b)(5) through (8) of this section for such control period, any unallocated CSAPR SO
(i) The Administrator will determine, for each unit described in paragraph (b)(1) of this section that commenced commercial operation during the period starting January 1 of the year before the year of such control period and ending November 30 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR SO
(ii) The Administrator will determine the sum of the positive differences determined under paragraph (b)(9)(i) of this section;
(iii) If the amount of unallocated CSAPR SO
(iv) If the amount of unallocated CSAPR SO
(10) If, after completion of the procedures under paragraphs (b)(9) and (12) of this section for a control period before 2021, or under paragraphs (b)(2) through (7) and (12) of this section for a control period in 2021 or thereafter, any unallocated CSAPR SO
(i) Transfer such unallocated CSAPR SO
(ii) If the State has a SIP revision approved under § 52.39(e) or (f) of this chapter covering such control period, include such unallocated CSAPR SO
(11)(i) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.611(b)(2)(iii), (iv), and (v), of the amount of CSAPR SO
(ii) For a control period in 2021 or thereafter, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.611(b)(2)(i), (ii), and (v), of the amount of CSAPR SO
(12) Notwithstanding the requirements of paragraphs (b)(2) through (11) of this section, if the calculations of allocations from an Indian country new unit set-aside for a control period before 2021 under paragraph (b)(7) of this section or paragraphs (b)(6) and (b)(9)(iv) of this section, or for a control period in 2021 or thereafter under paragraph (b)(7) of this section, would otherwise result in total allocations from such Indian country new unit set-aside unequal to the total amount of such Indian country new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR SO
§ 97.613 Authorization of designated representative and alternate designated representative.
(a) Except as provided under § 97.615, each CSAPR SO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR SO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.616:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each CSAPR SO
(ii) The owners and operators of the source and each CSAPR SO
(b) Except as provided under § 97.615, each CSAPR SO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR SO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.616,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each CSAPR SO
(c) Except in this section, § 97.602, and §§ 97.614 through 97.618, whenever the term “designated representative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
§ 97.614 Responsibilities of designated representative and alternate designated representative.
(a) Except as provided under § 97.618 concerning delegation of authority to make submissions, each submission under the CSAPR SO
(b) The Administrator will accept or act on a submission made for a CSAPR SO
§ 97.615 Changing designated representative and alternate designated representative; changes in owners and operators; changes in units at the source.
(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.616. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the CSAPR SO
(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.616. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the CSAPR SO
(c) Changes in owners and operators. (1) In the event an owner or operator of a CSAPR SO
(2) Within 30 days after any change in the owners and operators of a CSAPR SO
(d) Changes in units at the source. Within 30 days of any change in which units are located at a CSAPR SO
(1) If the change is the addition of a unit that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the source, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity from whom the unit was purchased or otherwise obtained (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was purchased or otherwise obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity to which the unit was sold or that otherwise obtained the unit (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was sold or otherwise obtained, and the date on which the unit became no longer located at the source.
§ 97.616 Certificate of representation.
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the CSAPR SO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the CSAPR SO
(4) The following certification statements by the designated representative and any alternate designated representative –
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each CSAPR SO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CSAPR SO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a CSAPR SO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(c) A certificate of representation under this section that complies with the provisions of paragraph (a) of this section except that it contains the acronym “TR” in place of the acronym “CSAPR” in the required certification statements will be considered a complete certificate of representation under this section, and the certification statements included in such certificate of representation will be interpreted as if the acronym “CSAPR” appeared in place of the acronym “TR”.
§ 97.617 Objections concerning designated representative and alternate designated representative.
(a) Once a complete certificate of representation under § 97.616 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.616 is received by the Administrator.
(b) Except as provided in paragraph (a) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CSAPR SO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of CSAPR SO
§ 97.618 Delegation by designated representative and alternate designated representative.
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.618(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.618(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.618 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
§ 97.619 [Reserved]
§ 97.620 Establishment of compliance accounts, assurance accounts, and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.616, the Administrator will establish a compliance account for the CSAPR SO
(b) Assurance accounts. The Administrator will establish assurance accounts for certain owners and operators and States in accordance with § 97.625(b)(3).
(c) General accounts – (1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring CSAPR SO
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to CSAPR SO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the CSAPR SO
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to CSAPR SO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(iv) An application for a general account under paragraph (c)(1) of this section that complies with the provisions of such paragraph except that it contains the acronym “TR” in place of the acronym “CSAPR” in the required certification statement will be considered a complete application for a general account under such paragraph, and the certification statement included in such application for a general account will be interpreted as if the acronym “CSAPR” appeared in place of the acronym “TR”.
(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (c)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CSAPR SO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to CSAPR SO
(ii) Except as provided in paragraph (c)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to CSAPR SO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(iv) A certification statement submitted in accordance with paragraph (c)(2)(ii) of this section that contains the acronym “TR” will be interpreted as if the acronym “CSAPR” appeared in place of the acronym “TR”.
(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the CSAPR SO
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the CSAPR SO
(iii)(A) In the event a person having an ownership interest with respect to CSAPR SO
(B) Within 30 days after any change in the persons having an ownership interest with respect to CSAPR SO
(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the CSAPR SO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of CSAPR SO
(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (c)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (c)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized account representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.620(c)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.620(c)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.620(c)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (c)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (c)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this section shall be deemed to be an electronic submission by the authorized account representative or alternate authorized account representative submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted CSAPR SO
(ii) If a general account has no CSAPR SO
(d) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a), (b), or (c) of this section.
(e) Responsibilities of authorized account representative and alternate authorized account representative. After the establishment of a compliance account or general account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of CSAPR SO
§ 97.621 Recordation of CSAPR SO2 Group 1 allowance allocations and auction results.
(a) By November 7, 2011, the Administrator will record in each CSAPR SO
(b) By November 7, 2011, the Administrator will record in each CSAPR SO
(1) If, by April 1, 2015, the State does not submit to the Administrator such complete SIP revision, the Administrator will record by April 15, 2015 in each CSAPR SO
(2) If the State submits to the Administrator by April 1, 2015, and the Administrator approves by October 1, 2015, such complete SIP revision, the Administrator will record by October 1, 2015 in each CSAPR SO
(3) If the State submits to the Administrator by April 1, 2015, and the Administrator does not approve by October 1, 2015, such complete SIP revision, the Administrator will record by October 1, 2015 in each CSAPR SO
(c) By July 1, 2016, the Administrator will record in each CSAPR SO
(d) By July 1, 2017, the Administrator will record in each CSAPR SO
(e) By July 1, 2018, the Administrator will record in each CSAPR SO
(f)(1)By July 1, 2019 and July 1, 2020, the Administrator will record in each CSAPR SO
(2) By July 1, 2024 and July 1 of each year thereafter, the Administrator will record in each CSAPR SO
(g)(1) By August 1 of each year from 2015 through 2020, the Administrator will record in each CSAPR SO
(2) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR SO
(h)(1) By August 1 of each year from 2015 through 2020, the Administrator will record in each CSAPR SO
(2) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR SO
(i) By February 15 of each year from 2016 through 2021, the Administrator will record in each CSAPR SO
(j) By February 15 of each year from 2016 through 2021, the Administrator will record in each CSAPR SO
(k) By the date 15 days after the date on which any allocation or auction results, other than an allocation or auction results described in paragraphs (a) through (j) of this section, of CSAPR SO
(l) When recording the allocation or auction of CSAPR SO
§ 97.622 Submission of CSAPR SO2 Group 1 allowance transfers.
(a) An authorized account representative seeking recordation of a CSAPR SO
(b) A CSAPR SO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each CSAPR SO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each CSAPR SO
§ 97.623 Recordation of CSAPR SO2 Group 1 allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a CSAPR SO
(b) A CSAPR SO
(c) Where a CSAPR SO
(d) Within 5 business days of recordation of a CSAPR SO
(e) Within 10 business days of receipt of a CSAPR SO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
§ 97.624 Compliance with CSAPR SO2 Group 1 emissions limitation.
(a) Availability for deduction for compliance. CSAPR SO
(1) Were allocated or auctioned for such control period or a control period in a prior year; and
(2) Are held in the source’s compliance account as of the allowance transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance with § 97.623, of CSAPR SO
(1) Until the amount of CSAPR SO
(2) If there are insufficient CSAPR SO
(c) Selection of CSAPR SO
(2) First-in, first-out. The Administrator will deduct CSAPR SO
(i) Any CSAPR SO
(ii) Any other CSAPR SO
(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in which the CSAPR SO
(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and (d) of this section.
§ 97.625 Compliance with CSAPR SO2 Group 1 assurance provisions.
(a) Availability for deduction. CSAPR SO
(1) Were allocated or auctioned for a control period in a prior year or the control period in the given year or in the immediately following year; and
(2) Are held in the assurance account, established by the Administrator for such owners and operators of such group of CSAPR SO
(b) Deductions for compliance. The Administrator will deduct CSAPR SO
(1) By June 1 of each year from 2018 through 2021 and August 1 of each year thereafter, the Administrator will:
(i) Calculate, for each State (and Indian country within the borders of such State), the total SO
(ii) For the set of any States (and Indian country within the borders of such States) for which the results of the calculations required in paragraph (b)(1)(i) of this section indicate that total SO
(A) Calculate, for each such State (and Indian country within the borders of such State) and such control period and each common designated representative for such control period for a group of one or more CSAPR SO
(B) Promulgate a notice of data availability of the results of the calculations required in paragraphs (b)(1)(i) and (b)(1)(ii)(A) of this section, including separate calculations of the SO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice of data availability required in paragraph (b)(1)(ii) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations referenced in such notice are in accordance with § 97.606(c)(2)(iii), §§ 97.606(b) and 97.630 through 97.635, the definitions of “common designated representative”, “common designated representative’s assurance level”, and “common designated representative’s share” in § 97.602, and the calculation formula in § 97.606(c)(2)(i).
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By October 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) For any State (and Indian country within the borders of such State) referenced in each notice of data availability required in paragraph (b)(2)(ii) of this section as having CSAPR SO
(4)(i) As of midnight of November 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section, the owners and operators described in paragraph (b)(3) of this section shall hold in the assurance account established for them and for the appropriate CSAPR SO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(4)(i) of this section, if November 1 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section and after the recordation, in accordance with § 97.623, of CSAPR SO
(6) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notice of data availability required in paragraph (b)(2)(ii) of this section for a control period in a given year, of any data used in making the calculations referenced in such notice, the amounts of CSAPR SO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of CSAPR SO
(ii) [Reserved]
(iii) If the revised data are used to recalculate, in accordance with paragraph (b)(6)(i) of this section, the amount of CSAPR SO
(A) Where the amount of CSAPR SO
(B) For the owners and operators for which the amount of CSAPR SO
(C) Each CSAPR SO
§ 97.626 Banking.
(a) A CSAPR SO
(b) Any CSAPR SO
(c) At any time after the allowance transfer deadline for the last control period for which a State SO
§ 97.627 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
§ 97.628 Administrator’s action on submissions.
(a) The Administrator may review and conduct independent audits concerning any submission under the CSAPR SO
(b) The Administrator may deduct CSAPR SO
§ 97.629 [Reserved]
§ 97.630 General monitoring, recordkeeping, and reporting requirements.
The owners and operators, and to the extent applicable, the designated representative, of a CSAPR SO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each CSAPR SO
(1) Install all monitoring systems required under this subpart for monitoring SO
(2) Successfully complete all certification tests required under § 97.631 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator of a CSAPR SO
(1) January 1, 2015; or
(2) 180 calendar days after the date on which the unit commences commercial operation.
(3) The owner or operator of a CSAPR SO
(i) Such requirements shall apply to the monitoring systems required under § 97.630 through § 97.635, rather than the monitoring systems required under part 75 of this chapter;
(ii) SO
(iii) Any petition for another procedure under § 75.4(e)(2) of this chapter shall be submitted under § 97.635, rather than § 75.66 of this chapter.
(c) Reporting data. The owner or operator of a CSAPR SO
(d) Prohibitions. (1) No owner or operator of a CSAPR SO
(2) No owner or operator of a CSAPR SO
(3) No owner or operator of a CSAPR SO
(4) No owner or operator of a CSAPR SO
(i) During the period that the unit is covered by an exemption under § 97.605 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.631(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a CSAPR SO
§ 97.631 Initial monitoring system certification and recertification procedures.
(a) The owner or operator of a CSAPR SO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B and D to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.630(a)(1) that is exempt from initial certification requirements under paragraph (a) of this section.
(c) [Reserved]
(d) Except as provided in paragraph (a) of this section, the owner or operator of a CSAPR SO
(1) Requirements for initial certification. The owner or operator shall ensure that each continuous monitoring system under § 97.630(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.630(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.630(a)(1) that may significantly affect the ability of the system to accurately measure or record SO
(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.630(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in § 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words “certification” and “initial certification” are replaced by the word “recertification” and the word “certified” is replaced by the word “recertified”.
(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office and the Administrator written notice of the dates of certification testing, in accordance with § 97.633.
(ii) Certification application. The designated representative shall submit to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the CSAPR SO
(iv) Certification application approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the CSAPR SO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.632(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved SO
(2) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(3) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
§ 97.632 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D of, or appendix D to, part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.631 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the Administrator or any State or permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 97.631 for each disapproved monitoring system.
§ 97.633 Notifications concerning monitoring.
The designated representative of a CSAPR SO
§ 97.634 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply with all recordkeeping and reporting requirements in paragraphs (b) through (e) of this section, the applicable recordkeeping and reporting requirements in subparts F and G of part 75 of this chapter, and the requirements of § 97.614(a).
(b) Monitoring plans. The owner or operator of a CSAPR SO
(c) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all initial certification or recertification tests required under § 97.631, including the information required under § 75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit quarterly reports, as follows:
(1) The designated representative shall report the SO
(i) The calendar quarter covering January 1, 2015 through March 31, 2015; or
(ii) The calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.630(b).
(2) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.64 of this chapter.
(3) For CSAPR SO
(4) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(2) of this section.
(e) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and
(2) For a unit with add-on SO
§ 97.635 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements.
(a) The designated representative of a CSAPR SO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(1) Identification of each unit and source covered by the petition;
(2) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used in the proposed alternative;
(4) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be de minimis; and
(5) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
Subpart DDDDD – CSAPR SO2 Group 2 Trading Program
§ 97.701 Purpose.
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Cross-State Air Pollution Rule (CSAPR) SO
§ 97.702 Definitions.
The terms used in this subpart shall have the meanings set forth in this section as follows, provided that any term that includes the acronym “CSAPR” shall be considered synonymous with a term that is used in a SIP revision approved by the Administrator under § 52.38 or § 52.39 of this chapter and that is substantively identical except for the inclusion of the acronym “TR” in place of the acronym “CSAPR”:
Acid Rain Program means a multi-state SO
Administrator means the Administrator of the United States Environmental Protection Agency or the Director of the Clean Air Markets Division (or its successor determined by the Administrator) of the United States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.
Allocate or allocation means, with regard to CSAPR SO
(1) A CSAPR SO
(2) A new unit set-aside;
(3) An Indian country new unit set-aside; or
(4) An entity not listed in paragraphs (1) through (3) of this definition;
(5) Provided that, if the Administrator, State, or permitting authority initially credits, to a CSAPR SO
Allowance Management System means the system by which the Administrator records allocations, auctions, transfers, and deductions of CSAPR SO
Allowance Management System account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, auction, holding, transfer, or deduction of CSAPR SO
Allowance transfer deadline means, for a control period before 2021, midnight of March 1 immediately after such control period or, for a control period in 2021 or thereafter, midnight of June 1 immediately after such control period (or if such March 1 or June 1 is not a business day, midnight of the first business day thereafter) and is the deadline by which a CSAPR SO
Alternate designated representative means, for a CSAPR SO
Assurance account means an Allowance Management System account, established by the Administrator under § 97.725(b)(3) for certain owners and operators of a group of one or more CSAPR SO
Auction means, with regard to CSAPR SO
Authorized account representative means, for a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of CSAPR SO
Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by this subpart.
Biomass means –
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other material that is nonmerchantable for other purposes, and that is:
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
Bottoming-cycle unit means a unit in which the energy input to the unit is first used to produce useful thermal energy, where at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.
Business day means a day that does not fall on a weekend or a federal holiday.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function or any other person who performs similar policy- or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means “coal” as defined in § 72.2 of this chapter.
Cogeneration system means an integrated group, at a source, of equipment (including a boiler, or combustion turbine, and a generator) designed to produce useful thermal energy for industrial, commercial, heating, or cooling purposes and electricity through the sequential use of energy.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a topping-cycle unit or a bottoming-cycle unit:
(1) Operating as part of a cogeneration system; and
(2) Producing on an annual average basis –
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output; or
(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;
(3) Provided that the requirements in paragraph (2) of this definition shall not apply to a calendar year referenced in paragraph (2) of this definition during which the unit did not operate at all;
(4) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel, except biomass if the unit is a boiler; and
(5) Provided that, if, throughout its operation during the 12-month period or a calendar year referenced in paragraph (2) of this definition, a unit is operated as part of a cogeneration system and the cogeneration system meets on a system-wide basis the requirement in paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be deemed to meet such requirement during that 12-month period or calendar year.
Combustion turbine means an enclosed device comprising:
(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.705.
(i) For a unit that is a CSAPR SO
(ii) For a unit that is a CSAPR SO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.705, for a unit that is not a CSAPR SO
(i) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change or is moved to a different location or source, such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same or a different source, such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
Common designated representative means, with regard to a control period in a given year, a designated representative where, as of April 1 immediately after the allowance transfer deadline for such a control period before 2021, or as of July 1 immediately after such deadline for such a control period in 2021 or thereafter, the same natural person is authorized under §§ 97.713(a) and 97.715(a) as the designated representative for a group of one or more CSAPR SO
Common designated representative’s assurance level means, with regard to a specific common designated representative and a State (and Indian country within the borders of such State) and control period in a given year for which the State assurance level is exceeded as described in § 97.706(c)(2)(iii), the amount (rounded to the nearest allowance) equal to the sum of the total amount of CSAPR SO
Common designated representative’s share means, with regard to a specific common designated representative for a control period in a given year and a total amount of SO
Common stack means a single flue through which emissions from 2 or more units are exhausted.
Compliance account means an Allowance Management System account, established by the Administrator for a CSAPR SO
Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent record of SO
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A SO
(3) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(4) A CO
(5) An O
Control period means the period starting January 1 of a calendar year, except as provided in § 97.706(c)(3), and ending on December 31 of the same year, inclusive.
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR SO
CSAPR SO
CSAPR SO
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, CSAPR SO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, CSAPR SO
CSAPR SO
CSAPR SO
CSAPR SO
CSAPR SO
Designated representative means, for a CSAPR SO
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative, and as modified by the Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required to measure, record, and report such air pollutants in accordance with this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the CSAPR SO
Fossil fuel means –
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or
(2) For purposes of applying the limitation on “average annual fuel consumption of fossil fuel” in § 97.704(b)(2)(i)(B) and (b)(2)(ii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account, established under this subpart, that is not a compliance account or an assurance account.
Generator means a device that produces electricity.
Heat input means, for a unit for a specified period of unit operating time, the product (in mmBtu) of the gross calorific value of the fuel (in mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of fuel/time) and unit operating time, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the quotient (in mmBtu/hr) of the amount of heat input for a specified period of unit operating time (in mmBtu) divided by unit operating time (in hr) or, for a unit and a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Indian country means “Indian country” as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Maximum design heat input rate means, for a unit, the maximum amount of fuel per hour (in Btu/hr) that the unit is capable of combusting on a steady state basis as of the initial installation of the unit as specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe, rounded to the nearest tenth) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount (in MWe, rounded to the nearest tenth) as of such completion as specified by the person conducting the physical change.
Natural gas means “natural gas” as defined in § 72.2 of this chapter.
Newly affected CSAPR SO
Nitrogen oxides means all oxides of nitrogen except nitrous oxide (N
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a CSAPR SO
Owner means, for a CSAPR SO
(1) Any holder of any portion of the legal or equitable title in a CSAPR SO
(2) Any holder of a leasehold interest in a CSAPR SO
(3) Any purchaser of power from a CSAPR SO
Permanently retired means, with regard to a unit, a unit that is unavailable for service and that the unit’s owners and operators do not expect to return to service in the future.
Permitting authority means “permitting authority” as defined in §§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity means, for a unit (in MWh/yr), 33 percent of the unit’s maximum design heat input rate (in Btu/hr), divided by 3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to CSAPR SO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.
Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or retired unit (the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from electricity production in a useful thermal energy application or process; or
(2) The use of reject heat from a useful thermal energy application or process in electricity production.
Serial number means, for a CSAPR SO
Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act.
Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the definition of “major source”, “stationary source”, or “source” as set forth and implemented in a title V operating permit program or any other program under the Clean Air Act.
State means one of the States that is subject to the CSAPR SO
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Topping-cycle unit means a unit in which the energy input to the unit is first used to produce useful power, including electricity, where at least some of the reject heat from the electricity production is then used to provide useful thermal energy.
Total energy input means, for a unit, total energy of all forms supplied to the unit, excluding energy produced by the unit. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:
Total energy output means, for a unit, the sum of useful power and useful thermal energy produced by the unit.
Unit means a stationary, fossil-fuel-fired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-fired combustion device. A unit that undergoes a physical change or is moved to a different location or source shall continue to be treated as the same unit. A unit (the replaced unit) that is replaced by another unit (the replacement unit) at the same or a different source shall continue to be treated as the same unit, and the replacement unit shall be treated as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to a unit, an hour in which the unit combusts any fuel.
Useful power means, with regard to a unit, electricity or mechanical energy that the unit makes available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means thermal energy that is:
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption chiller).
Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.
§ 97.703 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
§ 97.704 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State (and Indian country within the borders of such State) shall be CSAPR SO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a CSAPR SO
(b) Any unit in a State (and Indian country within the borders of such State) that otherwise is a CSAPR SO
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) Not supplying in 2005 or any calendar year thereafter more than one-third of the unit’s potential electrical output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If, after qualifying under paragraph (b)(1)(i) of this section as not being a CSAPR SO
(2)(i) Any unit:
(A) Qualifying as a solid waste incineration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) With an average annual fuel consumption of fossil fuel for the first 3 consecutive calendar years of operation starting no earlier than 2005 of less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years thereafter of less than 20 percent (on a Btu basis).
(ii) If, after qualifying under paragraph (b)(2)(i) of this section as not being a CSAPR SO
(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section or a SIP revision approved under § 52.39(h) or (i) of this chapter, of the CSAPR SO
(1) Petition content. The petition shall be in writing and include the identification of the unit or other equipment and the relevant facts about the unit or other equipment. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying official: “I am authorized to make this submission on behalf of the owners and operators of the unit or other equipment for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) Response. The Administrator will issue a written response to the petition and may request supplemental information determined by the Administrator to be relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CSAPR SO
§ 97.705 Retired unit exemption.
(a)(1) Any CSAPR SO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the CSAPR SO
(b)(1) A unit exempt under paragraph (a) of this section shall not emit any SO
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the CSAPR SO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.
§ 97.706 Standard requirements.
(a) Designated representative requirements. The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.713 through 97.718.
(b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each CSAPR SO
(2) The emissions data determined in accordance with §§ 97.730 through 97.735 shall be used to calculate allocations of CSAPR SO
(c) SO
(ii) If total SO
(A) The owners and operators of the source and each CSAPR SO
(B) The owners and operators of the source and each CSAPR SO
(2) CSAPR SO
(A) The quotient of the amount by which the common designated representative’s share of such SO
(B) The amount by which total SO
(ii) The owners and operators shall hold the CSAPR SO
(iii) Total SO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if total SO
(v) To the extent the owners and operators fail to hold CSAPR SO
(A) The owners and operators shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each CSAPR SO
(3) Compliance periods. (i) A CSAPR SO
(ii) A CSAPR SO
(4) Vintage of CSAPR SO
(ii) A CSAPR SO
(5) Allowance Management System requirements. Each CSAPR SO
(6) Limited authorization. A CSAPR SO
(i) Such authorization shall only be used in accordance with the CSAPR SO
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7) Property right. A CSAPR SO
(d) Title V permit requirements. (1) No title V permit revision shall be required for any allocation, holding, deduction, or transfer of CSAPR SO
(2) A description of whether a unit is required to monitor and report SO
(e) Additional recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of each CSAPR SO
(i) The certificate of representation under § 97.716 for the designated representative for the source and each CSAPR SO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the CSAPR SO
(2) The designated representative of a CSAPR SO
(f) Liability. (1) Any provision of the CSAPR SO
(2) Any provision of the CSAPR SO
(g) Effect on other authorities. No provision of the CSAPR SO
§ 97.707 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the CSAPR SO
(b) Unless otherwise stated, any time period scheduled, under the CSAPR SO
(c) Unless otherwise stated, if the final day of any time period, under the CSAPR SO
§ 97.708 Administrative appeal procedures.
The administrative appeal procedures for decisions of the Administrator under the CSAPR SO
§ 97.709 [Reserved]
§ 97.710 State SO2 Group 2 trading budgets, new unit set-asides, Indian country new unit set-asides, and variability limits.
(a) The State SO
(1) Alabama. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 4,321 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 4,265 tons.
(vi) [Reserved]
(2) Georgia. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 3,171 tons.
(iii) [Reserved]
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 2,721 tons.
(vi) [Reserved]
(3) Kansas. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 798 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 42 tons.
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 801 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 42 tons.
(4) Minnesota. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 798 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 42 tons.
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 800 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 42 tons.
(5) Nebraska. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 2,658 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 68 tons.
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 2,662 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 68 tons.
(6) South Carolina. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 1,836 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 97 tons.
(iv) The SO
(v) The new unit set-aside for 2017 and thereafter is 1,836 tons.
(vi) The Indian country new unit set-aside for 2017 and thereafter is 97 tons.
(7) Texas. (i) The SO
(ii) The new unit set-aside for 2015 and 2016 is 14,430 tons.
(iii) The Indian country new unit set-aside for 2015 and 2016 is 294 tons.
(iv)-(vi) [Reserved]
(b) The States’ variability limits for the State SO
(1) The variability limit for Alabama is 38,386 tons.
(2) The variability limit for Georgia is 24,402 tons.
(3) The variability limit for Kansas is 7,556 tons.
(4) The variability limit for Minnesota is 7,557 tons.
(5) The variability limit for Nebraska is 12,269 tons.
(6) The variability limit for South Carolina is 17,394 tons.
(7) [Reserved]
(c) Each State SO
§ 97.711 Timing requirements for CSAPR SO2 Group 2 allowance allocations.
(a) Existing units. (1) CSAPR SO
(2) Notwithstanding paragraph (a)(1) of this section, if a unit provided an allocation in the notice of data availability issued under paragraph (a)(1) of this section does not operate, starting after 2014, during the control period in two consecutive years, such unit will not be allocated the CSAPR SO
(b) New units – (1) New unit set-asides. (i)(A) By June 1 of each year from 2015 through 2020, the Administrator will calculate the CSAPR SO
(B) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR SO
(ii) For each notice of data availability required in paragraph (b)(1)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR SO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(1)(i)(A) or (B) of this section, as applicable. By August 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i)(A) of this section, or by May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i)(B) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(1)(ii)(A) of this section.
(iii) If the new unit set-aside for a control period before 2021 contains any CSAPR SO
(iv) For each notice of data availability required in paragraph (b)(1)(iii) of this section, the Administrator will provide an opportunity for submission of objections to the identification of CSAPR SO
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(iii) of this section and shall be limited to addressing whether the identification of CSAPR SO
(B) The Administrator will adjust the identification of CSAPR SO
(v) To the extent any CSAPR SO
(2) Indian country new unit set-asides. (i)(A) By June 1 of each year from 2015 through 2020, the Administrator will calculate the CSAPR SO
(B) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR SO
(ii) For each notice of data availability required in paragraph (b)(2)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR SO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i)(A) or (B) of this section, as applicable. By August 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i)(A) of this section, or by May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i)(B) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(ii)(A) of this section.
(iii) If the Indian country new unit set-aside for a control period before 2021 contains any CSAPR SO
(iv) For each notice of data availability required in paragraph (b)(2)(iii) of this section, the Administrator will provide an opportunity for submission of objections to the identification of CSAPR SO
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(iii) of this section and shall be limited to addressing whether the identification of CSAPR SO
(B) The Administrator will adjust the identification of CSAPR SO
(v) To the extent any CSAPR SO
(c) Units incorrectly allocated CSAPR SO
(i)(A) The recipient is not actually a CSAPR SO
(B) The recipient is not located as of January 1 of the control period in the State from whose SO
(ii) The recipient is not actually a CSAPR SO
(2) Except as provided in paragraph (c)(3) or (4) of this section, the Administrator will not record such CSAPR SO
(3) If the Administrator already recorded such CSAPR SO
(4) If the Administrator already recorded such CSAPR SO
(5)(i) With regard to the CSAPR SO
(A) Transfer such CSAPR SO
(B) If the State has a SIP revision approved under § 52.39(h) or (i) of this chapter covering such control period, include such CSAPR SO
(ii) With regard to the CSAPR SO
(A) Transfer such CSAPR SO
(B) If the State has a SIP revision approved under § 52.39(h) or (i) of this chapter covering such control period, include such CSAPR SO
(iii) With regard to the CSAPR SO
§ 97.712 CSAPR SO2 Group 2 allowance allocations to new units.
(a) Allocations from new unit set-asides. For each control period in 2015 and thereafter and for the CSAPR SO
(1) The CSAPR SO
(i) CSAPR SO
(ii) CSAPR SO
(iii) CSAPR SO
(iv) For purposes of paragraph (a)(9) of this section, CSAPR SO
(2) The Administrator will establish a separate new unit set-aside for the State for each such control period. Each such new unit set-aside will be allocated CSAPR SO
(3) The Administrator will determine, for each CSAPR SO
(i) The control period in 2015;
(ii)(A) The first control period after the control period in which the CSAPR SO
(B) The control period containing the deadline for certification of the CSAPR SO
(iii) For a unit described in paragraph (a)(1)(ii) of this section, the first control period in which the CSAPR SO
(iv) For a unit described in paragraph (a)(1)(iii) of this section, the first control period after the control period in which the unit resumes operation, for allocations for a control period before 2021, or the control period in which the unit resumes operation, for allocations for a control period in 2021 or thereafter.
(4)(i) The allocation to each CSAPR SO
(ii) The Administrator will adjust the allocation amount in paragraph (a)(4)(i) of this section in accordance with paragraphs (a)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR SO
(6) If the amount of CSAPR SO
(7) If the amount of CSAPR SO
(8) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.711(b)(1)(i) and (ii), of the amount of CSAPR SO
(9) For a control period before 2021, if, after completion of the procedures under paragraphs (a)(5) through (8) of this section for such control period, any unallocated CSAPR SO
(i) The Administrator will determine, for each unit described in paragraph (a)(1) of this section that commenced commercial operation during the period starting January 1 of the year before the year of such control period and ending November 30 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR SO
(ii) The Administrator will determine the sum of the positive differences determined under paragraph (a)(9)(i) of this section;
(iii) If the amount of unallocated CSAPR SO
(iv) If the amount of unallocated CSAPR SO
(10) If, after completion of the procedures under paragraphs (a)(9) and (12) of this section for a control period before 2021, or under paragraphs (a)(2) through (7) and (12) of this section for a control period in 2021 or thereafter, any unallocated CSAPR SO
(11)(i) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.711(b)(1)(iii), (iv), and (v), of the amount of CSAPR SO
(ii) For a control period in 2021 or thereafter, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.711(b)(1)(i), (ii), and (v), of the amount of CSAPR SO
(12) Notwithstanding the requirements of paragraphs (a)(2) through (11) of this section, if the calculations of allocations from a new unit set-aside for a control period before 2021 under paragraph (a)(7) of this section, paragraphs (a)(6) and (a)(9)(iv) of this section, or paragraphs (a)(6), (a)(9)(iii), and (a)(10) of this section, or for a control period in 2021 or thereafter under paragraph (a)(7) of this section or paragraphs (a)(6) and (10) of this section, would otherwise result in total allocations from such new unit set-aside unequal to the total amount of such new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR SO
(b) Allocations from Indian country new unit set-asides. For each control period in 2015 and thereafter and for the CSAPR SO
(1) The CSAPR SO
(i) CSAPR SO
(ii) For purposes of paragraph (b)(9) of this section, CSAPR SO
(2) The Administrator will establish a separate Indian country new unit set-aside for the State for each such control period. Each such Indian country new unit set-aside will be allocated CSAPR SO
(3) The Administrator will determine, for each CSAPR SO
(i) The control period in 2015; and
(ii)(A) The first control period after the control period in which the CSAPR SO
(B) The control period containing the deadline for certification of the CSAPR SO
(4)(i) The allocation to each CSAPR SO
(ii) The Administrator will adjust the allocation amount in paragraph (b)(4)(i) of this section in accordance with paragraphs (b)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR SO
(6) If the amount of CSAPR SO
(7) If the amount of CSAPR SO
(8) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.711(b)(2)(i) and (ii), of the amount of CSAPR SO
(9) For a control period before 2021, if, after completion of the procedures under paragraphs (b)(5) through (8) of this section for such control period, any unallocated CSAPR SO
(i) The Administrator will determine, for each unit described in paragraph (b)(1) of this section that commenced commercial operation during the period starting January 1 of the year before the year of such control period and ending November 30 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR SO
(ii) The Administrator will determine the sum of the positive differences determined under paragraph (b)(9)(i) of this section;
(iii) If the amount of unallocated CSAPR SO
(iv) If the amount of unallocated CSAPR SO
(10) If, after completion of the procedures under paragraphs (b)(9) and (12) of this section for a control period before 2021, or under paragraphs (b)(2) through (7) and (12) of this section for a control period in 2021 or thereafter, any unallocated CSAPR SO
(i) Transfer such unallocated CSAPR SO
(ii) If the State has a SIP revision approved under § 52.39(h) or (i) of this chapter covering such control period, include such unallocated CSAPR SO
(11)(i) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.711(b)(2)(iii), (iv), and (v), of the amount of CSAPR SO
(ii) For a control period in 2021 or thereafter, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.711(b)(2)(i), (ii), and (v), of the amount of CSAPR SO
(12) Notwithstanding the requirements of paragraphs (b)(2) through (11) of this section, if the calculations of allocations from an Indian country new unit set-aside for a control period before 2021 under paragraph (b)(7) of this section or paragraphs (b)(6) and (b)(9)(iv) of this section, or for a control period in 2021 or thereafter under paragraph (b)(7) of this section, would otherwise result in total allocations from such Indian country new unit set-aside unequal to the total amount of such Indian country new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR SO
§ 97.713 Authorization of designated representative and alternate designated representative.
(a) Except as provided under § 97.715, each CSAPR SO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR SO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.716:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each CSAPR SO
(ii) The owners and operators of the source and each CSAPR SO
(b) Except as provided under § 97.715, each CSAPR SO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR SO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.716,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each CSAPR SO
(c) Except in this section, § 97.702, and §§ 97.714 through 97.718, whenever the term “designated representative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
§ 97.714 Responsibilities of designated representative and alternate designated representative.
(a) Except as provided under § 97.718 concerning delegation of authority to make submissions, each submission under the CSAPR SO
(b) The Administrator will accept or act on a submission made for a CSAPR SO
§ 97.715 Changing designated representative and alternate designated representative; changes in owners and operators; changes in units at the source.
(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.716. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the CSAPR SO
(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.716. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the CSAPR SO
(c) Changes in owners and operators. (1) In the event an owner or operator of a CSAPR SO
(2) Within 30 days after any change in the owners and operators of a CSAPR SO
(d) Changes in units at the source. Within 30 days of any change in which units are located at a CSAPR SO
(1) If the change is the addition of a unit that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the source, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity from whom the unit was purchased or otherwise obtained (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was purchased or otherwise obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity to which the unit was sold or that otherwise obtained the unit (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was sold or otherwise obtained, and the date on which the unit became no longer located at the source.
§ 97.716 Certificate of representation.
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the CSAPR SO
(2) The name, address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the CSAPR SO
(4) The following certification statements by the designated representative and any alternate designated representative –
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each CSAPR SO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CSAPR SO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a CSAPR SO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(c) A certificate of representation under this section that complies with the provisions of paragraph (a) of this section except that it contains the acronym “TR” in place of the acronym “CSAPR” in the required certification statements will be considered a complete certificate of representation under this section, and the certification statements included in such certificate of representation will be interpreted as if the acronym “CSAPR” appeared in place of the acronym “TR”.
§ 97.717 Objections concerning designated representative and alternate designated representative.
(a) Once a complete certificate of representation under § 97.716 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.716 is received by the Administrator.
(b) Except as provided in paragraph (a) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CSAPR SO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of CSAPR SO
§ 97.718 Delegation by designated representative and alternate designated representative.
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.718(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.718(d), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.718 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
§ 97.719 [Reserved]
§ 97.720 Establishment of compliance accounts, assurance accounts, and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.716, the Administrator will establish a compliance account for the CSAPR SO
(b) Assurance accounts. The Administrator will establish assurance accounts for certain owners and operators and States in accordance with § 97.725(b)(3).
(c) General accounts – (1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring CSAPR SO
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to CSAPR SO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the CSAPR SO
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to CSAPR SO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(iv) An application for a general account under paragraph (c)(1) of this section that complies with the provisions of such paragraph except that it contains the acronym “TR” in place of the acronym “CSAPR” in the required certification statement will be considered a complete application for a general account under such paragraph, and the certification statement included in such application for a general account will be interpreted as if the acronym “CSAPR” appeared in place of the acronym “TR”.
(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (c)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CSAPR SO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to CSAPR SO
(ii) Except as provided in paragraph (c)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to CSAPR SO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(iv) A certification statement submitted in accordance with paragraph (c)(2)(ii) of this section that contains the acronym “TR” will be interpreted as if the acronym “CSAPR” appeared in place of the acronym “TR”.
(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the CSAPR SO
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the CSAPR SO
(iii)(A) In the event a person having an ownership interest with respect to CSAPR SO
(B) Within 30 days after any change in the persons having an ownership interest with respect to CSAPR SO
(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the CSAPR SO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of CSAPR SO
(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (c)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (c)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized account representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.720(c)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.720(c)(5)(iv), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under 40 CFR 97.720(c)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (c)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (c)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this section shall be deemed to be an electronic submission by the authorized account representative or alternate authorized account representative submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted CSAPR SO
(ii) If a general account has no CSAPR SO
(d) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a), (b), or (c) of this section.
(e) Responsibilities of authorized account representative and alternate authorized account representative. After the establishment of a compliance account or general account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of CSAPR SO
§ 97.721 Recordation of CSAPR SO2 Group 2 allowance allocations and auction results.
(a) By November 7, 2011, the Administrator will record in each CSAPR SO
(b) By November 7, 2011, the Administrator will record in each CSAPR SO
(1) If, by April 1, 2015, the State does not submit to the Administrator such complete SIP revision, the Administrator will record by April 15, 2015 in each CSAPR SO
(2) If the State submits to the Administrator by April 1, 2015, and the Administrator approves by October 1, 2015, such complete SIP revision, the Administrator will record by October 1, 2015 in each CSAPR SO
(3) If the State submits to the Administrator by April 1, 2015, and the Administrator does not approve by October 1, 2015, such complete SIP revision, the Administrator will record by October 1, 2015 in each CSAPR SO
(c) By July 1, 2016, the Administrator will record in each CSAPR SO
(d) By July 1, 2017, the Administrator will record in each CSAPR SO
(e) By July 1, 2018, the Administrator will record in each CSAPR SO
(f)(1) By July 1, 2019 and July 1, 2020, the Administrator will record in each CSAPR SO
(2) By July 1, 2024 and July 1 of each year thereafter, the Administrator will record in each CSAPR SO
(g)(1) By August 1 of each year from 2015 through 2020, the Administrator will record in each CSAPR SO
(2) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR SO
(h)(1) By August 1 of each year from 2015 through 2020, the Administrator will record in each CSAPR SO
(2) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR SO
(i) By February 15 of each year from 2016 through 2021, the Administrator will record in each CSAPR SO
(j) By February 15 of each year from 2016 through 2021, the Administrator will record in each CSAPR SO
(k) By the date 15 days after the date on which any allocation or auction results, other than an allocation or auction results described in paragraphs (a) through (j) of this section, of CSAPR SO
(l) When recording the allocation or auction of CSAPR SO
§ 97.722 Submission of CSAPR SO2 Group 2 allowance transfers.
(a) An authorized account representative seeking recordation of a CSAPR SO
(b) A CSAPR SO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each CSAPR SO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each CSAPR SO
§ 97.723 Recordation of CSAPR SO2 Group 2 allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a CSAPR SO
(b) A CSAPR SO
(c) Where a CSAPR SO
(d) Within 5 business days of recordation of a CSAPR SO
(e) Within 10 business days of receipt of a CSAPR SO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
§ 97.724 Compliance with CSAPR SO2 Group 2 emissions limitation.
(a) Availability for deduction for compliance. CSAPR SO
(1) Were allocated or auctioned for such control period or a control period in a prior year; and
(2) Are held in the source’s compliance account as of the allowance transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance with § 97.723, of CSAPR SO
(1) Until the amount of CSAPR SO
(2) If there are insufficient CSAPR SO
(c) Selection of CSAPR SO
(2) First-in, first-out. The Administrator will deduct CSAPR SO
(i) Any CSAPR SO
(ii) Any other CSAPR SO
(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in which the CSAPR SO
(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and (d) of this section.
§ 97.725 Compliance with CSAPR SO2 Group 2 assurance provisions.
(a) Availability for deduction. CSAPR SO
(1) Were allocated or auctioned for a control period in a prior year or the control period in the given year or in the immediately following year; and
(2) Are held in the assurance account, established by the Administrator for such owners and operators of such group of CSAPR SO
(b) Deductions for compliance. The Administrator will deduct CSAPR SO
(1) By June 1 of each year from 2018 through 2021 and August 1 of each year thereafter, the Administrator will:
(i) Calculate, for each State (and Indian country within the borders of such State), the total SO
(ii) For the set of any States (and Indian country within the borders of such States) for which the results of the calculations required in paragraph (b)(1)(i) of this section indicate that total SO
(A) Calculate, for each such State (and Indian country within the borders of such State) and such control period and each common designated representative for such control period for a group of one or more CSAPR SO
(B) Promulgate a notice of data availability of the results of the calculations required in paragraphs (b)(1)(i) and (b)(1)(ii)(A) of this section, including separate calculations of the SO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice of data availability required in paragraph (b)(1)(ii) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations referenced in such notice are in accordance with § 97.706(c)(2)(iii), §§ 97.706(b) and 97.730 through 97.735, the definitions of “common designated representative”, “common designated representative’s assurance level”, and “common designated representative’s share” in § 97.702, and the calculation formula in § 97.706(c)(2)(i).
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By October 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) For any State (and Indian country within the borders of such State) referenced in each notice of data availability required in paragraph (b)(2)(ii) of this section as having CSAPR SO
(4)(i) As of midnight of November 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section, the owners and operators described in paragraph (b)(3) of this section shall hold in the assurance account established for them and for the appropriate CSAPR SO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(4)(i) of this section, if November 1 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section and after the recordation, in accordance with § 97.723, of CSAPR SO
(6) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notice of data availability required in paragraph (b)(2)(ii) of this section for a control period in a given year, of any data used in making the calculations referenced in such notice, the amounts of CSAPR SO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of CSAPR SO
(ii) [Reserved]
(iii) If the revised data are used to recalculate, in accordance with paragraph (b)(6)(i) of this section, the amount of CSAPR SO
(A) Where the amount of CSAPR SO
(B) For the owners and operators for which the amount of CSAPR SO
(C) Each CSAPR SO
§ 97.726 Banking.
(a) A CSAPR SO
(b) Any CSAPR SO
(c) At any time after the allowance transfer deadline for the last control period for which a State SO
§ 97.727 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
§ 97.728 Administrator’s action on submissions.
(a) The Administrator may review and conduct independent audits concerning any submission under the CSAPR SO
(b) The Administrator may deduct CSAPR SO
§ 97.729 [Reserved]
§ 97.730 General monitoring, recordkeeping, and reporting requirements.
The owners and operators, and to the extent applicable, the designated representative, of a CSAPR SO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each CSAPR SO
(1) Install all monitoring systems required under this subpart for monitoring SO
(2) Successfully complete all certification tests required under § 97.731 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator of a CSAPR SO
(1) January 1, 2015; or
(2) 180 calendar days after the date on which the unit commences commercial operation.
(3) The owner or operator of a CSAPR SO
(i) Such requirements shall apply to the monitoring systems required under § 97.730 through § 97.735, rather than the monitoring systems required under part 75 of this chapter;
(ii) SO
(iii) Any petition for another procedure under § 75.4(e)(2) of this chapter shall be submitted under § 97.735, rather than § 75.66 of this chapter.
(c) Reporting data. The owner or operator of a CSAPR SO
(d) Prohibitions. (1) No owner or operator of a CSAPR SO
(2) No owner or operator of a CSAPR SO
(3) No owner or operator of a CSAPR SO
(4) No owner or operator of a CSAPR SO
(i) During the period that the unit is covered by an exemption under § 97.705 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.731(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a CSAPR SO
§ 97.731 Initial monitoring system certification and recertification procedures.
(a) The owner or operator of a CSAPR SO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B and D to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.730(a)(1) that is exempt from initial certification requirements under paragraph (a) of this section.
(c) [Reserved]
(d) Except as provided in paragraph (a) of this section, the owner or operator of a CSAPR SO
(1) Requirements for initial certification. The owner or operator shall ensure that each continuous monitoring system under § 97.730(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.730(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.730(a)(1) that may significantly affect the ability of the system to accurately measure or record SO
(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.730(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in § 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words “certification” and “initial certification” are replaced by the word “recertification” and the word “certified” is replaced by the word “recertified”.
(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office and the Administrator written notice of the dates of certification testing, in accordance with § 97.733.
(ii) Certification application. The designated representative shall submit to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the CSAPR SO
(iv) Certification application approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the CSAPR SO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.732(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved SO
(2) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(3) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
§ 97.732 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D of, or appendix D to, part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.731 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the Administrator or any State or permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 97.731 for each disapproved monitoring system.
§ 97.733 Notifications concerning monitoring.
The designated representative of a CSAPR SO
§ 97.734 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply with all recordkeeping and reporting requirements in paragraphs (b) through (e) of this section, the applicable recordkeeping and reporting requirements in subparts F and G of part 75 of this chapter, and the requirements of § 97.714(a).
(b) Monitoring plans. The owner or operator of a CSAPR SO
(c) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all initial certification or recertification tests required under § 97.731, including the information required under § 75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit quarterly reports, as follows:
(1) The designated representative shall report the SO
(i) The calendar quarter covering January 1, 2015 through March 31, 2015; or
(ii) The calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.730(b).
(2) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.64 of this chapter.
(3) For CSAPR SO
(4) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(2) of this section.
(e) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and
(2) For a unit with add-on SO
§ 97.735 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements.
(a) The designated representative of a CSAPR SO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(1) Identification of each unit and source covered by the petition;
(2) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used in the proposed alternative;
(4) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be de minimis; and
(5) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
Subpart EEEEE – CSAPR NOX Ozone Season Group 2 Trading Program
§ 97.801 Purpose.
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Cross-State Air Pollution Rule (CSAPR) NO
§ 97.802 Definitions.
The terms used in this subpart shall have the meanings set forth in this section as follows, provided that any term that includes the acronym “CSAPR” shall be considered synonymous with a term that is used in a SIP revision approved by the Administrator under § 52.38 or § 52.39 of this chapter and that is substantively identical except for the inclusion of the acronym “TR” in place of the acronym “CSAPR”:
Acid Rain Program means a multi-state SO
Administrator means the Administrator of the United States Environmental Protection Agency or the Director of the Clean Air Markets Division (or its successor determined by the Administrator) of the United States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.
Allocate or allocation means, with regard to CSAPR NO
(1) A CSAPR NO
(2) A new unit set-aside;
(3) An Indian country new unit set-aside; or
(4) An entity not listed in paragraphs (1) through (3) of this definition;
(5) Provided that, if the Administrator, State, or permitting authority initially credits, to a CSAPR NO
Allowance Management System means the system by which the Administrator records allocations, auctions, transfers, and deductions of CSAPR NO
Allowance Management System account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, auction, holding, transfer, or deduction of CSAPR NO
Allowance transfer deadline means, for a control period before 2021, midnight of March 1 immediately after such control period or, for a control period in 2021 or thereafter, midnight of June 1 immediately after such control period (or if such March 1 or June 1 is not a business day, midnight of the first business day thereafter) and is the deadline by which a CSAPR NO
Alternate designated representative means, for a CSAPR NO
Assurance account means an Allowance Management System account, established by the Administrator under § 97.825(b)(3) for certain owners and operators of a group of one or more base CSAPR NO
Auction means, with regard to CSAPR NO
Authorized account representative means, for a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of CSAPR NO
Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by this subpart.
Base CSAPR NO
Base CSAPR NO
Biomass means –
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other material that is nonmerchantable for other purposes, and that is:
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
Bottoming-cycle unit means a unit in which the energy input to the unit is first used to produce useful thermal energy, where at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.
Business day means a day that does not fall on a weekend or a federal holiday.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function or any other person who performs similar policy- or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means “coal” as defined in § 72.2 of this chapter.
Cogeneration system means an integrated group, at a source, of equipment (including a boiler, or combustion turbine, and a generator) designed to produce useful thermal energy for industrial, commercial, heating, or cooling purposes and electricity through the sequential use of energy.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a topping-cycle unit or a bottoming-cycle unit:
(1) Operating as part of a cogeneration system; and
(2) Producing on an annual average basis –
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output; or
(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;
(3) Provided that the requirements in paragraph (2) of this definition shall not apply to a calendar year referenced in paragraph (2) of this definition during which the unit did not operate at all;
(4) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel, except biomass if the unit is a boiler; and
(5) Provided that, if, throughout its operation during the 12-month period or a calendar year referenced in paragraph (2) of this definition, a unit is operated as part of a cogeneration system and the cogeneration system meets on a system-wide basis the requirement in paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be deemed to meet such requirement during that 12-month period or calendar year.
Combustion turbine means an enclosed device comprising:
(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.805.
(i) For a unit that is a CSAPR NO
(ii) For a unit that is a CSAPR NO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.805, for a unit that is not a CSAPR NO
(i) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change or is moved to a different location or source, such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same or a different source, such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
Common designated representative means, with regard to a control period in a given year, a designated representative where, as of April 1 immediately after the allowance transfer deadline for such a control period before 2021, or as of July 1 immediately after such deadline for such a control period in 2021 or thereafter, the same natural person is authorized under §§ 97.813(a) and 97.815(a) as the designated representative for a group of one or more base CSAPR NO
Common designated representative’s assurance level means, with regard to a specific common designated representative and a State (and Indian country within the borders of such State) and control period in a given year for which the State assurance level is exceeded as described in § 97.806(c)(2)(iii):
(1) The amount (rounded to the nearest allowance) equal to the sum of the total amount of CSAPR NO
(2) Provided that the allocations of CSAPR NO
Common designated representative’s share means, with regard to a specific common designated representative for a control period in a given year and a total amount of NO
Common stack means a single flue through which emissions from 2 or more units are exhausted.
Compliance account means an Allowance Management System account, established by the Administrator for a CSAPR NO
Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent record of NO
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A NO
(3) A NO
(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(5) A CO
(6) An O
Control period means the period starting May 1 of a calendar year, except as provided in § 97.806(c)(3), and ending on September 30 of the same year, inclusive.
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, CSAPR NO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR SO
CSAPR SO
Designated representative means, for a CSAPR NO
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative, and as modified by the Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required to measure, record, and report such air pollutants in accordance with this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the CSAPR NO
Fossil fuel means –
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or
(2) For purposes of applying the limitation on “average annual fuel consumption of fossil fuel” in § 97.804(b)(2)(i)(B) and (b)(2)(ii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account, established under this subpart, that is not a compliance account or an assurance account.
Generator means a device that produces electricity.
Heat input means, for a unit for a specified period of unit operating time, the product (in mmBtu) of the gross calorific value of the fuel (in mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of fuel/time) and unit operating time, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the quotient (in mmBtu/hr) of the amount of heat input for a specified period of unit operating time (in mmBtu) divided by unit operating time (in hr) or, for a unit and a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Indian country means “Indian country” as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Maximum design heat input rate means, for a unit, the maximum amount of fuel per hour (in Btu/hr) that the unit is capable of combusting on a steady state basis as of the initial installation of the unit as specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe, rounded to the nearest tenth) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount (in MWe, rounded to the nearest tenth) as of such completion as specified by the person conducting the physical change.
Natural gas means “natural gas” as defined in § 72.2 of this chapter.
Newly affected CSAPR NO
Nitrogen oxides means all oxides of nitrogen except nitrous oxide (N
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a CSAPR NO
Owner means, for a CSAPR NO
(1) Any holder of any portion of the legal or equitable title in a CSAPR NO
(2) Any holder of a leasehold interest in a CSAPR NO
(3) Any purchaser of power from a CSAPR NO
Permanently retired means, with regard to a unit, a unit that is unavailable for service and that the unit’s owners and operators do not expect to return to service in the future.
Permitting authority means “permitting authority” as defined in §§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity means, for a unit (in MWh/yr), 33 percent of the unit’s maximum design heat input rate (in Btu/hr), divided by 3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to CSAPR NO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.
Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or retired unit (the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from electricity production in a useful thermal energy application or process; or
(2) The use of reject heat from a useful thermal energy application or process in electricity production.
Serial number means, for a CSAPR NO
Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act.
Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the definition of “major source”, “stationary source”, or “source” as set forth and implemented in a title V operating permit program or any other program under the Clean Air Act.
State means one of the States that is subject to the CSAPR NO
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Topping-cycle unit means a unit in which the energy input to the unit is first used to produce useful power, including electricity, where at least some of the reject heat from the electricity production is then used to provide useful thermal energy.
Total energy input means, for a unit, total energy of all forms supplied to the unit, excluding energy produced by the unit. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:
Total energy output means, for a unit, the sum of useful power and useful thermal energy produced by the unit.
Unit means a stationary, fossil-fuel-fired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-fired combustion device. A unit that undergoes a physical change or is moved to a different location or source shall continue to be treated as the same unit. A unit (the replaced unit) that is replaced by another unit (the replacement unit) at the same or a different source shall continue to be treated as the same unit, and the replacement unit shall be treated as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to a unit, an hour in which the unit combusts any fuel.
Useful power means, with regard to a unit, electricity or mechanical energy that the unit makes available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means thermal energy that is:
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption chiller).
Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.
§ 97.803 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
§ 97.804 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State (and Indian country within the borders of such State) shall be CSAPR NO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a CSAPR NO
(b) Any unit in a State (and Indian country within the borders of such State) that otherwise is a CSAPR NO
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) Not supplying in 2005 or any calendar year thereafter more than one-third of the unit’s potential electrical output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If, after qualifying under paragraph (b)(1)(i) of this section as not being a CSAPR NO
(2)(i) Any unit:
(A) Qualifying as a solid waste incineration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) With an average annual fuel consumption of fossil fuel for the first 3 consecutive calendar years of operation starting no earlier than 2005 of less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years thereafter of less than 20 percent (on a Btu basis).
(ii) If, after qualifying under paragraph (b)(2)(i) of this section as not being a CSAPR NO
(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section or a SIP revision approved under § 52.38(b)(8) or (9) of this chapter, of the CSAPR NO
(1) Petition content. The petition shall be in writing and include the identification of the unit or other equipment and the relevant facts about the unit or other equipment. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying official: “I am authorized to make this submission on behalf of the owners and operators of the unit or other equipment for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) Response. The Administrator will issue a written response to the petition and may request supplemental information determined by the Administrator to be relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CSAPR NO
§ 97.805 Retired unit exemption.
(a)(1) Any CSAPR NO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the CSAPR NO
(b)(1) A unit exempt under paragraph (a) of this section shall not emit any NO
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the CSAPR NO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.
§ 97.806 Standard requirements.
(a) Designated representative requirements. The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.813 through 97.818.
(b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each CSAPR NO
(2) The emissions data determined in accordance with §§ 97.830 through 97.835 shall be used to calculate allocations of CSAPR NO
(c) NO
(ii) If total NO
(A) The owners and operators of the source and each CSAPR NO
(B) The owners and operators of the source and each CSAPR NO
(2) CSAPR NO
(A) The quotient of the amount by which the common designated representative’s share of such NO
(B) The amount by which total NO
(ii) The owners and operators shall hold the CSAPR NO
(iii) Total NO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if total NO
(v) To the extent the owners and operators fail to hold CSAPR NO
(A) The owners and operators shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each CSAPR NO
(3) Compliance periods. (i) A CSAPR NO
(ii) A base CSAPR NO
(4) Vintage of CSAPR NO
(ii) A CSAPR NO
(5) Allowance Management System requirements. Each CSAPR NO
(6) Limited authorization. A CSAPR NO
(i) Such authorization shall only be used in accordance with the CSAPR NO
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7) Property right. A CSAPR NO
(d) Title V permit requirements. (1) No title V permit revision shall be required for any allocation, holding, deduction, or transfer of CSAPR NO
(2) A description of whether a unit is required to monitor and report NO
(e) Additional recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of each CSAPR NO
(i) The certificate of representation under § 97.816 for the designated representative for the source and each CSAPR NO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the CSAPR NO
(2) The designated representative of a CSAPR NO
(f) Liability. (1) Any provision of the CSAPR NO
(2) Any provision of the CSAPR NO
(g) Effect on other authorities. No provision of the CSAPR NO
§ 97.807 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the CSAPR NO
(b) Unless otherwise stated, any time period scheduled, under the CSAPR NO
(c) Unless otherwise stated, if the final day of any time period, under the CSAPR NO
§ 97.808 Administrative appeal procedures.
The administrative appeal procedures for decisions of the Administrator under the CSAPR NO
§ 97.809 [Reserved]
§ 97.810 State NOX Ozone Season Group 2 trading budgets, new unit set-asides, Indian country new unit set-asides, and variability limits.
(a) The State NO
(1) Alabama. (i) The NO
(ii) The new unit set-aside for 2017 and thereafter is 255 tons.
(iii) The Indian country new unit set-aside for 2017 and thereafter is 13 tons.
(2) Arkansas. (i) The NO
(ii) The new unit set-aside for 2017 is 240 tons and for 2018 and thereafter is 185 tons.
(iii) [Reserved]
(3) [Reserved]
(4) Illinois. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 302 tons.
(iii) [Reserved]
(5) Indiana. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 468 tons.
(iii) [Reserved]
(6) Iowa. (i) The NO
(ii) The new unit set-aside for 2017 and thereafter is 324 tons.
(iii) The Indian country new unit set-aside for 2017 and thereafter is 11 tons.
(7) Kansas. (i) The NO
(ii) The new unit set-aside for 2017 and thereafter is 148 tons.
(iii) The Indian country new unit set-aside for 2017 and thereafter is 8 tons.
(8) Kentucky. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 426 tons.
(iii) [Reserved]
(9) Louisiana. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 352 tons.
(iii) The Indian country new unit set-aside for 2017 through 2020 is 19 tons.
(10) Maryland. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 152 tons.
(iii) [Reserved]
(11) Michigan. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 665 tons.
(iii) The Indian country new unit set-aside for 2017 through 2020 is 17 tons.
(12) Mississippi. (i) The NO
(ii) The new unit set-aside for 2017 and thereafter is 120 tons.
(iii) The Indian country new unit set-aside for 2017 and thereafter is 6 tons.
(13) Missouri. (i) The NO
(ii) The new unit set-aside for 2017 and thereafter is 324 tons.
(iii) [Reserved]
(14) New Jersey. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 192 tons.
(iii) [Reserved]
(15) New York. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 252 tons.
(iii) The Indian country new unit set-aside for 2017 through 2020 is 5 tons.
(16) Ohio. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 401 tons.
(iii) [Reserved]
(17) Oklahoma. (i) The NO
(ii) The new unit set-aside for 2017 and thereafter is 221 tons.
(iii) The Indian country new unit set-aside for 2017 and thereafter is 12 tons.
(18) Pennsylvania. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 541 tons.
(iii) [Reserved]
(19) Tennessee. (i) The NO
(ii) The new unit set-aside for 2017 and thereafter is 156 tons.
(iii) [Reserved]
(20) Texas. (i) The NO
(ii) The new unit set-aside for 2017 and thereafter is 998 tons.
(iii) The Indian country new unit set-aside for 2017 and thereafter is 52 tons.
(21) Virginia. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 562 tons.
(iii) [Reserved]
(22) West Virginia. (i) The NO
(ii) The new unit set-aside for 2017 through 2020 is 356 tons.
(iii) [Reserved]
(23) Wisconsin. (i) The NO
(ii) The new unit set-aside for 2017 and thereafter is 151 tons.
(iii) The Indian country new unit set-aside for 2017 and thereafter is 8 tons.
(b) The States’ variability limits for the State NO
(1) The variability limit for Alabama for 2017 and thereafter is 2,774 tons.
(2) The variability limit for Arkansas for 2017 is 2,530 tons and for 2018 and thereafter is 1,934 tons.
(3) [Reserved]
(4) The variability limit for Illinois for 2017 through 2020 is 3,066 tons.
(5) The variability limit for Indiana for 2017 through 2020 is 4,894 tons.
(6) The variability limit for Iowa for 2017 and thereafter is 2,367 tons.
(7) The variability limit for Kansas for 2017 and thereafter is 1,686 tons.
(8) The variability limit for Kentucky for 2017 through 2020 is 4,434 tons.
(9) The variability limit for Louisiana for 2017 through 2020 is 3,914 tons.
(10) The variability limit for Maryland for 2017 through 2020 is 804 tons.
(11) The variability limit for Michigan for 2017 through 2020 is 3,575 tons.
(12) The variability limit for Mississippi for 2017 and thereafter is 1,326 tons.
(13) The variability limit for Missouri for 2017 and thereafter is 3,314 tons.
(14) The variability limit for New Jersey for 2017 through 2020 is 433 tons.
(15) The variability limit for New York for 2017 through 2020 is 1,078 tons.
(16) The variability limit for Ohio for 2017 through 2020 is 4,100 tons.
(17) The variability limit for Oklahoma for 2017 and thereafter is 2,445 tons.
(18) The variability limit for Pennsylvania for 2017 through 2020 is 3,770 tons.
(19) The variability limit for Tennessee for 2017 and thereafter is 1,625 tons.
(20) The variability limit for Texas for 2017 and thereafter is 10,983 tons.
(21) The variability limit for Virginia for 2017 through 2020 is 1,937 tons.
(22) The variability limit for West Virginia for 2017 through 2020 is 3,741 tons.
(23) The variability limit for Wisconsin for 2017 and thereafter is 1,662 tons.
(c) Each State NO
§ 97.811 Timing requirements for CSAPR NOX Ozone Season Group 2 allowance allocations.
(a) Existing units. (1) CSAPR NO
(2) Notwithstanding paragraph (a)(1) of this section, if a unit provided an allocation in the notice of data availability issued under paragraph (a)(1) of this section does not operate, starting after 2016, during the control period in two consecutive years, such unit will not be allocated the CSAPR NO
(b) New units – (1) New unit set-asides. (i)(A) By June 1 of each year from 2017 through 2020, the Administrator will calculate the CSAPR NO
(B) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR NO
(ii) For each notice of data availability required in paragraph (b)(1)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR NO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(1)(i)(A) or (B) of this section, as applicable. By August 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i)(A) of this section, or by May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i)(B) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(1)(ii)(A) of this section.
(iii) If the new unit set-aside for a control period before 2021 contains any CSAPR NO
(iv) For each notice of data availability required in paragraph (b)(1)(iii) of this section, the Administrator will provide an opportunity for submission of objections to the identification of CSAPR NO
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(iii) of this section and shall be limited to addressing whether the identification of CSAPR NO
(B) The Administrator will adjust the identification of CSAPR NO
(v) To the extent any CSAPR NO
(2) Indian country new unit set-asides. (i)(A) By June 1 of each year from 2017 through 2020, the Administrator will calculate the CSAPR NO
(B) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR NO
(ii) For each notice of data availability required in paragraph (b)(2)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR NO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i)(A) or (B) of this section, as applicable. By August 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i)(A) of this section, or by May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i)(B) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(ii)(A) of this section.
(iii) If the Indian country new unit set-aside for a control period before 2021 contains any CSAPR NO
(iv) For each notice of data availability required in paragraph (b)(2)(iii) of this section, the Administrator will provide an opportunity for submission of objections to the identification of CSAPR NO
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(iii) of this section and shall be limited to addressing whether the identification of CSAPR NO
(B) The Administrator will adjust the identification of CSAPR NO
(v) To the extent any CSAPR NO
(c) Units incorrectly allocated CSAPR NO
(i)(A) The recipient is not actually a CSAPR NO
(B) The recipient is not located as of May 1 of the control period in the State from whose NO
(ii) The recipient is not actually a CSAPR NO
(2) Except as provided in paragraph (c)(3) or (4) of this section, the Administrator will not record such CSAPR NO
(3) If the Administrator already recorded such CSAPR NO
(4) If the Administrator already recorded such CSAPR NO
(5)(i) With regard to the CSAPR NO
(A) Transfer such CSAPR NO
(B) If the State has a SIP revision approved under § 52.38(b)(8) or (9) of this chapter covering such control period, include such CSAPR NO
(ii) With regard to the CSAPR NO
(A) Transfer such CSAPR NO
(B) If the State has a SIP revision approved under § 52.38(b)(8) or (9) of this chapter covering such control period, include such CSAPR NO
(iii) With regard to the CSAPR NO
(d) Recall of CSAPR NO
(2)(i) For each CSAPR NO
(ii)(A) The surrender requirement under paragraph (d)(2)(i) of this section corresponding to each CSAPR NO
(B) If the owners and operators of a given source as of a given date assumed ownership and operational control of the source through a transaction that did not also provide rights to direct the use or transfer of a given CSAPR NO
(C) The Administrator will not adjudicate any private legal dispute among the owners and operators of a source or among the former owners and operators of a source, including any disputes relating to the requirements to surrender CSAPR NO
(3)(i) As soon as practicable on or after June 29, 2021, the Administrator will send a notification to the designated representative for each source described in paragraph (d)(1) of this section identifying the amounts of CSAPR NO
(ii) As soon as practicable on or after July 14, 2021, the Administrator will deduct from the compliance account for each source described in paragraph (d)(1) of this section CSAPR NO
(iii) As soon as practicable after completion of the deductions under paragraph (d)(3)(ii) of this section, the Administrator will identify for each source described in paragraph (d)(1) of this section the amounts, if any, of CSAPR NO
(iv) With regard to each source for which unsatisfied surrender requirements under paragraph (d)(2)(i) of this section remain after the deductions under paragraph (d)(3)(ii) of this section:
(A) Except as provided in paragraph (d)(3)(iv)(B) of this section, not later than September 15, 2021, the owners and operators of the source shall hold sufficient CSAPR NO
(B) With regard to any portion of such unsatisfied surrender requirements that apply to former owners and operators of the source pursuant to paragraph (d)(2)(ii)(B) of this section, not later than September 15, 2021, such former owners and operators shall hold sufficient CSAPR NO
(C) As soon as practicable on or after September 15, 2021, the Administrator will deduct from the Allowance Management System account identified in accordance with paragraph (d)(3)(iv)(A) or (B) of this section CSAPR NO
(v) When making deductions under paragraph (d)(3)(ii) or (iv) of this section to address the surrender requirements under paragraph (d)(2)(i) of this section for a given source:
(A) The Administrator will make deductions to address any surrender requirements with regard to first the 2021 control period, then the 2022 control period, then the 2023 control period, and finally the 2024 control period.
(B) When making deductions to address the surrender requirements with regard to a given control period, the Administrator will first deduct CSAPR NO
(C) When deducting CSAPR NO
(4)(i) To the extent the surrender requirements under paragraph (d)(2)(i) of this section corresponding to any CSAPR NO
(ii) If no person with an ownership interest in a given CSAPR NO
(iii) Not less than 45 days before the planned date for any deductions under paragraph (d)(4)(i) of this section, the Administrator will send a notification to the authorized account representative for the Allowance Management System account from which such deductions will be made identifying the CSAPR NO
(5) To the extent the surrender requirements under paragraph (d)(2)(i) of this section corresponding to any CSAPR NO
(i) The persons identified in accordance with paragraph (d)(2)(ii) of this section with regard to such source and each such CSAPR NO
(ii) Each such CSAPR NO
(6) The Administrator will record in the appropriate Allowance Management System accounts all deductions of CSAPR NO
(7)(i) Each submission, objection, or other written communication from a designated representative, authorized account representative, or other person to the Administrator under paragraph (d)(2), (3), or (4) of this section shall be sent electronically to the email address [email protected]. Each such communication from a designated representative must contain the certification statement set forth in § 97.814(a), and each such communication from the authorized account representative for a general account must contain the certification statement set forth in § 97.820(c)(2)(ii).
(ii) Each notification from the Administrator to a designated representative or authorized account representative under paragraph (d)(3) or (4) of this section will be sent electronically to the email address most recently received by the Administrator for such representative. In any such notification, the Administrator may provide information by means of a reference to a publicly accessible website where the information is available.
§ 97.812 CSAPR NOX Ozone Season Group 2 allowance allocations to new units.
(a) Allocations from new unit set-asides. For each control period in 2017 and thereafter and for the CSAPR NO
(1) The CSAPR NO
(i) CSAPR NO
(ii) CSAPR NO
(iii) CSAPR NO
(iv) For purposes of paragraph (a)(9) of this section, CSAPR NO
(2) The Administrator will establish a separate new unit set-aside for the State for each such control period. Each such new unit set-aside will be allocated CSAPR NO
(3) The Administrator will determine, for each CSAPR NO
(i) The control period in 2017;
(ii)(A) The first control period after the control period in which the CSAPR NO
(B) The control period containing the deadline for certification of the CSAPR NO
(iii) For a unit described in paragraph (a)(1)(ii) of this section, the first control period in which the CSAPR NO
(iv) For a unit described in paragraph (a)(1)(iii) of this section, the first control period after the control period in which the unit resumes operation, for allocations for a control period before 2021, or the control period in which the unit resumes operation, for allocations for a control period in 2021 or thereafter.
(4)(i) The allocation to each CSAPR NO
(ii) The Administrator will adjust the allocation amount in paragraph (a)(4)(i) of this section in accordance with paragraphs (a)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR NO
(6) If the amount of CSAPR NO
(7) If the amount of CSAPR NO
(8) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.811(b)(1)(i) and (ii), of the amount of CSAPR NO
(9) For a control period before 2021, if, after completion of the procedures under paragraphs (a)(5) through (8) of this section for such control period, any unallocated CSAPR NO
(i) The Administrator will determine, for each unit described in paragraph (a)(1) of this section that commenced commercial operation during the period starting January 1 of the year before the year of such control period and ending November 30 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR NO
(ii) The Administrator will determine the sum of the positive differences determined under paragraph (a)(9)(i) of this section;
(iii) If the amount of unallocated CSAPR NO
(iv) If the amount of unallocated CSAPR NO
(10) If, after completion of the procedures under paragraphs (a)(9) and (12) of this section for a control period before 2021, or under paragraphs (a)(2) through (7) and (12) of this section for a control period in 2021 or thereafter, any unallocated CSAPR NO
(11)(i) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.811(b)(1)(iii), (iv), and (v), of the amount of CSAPR NO
(ii) For a control period in 2021 or thereafter, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.811(b)(1)(i), (ii), and (v), of the amount of CSAPR NO
(12) Notwithstanding the requirements of paragraphs (a)(2) through (11) of this section, if the calculations of allocations from a new unit set-aside for a control period before 2021 under paragraph (a)(7) of this section, paragraphs (a)(6) and (a)(9)(iv) of this section, or paragraphs (a)(6), (a)(9)(iii), and (a)(10) of this section, or for a control period in 2021 or thereafter under paragraph (a)(7) of this section or paragraphs (a)(6) and (10) of this section, would otherwise result in total allocations from such new unit set-aside unequal to the total amount of such new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR NO
(b) Allocations from Indian country new unit set-asides. For each control period in 2017 and thereafter and for the CSAPR NO
(1) The CSAPR NO
(i) CSAPR NO
(ii) For purposes of paragraph (b)(9) of this section, CSAPR NO
(2) The Administrator will establish a separate Indian country new unit set-aside for the State for each such control period. Each such Indian country new unit set-aside will be allocated CSAPR NO
(3) The Administrator will determine, for each CSAPR NO
(i) The control period in 2017; and
(ii)(A) The first control period after the control period in which the CSAPR NO
(B) The control period containing the deadline for certification of the CSAPR NO
(4)(i) The allocation to each CSAPR NO
(ii) The Administrator will adjust the allocation amount in paragraph (b)(4)(i) of this section in accordance with paragraphs (b)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR NO
(6) If the amount of CSAPR NO
(7) If the amount of CSAPR NO
(8) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.811(b)(2)(i) and (ii), of the amount of CSAPR NO
(9) For a control period before 2021, if, after completion of the procedures under paragraphs (b)(5) through (8) of this section for such control period, any unallocated CSAPR NO
(i) The Administrator will determine, for each unit described in paragraph (b)(1) of this section that commenced commercial operation during the period starting January 1 of the year before the year of such control period and ending November 30 of the year of such control period, the positive difference (if any) between the unit’s emissions during such control period and the amount of CSAPR NO
(ii) The Administrator will determine the sum of the positive differences determined under paragraph (b)(9)(i) of this section;
(iii) If the amount of unallocated CSAPR NO
(iv) If the amount of unallocated CSAPR NO
(10) If, after completion of the procedures under paragraphs (b)(9) and (12) of this section for a control period before 2021, or under paragraphs (b)(2) through (7) and (12) of this section for a control period in 2021 or thereafter, any unallocated CSAPR NO
(i) Transfer such unallocated CSAPR NO
(ii) If the State has a SIP revision approved under § 52.38(b)(8) or (9) of this chapter covering such control period, include such unallocated CSAPR NO
(11)(i) For a control period before 2021, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.811(b)(2)(iii), (iv), and (v), of the amount of CSAPR NO
(ii) For a control period in 2021 or thereafter, the Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.811(b)(2)(i), (ii), and (v), of the amount of CSAPR NO
(12) Notwithstanding the requirements of paragraphs (b)(2) through (11) of this section, if the calculations of allocations from an Indian country new unit set-aside for a control period before 2021 under paragraph (b)(7) of this section or paragraphs (b)(6) and (b)(9)(iv) of this section, or for a control period in 2021 or thereafter under paragraph (b)(7) of this section, would otherwise result in total allocations from such Indian country new unit set-aside unequal to the total amount of such Indian country new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR NO
§ 97.813 Authorization of designated representative and alternate designated representative.
(a) Except as provided under § 97.815, each CSAPR NO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.816:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each CSAPR NO
(ii) The owners and operators of the source and each CSAPR NO
(b) Except as provided under § 97.815, each CSAPR NO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.816,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each CSAPR NO
(c) Except in this section, § 97.802, and §§ 97.814 through 97.818, whenever the term “designated representative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
§ 97.814 Responsibilities of designated representative and alternate designated representative.
(a) Except as provided under § 97.818 concerning delegation of authority to make submissions, each submission under the CSAPR NO
(b) The Administrator will accept or act on a submission made for a CSAPR NO
§ 97.815 Changing designated representative and alternate designated representative; changes in owners and operators; changes in units at the source.
(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.816. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the CSAPR NO
(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.816. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the CSAPR NO
(c) Changes in owners and operators. (1) In the event an owner or operator of a CSAPR NO
(2) Within 30 days after any change in the owners and operators of a CSAPR NO
(d) Changes in units at the source. Within 30 days of any change in which units are located at a CSAPR NO
(1) If the change is the addition of a unit that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the source, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity from whom the unit was purchased or otherwise obtained (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was purchased or otherwise obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity to which the unit was sold or that otherwise obtained the unit (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was sold or otherwise obtained, and the date on which the unit became no longer located at the source.
§ 97.816 Certificate of representation.
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the CSAPR NO
(2) The name, address, email address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the CSAPR NO
(4) The following certification statements by the designated representative and any alternate designated representative –
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each CSAPR NO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CSAPR NO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a CSAPR NO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(c) A certificate of representation under this section or § 97.516 that complies with the provisions of paragraph (a) of this section except that it contains the phrase “TR NO
§ 97.817 Objections concerning designated representative and alternate designated representative.
(a) Once a complete certificate of representation under § 97.816 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.816 is received by the Administrator.
(b) Except as provided in paragraph (a) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CSAPR NO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of CSAPR NO
§ 97.818 Delegation by designated representative and alternate designated representative.
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, email address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.818(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.818(d), I agree to maintain an email account and to notify the Administrator immediately of any change in my email address unless all delegation of authority by me under 40 CFR 97.818 is terminated.”.
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(f) A notice of delegation submitted under paragraph (c) of this section or § 97.518(c) that complies with the provisions of paragraph (c) of this section except that it contains the terms “40 CFR 97.518(d)” and “40 CFR 97.518” in place of the terms “40 CFR 97.818(d)” and “40 CFR 97.818”, respectively, in the required certification statements will be considered a valid notice of delegation submitted under paragraph (c) of this section, and the certification statements included in such notice of delegation will be interpreted for purposes of this subpart as if the terms “40 CFR 97.818(d)” and “40 CFR 97.818” appeared in place of the terms “40 CFR 97.518(d)” and “40 CFR 97.518”, respectively.
§ 97.819 [Reserved]
§ 97.820 Establishment of compliance accounts, assurance accounts, and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.816, the Administrator will establish a compliance account for the CSAPR NO
(b) Assurance accounts. The Administrator will establish assurance accounts for certain owners and operators and States in accordance with § 97.825(b)(3).
(c) General accounts – (1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring CSAPR NO
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to CSAPR NO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, email address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the CSAPR NO
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to CSAPR NO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(iv) An application for a general account under paragraph (c)(1) of this section or § 97.520(c)(1) that complies with the provisions of paragraph (c)(1) of this section except that it contains the phrase “TR NO
(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (c)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CSAPR NO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to CSAPR NO
(ii) Except as provided in paragraph (c)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to CSAPR NO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(iv) A certification statement submitted in accordance with paragraph (c)(2)(ii) of this section that contains the phrase “TR NO
(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the CSAPR NO
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the CSAPR NO
(iii)(A) In the event a person having an ownership interest with respect to CSAPR NO
(B) Within 30 days after any change in the persons having an ownership interest with respect to CSAPR NO
(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the CSAPR NO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of CSAPR NO
(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (c)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, email address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (c)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized account representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.820(c)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.820(c)(5)(iv), I agree to maintain an email account and to notify the Administrator immediately of any change in my email address unless all delegation of authority by me under 40 CFR 97.820(c)(5) is terminated.”.
(iv) A notice of delegation submitted under paragraph (c)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (c)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this section shall be deemed to be an electronic submission by the authorized account representative or alternate authorized account representative submitting such notice of delegation.
(vi) A notice of delegation submitted under paragraph (c)(5)(iii) of this section or § 97.520(c)(5)(iii) that complies with the provisions of paragraph (c)(5)(iii) of this section except that it contains the terms “40 CFR 97.520(c)(5)(iv)” and “40 CFR 97.520(c)(5)” in place of the terms “40 CFR 97.820(c)(5)(iv)” and “40 CFR 97.820(c)(5)”, respectively, in the required certification statements will be considered a valid notice of delegation submitted under paragraph (c)(5)(iii) of this section, and the certification statements included in such notice of delegation will be interpreted for purposes of this subpart as if the terms “40 CFR 97.820(c)(5)(iv)” and “40 CFR 97.820(c)(5)” appeared in place of the terms “40 CFR 97.520(c)(5)(iv)” and “40 CFR 97.520(c)(5)”, respectively.
(6) Closing a general account. (i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted CSAPR NO
(ii) If a general account has no CSAPR NO
(d) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a), (b), or (c) of this section.
(e) Responsibilities of authorized account representative and alternate authorized account representative. After the establishment of a compliance account or general account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of CSAPR NO
§ 97.821 Recordation of CSAPR NOX Ozone Season Group 2 allowance allocations and auction results.
(a) By January 9, 2017, the Administrator will record in each CSAPR NO
(b) By January 9, 2017, the Administrator will record in each CSAPR NO
(1) If, by April 1, 2017 the State does not submit to the Administrator such complete SIP revision, the Administrator will record by April 15, 2017 in each CSAPR NO
(2) If the State submits to the Administrator by April 1, 2017 and the Administrator approves by October 1, 2017 such complete SIP revision, the Administrator will record by October 1, 2017 in each CSAPR NO
(3) If the State submits to the Administrator by April 1, 2017 and the Administrator does not approve by October 1, 2017 such complete SIP revision, the Administrator will record by October 1, 2017 in each CSAPR NO
(c) By July 1, 2018, the Administrator will record in each CSAPR NO
(d) By July 1, 2019, the Administrator will record in each CSAPR NO
(e) By July 1, 2020, the Administrator will record in each CSAPR NO
(f) By July 1, 2024 and July 1 of each year thereafter, the Administrator will record in each CSAPR NO
(g)(1) By August 1 of each year from 2017 through 2020, the Administrator will record in each CSAPR NO
(2) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR NO
(h)(1) By August 1 of each year from 2017 through 2020, the Administrator will record in each CSAPR NO
(2) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR NO
(i) By February 15 of each year from 2018 through 2021, the Administrator will record in each CSAPR NO
(j) By February 15 of each year from 2018 through 2021, the Administrator will record in each CSAPR NO
(k) By the date 15 days after the date on which any allocation or auction results, other than an allocation or auction results described in paragraphs (a) through (j) of this section, of CSAPR NO
(l) When recording the allocation or auction of CSAPR NO
§ 97.822 Submission of CSAPR NOX Ozone Season Group 2 allowance transfers.
(a) An authorized account representative seeking recordation of a CSAPR NO
(b) A CSAPR NO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each CSAPR NO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each CSAPR NO
§ 97.823 Recordation of CSAPR NOX Ozone Season Group 2 allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a CSAPR NO
(b) A CSAPR NO
(c) Where a CSAPR NO
(d) Within 5 business days of recordation of a CSAPR NO
(e) Within 10 business days of receipt of a CSAPR NO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
§ 97.824 Compliance with CSAPR NOX Ozone Season Group 2 emissions limitation.
(a) Availability for deduction for compliance. CSAPR NO
(1) Were allocated or auctioned for such control period or a control period in a prior year; and
(2) Are held in the source’s compliance account as of the allowance transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance with § 97.823, of CSAPR NO
(1) Until the amount of CSAPR NO
(2) If there are insufficient CSAPR NO
(c) Selection of CSAPR NO
(2) First-in, first-out. The Administrator will deduct CSAPR NO
(i) Any CSAPR NO
(ii) Any other CSAPR NO
(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in which the CSAPR NO
(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and (d) of this section.
§ 97.825 Compliance with CSAPR NOX Ozone Season Group 2 assurance provisions.
(a) Availability for deduction. CSAPR NO
(1) Were allocated or auctioned for a control period in a prior year or the control period in the given year or in the immediately following year; and
(2) Are held in the assurance account, established by the Administrator for such owners and operators of such group of base CSAPR NO
(b) Deductions for compliance. The Administrator will deduct CSAPR NO
(1) By June 1 of each year from 2018 through 2021 and August 1 of each year thereafter, the Administrator will:
(i) Calculate, for each State (and Indian country within the borders of such State), the total NO
(ii) For the set of any States (and Indian country within the borders of such States) for which the results of the calculations required in paragraph (b)(1)(i) of this section indicate that total NO
(A) Calculate, for each such State (and Indian country within the borders of such State) and such control period and each common designated representative for such control period for a group of one or more base CSAPR NO
(B) Promulgate a notice of data availability of the results of the calculations required in paragraphs (b)(1)(i) and (b)(1)(ii)(A) of this section, including separate calculations of the NO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice of data availability required in paragraph (b)(1)(ii) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations referenced in such notice are in accordance with § 97.806(c)(2)(iii), §§ 97.806(b) and 97.830 through 97.835, the definitions of “common designated representative”, “common designated representative’s assurance level”, and “common designated representative’s share” in § 97.802, and the calculation formula in § 97.806(c)(2)(i).
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By October 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) For any State (and Indian country within the borders of such State) referenced in each notice of data availability required in paragraph (b)(2)(ii) of this section as having base CSAPR NO
(4)(i) As of midnight of November 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section, the owners and operators described in paragraph (b)(3) of this section shall hold in the assurance account established for them and for the appropriate base CSAPR NO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(4)(i) of this section, if November 1 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section and after the recordation, in accordance with § 97.823, of CSAPR NO
(6) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notice of data availability required in paragraph (b)(2)(ii) of this section for a control period in a given year, of any data used in making the calculations referenced in such notice, the amounts of CSAPR NO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of CSAPR NO
(ii) [Reserved]
(iii) If the revised data are used to recalculate, in accordance with paragraph (b)(6)(i) of this section, the amount of CSAPR NO
(A) Where the amount of CSAPR NO
(B) For the owners and operators for which the amount of CSAPR NO
(C) Each CSAPR NO
§ 97.826 Banking and conversion.
(a) A CSAPR NO
(b) Any CSAPR NO
(c) At any time after the allowance transfer deadline for the last control period for which a State NO
(d) Notwithstanding any other provision of this subpart, part 52 of this chapter, or any SIP revision approved under § 52.38(b)(8) or (9) of this chapter:
(1) By August 13, 2021, the Administrator will temporarily suspend acceptance of CSAPR NO
(i) The Administrator will determine each of the following values:
(A) The total amount of CSAPR NO
(B) The total tons of NO
(C) The full-season CSAPR NO
(D) A conversion factor, computed as the quotient, rounded down to the nearest whole number, of the remainder of the total amount of CSAPR NO
(E) The adjusted CSAPR NO
(ii) The Administrator will allocate CSAPR NO
(A) The Administrator will determine for each such source the source’s maximum share, computed as the quotient, rounded down to the nearest whole number, of the amount of CSAPR NO
(B) The Administrator will determine a source allocation scaling factor, computed as the lesser of 1.0000 or the quotient, expressed to four decimal places, of the adjusted CSAPR NO
(C) The Administrator will allocate to each such source an amount of CSAPR NO
(iii) If the sum for all sources of the allocations under paragraph (d)(1)(ii)(C) of this section is less than the adjusted CSAPR NO
(A) The Administrator will determine for each general account the account’s maximum share, computed as the quotient, rounded down to the nearest whole number, of the amount of CSAPR NO
(B) The Administrator will determine a general account allocation scaling factor, computed as the lesser of 1.0000 or the quotient, expressed to four decimal places, of the remainder of the adjusted CSAPR NO
(C) The Administrator will allocate to each general account an amount of CSAPR NO
(iv) For the compliance account of each source, and for each general account, to which an amount of CSAPR NO
(A) The Administrator will determine the amount of CSAPR NO
(B) The Administrator will record in the account the allocations of CSAPR NO
(2)(i) During the period beginning February 1, 2022 and ending February 28, 2022, the designated representative for a source in a State listed in § 52.38(b)(2)(v) of this chapter (or Indian country within the borders of such a State) may request that the Administrator allocate additional CSAPR NO
(ii) For each source covered by a request under paragraph (d)(2)(i) of this section, as soon as practicable on or after March 1, 2022, the Administrator will deduct from the source’s compliance account, on a first-in, first-out basis in the order set forth in § 97.824(c)(2)(i) and (ii), the maximum number of sets of 18 CSAPR NO
(3) After the Administrator has carried out the procedures set forth in paragraph (d)(1) of this section, upon any determination that would otherwise result in the initial recordation of a given number of CSAPR NO
(e) Notwithstanding any other provision of this subpart or any SIP revision approved under § 52.38(b)(8) or (9) of this chapter, CSAPR NO
(1) Except as provided in paragraph (e)(2) of this section, after the Administrator has carried out the procedures set forth in paragraph (d)(1) of this section, the owner or operator of a CSAPR NO
(2) CSAPR NO
§ 97.827 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
§ 97.828 Administrator’s action on submissions.
(a) The Administrator may review and conduct independent audits concerning any submission under the CSAPR NO
(b) The Administrator may deduct CSAPR NO
§ 97.829 [Reserved]
§ 97.830 General monitoring, recordkeeping, and reporting requirements.
The owners and operators, and to the extent applicable, the designated representative, of a CSAPR NO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each CSAPR NO
(1) Install all monitoring systems required under this subpart for monitoring NO
(2) Successfully complete all certification tests required under § 97.831 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator of a CSAPR NO
(1) May 1, 2017;
(2) 180 calendar days after the date on which the unit commences commercial operation; or
(3) Where data for the unit are reported on a control period basis under § 97.834(d)(1)(ii)(B), and where the compliance date under paragraph (b)(2) of this section is not in a month from May through September, May 1 immediately after the compliance date under paragraph (b)(2) of this section.
(4) The owner or operator of a CSAPR NO
(i) Such requirements shall apply to the monitoring systems required under § 97.830 through § 97.835, rather than the monitoring systems required under part 75 of this chapter;
(ii) NO
(iii) Any petition for another procedure under § 75.4(e)(2) of this chapter shall be submitted under § 97.835, rather than § 75.66 of this chapter.
(c) Reporting data. The owner or operator of a CSAPR NO
(d) Prohibitions. (1) No owner or operator of a CSAPR NO
(2) No owner or operator of a CSAPR NO
(3) No owner or operator of a CSAPR NO
(4) No owner or operator of a CSAPR NO
(i) During the period that the unit is covered by an exemption under § 97.805 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.831(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a CSAPR NO
§ 97.831 Initial monitoring system certification and recertification procedures.
(a) The owner or operator of a CSAPR NO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B, D, and E to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.830(a)(1) that is exempt from initial certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the NO
(d) Except as provided in paragraph (a) of this section, the owner or operator of a CSAPR NO
(1) Requirements for initial certification. The owner or operator shall ensure that each continuous monitoring system under § 97.830(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.830(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.830(a)(1) that may significantly affect the ability of the system to accurately measure or record NO
(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.830(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in § 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words “certification” and “initial certification” are replaced by the word “recertification” and the word “certified” is replaced by the word “recertified”.
(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office and the Administrator written notice of the dates of certification testing, in accordance with § 97.833.
(ii) Certification application. The designated representative shall submit to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the CSAPR NO
(iv) Certification application approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the CSAPR NO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.832(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NO
(2) For a disapproved NO
(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(5) For a disapproved excepted NO
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
§ 97.832 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D or subpart H of, or appendix D or appendix E to, part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.831 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the Administrator or any State or permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 97.831 for each disapproved monitoring system.
§ 97.833 Notifications concerning monitoring.
The designated representative of a CSAPR NO
§ 97.834 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply with all recordkeeping and reporting requirements in paragraphs (b) through (e) of this section, the applicable recordkeeping and reporting requirements under § 75.73 of this chapter, and the requirements of § 97.814(a).
(b) Monitoring plans. The owner or operator of a CSAPR NO
(c) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all initial certification or recertification tests required under § 97.831, including the information required under § 75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit quarterly reports, as follows:
(1)(i) If a CSAPR NO
(ii) If a CSAPR NO
(A) Meet the requirements of subpart H of part 75 of this chapter for such unit for the entire year and report the NO
(B) Meet the requirements of subpart H of part 75 of this chapter (including the requirements in § 75.74(c) of this chapter) for such unit for the control period and report the NO
(2) The designated representative shall report the NO
(i) The calendar quarter covering May 1, 2017 through June 30, 2017;
(ii) The calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.830(b); or
(iii) For a unit that reports on a control period basis under paragraph (d)(1)(ii)(B) of this section, if the calendar quarter under paragraph (d)(2)(ii) of this section does not include a month from May through September, the calendar quarter covering May 1 through June 30 immediately after the calendar quarter under paragraph (d)(2)(ii) of this section.
(3) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.
(4) For CSAPR NO
(5) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(3) of this section.
(e) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications;
(2) For a unit with add-on NO
(3) For a unit that is reporting on a control period basis under paragraph (d)(1)(ii)(B) of this section, the NO
§ 97.835 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements.
(a) The designated representative of a CSAPR NO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(1) Identification of each unit and source covered by the petition;
(2) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used in the proposed alternative;
(4) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be de minimis; and
(5) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
Subpart FFFFF – Texas SO2 Trading Program
§ 97.901 Purpose.
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Texas SO
§ 97.902 Definitions.
The terms used in this subpart shall have the meanings set forth in this section as follows:
Acid Rain Program means a multi-state SO
Administrator means the Administrator of the United States Environmental Protection Agency or the Director of the Clean Air Markets Division (or its successor determined by the Administrator) of the United States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.
Allocate or allocation means, with regard to Texas SO
Allowance Management System means the system by which the Administrator records allocations, transfers, and deductions of Texas SO
Allowance Management System account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, holding, transfer, or deduction of Texas SO
Allowance transfer deadline means, for a control period before 2021, midnight of March 1 immediately after such control period or, for a control period in 2021 or thereafter, midnight of June 1 immediately after such control period (or if such March 1 or June 1 is not a business day, midnight of the first business day thereafter) and is the deadline by which a Texas SO
Alternate designated representative means, for a Texas SO
Assurance account means an Allowance Management System account, established by the Administrator under § 97.925(b)(3) for certain owners and operators of a group of one or more Texas SO
Authorized account representative means, for a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of Texas SO
Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by this subpart.
Business day means a day that does not fall on a weekend or a federal holiday.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means “coal” as defined in § 72.2 of this chapter.
Commence commercial operation means, with regard to a Texas SO
Common designated representative means, with regard to a control period in a given year, a designated representative where, as of July 1 immediately after the allowance transfer deadline for such control period, the same natural person is authorized under §§ 97.913(a) and 97.915(a) as the designated representative for a group of one or more Texas SO
Common designated representative’s assurance level means, with regard to a specific common designated representative and control period in a given year for which the State assurance level is exceeded as described in § 97.906(c)(2)(iii):
(1) The amount (rounded to the nearest allowance) equal to the sum of the total amount of Texas SO
(2) Provided that, in the case of a Texas SO
Common designated representative’s share means, with regard to a specific common designated representative for a control period in a given year and the total amount of SO
Common stack means a single flue through which emissions from 2 or more units are exhausted.
Compliance account means an Allowance Management System account, established by the Administrator for a Texas SO
Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent record of SO
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A SO
(3) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(4) A CO
(5) An O
Control period means the period starting January 1 of a calendar year, except as provided in § 97.906(c)(3), and ending on December 31 of the same year, inclusive.
CSAPR NO
Designated representative means, for a Texas SO
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative, and as modified by the Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required to measure, record, and report such air pollutants in accordance with this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the Texas SO
Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.
Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account, established under this subpart, that is not a compliance account or an assurance account.
Generator means a device that produces electricity.
Heat input means, for a unit for a specified period of unit operating time, the product (in mmBtu) of the gross calorific value of the fuel (in mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of fuel/time) and unit operating time, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the quotient (in mmBtu/hr) of the amount of heat input for a specified period of unit operating time (in mmBtu) divided by unit operating time (in hr) or, for a unit and a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Indian country means “Indian country” as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe, rounded to the nearest tenth) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount (in MWe, rounded to the nearest tenth) as of such completion as specified by the person conducting the physical change.
Natural gas means “natural gas” as defined in § 72.2 of this chapter.
Natural person means a human being, as opposed to a legal person, which may be a private (i.e., business entity or non-governmental organization) or public (i.e., government) organization.
Nitrogen oxides means all oxides of nitrogen except nitrous oxide (N
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a Texas SO
Owner means, for a Texas SO
(1) Any holder of any portion of the legal or equitable title in a Texas SO
(2) Any holder of a leasehold interest in a Texas SO
(3) Any purchaser of power from a Texas SO
Permanently retired means, with regard to a unit, a unit that is unavailable for service and that the unit’s owners and operators do not expect to return to service in the future.
Permitting authority means “permitting authority” as defined in §§ 70.2 and 71.2 of this chapter.
Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to Texas SO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.
Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or retired unit (the replaced unit).
Serial number means, for a Texas SO
Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the definition of “major source”, “stationary source”, or “source” as set forth and implemented in a title V operating permit program or any other program under the Clean Air Act.
State means Texas.
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Texas SO
Texas SO
Texas SO
Texas SO
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, Texas SO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, Texas SO
Texas SO
Texas SO
Texas SO
Unit means a stationary, fossil-fuel-fired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-fired combustion device. A unit that undergoes a physical change or is moved to a different location or source shall continue to be treated as the same unit. A unit (the replaced unit) that is replaced by another unit (the replacement unit) at the same or a different source shall continue to be treated as the same unit, and the replacement unit shall be treated as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to a unit, an hour in which the unit combusts any fuel.
§ 97.903 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
§ 97.904 Applicability.
(a) Each of the units in Texas listed in the table in § 97.911(a)(1) shall be a Texas SO
(b) [Reserved]
§ 97.905 Retired unit exemptions.
(a)(1) Any Texas SO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the Texas SO
(b)(1) A unit exempt under paragraph (a) of this section shall not emit any SO
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the Texas SO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. A retired unit that resumes operation will not receive an allowance allocation under § 97.911. The unit may receive allowances from the Supplemental Allowance Pool pursuant to § 97.912. All other provisions of Subpart FFFFF regarding monitoring, reporting, recordkeeping and compliance will apply on the first date on which the unit resumes operation.
§ 97.906 General provisions.
(a) Designated representative requirements. The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.913 through 97.918.
(b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each Texas SO
(2) The emissions data determined in accordance with §§ 97.930 through 97.935 shall be used to calculate allocations of Texas SO
(c) SO
(ii) If total SO
(A) The owners and operators of the source and each Texas SO
(B) The owners and operators of the source and each Texas SO
(2) Texas SO
(A) The quotient of the amount by which the common designated representative’s share of such SO
(B) The amount by which total SO
(ii) The owners and operators shall hold the Texas SO
(iii) Total SO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if total SO
(v) To the extent the owners and operators fail to hold Texas SO
(A) The owners and operators shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each Texas SO
(3) Compliance periods. (i) A Texas SO
(ii) A Texas SO
(4) Vintage of Texas SO
(ii) A Texas SO
(5) Allowance Management System requirements. Each Texas SO
(6) Limited authorization. A Texas SO
(i) Such authorization shall only be used in accordance with the Texas SO
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7) Property right. A Texas SO
(d) Title V permit requirements. (1) No title V permit revision shall be required for any allocation, holding, deduction, or transfer of Texas SO
(2) A description of whether a unit is required to monitor and report SO
(e) Additional recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of each Texas SO
(i) The certificate of representation under § 97.916 for the designated representative for the source and each Texas SO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the Texas SO
(2) The designated representative of a Texas SO
(f) Liability. (1) Any provision of the Texas SO
(2) Any provision of the Texas SO
(g) Effect on other authorities. No provision of the Texas SO
§ 97.907 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the Texas SO
(b) Unless otherwise stated, any time period scheduled, under the Texas SO
(c) Unless otherwise stated, if the final day of any time period, under the Texas SO
§ 97.908 Administrative appeal procedures.
The administrative appeal procedures for decisions of the Administrator under the Texas SO
§ 97.909 [Reserved]
§ 97.910 Texas SO2 Trading Program budget, Supplemental Allowance Pool budget, and variability limit.
(a) The budgets for the Texas SO
(1) The Texas SO
(2) The Texas SO
(b) The variability limit for the Texas SO
(c) The Texas SO
§ 97.911 Texas SO2 Trading Program allowance allocations.
(a) Allocations from the Texas SO
Table 1 to Paragraph (
Texas SO | ORIS code | Texas SO Program allocation (tons) | Affiliated ownership group |
---|---|---|---|
Big Brown Unit 1 | 3497 | 8,473 | Vistra. |
Big Brown Unit 2 | 3497 | 8,559 | Vistra. |
Coleto Creek Unit 1 | 6178 | 9,057 | Vistra. |
Fayette (Sam Seymour) Unit 1 | 6179 | 7,979 | Lower Colorado River Authority/City of Austin. |
Fayette (Sam Seymour) Unit 2 | 6179 | 8,019 | Lower Colorado River Authority/City of Austin. |
Graham Unit 2 | 3490 | 226 | Vistra. |
HW Pirkey Unit 1 | 7902 | 8,882 | American Electric Power. |
Harrington Unit 061B | 6193 | 5,361 | Xcel Energy. |
Harrington Unit 062B | 6193 | 5,255 | Xcel Energy. |
Harrington Unit 063B | 6193 | 5,055 | Xcel Energy. |
JT Deely Unit 1 | 6181 | 6,170 | City of San Antonio. |
JT Deely Unit 2 | 6181 | 6,082 | City of San Antonio. |
Limestone Unit 1 | 298 | 12,081 | NRG Energy. |
Limestone Unit 2 | 298 | 12,293 | NRG Energy. |
Martin Lake Unit 1 | 6146 | 12,024 | Vistra. |
Martin Lake Unit 2 | 6146 | 11,580 | Vistra. |
Martin Lake Unit 3 | 6146 | 12,236 | Vistra. |
Monticello Unit 1 | 6147 | 8,598 | Vistra. |
Monticello Unit 2 | 6147 | 8,795 | Vistra. |
Monticello Unit 3 | 6147 | 12,216 | Vistra. |
Newman Unit 2 | 3456 | 1 | El Paso Electric. |
Newman Unit 3 | 3456 | 1 | El Paso Electric. |
Newman Unit **4 | 3456 | 2 | El Paso Electric. |
Newman Unit **5 | 3456 | 2 | El Paso Electric. |
Sandow Unit 4 | 6648 | 8,370 | Vistra. |
Sommers Unit 1 | 3611 | 55 | City of San Antonio. |
Sommers Unit 2 | 3611 | 7 | City of San Antonio. |
Stryker Unit ST2 | 3504 | 145 | Vistra. |
Tolk Unit 171B | 6194 | 6,900 | Xcel Energy. |
Tolk Unit 172B | 6194 | 7,062 | Xcel Energy. |
WA Parish Unit WAP4 | 3470 | 3 | NRG Energy. |
WA Parish Unit WAP5 | 3470 | 9,580 | NRG Energy. |
WA Parish Unit WAP6 | 3470 | 8,900 | NRG Energy. |
WA Parish Unit WAP7 | 3470 | 7,653 | NRG Energy. |
Welsh Unit 1 | 6139 | 6,496 | American Electric Power. |
Welsh Unit 2 | 6139 | 7,050 | American Electric Power. |
Welsh Unit 3 | 6139 | 7,208 | American Electric Power. |
Wilkes Unit 1 | 3478 | 14 | American Electric Power. |
Wilkes Unit 2 | 3478 | 2 | American Electric Power. |
Wilkes Unit 3 | 3478 | 3 | American Electric Power. |
(2) Notwithstanding paragraph (a)(1) of this section, if a unit provided an allocation pursuant to the table in paragraph (a)(1) of this section does not operate, starting after 2018, during the control period in two consecutive years, such unit will not be allocated the Texas SO
(b) [Reserved]
(c) Units incorrectly allocated Texas SO
(2) Except as provided in paragraph (c)(3) or (4) of this section, the Administrator will not record such Texas SO
(3) If the Administrator already recorded such Texas SO
(4) If the Administrator already recorded such Texas SO
(5) With regard to the Texas SO
§ 97.912 Texas SO2 Trading Program Supplemental Allowance Pool.
(a) For the control periods in 2019 and 2020, the Administrator will allocate Texas SO
(1) No later than February 15, 2020 and February 15, 2021, the Administrator will review all the quarterly SO
(2) For each Texas SO
(3)(i) For Coleto Creek (ORIS 6178), if the source is identified under paragraph (a)(1) of this section, the Administrator will allocate and record in the source’s compliance account an amount of allowances from the Supplemental Allowance Pool equal to the lesser of the amount calculated for the source under paragraph (a)(2) of this section or the total number of allowances in the Supplemental Allowance Pool available for allocation under paragraph (d) of this section.
(ii) For any Texas SO
(A) If the total for all such sources of the amounts calculated under paragraph (a)(2) of this section is less than or equal to the total number of allowances in the Supplemental Allowance Pool available for allocation under paragraph (d) of this section that remain after any allocation under paragraph (a)(3)(i) of this section, then the Administrator will allocate and record in the compliance account for each such source an amount of allowances from the Supplemental Allowance Pool equal to the amount calculated for the source under paragraph (a)(2) of this section.
(B) If the total for all such sources of the amounts calculated under paragraph (a)(2) of this section is greater than the total number of allowances in the Supplemental Allowance Pool available for allocation under paragraph (d) of this section that remain after any allocation under paragraph (a)(3)(i) of this section, then the Administrator will calculate each such source’s allocation of allowances from the Supplemental Allowance Pool by dividing the amount calculated under paragraph (a)(2) of this section for the source by the sum of the amounts calculated under paragraph (a)(2) of this section for all such sources, then multiplying by the number of allowances in the Supplemental Allowance Pool available for allocation under paragraph (d) of this section that remain after any allocation under paragraph (a)(3)(i) of this section and rounding to the nearest allowance. The Administrator will adjust the sources’ allocations up or down by one allowance, starting with the largest allocation and continuing in descending order, as necessary to cause the sum of the sources’ allocations to equal the total number of allowances in the Supplemental Allowance Pool available for allocation under paragraph (d) of this section that remain after any allocation under paragraph (a)(3)(i) of this section. The Administrator will then record the calculated allocations of allowances in the applicable compliance accounts.
(iii) Any unallocated allowances remaining in the Supplemental Allowance Pool after the allocations determined under paragraphs (a)(3)(i) and (ii) of this section will be maintained in the Supplemental Allowance Pool. These allowances will be available for allocation by the Administrator in subsequent control periods to the extent consistent with paragraph (d) of this section.
(b) For each control period in 2021 and thereafter, the Administrator will allocate Texas SO
(1) For each control period, the Administrator will assign each Texas SO
(2) No later than May 1, 2022 and May 1 of each year thereafter, the Administrator will review all the quarterly SO
(3) For each affiliated ownership group of Texas SO
(4)(i) The Administrator will allocate and record allowances from the Supplemental Allowance Pool as follows:
(A) If the total for all such affiliated ownership groups of the amounts calculated under paragraph (b)(3) of this section is less than or equal to the total number of allowances in the Supplemental Allowance Pool available for allocation under paragraph (d) of this section, then each such group’s allocation of allowances from the Supplemental Allowance Pool shall equal to the amount calculated for the group under paragraph (b)(3) of this section.
(B) If the total for all such affiliated ownership groups of the amounts calculated under paragraph (b)(3) of this section is greater than the total number of allowances in the Supplemental Allowance Pool available for allocation under paragraph (d) of this section, then the Administrator will calculate each such group’s allocation of allowances from the Supplemental Allowance Pool by dividing the amount calculated under paragraph (b)(3) of this section for the group by the sum of the amounts calculated under paragraph (b)(3) of this section for all such groups, then multiplying by the number of allowances in the Supplemental Allowance Pool available for allocation under paragraph (d) of this section and rounding to the nearest allowance. The Administrator will adjust the groups’ allocations up or down by one allowance, starting with the largest allocation and continuing in descending order, as necessary to cause the sum of the groups’ allocations to equal the total number of allowances in the Supplemental Allowance Pool available for allocation under paragraph (d) of this section.
(C) When an affiliated ownership group receives an allocation of allowances under paragraph (b)(4)(i)(A) or (B) of this section, each source in the group whose emissions during the control period for which allowances are being allocated exceed the amount of allowances allocated to the source under § 97.911 and recorded under § 97.921 will receive a share of the group’s allocation. The Administrator will compute each such source’s share by dividing the amount of the source’s emissions during the control period exceeding the source’s allocation under § 97.911 by the sum for all such sources of the amounts of the sources’ emissions during the control period exceeding the sources’ allocations under § 97.911, then multiplying by the group’s allocation under paragraph (b)(4)(i)(A) or (B) of this section and rounding to the nearest allowance. The Administrator will adjust the sources’ allocations up or down by one allowance, starting with the largest allocation and continuing in descending order, as necessary to cause the sum of the sources’ allocations to equal the group’s allocation. The Administrator will then record the calculated allocations of allowances in the applicable sources’ compliance accounts.
(ii) Any unallocated allowances remaining in the Supplemental Allowance Pool after the allocations determined under paragraph (b)(4)(i) of this section will be maintained in the Supplemental Allowance Pool. These allowances will be available for allocation by the Administrator in subsequent control periods to the extent consistent with paragraph (d) of this section.
(c) The Administrator will notify the designated representative of each Texas SO
(d) The total amount of allowances in the Supplemental Allowance Pool available for allocation for a control period is equal to the sum of the Supplemental Allowance Pool budget under § 97.910(a)(2), any allowances from retired units pursuant to § 97.911(a)(2) and from corrections pursuant to § 97.911(c)(5), and any allowances maintained in the Supplemental Allowance Pool pursuant to paragraph (a)(3)(iii) or (b)(4)(ii) of this section, provided that if the number of allowances in the Supplemental Allowance Pool exceeds the applicable limit for the control period under paragraph (d)(1) or (d)(2) of this section, then the Administrator may only allocate allowances up to such applicable limit.
(1) For the control periods in 2019 and 2020, the total amount of allowances allocated from the Supplemental Allowance Pool for a control period may not exceed by more than 44,711 tons the sum of the Supplemental Allowance Pool budget under § 97.910(a)(2) and any portion of the Texas SO
(2) For each control period in 2021 and thereafter, the total amount of allowances allocated from the Supplemental Allowance Pool for a control period may not exceed the sum of the variability limit under § 97.910(b) and any portion of the Texas SO
§ 97.913 Authorization of designated representative and alternate designated representative.
(a) Except as provided under § 97.915, each Texas SO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all Texas SO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.916:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each Texas SO
(ii) The owners and operators of the source and each Texas SO
(b) Except as provided under § 97.915, each Texas SO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all Texas SO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.916,
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each Texas SO
(c) Except in this section, § 97.902, and §§ 97.914 through 97.918, whenever the term “designated representative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
§ 97.914 Responsibilities of designated representative and alternate designated representative.
(a) Except as provided under § 97.918 concerning delegation of authority to make submissions, each submission under the Texas SO
(b) The Administrator will accept or act on a submission made for a Texas SO
§ 97.915 Changing designated representative and alternate designated representative; changes in owners and operators; changes in units at the source.
(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.916. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the Texas SO
(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.916. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the Texas SO
(c) Changes in owners and operators. (1) In the event an owner or operator of a Texas SO
(2) Within 30 days after any change in the owners and operators of a Texas SO
(d) Changes in units at the source. Within 30 days of any change in which units are located at a Texas SO
(1) If the change is the addition of a unit that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the source, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity from whom the unit was purchased or otherwise obtained (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was purchased or otherwise obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity to which the unit was sold or that otherwise obtained the unit (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was sold or otherwise obtained, and the date on which the unit became no longer located at the source.
§ 97.916 Certificate of representation.
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the Texas SO
(2) The name, address, email address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the Texas SO
(4) The following certification statements by the designated representative and any alternate designated representative –
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each Texas SO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the Texas SO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a Texas SO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
§ 97.917 Objections concerning designated representative and alternate designated representative.
(a) Once a complete certificate of representation under § 97.916 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.916 is received by the Administrator.
(b) Except as provided in paragraph (a) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the Texas SO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of Texas SO
§ 97.918 Delegation by designated representative and alternate designated representative.
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, email address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.918(d) shall be deemed to be an electronic submission by me.”
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.918(d), I agree to maintain an email account and to notify the Administrator immediately of any change in my email address unless all delegation of authority by me under 40 CFR 97.918 is terminated.”
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
§ 97.919 [Reserved]
§ 97.920 Establishment of compliance accounts, assurance accounts, and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.916, the Administrator will establish a compliance account for the Texas SO
(b) Assurance accounts. The Administrator will establish assurance accounts for certain owners and operators and States in accordance with § 97.925(b)(3).
(c) General accounts – (1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring Texas SO
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to Texas SO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, email address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the Texas SO
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to Texas SO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (c)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to Texas SO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to Texas SO
(ii) Except as provided in paragraph (c)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to Texas SO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the Texas SO
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the Texas SO
(iii)(A) In the event a person having an ownership interest with respect to Texas SO
(B) Within 30 days after any change in the persons having an ownership interest with respect to Texas SO
(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the Texas SO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of Texas SO
(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (c)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, email address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (c)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized account representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.920(c)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.920(c)(5)(iv), I agree to maintain an email account and to notify the Administrator immediately of any change in my email address unless all delegation of authority by me under 40 CFR 97.920(c)(5) is terminated.”
(iv) A notice of delegation submitted under paragraph (c)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (c)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this section shall be deemed to be an electronic submission by the authorized account representative or alternate authorized account representative submitting such notice of delegation.
(6) Closing a general account. (i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted Texas SO
(ii) If a general account has no Texas SO
(d) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a), (b), or (c) of this section.
(e) Responsibilities of authorized account representative and alternate authorized account representative. After the establishment of a compliance account or general account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of Texas SO
§ 97.921 Recordation of Texas SO2 Trading Program allowance allocations.
(a) By November 1, 2018, the Administrator will record in each Texas SO
(b)(1) By July 1, 2019 and July 1, 2020, the Administrator will record in each Texas SO
(2) By July 1, 2024 and July 1 of each year thereafter, the Administrator will record in each Texas SO
(c) By February 15 of 2020 and 2021 and May 1 of each year thereafter, the Administrator will record in each Texas SO
(d) [Reserved]
(e) When recording the allocation of Texas SO
(f) Notwithstanding paragraphs (a) and (b) of this section, with respect to the Texas SO
§ 97.922 Submission of Texas SO2 Trading Program allowance transfers.
(a) An authorized account representative seeking recordation of a Texas SO
(b) A Texas SO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each Texas SO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each Texas SO
§ 97.923 Recordation of Texas SO2 Trading Program allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a Texas SO
(b) A Texas SO
(c) Where a Texas SO
(d) Within 5 business days of recordation of a Texas SO
(e) Within 10 business days of receipt of a Texas SO
(1) A decision not to record the transfer, and
(2) The reasons for such non-recordation.
§ 97.924 Compliance with Texas SO2 Trading Program emissions limitations.
(a) Availability for deduction for compliance. Texas SO
(1) Were allocated for such control period or a control period in a prior year; and
(2) Are held in the source’s compliance account as of the allowance transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance with § 97.923, of Texas SO
(1) Until the amount of Texas SO
(2) If there are insufficient Texas SO
(c) Selection of Texas SO
(2) First-in, first-out. The Administrator will deduct Texas SO
(i) Any Texas SO
(ii) Any other Texas SO
(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in which the Texas SO
(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and (d) of this section.
§ 97.925 Compliance with Texas SO2 Trading Program assurance provisions.
(a) Availability for deduction. Texas SO
(1) Were allocated for a control period in a prior year or the control period in the given year or in the immediately following year; and
(2) Are held in the assurance account, established by the Administrator for such owners and operators of such group of Texas SO
(b) Deductions for compliance. The Administrator will deduct Texas SO
(1) By August 1, 2022 and August 1 of each year thereafter, the Administrator will:
(i) Calculate the total SO
(ii) If the results of the calculations required in paragraph (b)(1)(i) of this section indicate that total SO
(A) Calculate, for such control period and each common designated representative for such control period for a group of one or more Texas SO
(B) Promulgate a notice of data availability of the results of the calculations required in paragraphs (b)(1)(i) and (b)(1)(ii)(A) of this section, including separate calculations of the SO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice of data availability required in paragraph (b)(1)(ii) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations referenced in such notice are in accordance with § 97.906(c)(2)(iii), §§ 97.906(b) and 97.930 through 97.935, the definitions of “common designated representative”, “common designated representative’s assurance level”, and “common designated representative’s share” in § 97.902, and the calculation formula in § 97.906(c)(2)(i).
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By October 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) The Administrator will establish one assurance account for each set of owners and operators referenced, in each notice of data availability required under paragraph (b)(2)(ii) of this section, as all of the owners and operators of a group of Texas SO
(4)(i) As of midnight of November 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section, the owners and operators described in paragraph (b)(3) of this section shall hold in the assurance account established for them and for the appropriate Texas SO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(4)(i) of this section, if November 1 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section and after the recordation, in accordance with § 97.923, of Texas SO
(6) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notice of data availability required in paragraph (b)(2)(ii) of this section for a control period in a given year, of any data used in making the calculations referenced in such notice, the amounts of Texas SO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of Texas SO
(ii) [Reserved]
(iii) If the revised data are used to recalculate, in accordance with paragraph (b)(6)(i) of this section, the amount of Texas SO
(A) Where the amount of Texas SO
(B) For the owners and operators for which the amount of Texas SO
(C) Each Texas SO
§ 97.926 Banking.
(a) A Texas SO
(b) Any Texas SO
§ 97.927 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
§ 97.928 Administrator’s action on submissions.
(a) The Administrator may review and conduct independent audits concerning any submission under the Texas SO
(b) The Administrator may deduct Texas SO
§ 97.929 [Reserved]
§ 97.930 General monitoring, recordkeeping, and reporting requirements.
The owners and operators, and to the extent applicable, the designated representative, of a Texas SO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each Texas SO
(1) Install all monitoring systems required under this subpart for monitoring SO
(2) Successfully complete all certification tests required under § 97.931 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator of a Texas SO
(1) [Reserved]
(2) [Reserved]
(3) The owner or operator of a Texas SO
(i) Such requirements shall apply to the monitoring systems required under § 97.930 through § 97.935, rather than the monitoring systems required under part 75 of this chapter;
(ii) SO
(iii) Any petition for another procedure under § 75.4(e)(2) of this chapter shall be submitted under § 97.935, rather than § 75.66 of this chapter.
(c) Reporting data. The owner or operator of a Texas SO
(d) Prohibitions. (1) No owner or operator of a Texas SO
(2) No owner or operator of a Texas SO
(3) No owner or operator of a Texas SO
(4) No owner or operator of a Texas SO
(i) During the period that the unit is covered by an exemption under § 97.905 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.931(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a Texas SO
§ 97.931 Initial monitoring system certification and recertification procedures.
(a) The owner or operator of a Texas SO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B and D to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.930(a)(1) that is exempt from initial certification requirements under paragraph (a) of this section.
(c) [Reserved]
(d) Except as provided in paragraph (a) of this section, the owner or operator of a Texas SO
(1) Requirements for initial certification. The owner or operator shall ensure that each continuous monitoring system under § 97.930(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.930(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.930(a)(1) that may significantly affect the ability of the system to accurately measure or record SO
(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.930(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in § 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words “certification” and “initial certification” are replaced by the word “recertification” and the word “certified” is replaced by the word “recertified”.
(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office and the Administrator written notice of the dates of certification testing, in accordance with § 97.933.
(ii) Certification application. The designated representative shall submit to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the Texas SO
(iv) Certification application approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the Texas SO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.932(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved SO
(2) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(3) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
§ 97.932 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D of, or appendix D to, part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.931 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the Administrator or any State or permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 97.931 for each disapproved monitoring system.
§ 97.933 Notifications concerning monitoring.
The designated representative of a Texas SO
§ 97.934 Recordkeeping and reporting.
(a) General provisions. The designated representative of a Texas SO
(b) Monitoring plans. The owner or operator of a Texas SO
(c) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all initial certification or recertification tests required under § 97.931, including the information required under § 75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit quarterly reports, as follows:
(1) The designated representative shall report the SO
(2) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.64 of this chapter.
(3) For Texas SO
(4) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(2) of this section.
(e) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications; and
(2) For a unit with add-on SO
§ 97.935 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements.
(a) The designated representative of a Texas SO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(1) Identification of each unit and source covered by the petition;
(2) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used in the proposed alternative;
(4) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be de minimis; and
(5) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
Subpart GGGGG – CSAPR NOX Ozone Season Group 3 Trading Program
§ 97.1001 Purpose.
This subpart sets forth the general, designated representative, allowance, and monitoring provisions for the Cross-State Air Pollution Rule (CSAPR) NO
§ 97.1002 Definitions.
The terms used in this subpart shall have the meanings set forth in this section as follows, provided that any term that includes the acronym “CSAPR” shall be considered synonymous with a term that is used in a SIP revision approved by the Administrator under § 52.38 or § 52.39 of this chapter and that is substantively identical except for the inclusion of the acronym “TR” in place of the acronym “CSAPR”:
Acid Rain Program means a multi-state SO
Administrator means the Administrator of the United States Environmental Protection Agency or the Director of the Clean Air Markets Division (or its successor determined by the Administrator) of the United States Environmental Protection Agency, the Administrator’s duly authorized representative under this subpart.
Allocate or allocation means, with regard to CSAPR NO
(1) A CSAPR NO
(2) A new unit set-aside;
(3) An Indian country new unit set-aside; or
(4) An entity not listed in paragraphs (1) through (3) of this definition;
(5) Provided that, if the Administrator, State, or permitting authority initially credits, to a CSAPR NO
Allowance Management System means the system by which the Administrator records allocations, auctions, transfers, and deductions of CSAPR NO
Allowance Management System account means an account in the Allowance Management System established by the Administrator for purposes of recording the allocation, auction, holding, transfer, or deduction of CSAPR NO
Allowance transfer deadline means, for a control period in a given year, midnight of June 1 immediately after such control period (or if such June 1 is not a business day, midnight of the first business day thereafter) and is the deadline by which a CSAPR NO
Alternate designated representative means, for a CSAPR NO
Assurance account means an Allowance Management System account, established by the Administrator under § 97.1025(b)(3) for certain owners and operators of a group of one or more base CSAPR NO
Auction means, with regard to CSAPR NO
Authorized account representative means, for a general account, the natural person who is authorized, in accordance with this subpart, to transfer and otherwise dispose of CSAPR NO
Automated data acquisition and handling system or DAHS means the component of the continuous emission monitoring system, or other emissions monitoring system approved for use under this subpart, designed to interpret and convert individual output signals from pollutant concentration monitors, flow monitors, diluent gas monitors, and other component parts of the monitoring system to produce a continuous record of the measured parameters in the measurement units required by this subpart.
Base CSAPR NO
Base CSAPR NO
Biomass means –
(1) Any organic material grown for the purpose of being converted to energy;
(2) Any organic byproduct of agriculture that can be converted into energy; or
(3) Any material that can be converted into energy and is nonmerchantable for other purposes, that is segregated from other material that is nonmerchantable for other purposes, and that is:
(i) A forest-related organic resource, including mill residues, precommercial thinnings, slash, brush, or byproduct from conversion of trees to merchantable material; or
(ii) A wood material, including pallets, crates, dunnage, manufacturing and construction materials (other than pressure-treated, chemically-treated, or painted wood products), and landscape or right-of-way tree trimmings.
Boiler means an enclosed fossil- or other-fuel-fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.
Bottoming-cycle unit means a unit in which the energy input to the unit is first used to produce useful thermal energy, where at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.
Business day means a day that does not fall on a weekend or a federal holiday.
Certifying official means a natural person who is:
(1) For a corporation, a president, secretary, treasurer, or vice-president of the corporation in charge of a principal business function or any other person who performs similar policy- or decision-making functions for the corporation;
(2) For a partnership or sole proprietorship, a general partner or the proprietor respectively; or
(3) For a local government entity or State, federal, or other public agency, a principal executive officer or ranking elected official.
Clean Air Act means the Clean Air Act, 42 U.S.C. 7401, et seq.
Coal means “coal” as defined in § 72.2 of this chapter.
Cogeneration system means an integrated group, at a source, of equipment (including a boiler, or combustion turbine, and a generator) designed to produce useful thermal energy for industrial, commercial, heating, or cooling purposes and electricity through the sequential use of energy.
Cogeneration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a topping-cycle unit or a bottoming-cycle unit:
(1) Operating as part of a cogeneration system; and
(2) Producing on an annual average basis –
(i) For a topping-cycle unit,
(A) Useful thermal energy not less than 5 percent of total energy output; and
(B) Useful power that, when added to one-half of useful thermal energy produced, is not less than 42.5 percent of total energy input, if useful thermal energy produced is 15 percent or more of total energy output, or not less than 45 percent of total energy input, if useful thermal energy produced is less than 15 percent of total energy output; or
(ii) For a bottoming-cycle unit, useful power not less than 45 percent of total energy input;
(3) Provided that the requirements in paragraph (2) of this definition shall not apply to a calendar year referenced in paragraph (2) of this definition during which the unit did not operate at all;
(4) Provided that the total energy input under paragraphs (2)(i)(B) and (2)(ii) of this definition shall equal the unit’s total energy input from all fuel, except biomass if the unit is a boiler; and
(5) Provided that, if, throughout its operation during the 12-month period or a calendar year referenced in paragraph (2) of this definition, a unit is operated as part of a cogeneration system and the cogeneration system meets on a system-wide basis the requirement in paragraph (2)(i)(B) or (2)(ii) of this definition, the unit shall be deemed to meet such requirement during that 12-month period or calendar year.
Combustion turbine means an enclosed device comprising:
(1) If the device is simple cycle, a compressor, a combustor, and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine, rotating the turbine; and
(2) If the device is combined cycle, the equipment described in paragraph (1) of this definition and any associated duct burner, heat recovery steam generator, and steam turbine.
Commence commercial operation means, with regard to a unit:
(1) To have begun to produce steam, gas, or other heated medium used to generate electricity for sale or use, including test generation, except as provided in § 97.1005.
(i) For a unit that is a CSAPR NO
(ii) For a unit that is a CSAPR NO
(2) Notwithstanding paragraph (1) of this definition and except as provided in § 97.1005, for a unit that is not a CSAPR NO
(i) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that subsequently undergoes a physical change or is moved to a different location or source, such date shall remain the date of commencement of commercial operation of the unit, which shall continue to be treated as the same unit.
(ii) For a unit with a date for commencement of commercial operation as defined in the introductory text of paragraph (2) of this definition and that is subsequently replaced by a unit at the same or a different source, such date shall remain the replaced unit’s date of commencement of commercial operation, and the replacement unit shall be treated as a separate unit with a separate date for commencement of commercial operation as defined in paragraph (1) or (2) of this definition as appropriate.
Common designated representative means, with regard to a control period in a given year, a designated representative where, as of July 1 immediately after the allowance transfer deadline for such control period, the same natural person is authorized under §§ 97.1013(a) and 97.1015(a) as the designated representative for a group of one or more base CSAPR NO
Common designated representative’s assurance level means, with regard to a specific common designated representative and a State (and Indian country within the borders of such State) and control period in a given year for which the State assurance level is exceeded as described in § 97.1006(c)(2)(iii):
(1) The amount (rounded to the nearest allowance) equal to the sum of the total amount of CSAPR NO
(2) Provided that –
(i) The allocations of CSAPR NO
(ii) For purposes of this definition for the control period in 2021 only, for each State the amount of the State NO
Common designated representative’s share means, with regard to a specific common designated representative for a control period in a given year and a total amount of NO
Common stack means a single flue through which emissions from 2 or more units are exhausted.
Compliance account means an Allowance Management System account, established by the Administrator for a CSAPR NO
Continuous emission monitoring system or CEMS means the equipment required under this subpart to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes and using an automated data acquisition and handling system (DAHS), a permanent record of NO
(1) A flow monitoring system, consisting of a stack flow rate monitor and an automated data acquisition and handling system and providing a permanent, continuous record of stack gas volumetric flow rate, in standard cubic feet per hour (scfh);
(2) A NO
(3) A NO
(4) A moisture monitoring system, as defined in § 75.11(b)(2) of this chapter and providing a permanent, continuous record of the stack gas moisture content, in percent H
(5) A CO
(6) An O
Control period means the period starting May 1 of a calendar year, except as provided in § 97.1006(c)(3), and ending on September 30 of the same year, inclusive.
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
(1) Have been recorded by the Administrator in the account or transferred into the account by a correctly submitted, but not yet recorded, CSAPR NO
(2) Have not been transferred out of the account by a correctly submitted, but not yet recorded, CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR NO
CSAPR SO
Designated representative means, for a CSAPR NO
Emissions means air pollutants exhausted from a unit or source into the atmosphere, as measured, recorded, and reported to the Administrator by the designated representative, and as modified by the Administrator:
(1) In accordance with this subpart; and
(2) With regard to a period before the unit or source is required to measure, record, and report such air pollutants in accordance with this subpart, in accordance with part 75 of this chapter.
Excess emissions means any ton of emissions from the CSAPR NO
Fossil fuel means –
(1) Natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material; or
(2) For purposes of applying the limitation on “average annual fuel consumption of fossil fuel” in § 97.1004(b)(2)(i)(B) and (b)(2)(ii), natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material for the purpose of creating useful heat.
Fossil-fuel-fired means, with regard to a unit, combusting any amount of fossil fuel in 2005 or any calendar year thereafter.
General account means an Allowance Management System account, established under this subpart, that is not a compliance account or an assurance account.
Generator means a device that produces electricity.
Heat input means, for a unit for a specified period of unit operating time, the product (in mmBtu) of the gross calorific value of the fuel (in mmBtu/lb) fed into the unit multiplied by the fuel feed rate (in lb of fuel/time) and unit operating time, as measured, recorded, and reported to the Administrator by the designated representative and as modified by the Administrator in accordance with this subpart and excluding the heat derived from preheated combustion air, recirculated flue gases, or exhaust.
Heat input rate means, for a unit, the quotient (in mmBtu/hr) of the amount of heat input for a specified period of unit operating time (in mmBtu) divided by unit operating time (in hr) or, for a unit and a specific fuel, the amount of heat input attributed to the fuel (in mmBtu) divided by the unit operating time (in hr) during which the unit combusts the fuel.
Indian country means “Indian country” as defined in 18 U.S.C. 1151.
Life-of-the-unit, firm power contractual arrangement means a unit participation power sales agreement under which a utility or industrial customer reserves, or is entitled to receive, a specified amount or percentage of nameplate capacity and associated energy generated by any specified unit and pays its proportional amount of such unit’s total costs, pursuant to a contract:
(1) For the life of the unit;
(2) For a cumulative term of no less than 30 years, including contracts that permit an election for early termination; or
(3) For a period no less than 25 years or 70 percent of the economic useful life of the unit determined as of the time the unit is built, with option rights to purchase or release some portion of the nameplate capacity and associated energy generated by the unit at the end of the period.
Maximum design heat input rate means, for a unit, the maximum amount of fuel per hour (in Btu/hr) that the unit is capable of combusting on a steady state basis as of the initial installation of the unit as specified by the manufacturer of the unit.
Monitoring system means any monitoring system that meets the requirements of this subpart, including a continuous emission monitoring system, an alternative monitoring system, or an excepted monitoring system under part 75 of this chapter.
Nameplate capacity means, starting from the initial installation of a generator, the maximum electrical generating output (in MWe, rounded to the nearest tenth) that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings) as of such installation as specified by the manufacturer of the generator or, starting from the completion of any subsequent physical change in the generator resulting in an increase in the maximum electrical generating output that the generator is capable of producing on a steady state basis and during continuous operation (when not restricted by seasonal or other deratings), such increased maximum amount (in MWe, rounded to the nearest tenth) as of such completion as specified by the person conducting the physical change.
Natural gas means “natural gas” as defined in § 72.2 of this chapter.
Newly affected CSAPR NO
Nitrogen oxides means all oxides of nitrogen except nitrous oxide (N
Operate or operation means, with regard to a unit, to combust fuel.
Operator means, for a CSAPR NO
Owner means, for a CSAPR NO
(1) Any holder of any portion of the legal or equitable title in a CSAPR NO
(2) Any holder of a leasehold interest in a CSAPR NO
(3) Any purchaser of power from a CSAPR NO
Permanently retired means, with regard to a unit, a unit that is unavailable for service and that the unit’s owners and operators do not expect to return to service in the future.
Permitting authority means “permitting authority” as defined in §§ 70.2 and 71.2 of this chapter.
Potential electrical output capacity means, for a unit (in MWh/yr), 33 percent of the unit’s maximum design heat input rate (in Btu/hr), divided by 3,413 Btu/kWh, divided by 1,000 kWh/MWh, and multiplied by 8,760 hr/yr.
Receive or receipt of means, when referring to the Administrator, to come into possession of a document, information, or correspondence (whether sent in hard copy or by authorized electronic transmission), as indicated in an official log, or by a notation made on the document, information, or correspondence, by the Administrator in the regular course of business.
Recordation, record, or recorded means, with regard to CSAPR NO
Reference method means any direct test method of sampling and analyzing for an air pollutant as specified in § 75.22 of this chapter.
Replacement, replace, or replaced means, with regard to a unit, the demolishing of a unit, or the permanent retirement and permanent disabling of a unit, and the construction of another unit (the replacement unit) to be used instead of the demolished or retired unit (the replaced unit).
Sequential use of energy means:
(1) The use of reject heat from electricity production in a useful thermal energy application or process; or
(2) The use of reject heat from a useful thermal energy application or process in electricity production.
Serial number means, for a CSAPR NO
Solid waste incineration unit means a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine that is a “solid waste incineration unit” as defined in section 129(g)(1) of the Clean Air Act.
Source means all buildings, structures, or installations located in one or more contiguous or adjacent properties under common control of the same person or persons. This definition does not change or otherwise affect the definition of “major source”, “stationary source”, or “source” as set forth and implemented in a title V operating permit program or any other program under the Clean Air Act.
State means one of the States that is subject to the CSAPR NO
Submit or serve means to send or transmit a document, information, or correspondence to the person specified in accordance with the applicable regulation:
(1) In person;
(2) By United States Postal Service; or
(3) By other means of dispatch or transmission and delivery;
(4) Provided that compliance with any “submission” or “service” deadline shall be determined by the date of dispatch, transmission, or mailing and not the date of receipt.
Topping-cycle unit means a unit in which the energy input to the unit is first used to produce useful power, including electricity, where at least some of the reject heat from the electricity production is then used to provide useful thermal energy.
Total energy input means, for a unit, total energy of all forms supplied to the unit, excluding energy produced by the unit. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:
Total energy output means, for a unit, the sum of useful power and useful thermal energy produced by the unit.
Unit means a stationary, fossil-fuel-fired boiler, stationary, fossil-fuel-fired combustion turbine, or other stationary, fossil-fuel-fired combustion device. A unit that undergoes a physical change or is moved to a different location or source shall continue to be treated as the same unit. A unit (the replaced unit) that is replaced by another unit (the replacement unit) at the same or a different source shall continue to be treated as the same unit, and the replacement unit shall be treated as a separate unit.
Unit operating day means, with regard to a unit, a calendar day in which the unit combusts any fuel.
Unit operating hour or hour of unit operation means, with regard to a unit, an hour in which the unit combusts any fuel.
Useful power means, with regard to a unit, electricity or mechanical energy that the unit makes available for use, excluding any such energy used in the power production process (which process includes, but is not limited to, any on-site processing or treatment of fuel combusted at the unit and any on-site emission controls).
Useful thermal energy means thermal energy that is:
(1) Made available to an industrial or commercial process (not a power production process), excluding any heat contained in condensate return or makeup water;
(2) Used in a heating application (e.g., space heating or domestic hot water heating); or
(3) Used in a space cooling application (i.e., in an absorption chiller).
Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.
§ 97.1003 Measurements, abbreviations, and acronyms.
Measurements, abbreviations, and acronyms used in this subpart are defined as follows:
§ 97.1004 Applicability.
(a) Except as provided in paragraph (b) of this section:
(1) The following units in a State (and Indian country within the borders of such State) shall be CSAPR NO
(2) If a stationary boiler or stationary combustion turbine that, under paragraph (a)(1) of this section, is not a CSAPR NO
(b) Any unit in a State (and Indian country within the borders of such State) that otherwise is a CSAPR NO
(1)(i) Any unit:
(A) Qualifying as a cogeneration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a cogeneration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) Not supplying in 2005 or any calendar year thereafter more than one-third of the unit’s potential electrical output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale.
(ii) If, after qualifying under paragraph (b)(1)(i) of this section as not being a CSAPR NO
(2)(i) Any unit:
(A) Qualifying as a solid waste incineration unit throughout the later of 2005 or the 12-month period starting on the date the unit first produces electricity and continuing to qualify as a solid waste incineration unit throughout each calendar year ending after the later of 2005 or such 12-month period; and
(B) With an average annual fuel consumption of fossil fuel for the first 3 consecutive calendar years of operation starting no earlier than 2005 of less than 20 percent (on a Btu basis) and an average annual fuel consumption of fossil fuel for any 3 consecutive calendar years thereafter of less than 20 percent (on a Btu basis).
(ii) If, after qualifying under paragraph (b)(2)(i) of this section as not being a CSAPR NO
(c) A certifying official of an owner or operator of any unit or other equipment may submit a petition (including any supporting documents) to the Administrator at any time for a determination concerning the applicability, under paragraphs (a) and (b) of this section or a SIP revision approved under § 52.38(b)(11) or (12) of this chapter, of the CSAPR NO
(1) Petition content. The petition shall be in writing and include the identification of the unit or other equipment and the relevant facts about the unit or other equipment. The petition and any other documents provided to the Administrator in connection with the petition shall include the following certification statement, signed by the certifying official: “I am authorized to make this submission on behalf of the owners and operators of the unit or other equipment for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) Response. The Administrator will issue a written response to the petition and may request supplemental information determined by the Administrator to be relevant to such petition. The Administrator’s determination concerning the applicability, under paragraphs (a) and (b) of this section, of the CSAPR NO
§ 97.1005 Retired unit exemption.
(a)(1) Any CSAPR NO
(2) The exemption under paragraph (a)(1) of this section shall become effective the day on which the CSAPR NO
(b)(1) A unit exempt under paragraph (a) of this section shall not emit any NO
(2) For a period of 5 years from the date the records are created, the owners and operators of a unit exempt under paragraph (a) of this section shall retain, at the source that includes the unit, records demonstrating that the unit is permanently retired. The 5-year period for keeping records may be extended for cause, at any time before the end of the period, in writing by the Administrator. The owners and operators bear the burden of proof that the unit is permanently retired.
(3) The owners and operators and, to the extent applicable, the designated representative of a unit exempt under paragraph (a) of this section shall comply with the requirements of the CSAPR NO
(4) A unit exempt under paragraph (a) of this section shall lose its exemption on the first date on which the unit resumes operation. Such unit shall be treated, for purposes of applying allocation, monitoring, reporting, and recordkeeping requirements under this subpart, as a unit that commences commercial operation on the first date on which the unit resumes operation.
§ 97.1006 Standard requirements.
(a) Designated representative requirements. The owners and operators shall comply with the requirement to have a designated representative, and may have an alternate designated representative, in accordance with §§ 97.1013 through 97.1018.
(b) Emissions monitoring, reporting, and recordkeeping requirements. (1) The owners and operators, and the designated representative, of each CSAPR NO
(2) The emissions data determined in accordance with §§ 97.1030 through 97.1035 shall be used to calculate allocations of CSAPR NO
(c) NO
(ii) If total NO
(A) The owners and operators of the source and each CSAPR NO
(B) The owners and operators of the source and each CSAPR NO
(2) CSAPR NO
(A) The quotient of the amount by which the common designated representative’s share of such NO
(B) The amount by which total NO
(ii) The owners and operators shall hold the CSAPR NO
(iii) Total NO
(iv) It shall not be a violation of this subpart or of the Clean Air Act if total NO
(v) To the extent the owners and operators fail to hold CSAPR NO
(A) The owners and operators shall pay any fine, penalty, or assessment or comply with any other remedy imposed under the Clean Air Act; and
(B) Each CSAPR NO
(3) Compliance periods. (i) A CSAPR NO
(ii) A base CSAPR NO
(4) Vintage of CSAPR NO
(ii) A CSAPR NO
(5) Allowance Management System requirements. Each CSAPR NO
(6) Limited authorization. A CSAPR NO
(i) Such authorization shall only be used in accordance with the CSAPR NO
(ii) Notwithstanding any other provision of this subpart, the Administrator has the authority to terminate or limit the use and duration of such authorization to the extent the Administrator determines is necessary or appropriate to implement any provision of the Clean Air Act.
(7) Property right. A CSAPR NO
(d) Title V permit requirements. (1) No title V permit revision shall be required for any allocation, holding, deduction, or transfer of CSAPR NO
(2) A description of whether a unit is required to monitor and report NO
(e) Additional recordkeeping and reporting requirements. (1) Unless otherwise provided, the owners and operators of each CSAPR NO
(i) The certificate of representation under § 97.1016 for the designated representative for the source and each CSAPR NO
(ii) All emissions monitoring information, in accordance with this subpart.
(iii) Copies of all reports, compliance certifications, and other submissions and all records made or required under, or to demonstrate compliance with the requirements of, the CSAPR NO
(2) The designated representative of a CSAPR NO
(f) Liability. (1) Any provision of the CSAPR NO
(2) Any provision of the CSAPR NO
(g) Effect on other authorities. No provision of the CSAPR NO
§ 97.1007 Computation of time.
(a) Unless otherwise stated, any time period scheduled, under the CSAPR NO
(b) Unless otherwise stated, any time period scheduled, under the CSAPR NO
(c) Unless otherwise stated, if the final day of any time period, under the CSAPR NO
§ 97.1008 Administrative appeal procedures.
The administrative appeal procedures for decisions of the Administrator under the CSAPR NO
§ 97.1009 [Reserved]
§ 97.1010 State NOX Ozone Season Group 3 trading budgets, new unit set-asides, Indian country new unit set-asides, and variability limits.
(a) The State NO
Table 1 to Paragraph (
[Tons]
State | 2021 | 2022 | 2023 | 2024 and thereafter |
---|---|---|---|---|
Illinois | 9,102 | 9,102 | 8,179 | 8,059 |
Indiana | 13,051 | 12,582 | 12,553 | 9,564 |
Kentucky | 15,300 | 14,051 | 14,051 | 14,051 |
Louisiana | 14,818 | 14,818 | 14,818 | 14,818 |
Maryland | 1,499 | 1,266 | 1,266 | 1,348 |
Michigan | 12,727 | 12,290 | 9,975 | 9,786 |
New Jersey | 1,253 | 1,253 | 1,253 | 1,253 |
New York | 3,416 | 3,416 | 3,421 | 3,403 |
Ohio | 9,690 | 9,773 | 9,773 | 9,773 |
Pennsylvania | 8,379 | 8,373 | 8,373 | 8,373 |
Virginia | 4,516 | 3,897 | 3,980 | 3,663 |
West Virginia | 13,334 | 12,884 | 12,884 | 12,884 |
Table 2 to Paragraph (
[Tons]
State | 2021 | 2022 | 2023 | 2024 and thereafter |
---|---|---|---|---|
Illinois | 265 | 265 | 248 | 244 |
Indiana | 262 | 254 | 249 | 190 |
Kentucky | 309 | 283 | 283 | 283 |
Louisiana | 430 | 430 | 430 | 430 |
Maryland | 135 | 115 | 115 | 122 |
Michigan | 500 | 482 | 388 | 382 |
New Jersey | 27 | 27 | 27 | 27 |
New York | 168 | 168 | 168 | 167 |
Ohio | 291 | 290 | 290 | 290 |
Pennsylvania | 335 | 339 | 339 | 339 |
Virginia | 185 | 161 | 166 | 150 |
West Virginia | 266 | 261 | 261 | 261 |
Table 3 to Paragraph (
[Tons]
State | 2021 | 2022 | 2023 | 2024 and thereafter |
---|---|---|---|---|
Illinois | ||||
Indiana | ||||
Kentucky | ||||
Louisiana | 15 | 15 | 15 | 15 |
Maryland | ||||
Michigan | 13 | 12 | 10 | 10 |
New Jersey | ||||
New York | 3 | 3 | 3 | 3 |
Ohio | ||||
Pennsylvania | ||||
Virginia | ||||
West Virginia |
(b) The States’ variability limits for the State NO
Table 4 to Paragraph (
[Tons]
State | 2021 | 2022 | 2023 | 2024 and thereafter |
---|---|---|---|---|
Illinois | 1,911 | 1,911 | 1,718 | 1,692 |
Indiana | 2,741 | 2,642 | 2,636 | 2,008 |
Kentucky | 3,213 | 2,951 | 2,951 | 2,951 |
Louisiana | 3,112 | 3,112 | 3,112 | 3,112 |
Maryland | 315 | 266 | 266 | 283 |
Michigan | 2,673 | 2,581 | 2,095 | 2,055 |
New Jersey | 263 | 263 | 263 | 263 |
New York | 717 | 717 | 718 | 715 |
Ohio | 2,035 | 2,052 | 2,052 | 2,052 |
Pennsylvania | 1,760 | 1,758 | 1,758 | 1,758 |
Virginia | 948 | 818 | 836 | 769 |
West Virginia | 2,800 | 2,706 | 2,706 | 2,706 |
(c) Each State NO
(d) For the control period in 2021 only, the Administrator will determine for each State a supplemental amount of CSAPR NO
§ 97.1011 Timing requirements for CSAPR NOX Ozone Season Group 3 allowance allocations.
(a) Existing units. (1) CSAPR NO
(2) Notwithstanding paragraph (a)(1) of this section, if a unit provided an allocation in the notice of data availability issued under paragraph (a)(1) of this section does not operate, starting after 2020, during the control period in two consecutive years, such unit will not be allocated the CSAPR NO
(b) New units – (1) New unit set-asides. (i) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR NO
(ii) For each notice of data availability required in paragraph (b)(1)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(1)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR NO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(1)(i) of this section. By May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(1)(i) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(1)(ii)(A) of this section.
(iii) [Reserved]
(iv) [Reserved]
(v) To the extent any CSAPR NO
(2) Indian country new unit set-asides. (i) By March 1, 2022 and March 1 of each year thereafter, the Administrator will calculate the CSAPR NO
(ii) For each notice of data availability required in paragraph (b)(2)(i) of this section, the Administrator will provide an opportunity for submission of objections to the calculations referenced in such notice.
(A) Objections shall be submitted by the deadline specified in each notice of data availability required in paragraph (b)(2)(i) of this section and shall be limited to addressing whether the calculations (including the identification of the CSAPR NO
(B) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By May 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(i) of this section, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(ii)(A) of this section.
(iii) [Reserved]
(iv) [Reserved]
(v) To the extent any CSAPR NO
(c) Units incorrectly allocated CSAPR NO
(i)(A) The recipient is not actually a CSAPR NO
(B) The recipient is not located as of May 1 of the control period in the State from whose NO
(ii) The recipient is not actually a CSAPR NO
(2) Except as provided in paragraph (c)(3) or (4) of this section, the Administrator will not record such CSAPR NO
(3) If the Administrator already recorded such CSAPR NO
(4) If the Administrator already recorded such CSAPR NO
(5)(i) With regard to the CSAPR NO
(A) Transfer such CSAPR NO
(B) If the State has a SIP revision approved under § 52.38(b)(11) or (12) of this chapter covering such control period, include such CSAPR NO
(ii) With regard to the CSAPR NO
(A) Transfer such CSAPR NO
(B) If the State has a SIP revision approved under § 52.38(b)(11) or (12) of this chapter covering such control period, include such CSAPR NO
(iii) With regard to the CSAPR NO
§ 97.1012 CSAPR NOX Ozone Season Group 3 allowance allocations to new units.
(a) Allocations from new unit set-asides. For each control period in 2021 and thereafter and for the CSAPR NO
(1) The CSAPR NO
(i) CSAPR NO
(ii) CSAPR NO
(iii) CSAPR NO
(iv) [Reserved]
(2) The Administrator will establish a separate new unit set-aside for the State for each such control period. Each such new unit set-aside will be allocated CSAPR NO
(3) The Administrator will determine, for each CSAPR NO
(i) The control period in 2021;
(ii) The control period containing the deadline for certification of the CSAPR NO
(iii) For a unit described in paragraph (a)(1)(ii) of this section, the first control period in which the CSAPR NO
(iv) For a unit described in paragraph (a)(1)(iii) of this section, the control period in which the unit resumes operation.
(4)(i) The allocation to each CSAPR NO
(ii) The Administrator will adjust the allocation amount in paragraph (a)(4)(i) of this section in accordance with paragraphs (a)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR NO
(6) If the amount of CSAPR NO
(7) If the amount of CSAPR NO
(8)-(9) [Reserved]
(10) If, after completion of the procedures under paragraphs (a)(2) through (7) and (12) of this section for a control period, any unallocated CSAPR NO
(11) The Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.1011(b)(1)(i), (ii), and (v), of the amount of CSAPR NO
(12) Notwithstanding the requirements of paragraphs (a)(2) through (11) of this section, if the calculations of allocations from a new unit set-aside for a control period in a given year under paragraph (a)(7) of this section or paragraphs (a)(6) and (10) of this section would otherwise result in total allocations from such new unit set-aside unequal to the total amount of such new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR NO
(b) Allocations from Indian country new unit set-asides. For each control period in 2021 and thereafter and for the CSAPR NO
(1) The CSAPR NO
(i) CSAPR NO
(ii) [Reserved]
(2) The Administrator will establish a separate Indian country new unit set-aside for the State for each such control period. Each such Indian country new unit set-aside will be allocated CSAPR NO
(3) The Administrator will determine, for each CSAPR NO
(i) The control period in 2021; and
(ii) The control period containing the deadline for certification of the CSAPR NO
(4)(i) The allocation to each CSAPR NO
(ii) The Administrator will adjust the allocation amount in paragraph (b)(4)(i) of this section in accordance with paragraphs (b)(5) through (7) and (12) of this section.
(5) The Administrator will calculate the sum of the allocation amounts of CSAPR NO
(6) If the amount of CSAPR NO
(7) If the amount of CSAPR NO
(8) [Reserved]
(9) [Reserved]
(10) If, after completion of the procedures under paragraphs (b)(2) through (7) and (12) of this section for a control period, any unallocated CSAPR NO
(i) Transfer such unallocated CSAPR NO
(ii) If the State has a SIP revision approved under § 52.38(b)(11) or (12) of this chapter covering such control period, include such unallocated CSAPR NO
(11) The Administrator will notify the public, through the promulgation of the notices of data availability described in § 97.1011(b)(2)(i), (ii), and (v), of the amount of CSAPR NO
(12) Notwithstanding the requirements of paragraphs (b)(2) through (11) of this section, if the calculations of allocations from an Indian country new unit set-aside for a control period in a given year under paragraph (b)(7) of this section would otherwise result in total allocations from such Indian country new unit set-aside unequal to the total amount of such Indian country new unit set-aside, then the Administrator will adjust the results of such calculations as follows. The Administrator will list the CSAPR NO
§ 97.1013 Authorization of designated representative and alternate designated representative.
(a) Except as provided under § 97.1015, each CSAPR NO
(1) The designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.1016:
(i) The designated representative shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of the source and each CSAPR NO
(ii) The owners and operators of the source and each CSAPR NO
(b) Except as provided under § 97.1015, each CSAPR NO
(1) The alternate designated representative shall be selected by an agreement binding on the owners and operators of the source and all CSAPR NO
(2) Upon and after receipt by the Administrator of a complete certificate of representation under § 97.1016:
(i) The alternate designated representative shall be authorized;
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative; and
(iii) The owners and operators of the source and each CSAPR NO
(c) Except in this section, § 97.1002, and §§ 97.1014 through 97.1018, whenever the term “designated representative” (as distinguished from the term “common designated representative”) is used in this subpart, the term shall be construed to include the designated representative or any alternate designated representative.
§ 97.1014 Responsibilities of designated representative and alternate designated representative.
(a) Except as provided under § 97.1018 concerning delegation of authority to make submissions, each submission under the CSAPR NO
(b) The Administrator will accept or act on a submission made for a CSAPR NO
§ 97.1015 Changing designated representative and alternate designated representative; changes in owners and operators; changes in units at the source.
(a) Changing designated representative. The designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.1016. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new designated representative and the owners and operators of the CSAPR NO
(b) Changing alternate designated representative. The alternate designated representative may be changed at any time upon receipt by the Administrator of a superseding complete certificate of representation under § 97.1016. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate designated representative before the time and date when the Administrator receives the superseding certificate of representation shall be binding on the new alternate designated representative, the designated representative, and the owners and operators of the CSAPR NO
(c) Changes in owners and operators. (1) In the event an owner or operator of a CSAPR NO
(2) Within 30 days after any change in the owners and operators of a CSAPR NO
(d) Changes in units at the source. Within 30 days of any change in which units are located at a CSAPR NO
(1) If the change is the addition of a unit that operated (other than for purposes of testing by the manufacturer before initial installation) before being located at the source, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity from whom the unit was purchased or otherwise obtained (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was purchased or otherwise obtained, and the date on which the unit became located at the source.
(2) If the change is the removal of a unit, then the certificate of representation shall identify, in a format prescribed by the Administrator, the entity to which the unit was sold or that otherwise obtained the unit (including name, address, telephone number, and facsimile number (if any)), the date on which the unit was sold or otherwise obtained, and the date on which the unit became no longer located at the source.
§ 97.1016 Certificate of representation.
(a) A complete certificate of representation for a designated representative or an alternate designated representative shall include the following elements in a format prescribed by the Administrator:
(1) Identification of the CSAPR NO
(2) The name, address, email address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative;
(3) A list of the owners and operators of the CSAPR NO
(4) The following certification statements by the designated representative and any alternate designated representative –
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the source and each CSAPR NO
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under the CSAPR NO
(iii) “Where there are multiple holders of a legal or equitable title to, or a leasehold interest in, a CSAPR NO
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(b) Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(c) A certificate of representation under this section, § 97.516, or § 97.816 that complies with the provisions of paragraph (a) of this section except that it contains the phrase “TR NO
§ 97.1017 Objections concerning designated representative and alternate designated representative.
(a) Once a complete certificate of representation under § 97.1016 has been submitted and received, the Administrator will rely on the certificate of representation unless and until a superseding complete certificate of representation under § 97.1016 is received by the Administrator.
(b) Except as provided in paragraph (a) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of a designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative or the finality of any decision or order by the Administrator under the CSAPR NO
(c) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative, including private legal disputes concerning the proceeds of CSAPR NO
§ 97.1018 Delegation by designated representative and alternate designated representative.
(a) A designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(b) An alternate designated representative may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(c) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (a) or (b) of this section, the designated representative or alternate designated representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(1) The name, address, email address, telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative;
(2) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(3) For each such natural person, a list of the type or types of electronic submissions under paragraph (a) or (b) of this section for which authority is delegated to him or her; and
(4) The following certification statements by such designated representative or alternate designated representative:
(i) “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.1018(d) shall be deemed to be an electronic submission by me.”; and
(ii) “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.1018(d), I agree to maintain an email account and to notify the Administrator immediately of any change in my email address unless all delegation of authority by me under 40 CFR 97.1018 is terminated.”
(d) A notice of delegation submitted under paragraph (c) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such designated representative or alternate designated representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(e) Any electronic submission covered by the certification in paragraph (c)(4)(i) of this section and made in accordance with a notice of delegation effective under paragraph (d) of this section shall be deemed to be an electronic submission by the designated representative or alternate designated representative submitting such notice of delegation.
(f) A notice of delegation submitted under paragraph (c) of this section, § 97.518(c), or § 97.818(c) that complies with the provisions of paragraph (c) of this section except that it contains the terms “40 CFR 97.518(d)” and “40 CFR 97.518” or the terms “40 CFR 97.818(d)” and “40 CFR 97.818” in place of the terms “40 CFR 97.1018(d)” and “40 CFR 97.1018”, respectively, in the required certification statements will be considered a valid notice of delegation submitted under paragraph (c) of this section, and the certification statements included in such notice of delegation will be interpreted for purposes of this subpart as if the terms “40 CFR 97.1018(d)” and “40 CFR 97.1018” appeared in place of the terms “40 CFR 97.518(d)” and “40 CFR 97.518” or the terms “40 CFR 97.818(d)” and “40 CFR 97.818”, respectively.
§ 97.1019 [Reserved]
§ 97.1020 Establishment of compliance accounts, assurance accounts, and general accounts.
(a) Compliance accounts. Upon receipt of a complete certificate of representation under § 97.1016, the Administrator will establish a compliance account for the CSAPR NO
(b) Assurance accounts. The Administrator will establish assurance accounts for certain owners and operators and States in accordance with § 97.1025(b)(3).
(c) General accounts – (1) Application for general account. (i) Any person may apply to open a general account, for the purpose of holding and transferring CSAPR NO
(A) The authorized account representative and alternate authorized account representative shall be selected by an agreement binding on the persons who have an ownership interest with respect to CSAPR NO
(B) The agreement by which the alternate authorized account representative is selected shall include a procedure for authorizing the alternate authorized account representative to act in lieu of the authorized account representative.
(ii) A complete application for a general account shall include the following elements in a format prescribed by the Administrator:
(A) Name, mailing address, email address (if any), telephone number, and facsimile transmission number (if any) of the authorized account representative and any alternate authorized account representative;
(B) An identifying name for the general account;
(C) A list of all persons subject to a binding agreement for the authorized account representative and any alternate authorized account representative to represent their ownership interest with respect to the CSAPR NO
(D) The following certification statement by the authorized account representative and any alternate authorized account representative: “I certify that I was selected as the authorized account representative or the alternate authorized account representative, as applicable, by an agreement that is binding on all persons who have an ownership interest with respect to CSAPR NO
(E) The signature of the authorized account representative and any alternate authorized account representative and the dates signed.
(iii) Unless otherwise required by the Administrator, documents of agreement referred to in the application for a general account shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(iv) An application for a general account under paragraph (c)(1) of this section, § 97.520(c)(1), or § 97.820(c)(1) that complies with the provisions of paragraph (c)(1) of this section except that it contains the phrase “TR NO
(2) Authorization of authorized account representative and alternate authorized account representative. (i) Upon receipt by the Administrator of a complete application for a general account under paragraph (c)(1) of this section, the Administrator will establish a general account for the person or persons for whom the application is submitted, and upon and after such receipt by the Administrator:
(A) The authorized account representative of the general account shall be authorized and shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each person who has an ownership interest with respect to CSAPR NO
(B) Any alternate authorized account representative shall be authorized, and any representation, action, inaction, or submission by any alternate authorized account representative shall be deemed to be a representation, action, inaction, or submission by the authorized account representative.
(C) Each person who has an ownership interest with respect to CSAPR NO
(ii) Except as provided in paragraph (c)(5) of this section concerning delegation of authority to make submissions, each submission concerning the general account shall be made, signed, and certified by the authorized account representative or any alternate authorized account representative for the persons having an ownership interest with respect to CSAPR NO
(iii) Except in this section, whenever the term “authorized account representative” is used in this subpart, the term shall be construed to include the authorized account representative or any alternate authorized account representative.
(iv) A certification statement submitted in accordance with paragraph (c)(2)(ii) of this section that contains the phrase “TR NO
(3) Changing authorized account representative and alternate authorized account representative; changes in persons with ownership interest. (i) The authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new authorized account representative and the persons with an ownership interest with respect to the CSAPR NO
(ii) The alternate authorized account representative of a general account may be changed at any time upon receipt by the Administrator of a superseding complete application for a general account under paragraph (c)(1) of this section. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous alternate authorized account representative before the time and date when the Administrator receives the superseding application for a general account shall be binding on the new alternate authorized account representative, the authorized account representative, and the persons with an ownership interest with respect to the CSAPR NO
(iii)(A) In the event a person having an ownership interest with respect to CSAPR NO
(B) Within 30 days after any change in the persons having an ownership interest with respect to CSAPR NO
(4) Objections concerning authorized account representative and alternate authorized account representative. (i) Once a complete application for a general account under paragraph (c)(1) of this section has been submitted and received, the Administrator will rely on the application unless and until a superseding complete application for a general account under paragraph (c)(1) of this section is received by the Administrator.
(ii) Except as provided in paragraph (c)(4)(i) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account shall affect any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative or the finality of any decision or order by the Administrator under the CSAPR NO
(iii) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of the authorized account representative or any alternate authorized account representative of a general account, including private legal disputes concerning the proceeds of CSAPR NO
(5) Delegation by authorized account representative and alternate authorized account representative. (i) An authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(ii) An alternate authorized account representative of a general account may delegate, to one or more natural persons, his or her authority to make an electronic submission to the Administrator provided for or required under this subpart.
(iii) In order to delegate authority to a natural person to make an electronic submission to the Administrator in accordance with paragraph (c)(5)(i) or (ii) of this section, the authorized account representative or alternate authorized account representative, as appropriate, must submit to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(A) The name, address, email address, telephone number, and facsimile transmission number (if any) of such authorized account representative or alternate authorized account representative;
(B) The name, address, email address, telephone number, and facsimile transmission number (if any) of each such natural person (referred to in this section as an “agent”);
(C) For each such natural person, a list of the type or types of electronic submissions under paragraph (c)(5)(i) or (ii) of this section for which authority is delegated to him or her;
(D) The following certification statement by such authorized account representative or alternate authorized account representative: “I agree that any electronic submission to the Administrator that is made by an agent identified in this notice of delegation and of a type listed for such agent in this notice of delegation and that is made when I am an authorized account representative or alternate authorized account representative, as appropriate, and before this notice of delegation is superseded by another notice of delegation under 40 CFR 97.1020(c)(5)(iv) shall be deemed to be an electronic submission by me.”; and
(E) The following certification statement by such authorized account representative or alternate authorized account representative: “Until this notice of delegation is superseded by another notice of delegation under 40 CFR 97.1020(c)(5)(iv), I agree to maintain an email account and to notify the Administrator immediately of any change in my email address unless all delegation of authority by me under 40 CFR 97.1020(c)(5) is terminated.”
(iv) A notice of delegation submitted under paragraph (c)(5)(iii) of this section shall be effective, with regard to the authorized account representative or alternate authorized account representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of a superseding notice of delegation submitted by such authorized account representative or alternate authorized account representative, as appropriate. The superseding notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(v) Any electronic submission covered by the certification in paragraph (c)(5)(iii)(D) of this section and made in accordance with a notice of delegation effective under paragraph (c)(5)(iv) of this section shall be deemed to be an electronic submission by the authorized account representative or alternate authorized account representative submitting such notice of delegation.
(vi) A notice of delegation submitted under paragraph (c)(5)(iii) of this section, § 97.520(c)(5)(iii), or § 97.820(c)(5)(iii) that complies with the provisions of paragraph (c)(5)(iii) of this section except that it contains the terms “40 CFR 97.520(c)(5)(iv)” and “40 CFR 97.520(c)(5)” or the terms “40 CFR 97.820(c)(5)(iv)” and “40 CFR 97.820(c)(5)” in place of the terms “40 CFR 97.1020(c)(5)(iv)” and “40 CFR 97.1020(c)(5)”, respectively, in the required certification statements will be considered a valid notice of delegation submitted under paragraph (c)(5)(iii) of this section, and the certification statements included in such notice of delegation will be interpreted for purposes of this subpart as if the terms “40 CFR 97.1020(c)(5)(iv)” and “40 CFR 97.1020(c)(5)” appeared in place of the terms “40 CFR 97.520(c)(5)(iv)” and “40 CFR 97.520(c)(5)” or the terms “40 CFR 97.820(c)(5)(iv)” and “40 CFR 97.820(c)(5)”, respectively.
(6) Closing a general account. (i) The authorized account representative or alternate authorized account representative of a general account may submit to the Administrator a request to close the account. Such request shall include a correctly submitted CSAPR NO
(ii) If a general account has no CSAPR NO
(d) Account identification. The Administrator will assign a unique identifying number to each account established under paragraph (a), (b), or (c) of this section.
(e) Responsibilities of authorized account representative and alternate authorized account representative. After the establishment of a compliance account or general account, the Administrator will accept or act on a submission pertaining to the account, including, but not limited to, submissions concerning the deduction or transfer of CSAPR NO
§ 97.1021 Recordation of CSAPR NOX Ozone Season Group 3 allowance allocations and auction results.
(a) By July 29, 2021, the Administrator will record in each CSAPR NO
(b) By July 29, 2021, the Administrator will record in each CSAPR NO
(1) If, by September 1, 2021 the State does not submit to the Administrator such complete SIP revision, the Administrator will record by September 15, 2021 in each CSAPR NO
(2) If the State submits to the Administrator by September 1, 2021 and the Administrator approves by March 1, 2022 such complete SIP revision, the Administrator will record by March 1, 2022 in each CSAPR NO
(3) If the State submits to the Administrator by September 1, 2021 and the Administrator does not approve by March 1, 2022 such complete SIP revision, the Administrator will record by March 1, 2022 in each CSAPR NO
(c) By September 1, 2023, the Administrator will record in each CSAPR NO
(d)- (e) [Reserved]
(f) By July 1, 2024 and July 1 of each year thereafter, the Administrator will record in each CSAPR NO
(g) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR NO
(h) By May 1, 2022 and May 1 of each year thereafter, the Administrator will record in each CSAPR NO
(i)-(j) [Reserved]
(k) By the date 15 days after the date on which any allocation or auction results, other than an allocation or auction results described in paragraphs (a) through (h) of this section, of CSAPR NO
(l) When recording the allocation or auction of CSAPR NO
(m) Notwithstanding any other provision of this subpart, if, as of the otherwise applicable deadline for recording any CSAPR NO
§ 97.1022 Submission of CSAPR NOX Ozone Season Group 3 allowance transfers.
(a) An authorized account representative seeking recordation of a CSAPR NO
(b) A CSAPR NO
(1) The transfer includes the following elements, in a format prescribed by the Administrator:
(i) The account numbers established by the Administrator for both the transferor and transferee accounts;
(ii) The serial number of each CSAPR NO
(iii) The name and signature of the authorized account representative of the transferor account and the date signed; and
(2) When the Administrator attempts to record the transfer, the transferor account includes each CSAPR NO
§ 97.1023 Recordation of CSAPR NOX Ozone Season Group 3 allowance transfers.
(a) Within 5 business days (except as provided in paragraph (b) of this section) of receiving a CSAPR NO
(b) A CSAPR NO
(c) Where a CSAPR NO
(d) Within 5 business days of recordation of a CSAPR NO
(e) Within 10 business days of receipt of a CSAPR NO
(1) A decision not to record the transfer; and
(2) The reasons for such non-recordation.
§ 97.1024 Compliance with CSAPR NOX Ozone Season Group 3 emissions limitation.
(a) Availability for deduction for compliance. CSAPR NO
(1) Were allocated or auctioned for such control period or a control period in a prior year; and
(2) Are held in the source’s compliance account as of the allowance transfer deadline for such control period.
(b) Deductions for compliance. After the recordation, in accordance with § 97.1023, of CSAPR NO
(1) Until the amount of CSAPR NO
(2) If there are insufficient CSAPR NO
(c) Selection of CSAPR NO
(2) First-in, first-out. The Administrator will deduct CSAPR NO
(i) Any CSAPR NO
(ii) Any other CSAPR NO
(d) Deductions for excess emissions. After making the deductions for compliance under paragraph (b) of this section for a control period in a year in which the CSAPR NO
(e) Recordation of deductions. The Administrator will record in the appropriate compliance account all deductions from such an account under paragraphs (b) and (d) of this section.
§ 97.1025 Compliance with CSAPR NOX Ozone Season Group 3 assurance provisions.
(a) Availability for deduction. CSAPR NO
(1) Were allocated or auctioned for a control period in a prior year or the control period in the given year or in the immediately following year; and
(2) Are held in the assurance account, established by the Administrator for such owners and operators of such group of base CSAPR NO
(b) Deductions for compliance. The Administrator will deduct CSAPR NO
(1) By August 1, 2022 and August 1 of each year thereafter, the Administrator will:
(i) Calculate, for each State (and Indian country within the borders of such State), the total NO
(ii) For the set of any States (and Indian country within the borders of such States) for which the results of the calculations required in paragraph (b)(1)(i) of this section indicate that total NO
(A) Calculate, for each such State (and Indian country within the borders of such State) and such control period and each common designated representative for such control period for a group of one or more base CSAPR NO
(B) Promulgate a notice of data availability of the results of the calculations required in paragraphs (b)(1)(i) and (b)(1)(ii)(A) of this section, including separate calculations of the NO
(2) The Administrator will provide an opportunity for submission of objections to the calculations referenced by each notice of data availability required in paragraph (b)(1)(ii) of this section.
(i) Objections shall be submitted by the deadline specified in such notice and shall be limited to addressing whether the calculations referenced in such notice are in accordance with § 97.1006(c)(2)(iii), §§ 97.1006(b) and 97.1030 through 97.1035, the definitions of “common designated representative”, “common designated representative’s assurance level”, and “common designated representative’s share” in § 97.1002, and the calculation formula in § 97.1006(c)(2)(i).
(ii) The Administrator will adjust the calculations to the extent necessary to ensure that they are in accordance with the provisions referenced in paragraph (b)(2)(i) of this section. By October 1 immediately after the promulgation of such notice, the Administrator will promulgate a notice of data availability of the results of the calculations incorporating any adjustments that the Administrator determines to be necessary and the reasons for accepting or rejecting any objections submitted in accordance with paragraph (b)(2)(i) of this section.
(3) For any State (and Indian country within the borders of such State) referenced in each notice of data availability required in paragraph (b)(2)(ii) of this section as having base CSAPR NO
(4)(i) As of midnight of November 1 immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section, the owners and operators described in paragraph (b)(3) of this section shall hold in the assurance account established for them and for the appropriate base CSAPR NO
(ii) Notwithstanding the allowance-holding deadline specified in paragraph (b)(4)(i) of this section, if November 1 is not a business day, then such allowance-holding deadline shall be midnight of the first business day thereafter.
(5) After November 1 (or the date described in paragraph (b)(4)(ii) of this section) immediately after the promulgation of each notice of data availability required in paragraph (b)(2)(ii) of this section and after the recordation, in accordance with § 97.1023, of CSAPR NO
(6) Notwithstanding any other provision of this subpart and any revision, made by or submitted to the Administrator after the promulgation of the notice of data availability required in paragraph (b)(2)(ii) of this section for a control period in a given year, of any data used in making the calculations referenced in such notice, the amounts of CSAPR NO
(i) If any such data are revised by the Administrator as a result of a decision in or settlement of litigation concerning such data on appeal under part 78 of this chapter of such notice, or on appeal under section 307 of the Clean Air Act of a decision rendered under part 78 of this chapter on appeal of such notice, then the Administrator will use the data as so revised to recalculate the amounts of CSAPR NO
(ii) [Reserved]
(iii) If the revised data are used to recalculate, in accordance with paragraph (b)(6)(i) of this section, the amount of CSAPR NO
(A) Where the amount of CSAPR NO
(B) For the owners and operators for which the amount of CSAPR NO
(C) Each CSAPR NO
§ 97.1026 Banking.
(a) A CSAPR NO
(b) Any CSAPR NO
(c) At any time after the allowance transfer deadline for the last control period for which a State NO
§ 97.1027 Account error.
The Administrator may, at his or her sole discretion and on his or her own motion, correct any error in any Allowance Management System account. Within 10 business days of making such correction, the Administrator will notify the authorized account representative for the account.
§ 97.1028 Administrator’s action on submissions.
(a) The Administrator may review and conduct independent audits concerning any submission under the CSAPR NO
(b) The Administrator may deduct CSAPR NO
§ 97.1029 [Reserved]
§ 97.1030 General monitoring, recordkeeping, and reporting requirements.
The owners and operators, and to the extent applicable, the designated representative, of a CSAPR NO
(a) Requirements for installation, certification, and data accounting. The owner or operator of each CSAPR NO
(1) Install all monitoring systems required under this subpart for monitoring NO
(2) Successfully complete all certification tests required under § 97.1031 and meet all other requirements of this subpart and part 75 of this chapter applicable to the monitoring systems under paragraph (a)(1) of this section; and
(3) Record, report, and quality-assure the data from the monitoring systems under paragraph (a)(1) of this section.
(b) Compliance deadlines. Except as provided in paragraph (e) of this section, the owner or operator of a CSAPR NO
(1) May 1, 2021;
(2) 180 calendar days after the date on which the unit commences commercial operation; or
(3) Where data for the unit are reported on a control period basis under § 97.1034(d)(1)(ii)(B), and where the compliance date under paragraph (b)(2) of this section is not in a month from May through September, May 1 immediately after the compliance date under paragraph (b)(2) of this section.
(4) The owner or operator of a CSAPR NO
(i) Such requirements shall apply to the monitoring systems required under § 97.1030 through § 97.1035, rather than the monitoring systems required under part 75 of this chapter;
(ii) NO
(iii) Any petition for another procedure under § 75.4(e)(2) of this chapter shall be submitted under § 97.1035, rather than § 75.66 of this chapter.
(c) Reporting data. The owner or operator of a CSAPR NO
(d) Prohibitions. (1) No owner or operator of a CSAPR NO
(2) No owner or operator of a CSAPR NO
(3) No owner or operator of a CSAPR NO
(4) No owner or operator of a CSAPR NO
(i) During the period that the unit is covered by an exemption under § 97.1005 that is in effect;
(ii) The owner or operator is monitoring emissions from the unit with another certified monitoring system approved, in accordance with the applicable provisions of this subpart and part 75 of this chapter, by the Administrator for use at that unit that provides emission data for the same pollutant or parameter as the retired or discontinued monitoring system; or
(iii) The designated representative submits notification of the date of certification testing of a replacement monitoring system for the retired or discontinued monitoring system in accordance with § 97.1031(d)(3)(i).
(e) Long-term cold storage. The owner or operator of a CSAPR NO
§ 97.1031 Initial monitoring system certification and recertification procedures.
(a) The owner or operator of a CSAPR NO
(1) The monitoring system has been previously certified in accordance with part 75 of this chapter; and
(2) The applicable quality-assurance and quality-control requirements of § 75.21 of this chapter and appendices B, D, and E to part 75 of this chapter are fully met for the certified monitoring system described in paragraph (a)(1) of this section.
(b) The recertification provisions of this section shall apply to a monitoring system under § 97.1030(a)(1) that is exempt from initial certification requirements under paragraph (a) of this section.
(c) If the Administrator has previously approved a petition under § 75.17(a) or (b) of this chapter for apportioning the NO
(d) Except as provided in paragraph (a) of this section, the owner or operator of a CSAPR NO
(1) Requirements for initial certification. The owner or operator shall ensure that each continuous monitoring system under § 97.1030(a)(1) (including the automated data acquisition and handling system) successfully completes all of the initial certification testing required under § 75.20 of this chapter by the applicable deadline in § 97.1030(b). In addition, whenever the owner or operator installs a monitoring system to meet the requirements of this subpart in a location where no such monitoring system was previously installed, initial certification in accordance with § 75.20 of this chapter is required.
(2) Requirements for recertification. Whenever the owner or operator makes a replacement, modification, or change in any certified continuous emission monitoring system under § 97.1030(a)(1) that may significantly affect the ability of the system to accurately measure or record NO
(3) Approval process for initial certification and recertification. For initial certification of a continuous monitoring system under § 97.1030(a)(1), paragraphs (d)(3)(i) through (v) of this section apply. For recertifications of such monitoring systems, paragraphs (d)(3)(i) through (iv) of this section and the procedures in § 75.20(b)(5) and (g)(7) of this chapter (in lieu of the procedures in paragraph (d)(3)(v) of this section) apply, provided that in applying paragraphs (d)(3)(i) through (iv) of this section, the words “certification” and “initial certification” are replaced by the word “recertification” and the word “certified” is replaced by the word “recertified”.
(i) Notification of certification. The designated representative shall submit to the appropriate EPA Regional Office and the Administrator written notice of the dates of certification testing, in accordance with § 97.1033.
(ii) Certification application. The designated representative shall submit to the Administrator a certification application for each monitoring system. A complete certification application shall include the information specified in § 75.63 of this chapter.
(iii) Provisional certification date. The provisional certification date for a monitoring system shall be determined in accordance with § 75.20(a)(3) of this chapter. A provisionally certified monitoring system may be used under the CSAPR NO
(iv) Certification application approval process. The Administrator will issue a written notice of approval or disapproval of the certification application to the owner or operator within 120 days of receipt of the complete certification application under paragraph (d)(3)(ii) of this section. In the event the Administrator does not issue such a notice within such 120-day period, each monitoring system that meets the applicable performance requirements of part 75 of this chapter and is included in the certification application will be deemed certified for use under the CSAPR NO
(A) Approval notice. If the certification application is complete and shows that each monitoring system meets the applicable performance requirements of part 75 of this chapter, then the Administrator will issue a written notice of approval of the certification application within 120 days of receipt.
(B) Incomplete application notice. If the certification application is not complete, then the Administrator will issue a written notice of incompleteness that sets a reasonable date by which the designated representative must submit the additional information required to complete the certification application. If the designated representative does not comply with the notice of incompleteness by the specified date, then the Administrator may issue a notice of disapproval under paragraph (d)(3)(iv)(C) of this section.
(C) Disapproval notice. If the certification application shows that any monitoring system does not meet the performance requirements of part 75 of this chapter or if the certification application is incomplete and the requirement for disapproval under paragraph (d)(3)(iv)(B) of this section is met, then the Administrator will issue a written notice of disapproval of the certification application. Upon issuance of such notice of disapproval, the provisional certification is invalidated by the Administrator and the data measured and recorded by each uncertified monitoring system shall not be considered valid quality-assured data beginning with the date and hour of provisional certification (as defined under § 75.20(a)(3) of this chapter).
(D) Audit decertification. The Administrator may issue a notice of disapproval of the certification status of a monitor in accordance with § 97.1032(b).
(v) Procedures for loss of certification. If the Administrator issues a notice of disapproval of a certification application under paragraph (d)(3)(iv)(C) of this section or a notice of disapproval of certification status under paragraph (d)(3)(iv)(D) of this section, then:
(A) The owner or operator shall substitute the following values, for each disapproved monitoring system, for each hour of unit operation during the period of invalid data specified under § 75.20(a)(4)(iii), § 75.20(g)(7), or § 75.21(e) of this chapter and continuing until the applicable date and hour specified under § 75.20(a)(5)(i) or (g)(7) of this chapter:
(1) For a disapproved NO
(2) For a disapproved NO
(3) For a disapproved moisture monitoring system and disapproved diluent gas monitoring system, respectively, the minimum potential moisture percentage and either the maximum potential CO
(4) For a disapproved fuel flowmeter system, the maximum potential fuel flow rate, as defined in section 2.4.2.1 of appendix D to part 75 of this chapter.
(5) For a disapproved excepted NO
(B) The designated representative shall submit a notification of certification retest dates and a new certification application in accordance with paragraphs (d)(3)(i) and (ii) of this section.
(C) The owner or operator shall repeat all certification tests or other requirements that were failed by the monitoring system, as indicated in the Administrator’s notice of disapproval, no later than 30 unit operating days after the date of issuance of the notice of disapproval.
(e) The owner or operator of a unit qualified to use the low mass emissions (LME) excepted methodology under § 75.19 of this chapter shall meet the applicable certification and recertification requirements in §§ 75.19(a)(2) and 75.20(h) of this chapter. If the owner or operator of such a unit elects to certify a fuel flowmeter system for heat input determination, the owner or operator shall also meet the certification and recertification requirements in § 75.20(g) of this chapter.
(f) The designated representative of each unit for which the owner or operator intends to use an alternative monitoring system approved by the Administrator under subpart E of part 75 of this chapter shall comply with the applicable notification and application procedures of § 75.20(f) of this chapter.
§ 97.1032 Monitoring system out-of-control periods.
(a) General provisions. Whenever any monitoring system fails to meet the quality-assurance and quality-control requirements or data validation requirements of part 75 of this chapter, data shall be substituted using the applicable missing data procedures in subpart D or subpart H of, or appendix D or appendix E to, part 75 of this chapter.
(b) Audit decertification. Whenever both an audit of a monitoring system and a review of the initial certification or recertification application reveal that any monitoring system should not have been certified or recertified because it did not meet a particular performance specification or other requirement under § 97.1031 or the applicable provisions of part 75 of this chapter, both at the time of the initial certification or recertification application submission and at the time of the audit, the Administrator will issue a notice of disapproval of the certification status of such monitoring system. For the purposes of this paragraph, an audit shall be either a field audit or an audit of any information submitted to the Administrator or any State or permitting authority. By issuing the notice of disapproval, the Administrator revokes prospectively the certification status of the monitoring system. The data measured and recorded by the monitoring system shall not be considered valid quality-assured data from the date of issuance of the notification of the revoked certification status until the date and time that the owner or operator completes subsequently approved initial certification or recertification tests for the monitoring system. The owner or operator shall follow the applicable initial certification or recertification procedures in § 97.1031 for each disapproved monitoring system.
§ 97.1033 Notifications concerning monitoring.
The designated representative of a CSAPR NO
§ 97.1034 Recordkeeping and reporting.
(a) General provisions. The designated representative shall comply with all recordkeeping and reporting requirements in paragraphs (b) through (e) of this section, the applicable recordkeeping and reporting requirements under § 75.73 of this chapter, and the requirements of § 97.1014(a).
(b) Monitoring plans. The owner or operator of a CSAPR NO
(c) Certification applications. The designated representative shall submit an application to the Administrator within 45 days after completing all initial certification or recertification tests required under § 97.1031, including the information required under § 75.63 of this chapter.
(d) Quarterly reports. The designated representative shall submit quarterly reports, as follows:
(1)(i) If a CSAPR NO
(ii) If a CSAPR NO
(A) Meet the requirements of subpart H of part 75 of this chapter for such unit for the entire year and report the NO
(B) Meet the requirements of subpart H of part 75 of this chapter (including the requirements in § 75.74(c) of this chapter) for such unit for the control period and report the NO
(2) The designated representative shall report the NO
(i) The calendar quarter covering May 1, 2021 through June 30, 2021;
(ii) The calendar quarter corresponding to the earlier of the date of provisional certification or the applicable deadline for initial certification under § 97.1030(b); or
(iii) For a unit that reports on a control period basis under paragraph (d)(1)(ii)(B) of this section, if the calendar quarter under paragraph (d)(2)(ii) of this section does not include a month from May through September, the calendar quarter covering May 1 through June 30 immediately after the calendar quarter under paragraph (d)(2)(ii) of this section.
(3) The designated representative shall submit each quarterly report to the Administrator within 30 days after the end of the calendar quarter covered by the report. Quarterly reports shall be submitted in the manner specified in § 75.73(f) of this chapter.
(4) For CSAPR NO
(5) The Administrator may review and conduct independent audits of any quarterly report in order to determine whether the quarterly report meets the requirements of this subpart and part 75 of this chapter, including the requirement to use substitute data.
(i) The Administrator will notify the designated representative of any determination that the quarterly report fails to meet any such requirements and specify in such notification any corrections that the Administrator believes are necessary to make through resubmission of the quarterly report and a reasonable time period within which the designated representative must respond. Upon request by the designated representative, the Administrator may specify reasonable extensions of such time period. Within the time period (including any such extensions) specified by the Administrator, the designated representative shall resubmit the quarterly report with the corrections specified by the Administrator, except to the extent the designated representative provides information demonstrating that a specified correction is not necessary because the quarterly report already meets the requirements of this subpart and part 75 of this chapter that are relevant to the specified correction.
(ii) Any resubmission of a quarterly report shall meet the requirements applicable to the submission of a quarterly report under this subpart and part 75 of this chapter, except for the deadline set forth in paragraph (d)(3) of this section.
(e) Compliance certification. The designated representative shall submit to the Administrator a compliance certification (in a format prescribed by the Administrator) in support of each quarterly report based on reasonable inquiry of those persons with primary responsibility for ensuring that all of the unit’s emissions are correctly and fully monitored. The certification shall state that:
(1) The monitoring data submitted were recorded in accordance with the applicable requirements of this subpart and part 75 of this chapter, including the quality assurance procedures and specifications;
(2) For a unit with add-on NO
(3) For a unit that is reporting on a control period basis under paragraph (d)(1)(ii)(B) of this section, the NO
§ 97.1035 Petitions for alternatives to monitoring, recordkeeping, or reporting requirements.
(a) The designated representative of a CSAPR NO
(b) A petition submitted under paragraph (a) of this section shall include sufficient information for the evaluation of the petition, including, at a minimum, the following information:
(1) Identification of each unit and source covered by the petition;
(2) A detailed explanation of why the proposed alternative is being suggested in lieu of the requirement;
(3) A description and diagram of any equipment and procedures used in the proposed alternative;
(4) A demonstration that the proposed alternative is consistent with the purposes of the requirement for which the alternative is proposed and with the purposes of this subpart and part 75 of this chapter and that any adverse effect of approving the alternative will be de minimis; and
(5) Any other relevant information that the Administrator may require.
(c) Use of an alternative to any requirement referenced in paragraph (a) of this section is in accordance with this subpart only to the extent that the petition is approved in writing by the Administrator and that such use is in accordance with such approval.
PART 98 – MANDATORY GREENHOUSE GAS REPORTING
Subpart A – General Provision
§ 98.1 Purpose and scope.
(a) This part establishes mandatory greenhouse gas (GHG) reporting requirements for owners and operators of certain facilities that directly emit GHG as well as for certain suppliers. For suppliers, the GHGs reported are the quantity that would be emitted from combustion or use of the products supplied.
(b) Owners and operators of facilities and suppliers that are subject to this part must follow the requirements of this subpart and all applicable subparts of this part. If a conflict exists between a provision in subpart A and any other applicable subpart, the requirements of the applicable subpart shall take precedence.
(c) For facilities required to report under onshore petroleum and natural gas production under subpart W of this part, the terms Owner and Operator used in subpart A have the same definition as Onshore petroleum and natural gas production owner or operator, as defined in § 98.238 of this part.
§ 98.2 Who must report?
(a) The GHG reporting requirements and related monitoring, recordkeeping, and reporting requirements of this part apply to the owners and operators of any facility that is located in the United States or under or attached to the Outer Continental Shelf (as defined in 43 U.S.C. 1331) and that meets the requirements of either paragraph (a)(1), (a)(2), or (a)(3) of this section; and any supplier that meets the requirements of paragraph (a)(4) of this section:
(1) A facility that contains any source category that is listed in Table A-3 of this subpart. For these facilities, the annual GHG report must cover stationary fuel combustion sources (subpart C of this part), miscellaneous use of carbonates (subpart U of this part), and all applicable source categories listed in Tables A-3 and A-4 of this subpart.
(2) A facility that contains any source category that is listed in Table A-4 of this subpart and that emits 25,000 metric tons CO
(3) A facility that in any calendar year starting in 2010 meets all three of the conditions listed in this paragraph (a)(3). For these facilities, the annual GHG report must cover emissions from stationary fuel combustion sources only.
(i) The facility does not meet the requirements of either paragraph (a)(1) or (a)(2) of this section.
(ii) The aggregate maximum rated heat input capacity of the stationary fuel combustion units at the facility is 30 mmBtu/hr or greater.
(iii) The facility emits 25,000 metric tons CO
(4) A supplier that is listed in Table A-5 of this subpart. For these suppliers, the annual GHG report must cover all applicable products for which calculation methodologies are provided in the subparts listed in Table A-5 of this subpart.
(5) Research and development activities are not considered to be part of any source category defined in this part.
(b) To calculate GHG emissions for comparison to the 25,000 metric ton CO
(1) Calculate the annual emissions of CO
(2) For each general stationary fuel combustion unit, calculate the annual CO
(3) For miscellaneous uses of carbonate, calculate the annual CO
(4) Sum the emissions estimates from paragraphs (b)(1), (b)(2), and (b)(3) of this section for each GHG and calculate metric tons of CO
(5) For purpose of determining if an emission threshold has been exceeded, include in the emissions calculation any CO
(c) To calculate GHG emissions for comparison to the 25,000 metric ton CO
(d) To calculate GHG quantities for comparison to the 25,000 metric ton CO
(e) To calculate GHG quantities for comparison to the 25,000 metric ton CO
(f) To calculate GHG quantities for comparison to the 25,000 metric ton CO
(1) Calculate the mass in metric tons per year of CO
(2) Convert the mass of each imported and each GHG exported from paragraph (f)(1) of this section to metric tons of CO
(3) Sum the total annual metric tons of CO
(g) If a capacity or generation reporting threshold in paragraph (a)(1) of this section applies, the owner or operator shall review the appropriate records and perform any necessary calculations to determine whether the threshold has been exceeded.
(h) An owner or operator of a facility or supplier that does not meet the applicability requirements of paragraph (a) of this section is not subject to this rule. Such owner or operator would become subject to the rule and reporting requirements, if a facility or supplier exceeds the applicability requirements of paragraph (a) of this section at a later time pursuant to § 98.3(b)(3). Thus, the owner or operator should reevaluate the applicability to this part (including the revising of any relevant emissions calculations or other calculations) whenever there is any change that could cause a facility or supplier to meet the applicability requirements of paragraph (a) of this section. Such changes include but are not limited to process modifications, increases in operating hours, increases in production, changes in fuel or raw material use, addition of equipment, and facility expansion.
(i) Except as provided in this paragraph, once a facility or supplier is subject to the requirements of this part, the owner or operator must continue for each year thereafter to comply with all requirements of this part, including the requirement to submit annual GHG reports, even if the facility or supplier does not meet the applicability requirements in paragraph (a) of this section in a future year.
(1) If reported emissions are less than 25,000 metric tons CO
(2) If reported emissions are less than 15,000 metric tons CO
(3) If the operations of a facility or supplier are changed such that all applicable processes and operations subject to paragraphs (a)(1) through (4) of this section cease to operate, then the owner or operator may discontinue complying with this part for the reporting years following the year in which cessation of such operations occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting and certifies to the closure of all applicable processes and operations no later than March 31 of the year following such changes. If one or more processes or operations subject to paragraphs (a)(1) through (4) of this section at a facility or supplier cease to operate, but not all applicable processes or operations cease to operate, then the owner or operator is exempt from reporting for any such processes or operations in the reporting years following the reporting year in which cessation of the process or operation occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting for the process or operation no later than March 31 following the first reporting year in which the process or operation has ceased for an entire reporting year. Cessation of operations in the context of underground coal mines includes, but is not limited to, abandoning and sealing the facility. This paragraph (i)(3) does not apply to seasonal or other temporary cessation of operations. This paragraph (i)(3) does not apply to the municipal solid waste landfills source category (subpart HH of this subpart), or the industrial waste landfills source category (subpart TT of this part). The owner or operator must resume reporting for any future calendar year during which any of the GHG-emitting processes or operations resume operation.
(4) The provisions of paragraphs (i)(1) and (2) of this section apply to suppliers subject to subparts LL through QQ of this part by substituting the term “quantity of GHG supplied” for “emissions.” For suppliers, the provisions of paragraphs (i)(1) and (2) apply individually to each importer and exporter and individually to each petroleum refinery, fractionator of natural gas liquids, local natural gas distribution company, and producer of CO
(5) If the operations of a facility or supplier are changed such that a process or operation no longer meets the “Definition of Source Category” as specified in an applicable subpart, then the owner or operator may discontinue complying with any such subpart for the reporting years following the year in which change occurs, provided that the owner or operator submits a notification to the Administrator that announces the cessation of reporting for the process or operation no later than March 31 following the first reporting year in which such changes persist for an entire reporting year. The owner or operator must resume complying with this part for the process or operation starting in any future calendar year during which the process or operation meets the “Definition of Source Category” as specified in an applicable subpart.
(6) If an entire facility or supplier is merged into another facility or supplier that is already reporting GHG data under this part, then the owner or operator may discontinue complying with this part for the facility or supplier, provided that the owner or operator submits a notification to the Administrator that announces the discontinuation of reporting and the e-GGRT identification number of the reconstituted facility no later than March 31 of the year following such changes.
(j) Table A-2 of this subpart provides a conversion table for some of the common units of measure used in part 98.
§ 98.3 What are the general monitoring, reporting, recordkeeping and verification requirements of this part?
The owner or operator of a facility or supplier that is subject to the requirements of this part must submit GHG reports to the Administrator, as specified in this section.
(a) General. Except as provided in paragraph (d) of this section, follow the procedures for emission calculation, monitoring, quality assurance, missing data, recordkeeping, and reporting that are specified in each relevant subpart of this part.
(b) Schedule. The annual GHG report for reporting year 2010 must be submitted no later than September 30, 2011. The annual report for reporting years 2011 and beyond must be submitted no later than March 31 of each calendar year for GHG emissions in the previous calendar year, except as provided in paragraph (b)(1) of this section.
(1) For reporting year 2011, facilities with one or more of the subparts listed in paragraphs (b)(1)(i) through (b)(1)(xi) of this section and suppliers listed in paragraph (b)(1)(xii) of this section are required to submit their annual GHG report no later than September 28, 2012. Facilities and suppliers that are submitting their second annual GHG report in 2012 and that are reporting on one or more subparts listed in paragraphs (b)(1)(i) through (b)(1)(xii) of this section must notify EPA by March 31, 2012 that they are not required to submit their annual GHG report until September 28, 2012.
(i) Electronics Manufacturing (subpart I).
(ii) Fluorinated Gas Production (subpart L).
(iii) Magnesium Production (subpart T).
(iv) Petroleum and Natural Gas Systems (subpart W).
(v) Use of Electric Transmission and Distribution Equipment (subpart DD).
(vi) Underground Coal Mines (subpart FF).
(vii) Industrial Wastewater Treatment (subpart II).
(viii) Geologic Sequestration of Carbon Dioxide (subpart RR).
(ix) Manufacture of Electric Transmission and Distribution (subpart SS).
(x) Industrial Waste Landfills (subpart TT).
(xi) Injection of Carbon Dioxide (subpart UU).
(xii) Imports and Exports of Equipment Pre-charged with Fluorinated GHGs or Containing Fluorinated GHGs in Closed-cell Foams (subpart QQ).
(2) For a new facility or supplier that begins operation on or after January 1, 2010 and becomes subject to the rule in the year that it becomes operational, report emissions beginning with the first operating month and ending on December 31 of that year. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.
(3) For any facility or supplier that becomes subject to this rule because of a physical or operational change that is made after January 1, 2010, report emissions for the first calendar year in which the change occurs, beginning with the first month of the change and ending on December 31 of that year. For a facility or supplier that becomes subject to this rule solely because of an increase in hours of operation or level of production, the first month of the change is the month in which the increased hours of operation or level of production, if maintained for the remainder of the year, would cause the facility or supplier to exceed the applicable threshold. Each subsequent annual report must cover emissions for the calendar year, beginning on January 1 and ending on December 31.
(4) Unless otherwise stated, if the final day of any time period falls on a weekend or a federal holiday, the time period shall be extended to the next business day.
(c) Content of the annual report. Except as provided in paragraph (d) of this section, each annual GHG report shall contain the following information:
(1) Facility name or supplier name (as appropriate), and physical street address of the facility or supplier, including the city, State, and zip code. If the facility does not have a physical street address, then the facility must provide the latitude and longitude representing the geographic centroid or center point of facility operations in decimal degree format. This must be provided in a comma-delimited “latitude, longitude” coordinate pair reported in decimal degrees to at least four digits to the right of the decimal point.
(2) Year and months covered by the report.
(3) Date of submittal.
(4) For facilities, except as otherwise provided in paragraph (c)(12) of this section, report annual emissions of CO
(i) Annual emissions (excluding biogenic CO
(ii) Annual emissions of biogenic CO
(iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG listed in paragraphs (c)(4)(iii)(A) through (F) of this section.
(A) Biogenic CO
(B) CO
(C) CH
(D) N
(E) Each fluorinated GHG (as defined in § 98.6), except fluorinated gas production facilities must comply with § 98.126(a) rather than this paragraph (c)(4)(iii)(E). If a fluorinated GHG does not have a chemical-specific GWP in Table A-1 of this subpart, identify and report the fluorinated GHG group of which that fluorinated GHG is a member.
(F) For electronics manufacturing (as defined in § 98.90), each fluorinated heat transfer fluid (as defined in § 98.98) that is not also a fluorinated GHG as specified under (c)(4)(iii)(E) of this section. If a fluorinated heat transfer fluid does not have a chemical-specific GWP in Table A-1 of this subpart, identify and report the fluorinated GHG group of which that fluorinated heat transfer fluid is a member.
(G) For each reported fluorinated GHG and fluorinated heat transfer fluid, report the following identifying information:
(1) Chemical name. If the chemical is not listed in Table A-1 of this subpart, then use the method of naming organic chemical compounds as recommended by the International Union of Pure and Applied Chemistry (IUPAC).
(2) The CAS registry number assigned by the Chemical Abstracts Registry Service. If a CAS registry number is not assigned or is not associated with a single fluorinated GHG or fluorinated heat transfer fluid, then report an identification number assigned by EPA’s Substance Registry Services.
(3) Linear chemical formula.
(iv) Except as provided in paragraph (c)(4)(vii) of this section, emissions and other data for individual units, processes, activities, and operations as specified in the “Data reporting requirements” section of each applicable subpart of this part.
(v) Indicate (yes or no) whether reported emissions include emissions from a cogeneration unit located at the facility.
(vi) [Reserved]
(vii) The owner or operator of a facility is not required to report the data elements specified in Table A-6 of this subpart for calendar years 2010 through 2011 until March 31, 2013. The owner or operator of a facility is not required to report the data elements specified in Table A-7 of this subpart for calendar years 2010 through 2013 until March 31, 2015 (as part of the annual report for reporting year 2014), except as otherwise specified in Table A-7 of this subpart.
(viii) Applicable source categories means stationary fuel combustion sources (subpart C of this part), miscellaneous use of carbonates (subpart U of this part), and all of the source categories listed in Table A-3 and Table A-4 of this subpart present at the facility.
(5) For suppliers, report annual quantities of CO
(i) Total quantity of GHG aggregated for all GHG from all applicable supply categories in Table A-5 of this subpart and expressed in metric tons of CO
(ii) Quantity of each GHG from each applicable supply category in Table A-5 to this subpart, expressed in metric tons of each GHG. For each reported fluorinated GHG, report the following identifying information:
(A) Chemical name. If the chemical is not listed in Table A-1 of this subpart, then use the method of naming organic chemical compounds as recommended by the International Union of Pure and Applied Chemistry (IUPAC).
(B) The CAS registry number assigned by the Chemical Abstracts Registry Service. If a CAS registry number is not assigned or is not associated with a single fluorinated GHG, then report an identification number assigned by EPA’s Substance Registry Services.
(C) Linear chemical formula.
(iii) Any other data specified in the “Data reporting requirements” section of each applicable subpart of this part.
(6) A written explanation, as required under § 98.3(e), if you change emission calculation methodologies during the reporting period.
(7) A brief description of each “best available monitoring method” used, the parameter measured using the method, and the time period during which the “best available monitoring method” was used, if applicable.
(8) Each parameter for which a missing data procedure was used according to the procedures of an applicable subpart and the total number of hours in the year that a missing data procedure was used for each parameter. Parameters include not only reported data elements, but any data element required for monitoring and calculating emissions.
(9) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of § 98.4(e)(1).
(10) NAICS code(s) that apply to the facility or supplier.
(i) Primary NAICS code. Report the NAICS code that most accurately describes the facility or supplier’s primary product/activity/service. The primary product/activity/service is the principal source of revenue for the facility or supplier. A facility or supplier that has two distinct products/activities/services providing comparable revenue may report a second primary NAICS code.
(ii) Additional NAICS code(s). Report all additional NAICS codes that describe all product(s)/activity(s)/service(s) at the facility or supplier that are not related to the principal source of revenue.
(11) Legal name(s) and physical address(es) of the highest-level United States parent company(s) of the owners (or operators) of the facility or supplier and the percentage of ownership interest for each listed parent company as of December 31 of the year for which data are being reported according to the following instructions:
(i) If the facility or supplier is entirely owned by a single United States company that is not owned by another company, provide that company’s legal name and physical address as the United States parent company and report 100 percent ownership.
(ii) If the facility or supplier is entirely owned by a single United States company that is, itself, owned by another company (e.g., it is a division or subsidiary of a higher-level company), provide the legal name and physical address of the highest-level company in the ownership hierarchy as the United States parent company and report 100 percent ownership.
(iii) If the facility or supplier is owned by more than one United States company (e.g., company A owns 40 percent, company B owns 35 percent, and company C owns 25 percent), provide the legal names and physical addresses of all the highest-level companies with an ownership interest as the United States parent companies, and report the percent ownership of each company.
(iv) If the facility or supplier is owned by a joint venture or a cooperative, the joint venture or cooperative is its own United States parent company. Provide the legal name and physical address of the joint venture or cooperative as the United States parent company, and report 100 percent ownership by the joint venture or cooperative.
(v) If the facility or supplier is entirely owned by a foreign company, provide the legal name and physical address of the foreign company’s highest-level company based in the United States as the United States parent company, and report 100 percent ownership.
(vi) If the facility or supplier is partially owned by a foreign company and partially owned by one or more U.S. companies, provide the legal name and physical address of the foreign company’s highest-level company based in the United States, along with the legal names and physical addresses of the other U.S. parent companies, and report the percent ownership of each of these companies.
(vii) If the facility or supplier is a federally owned facility, report “U.S. Government” and do not report physical address or percent ownership.
(viii) The facility or supplier must refer to the reporting instructions of the electronic GHG reporting tool regarding standardized conventions for the naming of a parent company.
(12) For the 2010 reporting year only, facilities that have “part 75 units” (i.e. units that are subject to subpart D of this part or units that use the methods in part 75 of this chapter to quantify CO
(i) Annual emissions aggregated for all GHG from all applicable source categories, expressed in metric tons of CO
(ii) Annual emissions of biogenic CO
(iii) Annual emissions from each applicable source category, expressed in metric tons of each applicable GHG listed in paragraphs (c)(12)(iii)(A) through (c)(12)(iii)(E) of this section.
(A) Biogenic CO
(B) CO
(C) CH
(D) N
(E) Each fluorinated GHG (including those not listed in Table A-1 of this subpart).
(13) An indication of whether the facility includes one or more plant sites that have been assigned a “plant code” (as defined under § 98.6) by either the Department of Energy’s Energy Information Administration or by the EPA’s Clean Air Markets Division.
(d) Special provisions for reporting year 2010. (1) Best available monitoring methods. During January 1, 2010 through March 31, 2010, owners or operators may use best available monitoring methods for any parameter (e.g., fuel use, daily carbon content of feedstock by process line) that cannot reasonably be measured according to the monitoring and QA/QC requirements of a relevant subpart. The owner or operator must use the calculation methodologies and equations in the “Calculating GHG Emissions” sections of each relevant subpart, but may use the best available monitoring method for any parameter for which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2010. Starting no later than April 1, 2010, the owner or operator must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as provided in paragraphs (d)(2) and (d)(3) of this section. Best available monitoring methods means any of the following methods specified in this paragraph:
(i) Monitoring methods currently used by the facility that do not meet the specifications of a relevant subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2) Requests for extension of the use of best available monitoring methods. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods beyond March 31, 2010.
(i) Timing of request. The extension request must be submitted to EPA no later than 30 days after the effective date of the GHG reporting rule.
(ii) Content of request. Requests must contain the following information:
(A) A list of specific item of monitoring instrumentation for which the request is being made and the locations where each piece of monitoring instrumentation will be installed.
(B) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed.
(C) A description of the reasons why the needed equipment could not be obtained and installed before April 1, 2010.
(D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1, 2010, include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers and the dates by which alternative vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery, and the current expected date of delivery.
(E) If the reason for the extension is that the equipment cannot be installed without a process unit shutdown, include supporting documentation demonstrating that it is not practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns for this process unit, and the date of the next planned shutdown during which the monitoring equipment can be installed. If there has been a shutdown or if there is a planned process unit shutdown between promulgation of this part and April 1, 2010, include a justification of why the equipment could not be obtained and installed during that shutdown.
(F) A description of the specific actions the facility will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.
(iii) Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by April 1, 2010. The use of best available methods will not be approved beyond December 31, 2010.
(3) Abbreviated emissions report for facilities containing only general stationary fuel combustion sources. In lieu of the report required by paragraph (c) of this section, the owner or operator of an existing facility that is in operation on January 1, 2010 and that meets the conditions of § 98.2(a)(3) may submit an abbreviated GHG report for the facility for GHGs emitted in 2010. The abbreviated report must be submitted by September 30, 2011. An owner or operator that submits an abbreviated report must submit a full GHG report according to the requirements of paragraph (c) of this section beginning in calendar year 2012. The abbreviated facility report must include the following information:
(i) Facility name and physical street address including the city, state and zip code.
(ii) The year and months covered by the report.
(iii) Date of submittal.
(iv) Total facility GHG emissions aggregated for all stationary fuel combustion units calculated according to any method specified in § 98.33(a) and expressed in metric tons of CO
(v) For each stationary fuel combustion source that meets the criteria specified in § 98.36(f), report any facility operating data or process information used for the GHG emission calculations. A stationary fuel combustion source that does not meet the criteria specified in § 98.36(f) must either report the data specified in this paragraph (d)(3)(v) in the annual report or use verification software according to § 98.5(b) in lieu of reporting the data specified in this paragraph.
(vi) A signed and dated certification statement provided by the designated representative of the owner or operator, according to the requirements of paragraph (e)(1) of this section.
(e) Emission calculations. In preparing the GHG report, you must use the calculation methodologies specified in the relevant subparts, except as specified in paragraph (d) of this section. For each source category, you must use the same calculation methodology throughout a reporting period unless you provide a written explanation of why a change in methodology was required.
(f) Verification. To verify the completeness and accuracy of reported GHG emissions, the Administrator may review the certification statements described in paragraphs (c)(9) and (d)(3)(vi) of this section and any other credible evidence, in conjunction with a comprehensive review of the GHG reports and periodic audits of selected reporting facilities. Nothing in this section prohibits the Administrator from using additional information to verify the completeness and accuracy of the reports.
(g) Recordkeeping. An owner or operator that is required to report GHGs under this part must keep records as specified in this paragraph (g). Except as otherwise provided in this paragraph, retain all required records for at least 3 years from the date of submission of the annual GHG report for the reporting year in which the record was generated. The records shall be kept in an electronic or hard-copy format (as appropriate) and recorded in a form that is suitable for expeditious inspection and review. If the owner or operator of a facility is required under § 98.5(b) to use verification software specified by the Administrator, then all records required for the facility under this part must be retained for at least 5 years from the date of submission of the annual GHG report for the reporting year in which the record was generated, starting with records for reporting year 2010. Upon request by the Administrator, the records required under this section must be made available to EPA. Records may be retained off site if the records are readily available for expeditious inspection and review. For records that are electronically generated or maintained, the equipment or software necessary to read the records shall be made available, or, if requested by EPA, electronic records shall be converted to paper documents. You must retain the following records, in addition to those records prescribed in each applicable subpart of this part:
(1) A list of all units, operations, processes, and activities for which GHG emission were calculated.
(2) The data used to calculate the GHG emissions for each unit, operation, process, and activity, categorized by fuel or material type. These data include but are not limited to the following information in this paragraph (g)(2):
(i) The GHG emissions calculations and methods used. For data required by § 98.5(b) to be entered into verification software specified in § 98.5(b), maintain the entered data in the format generated by the verification software according to § 98.5(b).
(ii) Analytical results for the development of site-specific emissions factors.
(iii) The results of all required analyses for high heat value, carbon content, and other required fuel or feedstock parameters.
(iv) Any facility operating data or process information used for the GHG emission calculations.
(3) The annual GHG reports.
(4) Missing data computations. For each missing data event, also retain a record of the cause of the event and the corrective actions taken to restore malfunctioning monitoring equipment.
(5) A written GHG Monitoring Plan.
(i) At a minimum, the GHG Monitoring Plan shall include the elements listed in this paragraph (g)(5)(i).
(A) Identification of positions of responsibility (i.e., job titles) for collection of the emissions data.
(B) Explanation of the processes and methods used to collect the necessary data for the GHG calculations.
(C) Description of the procedures and methods that are used for quality assurance, maintenance, and repair of all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part.
(ii) The GHG Monitoring Plan may rely on references to existing corporate documents (e.g., standard operating procedures, quality assurance programs under appendix F to 40 CFR part 60 or appendix B to 40 CFR part 75, and other documents) provided that the elements required by paragraph (g)(5)(i) of this section are easily recognizable.
(iii) The owner or operator shall revise the GHG Monitoring Plan as needed to reflect changes in production processes, monitoring instrumentation, and quality assurance procedures; or to improve procedures for the maintenance and repair of monitoring systems to reduce the frequency of monitoring equipment downtime.
(iv) Upon request by the Administrator, the owner or operator shall make all information that is collected in conformance with the GHG Monitoring Plan available for review during an audit. Electronic storage of the information in the plan is permissible, provided that the information can be made available in hard copy upon request during an audit.
(6) The results of all required certification and quality assurance tests of continuous monitoring systems, fuel flow meters, and other instrumentation used to provide data for the GHGs reported under this part.
(7) Maintenance records for all continuous monitoring systems, flow meters, and other instrumentation used to provide data for the GHGs reported under this part.
(h) Annual GHG report revisions. This paragraph applies to the reporting years for which the owner or operator is required to maintain records for a facility or supplier according to the time periods specified in paragraph (g) of this section.
(1) The owner or operator shall submit a revised annual GHG report within 45 days of discovering that an annual GHG report that the owner or operator previously submitted contains one or more substantive errors. The revised report must correct all substantive errors.
(2) The Administrator may notify the owner or operator in writing that an annual GHG report previously submitted by the owner or operator contains one or more substantive errors. Such notification will identify each such substantive error. The owner or operator shall, within 45 days of receipt of the notification, either resubmit the report that, for each identified substantive error, corrects the identified substantive error (in accordance with the applicable requirements of this part) or provide information demonstrating that the previously submitted report does not contain the identified substantive error or that the identified error is not a substantive error.
(3) A substantive error is an error that impacts the quantity of GHG emissions reported or otherwise prevents the reported data from being validated or verified.
(4) Notwithstanding paragraphs (h)(1) and (2) of this section, upon request by the owner or operator, the Administrator may provide reasonable extensions of the 45-day period for submission of the revised report or information under paragraphs (h)(1) and (2). If the Administrator receives a request for extension of the 45-day period, by email to an address prescribed by the Administrator prior to the expiration of the 45-day period, the extension request is deemed to be automatically granted for 30 days. The Administrator may grant an additional extension beyond the automatic 30-day extension if the owner or operator submits a request for an additional extension and the request is received by the Administrator prior to the expiration of the automatic 30-day extension, provided the request demonstrates that it is not practicable to submit a revised report or information under paragraphs (h)(1) and (2) within 75 days. The Administrator will approve the extension request if the request demonstrates to the Administrator’s satisfaction that it is not practicable to collect and process the data needed to resolve potential reporting errors identified pursuant to paragraph (h)(1) or (2) within 75 days.
(5) The owner or operator shall retain documentation for 3 years to support any revision made to an annual GHG report.
(i) Calibration accuracy requirements. The owner or operator of a facility or supplier that is subject to the requirements of this part must meet the applicable flow meter calibration and accuracy requirements of this paragraph (i). The accuracy specifications in this paragraph (i) do not apply where either the use of company records (as defined in § 98.6) or the use of “best available information” is specified in an applicable subpart of this part to quantify fuel usage and/or other parameters. Further, the provisions of this paragraph (i) do not apply to stationary fuel combustion units that use the methodologies in part 75 of this chapter to calculate CO
(1) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of this section, flow meters that measure liquid and gaseous fuel feed rates, process stream flow rates, or feedstock flow rates and provide data for the GHG emissions calculations shall be calibrated prior to April 1, 2010 using the procedures specified in this paragraph (i) when such calibration is specified in a relevant subpart of this part. Each of these flow meters shall meet the applicable accuracy specification in paragraph (i)(2) or (i)(3) of this section. All other measurement devices (e.g., weighing devices) that are required by a relevant subpart of this part, and that are used to provide data for the GHG emissions calculations, shall also be calibrated prior to April 1, 2010; however, the accuracy specifications in paragraphs (i)(2) and (i)(3) of this section do not apply to these devices. Rather, each of these measurement devices shall be calibrated to meet the accuracy requirement specified for the device in the applicable subpart of this part, or, in the absence of such accuracy requirement, the device must be calibrated to an accuracy within the appropriate error range for the specific measurement technology, based on an applicable operating standard, including but not limited to manufacturer’s specifications and industry standards. The procedures and methods used to quality-assure the data from each measurement device shall be documented in the written monitoring plan, pursuant to paragraph (g)(5)(i)(C) of this section.
(i) All flow meters and other measurement devices that are subject to the provisions of this paragraph (i) must be calibrated according to one of the following: You may use the manufacturer’s recommended procedures; an appropriate industry consensus standard method; or a method specified in a relevant subpart of this part. The calibration method(s) used shall be documented in the monitoring plan required under paragraph (g) of this section.
(ii) For facilities and suppliers that become subject to this part after April 1, 2010, all flow meters and other measurement devices (if any) that are required by the relevant subpart(s) of this part to provide data for the GHG emissions calculations shall be installed no later than the date on which data collection is required to begin using the measurement device, and the initial calibration(s) required by this paragraph (i) (if any) shall be performed no later than that date.
(iii) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of this section, subsequent recalibrations of the flow meters and other measurement devices subject to the requirements of this paragraph (i) shall be performed at one of the following frequencies:
(A) You may use the frequency specified in each applicable subpart of this part.
(B) You may use the frequency recommended by the manufacturer or by an industry consensus standard practice, if no recalibration frequency is specified in an applicable subpart.
(2) Perform all flow meter calibration at measurement points that are representative of the normal operating range of the meter. Except for the orifice, nozzle, and venturi flow meters described in paragraph (i)(3) of this section, calculate the calibration error at each measurement point using Equation A-2 of this section. The terms “R” and “A” in Equation A-2 must be expressed in consistent units of measure (e.g., gallons/minute, ft
(3) For orifice, nozzle, and venturi flow meters, the initial quality assurance consists of in-situ calibration of the differential pressure (delta-P), total pressure, and temperature transmitters.
(i) Calibrate each transmitter at a zero point and at least one upscale point. Fixed reference points, such as the freezing point of water, may be used for temperature transmitter calibrations. Calculate the calibration error of each transmitter at each measurement point, using Equation A-3 of this subpart. The terms “R,” “A,” and “FS” in Equation A-3 of this subpart must be in consistent units of measure (e.g., milliamperes, inches of water, psi, degrees). For each transmitter, the CE value at each measurement point shall not exceed 2.0 percent of full-scale. Alternatively, the results are acceptable if the sum of the calculated CE values for the three transmitters at each calibration level (i.e., at the zero level and at each upscale level) does not exceed 6.0 percent.
(ii) In cases where there are only two transmitters (i.e., differential pressure and either temperature or total pressure) in the immediate vicinity of the flow meter’s primary element (e.g., the orifice plate), or when there is only a differential pressure transmitter in close proximity to the primary element, calibration of these existing transmitters to a CE of 2.0 percent or less at each measurement point is still required, in accordance with paragraph (i)(3)(i) of this section; alternatively, when two transmitters are calibrated, the results are acceptable if the sum of the CE values for the two transmitters at each calibration level does not exceed 4.0 percent. However, note that installation and calibration of an additional transmitter (or transmitters) at the flow monitor location to measure temperature or total pressure or both is not required in these cases. Instead, you may use assumed values for temperature and/or total pressure, based on measurements of these parameters at a remote location (or locations), provided that the following conditions are met:
(A) You must demonstrate that measurements at the remote location(s) can, when appropriate correction factors are applied, reliably and accurately represent the actual temperature or total pressure at the flow meter under all expected ambient conditions.
(B) You must make all temperature and/or total pressure measurements in the demonstration described in paragraph (i)(3)(ii)(A) of this section with calibrated gauges, sensors, transmitters, or other appropriate measurement devices. At a minimum, calibrate each of these devices to an accuracy within the appropriate error range for the specific measurement technology, according to one of the following. You may calibrate using a manufacturer’s specification or an industry consensus standard.
(C) You must document the methods used for the demonstration described in paragraph (i)(3)(ii)(A) of this section in the written GHG Monitoring Plan under paragraph (g)(5)(i)(C) of this section. You must also include the data from the demonstration, the mathematical correlation(s) between the remote readings and actual flow meter conditions derived from the data, and any supporting engineering calculations in the GHG Monitoring Plan. You must maintain all of this information in a format suitable for auditing and inspection.
(D) You must use the mathematical correlation(s) derived from the demonstration described in paragraph (i)(3)(ii)(A) of this section to convert the remote temperature or the total pressure readings, or both, to the actual temperature or total pressure at the flow meter, or both, on a daily basis. You shall then use the actual temperature and total pressure values to correct the measured flow rates to standard conditions.
(E) You shall periodically check the correlation(s) between the remote and actual readings (at least once a year), and make any necessary adjustments to the mathematical relationship(s).
(4) Fuel billing meters are exempted from the calibration requirements of this section and from the GHG Monitoring Plan and recordkeeping provisions of paragraphs (g)(5)(i)(C), (g)(6), and (g)(7) of this section, provided that the fuel supplier and any unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same company. Meters used exclusively to measure the flow rates of fuels that are used for unit startup are also exempted from the calibration requirements of this section.
(5) For a flow meter that has been previously calibrated in accordance with paragraph (i)(1) of this section, an additional calibration is not required by the date specified in paragraph (i)(1) of this section if, as of that date, the previous calibration is still active (i.e., the device is not yet due for recalibration because the time interval between successive calibrations has not elapsed). In this case, the deadline for the successive calibrations of the flow meter shall be set according to one of the following. You may use either the manufacturer’s recommended calibration schedule or you may use the industry consensus calibration schedule.
(6) For units and processes that operate continuously with infrequent outages, it may not be possible to meet the April 1, 2010 deadline for the initial calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may postpone the initial calibration until the next scheduled maintenance outage. The best available information from company records may be used in the interim. The subsequent required recalibrations of the flow meters may be similarly postponed. Such postponements shall be documented in the monitoring plan that is required under paragraph (g)(5) of this section.
(7) If the results of an initial calibration or a recalibration fail to meet the required accuracy specification, data from the flow meter shall be considered invalid, beginning with the hour of the failed calibration and continuing until a successful calibration is completed. You shall follow the missing data provisions provided in the relevant missing data sections during the period of data invalidation.
(j) Measurement device installation – (1) General. If an owner or operator required to report under subpart P, subpart X or subpart Y of this part has process equipment or units that operate continuously and it is not possible to install a required flow meter or other measurement device by April 1, 2010, (or by any later date in 2010 approved by the Administrator as part of an extension of best available monitoring methods per paragraph (d) of this section) without process equipment or unit shutdown, or through a hot tap, the owner or operator may request an extension from the Administrator to delay installing the measurement device until the next scheduled process equipment or unit shutdown. If approval for such an extension is granted by the Administrator, the owner or operator must use best available monitoring methods during the extension period.
(2) Requests for extension of the use of best available monitoring methods for measurement device installation. The owner or operator must first provide the Administrator an initial notification of the intent to submit an extension request for use of best available monitoring methods beyond December 31, 2010 (or an earlier date approved by EPA) in cases where measurement device installation would require a process equipment or unit shutdown, or could only be done through a hot tap. The owner or operator must follow-up this initial notification with the complete extension request containing the information specified in paragraph (j)(4) of this section.
(3) Timing of request. (i) The initial notice of intent must be submitted no later than January 1, 2011, or by the end of the approved use of best available monitoring methods extension in 2010, whichever is earlier. The completed extension request must be submitted to the Administrator no later than February 15, 2011.
(ii) Any subsequent extensions to the original request must be submitted to the Administrator within 4 weeks of the owner or operator identifying the need to extend the request, but in any event no later than 4 weeks before the date for the planned process equipment or unit shutdown that was provided in the original or most recently approved request.
(4) Content of the request. Requests must contain the following information:
(i) Specific measurement device for which the request is being made and the location where each measurement device will be installed.
(ii) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) requiring the measurement device.
(iii) A description of the reasons why the needed equipment could not be installed before April 1, 2010, or by the expiration date for the use of best available monitoring methods, in cases where an extension has been granted under § 98.3(d).
(iv) Supporting documentation showing that it is not practicable to isolate the process equipment or unit and install the measurement device without a full shutdown or a hot tap, and that there was no opportunity during 2010 to install the device. Include the date of the three most recent shutdowns for each relevant process equipment or unit, the frequency of shutdowns for each relevant process equipment or unit, and the date of the next planned process equipment or unit shutdown.
(v) Include a description of the proposed best available monitoring method for estimating GHG emissions during the time prior to installation of the meter.
(5) Approval criteria. The owner or operator must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to install the measurement device before April 1, 2010 (or by the expiration date for the use of best available monitoring methods, in cases where an extension has been granted under paragraph (d) of this section) without a process equipment or unit shutdown, or through a hot tap, and that the proposed method for estimating GHG emissions during the time before which the measurement device will be installed is appropriate. The Administrator will not initially approve the use of the proposed best available monitoring method past December 31, 2013.
(6) Measurement device installation deadline. Any owner or operator that submits both a timely initial notice of intent and a timely completed extension request under paragraph (j)(3) of this section to extend use of best available monitoring methods for measurement device installation must install all such devices by July 1, 2011 unless the extension request under this paragraph (j) is approved by the Administrator before July 1, 2011.
(7) One time extension past December 31, 2013. If an owner or operator determines that a scheduled process equipment or unit shutdown will not occur by December 31, 2013, the owner or operator may re-apply to use best available monitoring methods for one additional time period, not to extend beyond December 31, 2015. To extend use of best available monitoring methods past December 31, 2013, the owner or operator must submit a new extension request by June 1, 2013 that contains the information required in paragraph (j)(4) of this section. The owner or operator must demonstrate to the Administrator’s satisfaction that it continues to not be reasonably feasible to install the measurement device before December 31, 2013 without a process equipment or unit shutdown, or that installation of the measurement device could only be done through a hot tap, and that the proposed method for estimating GHG emissions during the time before which the measurement device will be installed is appropriate. An owner or operator that submits a request under this paragraph to extend use of best available monitoring methods for measurement device installation must install all such devices by December 31, 2013, unless the extension request under this paragraph is approved by the Administrator.
(k) Revised global warming potentials and special provisions for reporting year 2013 and subsequent reporting years. This paragraph (k) applies to owners or operators of facilities or suppliers that first become subject to any subpart of part 98 solely due to an amendment to Table A-1 of this subpart.
(1) A facility or supplier that first becomes subject to part 98 due to a change in the GWP for one or more compounds in Table A-1 of this subpart, Global Warming Potentials, is not required to submit an annual GHG report for the reporting year during which the change in GWPs is published.
(2) A facility or supplier that was already subject to one or more subparts of part 98 but becomes subject to one or more additional subparts due to a change in the GWP for one or more compounds in Table A-1 of this subpart, is not required to include those subparts to which the facility is subject only due to the change in the GWP in the annual GHG report submitted for the reporting year during which the change in GWPs is published.
(3) Starting on January 1 of the year after the year during which the change in GWPs is published, facilities or suppliers identified in paragraphs (k)(1) or (2) of this section must start monitoring and collecting GHG data in compliance with the applicable subparts of part 98 to which the facility is subject due to the change in the GWP for the annual greenhouse gas report for that reporting year, which is due by March 31 of the following calendar year.
(4) A change in the GWP for one or more compounds includes the addition to Table A-1 of this subpart of either a chemical-specific or a default GWP that applies to a compound to which no chemical-specific GWP in Table A-1 of this subpart previously applied.
(l) Special provision for best available monitoring methods in 2014 and subsequent years. This paragraph (l) applies to owners or operators of facilities or suppliers that first become subject to any subpart of part 98 due to an amendment to Table A-1 of this subpart, Global Warming Potentials.
(1) Best available monitoring methods. From January 1 to March 31 of the year after the year during which the change in GWPs is published, owners or operators subject to this paragraph (l) may use best available monitoring methods for any parameter (e.g., fuel use, feedstock rates) that cannot reasonably be measured according to the monitoring and QA/QC requirements of a relevant subpart. The owner or operator must use the calculation methodologies and equations in the “Calculating GHG Emissions” sections of each relevant subpart, but may use the best available monitoring method for any parameter for which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1 of the year after the year during which the change in GWPs is published. Starting no later than April 1 of the year after the year during which the change in GWPs is published, the owner or operator must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as provided in paragraph (l)(2) of this section. Best available monitoring methods means any of the following methods:
(i) Monitoring methods currently used by the facility that do not meet the specifications of a relevant subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2) Requests for extension of the use of best available monitoring methods. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods beyond March 31 of the year after the year during which the change in GWPs is published.
(i) Timing of request. The extension request must be submitted to EPA no later than January 31 of the year after the year during which the change in GWPs is published.
(ii) Content of request. Requests must contain the following information:
(A) A list of specific items of monitoring instrumentation for which the request is being made and the locations where each piece of monitoring instrumentation will be installed.
(B) Identification of the specific rule requirements (by rule subpart, section, and paragraph numbers) for which the instrumentation is needed.
(C) A description of the reasons that the needed equipment could not be obtained and installed before April 1 of the year after the year during which the change in GWPs is published.
(D) If the reason for the extension is that the equipment cannot be purchased and delivered by April 1 of the year after the year during which the change in GWPs is published, include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers and the dates by which alternative vendors promised delivery, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery, and the current expected date of delivery.
(E) If the reason for the extension is that the equipment cannot be installed without a process unit shutdown, include supporting documentation demonstrating that it is not practicable to isolate the equipment and install the monitoring instrument without a full process unit shutdown. Include the date of the most recent process unit shutdown, the frequency of shutdowns for this process unit, and the date of the next planned shutdown during which the monitoring equipment can be installed. If there has been a shutdown or if there is a planned process unit shutdown between November 29 of the year during which the change in GWPs is published and April 1 of the year after the year during which the change in GWPs is published, include a justification of why the equipment could not be obtained and installed during that shutdown.
(F) A description of the specific actions the facility will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.
(iii) Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by April 1 of the year after the year during which the change in GWPs is published. The use of best available methods under this paragraph (l) will not be approved beyond December 31 of the year after the year during which the change in GWPs is published.
§ 98.4 Authorization and responsibilities of the designated representative.
(a) General. Except as provided under paragraph (f) of this section, each facility, and each supplier, that is subject to this part, shall have one and only one designated representative, who shall be responsible for certifying, signing, and submitting GHG emissions reports and any other submissions for such facility and supplier respectively to the Administrator under this part. If the facility is required under any other part of title 40 of the Code of Federal Regulations to submit to the Administrator any other emission report that is subject to any requirement in 40 CFR part 75, the same individual shall be the designated representative responsible for certifying, signing, and submitting the GHG emissions reports and all such other emissions reports under this part.
(b) Authorization of a designated representative. The designated representative of the facility or supplier shall be an individual selected by an agreement binding on the owners and operators of such facility or supplier and shall act in accordance with the certification statement in paragraph (i)(4)(iv) of this section.
(c) Responsibility of the designated representative. Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier, the designated representative identified in such certificate of representation shall represent and, by his or her representations, actions, inactions, or submissions, legally bind each owner and operator of such facility or supplier in all matters pertaining to this part, notwithstanding any agreement between the designated representative and such owners and operators. The owners and operators shall be bound by any decision or order issued to the designated representative by the Administrator or a court.
(d) Timing. No GHG emissions report or other submissions under this part for a facility or supplier will be accepted until the Administrator has received a complete certificate of representation under this section for a designated representative of the facility or supplier. Such certificate of representation shall be submitted at least 60 days before the deadline for submission of the facility’s or supplier’s initial emission report under this part.
(e) Certification of the GHG emissions report. Each GHG emission report and any other submission under this part for a facility or supplier shall be certified, signed, and submitted by the designated representative or any alternate designated representative of the facility or supplier in accordance with this section and § 3.10 of this chapter.
(1) Each such submission shall include the following certification statement signed by the designated representative or any alternate designated representative: “I am authorized to make this submission on behalf of the owners and operators of the facility or supplier, as applicable, for which the submission is made. I certify under penalty of law that I have personally examined, and am familiar with, the statements and information submitted in this document and all its attachments. Based on my inquiry of those individuals with primary responsibility for obtaining the information, I certify that the statements and information are to the best of my knowledge and belief true, accurate, and complete. I am aware that there are significant penalties for submitting false statements and information or omitting required statements and information, including the possibility of fine or imprisonment.”
(2) The Administrator will accept a GHG emission report or other submission for a facility or supplier under this part only if the submission is certified, signed, and submitted in accordance with this section.
(f) Alternate designated representative. A certificate of representation under this section for a facility or supplier may designate one alternate designated representative, who shall be an individual selected by an agreement binding on the owners and operators, and may act on behalf of the designated representative, of such facility or supplier. The agreement by which the alternate designated representative is selected shall include a procedure for authorizing the alternate designated representative to act in lieu of the designated representative.
(1) Upon receipt by the Administrator of a complete certificate of representation under this section for a facility or supplier identifying an alternate designated representative.
(i) The alternate designated representative may act on behalf of the designated representative for such facility or supplier.
(ii) Any representation, action, inaction, or submission by the alternate designated representative shall be deemed to be a representation, action, inaction, or submission by the designated representative.
(2) Except in this section, whenever the term “designated representative” is used in this part, the term shall be construed to include the designated representative or any alternate designated representative.
(g) Changing a designated representative or alternate designated representative. The designated representative or alternate designated representative identified in a complete certificate of representation under this section for a facility or supplier received by the Administrator may be changed at any time upon receipt by the Administrator of another later signed, complete certificate of representation under this section for the facility or supplier. Notwithstanding any such change, all representations, actions, inactions, and submissions by the previous designated representative or the previous alternate designated representative of the facility or supplier before the time and date when the Administrator receives such later signed certificate of representation shall be binding on the new designated representative and the owners and operators of the facility or supplier.
(h) Changes in owners and operators. In the event an owner or operator of the facility or supplier is not included in the list of owners and operators in the certificate of representation under this section for the facility or supplier, such owner or operator shall be deemed to be subject to and bound by the certificate of representation, the representations, actions, inactions, and submissions of the designated representative and any alternate designated representative of the facility or supplier, as if the owner or operator were included in such list. Within 90 days after any change in the owners and operators of the facility or supplier (including the addition of a new owner or operator), the designated representative or any alternate designated representative shall submit a certificate of representation that is complete under this section except that such list shall be amended to reflect the change. If the designated representative or alternate designated representative determines at any time that an owner or operator of the facility or supplier is not included in such list and such exclusion is not the result of a change in the owners and operators, the designated representative or any alternate designated representative shall submit, within 90 days of making such determination, a certificate of representation that is complete under this section except that such list shall be amended to include such owner or operator.
(i) Certificate of representation. A certificate of representation shall be complete if it includes the following elements in a format prescribed by the Administrator in accordance with this section:
(1) Identification of the facility or supplier for which the certificate of representation is submitted.
(2) The name, organization name (company affiliation-employer), address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of the designated representative and any alternate designated representative.
(3) A list of the owners and operators of the facility or supplier identified in paragraph (i)(1) of this section, provided that, if the list includes the operators of the facility or supplier and the owners with control of the facility or supplier, the failure to include any other owners shall not make the certificate of representation incomplete.
(4) The following certification statements by the designated representative and any alternate designated representative:
(i) “I certify that I was selected as the designated representative or alternate designated representative, as applicable, by an agreement binding on the owners and operators of the facility or supplier, as applicable.”
(ii) “I certify that I have all the necessary authority to carry out my duties and responsibilities under 40 CFR part 98 on behalf of the owners and operators of the facility or supplier, as applicable, and that each such owner and operator shall be fully bound by my representations, actions, inactions, or submissions.”
(iii) “I certify that the owners and operators of the facility or supplier, as applicable, shall be bound by any order issued to me by the Administrator or a court regarding the facility or supplier.”
(iv) “If there are multiple owners and operators of the facility or supplier, as applicable, I certify that I have given a written notice of my selection as the ‘designated representative’ or ‘alternate designated representative’, as applicable, and of the agreement by which I was selected to each owner and operator of the facility or supplier.”
(5) The signature of the designated representative and any alternate designated representative and the dates signed.
(6) A list of the subparts that the owners and operators anticipate will be included in the annual GHG report. The list of potentially applicable subparts is required only for an initial certificate of representation that is submitted after January 1, 2018 (i.e., for a facility or supplier that previously was not registered under this part). The list of potentially applicable subparts does not need to be revised with revisions to the COR or if the actual applicable subparts change.
(j) Documents of agreement. Unless otherwise required by the Administrator, documents of agreement referred to in the certificate of representation shall not be submitted to the Administrator. The Administrator shall not be under any obligation to review or evaluate the sufficiency of such documents, if submitted.
(k) Binding nature of the certificate of representation. Once a complete certificate of representation under this section for a facility or supplier has been received, the Administrator will rely on the certificate of representation unless and until a later signed, complete certificate of representation under this section for the facility or supplier is received by the Administrator.
(l) Objections concerning a designated representative. (1) Except as provided in paragraph (g) of this section, no objection or other communication submitted to the Administrator concerning the authorization, or any representation, action, inaction, or submission, of the designated representative or alternate designated representative shall affect any representation, action, inaction, or submission of the designated representative or alternate designated representative, or the finality of any decision or order by the Administrator under this part.
(2) The Administrator will not adjudicate any private legal dispute concerning the authorization or any representation, action, inaction, or submission of any designated representative or alternate designated representative.
(m) Delegation by designated representative and alternate designated representative. (1) A designated representative or an alternate designated representative may delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator provided for or required under this part, except for a submission under this paragraph.
(2) In order to delegate his or her own authority, to one or more individuals, to submit an electronic submission to the Administrator in accordance with paragraph (m)(1) of this section, the designated representative or alternate designated representative must submit electronically to the Administrator a notice of delegation, in a format prescribed by the Administrator, that includes the following elements:
(i) The name, organization name (company affiliation-employer) address, e-mail address (if any), telephone number, and facsimile transmission number (if any) of such designated representative or alternate designated representative.
(ii) The name, address, e-mail address, telephone number, and facsimile transmission number (if any) of each such individual (referred to as an “agent”).
(iii) For each such individual, a list of the type or types of electronic submissions under paragraph (m)(1) of this section for which authority is delegated to him or her.
(iv) For each type of electronic submission listed in accordance with paragraph (m)(2)(iii) of this section, the facility or supplier for which the electronic submission may be made.
(v) The following certification statements by such designated representative or alternate designated representative:
(A) “I agree that any electronic submission to the Administrator that is by an agent identified in this notice of delegation and of a type listed, and for a facility or supplier designated, for such agent in this notice of delegation and that is made when I am a designated representative or alternate designated representative, as applicable, and before this notice of delegation is superseded by another notice of delegation under § 98.4(m)(3) shall be deemed to be an electronic submission certified, signed, and submitted by me.”
(B) “Until this notice of delegation is superseded by a later signed notice of delegation under § 98.4(m)(3), I agree to maintain an e-mail account and to notify the Administrator immediately of any change in my e-mail address unless all delegation of authority by me under § 98.4(m) is terminated.”
(vi) The signature of such designated representative or alternate designated representative and the date signed.
(3) A notice of delegation submitted in accordance with paragraph (m)(2) of this section shall be effective, with regard to the designated representative or alternate designated representative identified in such notice, upon receipt of such notice by the Administrator and until receipt by the Administrator of another such notice that was signed later by such designated representative or alternate designated representative, as applicable. The later signed notice of delegation may replace any previously identified agent, add a new agent, or eliminate entirely any delegation of authority.
(4) Any electronic submission covered by the certification in paragraph (m)(2)(v)(A) of this section and made in accordance with a notice of delegation effective under paragraph (m)(3) of this section shall be deemed to be an electronic submission certified, signed, and submitted by the designated representative or alternate designated representative submitting such notice of delegation.
§ 98.5 How is the report submitted?
(a) Each GHG report and certificate of representation for a facility or supplier must be submitted electronically in accordance with the requirements of § 98.4 and in a format specified by the Administrator.
(b) For reporting year 2014 and thereafter, unless a later year is specified in the applicable recordkeeping section, you must enter into verification software specified by the Administrator the data specified in the verification software records provision in each applicable recordkeeping section. For each data element entered into the verification software, if the software produces a warning message for the data value and you elect not to revise the data value, you may provide an explanation in the verification software of why the data value is not being revised.
§ 98.6 Definitions.
All terms used in this part shall have the same meaning given in the Clean Air Act and in this section.
Absorbent circulation pump means a pump commonly powered by natural gas pressure that circulates the absorbent liquid between the absorbent regenerator and natural gas contactor.
Accuracy of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that the mean of repeat measurements made by a device or technique are within 95 percent of the range bounded by the true value plus or minus the specified level.
Acid Rain Program means the program established under title IV of the Clean Air Act, and implemented under parts 72 through 78 of this chapter for the reduction of sulfur dioxide and nitrogen oxides emissions.
Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator’s authorized representative.
AGA means the American Gas Association
Agricultural by-products means those parts of arable crops that are not used for the primary purpose of producing food. Agricultural by-products include, but are not limited to, oat, corn and wheat straws, bagasse, peanut shells, rice and coconut husks, soybean hulls, palm kernel cake, cottonseed and sunflower seed cake, and pomace.
Air injected flare means a flare in which air is blown into the base of a flare stack to induce complete combustion of gas.
Alkali bypass means a duct between the feed end of the kiln and the preheater tower through which a portion of the kiln exit gas stream is withdrawn and quickly cooled by air or water to avoid excessive buildup of alkali, chloride and/or sulfur on the raw feed. This may also be referred to as the “kiln exhaust gas bypass.”
Anaerobic digester means the system where wastes are collected and anaerobically digested in large containment vessels or covered lagoons. Anaerobic digesters stabilize waste by the microbial reduction of complex organic compounds to CO2 and CH4, which is captured and may be flared or used as fuel. Anaerobic digestion systems, include but are not limited to covered lagoon, complete mix, plug flow, and fixed film digesters.
Anaerobic lagoon, with respect to subpart JJ of this part, means a type of liquid storage system component that is designed and operated to stabilize wastes using anaerobic microbial processes. Anaerobic lagoons may be designed for combined stabilization and storage with varying lengths of retention time (up to a year or greater), depending on the climate region, volatile solids loading rate, and other operational factors.
Anode effect is a process upset condition of an aluminum electrolysis cell caused by too little alumina dissolved in the electrolyte. The anode effect begins when the voltage rises rapidly and exceeds a threshold voltage, typically 8 volts.
Anode Effect Minutes per Cell Day (24 hours) are the total minutes during which an electrolysis cell voltage is above the threshold voltage, typically 8 volts.
ANSI means the American National Standards Institute.
API means the American Petroleum Institute.
ASABE means the American Society of Agricultural and Biological Engineers.
ASME means the American Society of Mechanical Engineers.
ASTM means the American Society of Testing and Materials.
Asphalt means a dark brown-to-black cement-like material obtained by petroleum processing and containing bitumens as the predominant component. It includes crude asphalt as well as the following finished products: cements, fluxes, the asphalt content of emulsions (exclusive of water), and petroleum distillates blended with asphalt to make cutback asphalts.
Aviation Gasoline means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in aviation reciprocating engines. Specifications can be found in ASTM Specification D910-07a, Standard Specification for Aviation Gasolines (incorporated by reference, see § 98.7).
B
Basic oxygen furnace means any refractory-lined vessel in which high-purity oxygen is blown under pressure through a bath of molten iron, scrap metal, and fluxes to produce steel.
bbl means barrel.
Biodiesel means a mono-akyl ester derived from biomass and conforming to ASTM D6751-08, Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels.
Biogenic CO
Biomass means non-fossilized and biodegradable organic material originating from plants, animals or micro-organisms, including products, by-products, residues and waste from agriculture, forestry and related industries as well as the non-fossilized and biodegradable organic fractions of industrial and municipal wastes, including gases and liquids recovered from the decomposition of non-fossilized and biodegradable organic material.
Blast furnace means a furnace that is located at an integrated iron and steel plant and is used for the production of molten iron from iron ore pellets and other iron bearing materials.
Blendstocks are petroleum products used for blending or compounding into finished motor gasoline. These include RBOB (reformulated blendstock for oxygenate blending) and CBOB (conventional blendstock for oxygenate blending), but exclude oxygenates, butane, and pentanes plus.
Blendstocks – Others are products used for blending or compounding into finished motor gasoline that are not defined elsewhere. Excludes Gasoline Treated as Blendstock (GTAB), Diesel Treated as Blendstock (DTAB), conventional blendstock for oxygenate blending (CBOB), reformulated blendstock for oxygenate blending (RBOB), oxygenates (e.g. fuel ethanol and methyl tertiary butyl ether), butane, and pentanes plus.
Blowdown mean the act of emptying or depressuring a vessel. This may also refer to the discarded material such as blowdown water from a boiler or cooling tower.
Blowdown vent stack emissions mean natural gas and/or CO
British Thermal Unit or Btu means the quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit at about 39.2 degrees Fahrenheit.
Bulk, with respect to industrial GHG suppliers and CO2 suppliers, means the transfer of a product inside containers, including but not limited to tanks, cylinders, drums, and pressure vessels.
Bulk natural gas liquid or NGL refers to mixtures of hydrocarbons that have been separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods. Generally, such liquids consist of ethane, propane, butanes, and pentanes plus. Bulk NGL is sold to fractionators or to refineries and petrochemical plants where the fractionation takes place.
Butane, or n-Butane, is a paraffinic straight-chain hydrocarbon with molecular formula C
Butylene, or n-Butylene, is an olefinic straight-chain hydrocarbon with molecular formula C
By-product coke oven battery means a group of ovens connected by common walls, where coal undergoes destructive distillation under positive pressure to produce coke and coke oven gas from which by-products are recovered.
Calcination means the process of thermally treating minerals to decompose carbonates from ore.
Calculation methodology means a methodology prescribed under the section “Calculating GHG Emissions” in any subpart of part 98.
Calibrated bag means a flexible, non-elastic, anti-static bag of a calibrated volume that can be affixed to an emitting source such that the emissions inflate the bag to its calibrated volume.
Carbon dioxide equivalent or CO
Carbon dioxide production well means any hole drilled in the earth for the primary purpose of extracting carbon dioxide from a geologic formation or group of formations which contain deposits of carbon dioxide.
Carbon dioxide production well facility means one or more carbon dioxide production wells that are located on one or more contiguous or adjacent properties, which are under the control of the same entity. Carbon dioxide production wells located on different oil and gas leases, mineral fee tracts, lease tracts, subsurface or surface unit areas, surface fee tracts, surface lease tracts, or separate surface sites, whether or not connected by a road, waterway, power line, or pipeline, shall be considered part of the same CO
Carbon dioxide stream means carbon dioxide that has been captured from an emission source (e.g. a power plant or other industrial facility) or extracted from a carbon dioxide production well plus incidental associated substances either derived from the source materials and the capture process or extracted with the carbon dioxide.
Carbon share means the percent of total mass that carbon represents in any product.
Carbonate means compounds containing the radical CO
Carbonate-based mineral means any of the following minerals used in the manufacture of glass: Calcium carbonate (CaCO
Carbonate-based mineral mass fraction means the following: For limestone, the mass fraction of calcium carbonate (CaCO
Carbonate-based raw material means any of the following materials used in the manufacture of glass: Limestone, dolomite, soda ash, barium carbonate, potassium carbonate, lithium carbonate, and strontium carbonate.
Carbonofluoridates means fluorinated GHGs that are composed of a -OCF(O) group (carbonyl group with a single-bonded oxygen atom and a fluorine atom) that is linked on the single-bonded oxygen to another hydrocarbon group in which one or more of the hydrogen atoms may be replaced by fluorine atoms.
Catalytic cracking unit means a refinery process unit in which petroleum derivatives are continuously charged and hydrocarbon molecules in the presence of a catalyst are fractured into smaller molecules, or react with a contact material suspended in a fluidized bed to improve feedstock quality for additional processing and the catalyst or contact material is continuously regenerated by burning off coke and other deposits. Catalytic cracking units include both fluidized bed systems, which are referred to as fluid catalytic cracking units (FCCU), and moving bed systems, which are also referred to as thermal catalytic cracking units. The unit includes the riser, reactor, regenerator, air blowers, spent catalyst or contact material stripper, catalyst or contact material recovery equipment, and regenerator equipment for controlling air pollutant emissions and for heat recovery.
CBOB-Summer (conventional blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Conventional-Summer.
CBOB-Winter (conventional blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Conventional-Winter.
Cement kiln dust means non-calcined to fully calcined dust produced in the kiln or pyroprocessing line. Cement kiln dust is a fine-grained, solid, highly alkaline material removed from the cement kiln exhaust gas by scrubbers (filtration baghouses and/or electrostatic precipitators).
Centrifugal compressor means any equipment that increases the pressure of a process natural gas or CO
Centrifugal compressor dry seal emissions mean natural gas or CO
Centrifugal compressor dry seals mean a series of rings around the compressor shaft where it exits the compressor case that operates mechanically under the opposing forces to prevent natural gas or CO
Centrifugal compressor wet seal degassing vent emissions means emissions that occur when the high-pressure oil barriers for centrifugal compressors are depressurized to release absorbed natural gas or CO
Certified standards means calibration gases certified by the manufacturer of the calibration gases to be accurate to within 2 percent of the value on the label or calibration gases.
CH
Chemical recovery combustion unit means a combustion device, such as a recovery furnace or fluidized-bed reactor where spent pulping liquor from sulfite or semi-chemical pulping processes is burned to recover pulping chemicals.
Chemical recovery furnace means an enclosed combustion device where concentrated spent liquor produced by the kraft or soda pulping process is burned to recover pulping chemicals and produce steam. Includes any recovery furnace that burns spent pulping liquor produced from both the kraft and soda pulping processes.
Chloride process means a production process where titanium dioxide is produced using calcined petroleum coke and chlorine as raw materials.
City gate means a location at which natural gas ownership or control passes from one party to another, neither of which is the ultimate consumer. In this rule, in keeping with common practice, the term refers to a point or measuring station at which a local gas distribution utility receives gas from a natural gas pipeline company or transmission system. Meters at the city gate station measure the flow of natural gas into the local distribution company system and typically are used to measure local distribution company system sendout to customers.
CO
Coal means all solid fuels classified as anthracite, bituminous, sub-bituminous, or lignite by the American Society for Testing and Materials Designation ASTM D388-05 Standard Classification of Coals by Rank (incorporated by reference, see § 98.7).
COD means the chemical oxygen demand as determined using methods specified pursuant to 40 CFR part 136.
Cogeneration unit means a unit that produces electrical energy and useful thermal energy for industrial, commercial, or heating or cooling purposes, through the sequential or simultaneous use of the original fuel energy.
Coke burn-off means the coke removed from the surface of a catalyst by combustion during catalyst regeneration. Coke burn-off also means the coke combusted in fluid coking unit burner.
Cokemaking means the production of coke from coal in either a by-product coke oven battery or a non-recovery coke oven battery.
Commercial applications means executing a commercial transaction subject to a contract. A commercial application includes transferring custody of a product from one facility to another if it otherwise meets the definition.
Company records means, in reference to the amount of fuel consumed by a stationary combustion unit (or by a group of such units), a complete record of the methods used, the measurements made, and the calculations performed to quantify fuel usage. Company records may include, but are not limited to, direct measurements of fuel consumption by gravimetric or volumetric means, tank drop measurements, and calculated values of fuel usage obtained by measuring auxiliary parameters such as steam generation or unit operating hours. Fuel billing records obtained from the fuel supplier qualify as company records.
Connector means to flanged, screwed, or other joined fittings used to connect pipe line segments, tubing, pipe components (such as elbows, reducers, “T’s” or valves) or a pipe line and a piece of equipment or an instrument to a pipe, tube or piece of equipment. A common connector is a flange. Joined fittings welded completely around the circumference of the interface are not considered connectors for the purpose of this part.
Container glass means glass made of soda-lime recipe, clear or colored, which is pressed and/or blown into bottles, jars, ampoules, and other products listed in North American Industry Classification System 327213 (NAICS 327213).
Continuous bleed means a continuous flow of pneumatic supply natural gas to the process control device (e.g. level control, temperature control, pressure control) where the supply gas pressure is modulated by the process condition, and then flows to the valve controller where the signal is compared with the process set-point to adjust gas pressure in the valve actuator.
Continuous emission monitoring system or CEMS means the total equipment required to sample, analyze, measure, and provide, by means of readings recorded at least once every 15 minutes, a permanent record of gas concentrations, pollutant emission rates, or gas volumetric flow rates from stationary sources.
Continuous glass melting furnace means a glass melting furnace that operates continuously except during periods of maintenance, malfunction, control device installation, reconstruction, or rebuilding.
Conventional-Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40, but which meet summer RVP standards required under 40 CFR 80.27 or as specified by the state.
Conventional-Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which do not meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 or the summer RVP standards required under 40 CFR 80.27 or as specified by the state.
Crude oil means a mixture of hydrocarbons that exists in liquid phase in natural underground reservoirs and remains liquid at atmospheric pressure after passing through surface separating facilities. (1) Depending upon the characteristics of the crude stream, it may also include any of the following:
(i) Small amounts of hydrocarbons that exist in gaseous phase in natural underground reservoirs but are liquid at atmospheric conditions (temperature and pressure) after being recovered from oil well (casing-head) gas in lease separators and are subsequently commingled with the crude stream without being separately measured. Lease condensate recovered as a liquid from natural gas wells in lease or field separation facilities and later mixed into the crude stream is also included.
(ii) Small amounts of non-hydrocarbons, such as sulfur and various metals.
(iii) Drip gases, and liquid hydrocarbons produced from tar sands, oil sands, gilsonite, and oil shale.
(iv) Petroleum products that are received or produced at a refinery and subsequently injected into a crude supply or reservoir by the same refinery owner or operator.
(2) Liquids produced at natural gas processing plants are excluded. Crude oil is refined to produce a wide array of petroleum products, including heating oils; gasoline, diesel and jet fuels; lubricants; asphalt; ethane, propane, and butane; and many other products used for their energy or chemical content.
Daily spread means a manure management system component in which manure is routinely removed from a confinement facility and is applied to cropland or pasture within 24 hours of excretion.
Day means any consistently designated 24 hour period during which an emission unit is operated.
Decarburization vessel means any vessel used to further refine molten steel with the primary intent of reducing the carbon content of the steel, including but not limited to vessels used for argon-oxygen decarburization and vacuum oxygen decarburization.
Deep bedding systems for cattle swine means a manure management system in which, as manure accumulates, bedding is continually added to absorb moisture over a production cycle and possibly for as long as 6 to 12 months. This manure management system also is known as a bedded pack manure management system and may be combined with a dry lot or pasture.
Degasification system means the entirety of the equipment that is used to drain gas from underground coal mines. This includes all degasification wells and gob gas vent holes at the underground coal mine. Degasification systems include gob and premine surface drainage wells, gob and premine in-mine drainage wells, and in-mine gob and premine cross-measure borehole wells.
Degradable organic carbon (DOC) means the fraction of the total mass of a waste material that can be biologically degraded.
Dehydrator means a device in which a liquid absorbent (including desiccant, ethylene glycol, diethylene glycol, or triethylene glycol) directly contacts a natural gas stream to absorb water vapor.
Dehydrator vent emissions means natural gas and CO
Delayed coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is produced in a series of closed, batch system reactors. A delayed coking unit consists of the coke drums and ancillary equipment associated with a single fractionator.
De-methanizer means the natural gas processing unit that separates methane rich residue gas from the heavier hydrocarbons (e.g., ethane, propane, butane, pentane-plus) in feed natural gas stream.
Density means the mass contained in a given unit volume (mass/volume).
Desiccant means a material used in solid-bed dehydrators to remove water from raw natural gas by adsorption or absorption. Desiccants include activated alumina, pelletized calcium chloride, lithium chloride and granular silica gel material. Wet natural gas is passed through a bed of the granular or pelletized solid adsorbent or absorbent in these dehydrators. As the wet gas contacts the surface of the particles of desiccant material, water is adsorbed on the surface or absorbed and dissolves the surface of these desiccant particles. Passing through the entire desiccant bed, almost all of the water is adsorbed onto or absorbed into the desiccant material, leaving the dry gas to exit the contactor.
Destruction means:
(1) With respect to landfills and manure management, the combustion of methane in any on-site or off-site combustion technology. Destroyed methane includes, but is not limited to, methane combusted by flaring, methane destroyed by thermal oxidation, methane combusted for use in on-site energy or heat production technologies, methane that is conveyed through pipelines (including natural gas pipelines) for off-site combustion, and methane that is collected for any other on-site or off-site use as a fuel.
(2) With respect to fluorinated GHGs, the expiration of a fluorinated GHG to the destruction efficiency actually achieved. Such destruction does not result in a commercially useful end product.
Destruction device, for the purposes of subparts II and TT of this part, means a flare, thermal oxidizer, boiler, turbine, internal combustion engine, or any other combustion unit used to destroy or oxidize methane contained in landfill gas or wastewater biogas.
Destruction efficiency means the efficiency with which a destruction device reduces the mass of a greenhouse gas fed into the device. Destruction efficiency, or flaring destruction efficiency, refers to the fraction of the gas that leaves the flare partially or fully oxidized. The destruction efficiency is expressed in Equation A-2 of this section:
Diesel – Other is any distillate fuel oil not defined elsewhere, including Diesel Treated as Blendstock (DTAB).
DIPE (diisopropyl ether, (CH
Direct liquefaction means the conversion of coal directly into liquids, rather than passing through an intermediate gaseous state.
Direct reduction furnace means a high temperature furnace typically fired with natural gas to produce solid iron from iron ore or iron ore pellets and coke, coal, or other carbonaceous materials.
Distillate fuel oil means a classification for one of the petroleum fractions produced in conventional distillation operations and from crackers and hydrotreating process units. The generic term distillate fuel oil includes kerosene, kerosene-type jet fuel, diesel fuels (Diesel Fuels No. 1, No. 2, and No. 4), and fuel oils (Fuel Oils No. 1, No. 2, and No. 4).
Distillate Fuel No. 1 has a maximum distillation temperature of 550 °F at the 90 percent recovery point and a minimum flash point of 100 °F and includes fuels commonly known as Diesel Fuel No. 1 and Fuel Oil No. 1, but excludes kerosene. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 ppm).
Distillate Fuel No. 2 has a minimum and maximum distillation temperature of 540 °F and 640 °F at the 90 percent recovery point, respectively, and includes fuels commonly known as Diesel Fuel No. 2 and Fuel Oil No. 2. This fuel is further subdivided into categories of sulfur content: High Sulfur (greater than 500 ppm), Low Sulfur (less than or equal to 500 ppm and greater than 15 ppm), and Ultra Low Sulfur (less than or equal to 15 ppm).
Distillate Fuel No. 4 is a distillate fuel oil made by blending distillate fuel oil and residual fuel oil, with a minimum flash point of 131 °F.
DOC
Dry lot means a manure management system component consisting of a paved or unpaved open confinement area without any significant vegetative cover where accumulating manure may be removed periodically.
Electric arc furnace (EAF) means a furnace that produces molten alloy metal and heats the charge materials with electric arcs from carbon electrodes.
Electric arc furnace steelmaking means the production of carbon, alloy, or specialty steels using an EAF. This definition excludes EAFs at steel foundries and EAFs used to produce nonferrous metals.
Electrothermic furnace means a furnace that heats the charged materials with electric arcs from carbon electrodes.
Emergency generator means a stationary combustion device, such as a reciprocating internal combustion engine or turbine that serves solely as a secondary source of mechanical or electrical power whenever the primary energy supply is disrupted or discontinued during power outages or natural disasters that are beyond the control of the owner or operator of a facility. An emergency generator operates only during emergency situations, for training of personnel under simulated emergency conditions, as part of emergency demand response procedures, or for standard performance testing procedures as required by law or by the generator manufacturer. A generator that serves as a back-up power source under conditions of load shedding, peak shaving, power interruptions pursuant to an interruptible power service agreement, or scheduled facility maintenance shall not be considered an emergency generator.
Emergency equipment means any auxiliary fossil fuel-powered equipment, such as a fire pump, that is used only in emergency situations.
ETBE (ethyl tertiary butyl ether, (CH
Ethane is a paraffinic hydrocarbon with molecular formula C
Ethanol is an anhydrous alcohol with molecular formula C
Ethylene is an olefinic hydrocarbon with molecular formula C
Ex refinery gate means the point at which a petroleum product leaves the refinery.
Experimental furnace means a glass melting furnace with the sole purpose of operating to evaluate glass melting processes, technologies, or glass products. An experimental furnace does not produce glass that is sold (except for further research and development purposes) or that is used as a raw material for non-experimental furnaces.
Export means to transport a product from inside the United States to persons outside the United States, excluding any such transport on behalf of the United States military including foreign military sales under the Arms Export Control Act.
Exporter means any person, company or organization of record that transfers for sale or for other benefit, domestic products from the United States to another country or to an affiliate in another country, excluding any such transfers on behalf of the United States military or military purposes including foreign military sales under the Arms Export Control Act. An exporter is not the entity merely transporting the domestic products, rather an exporter is the entity deriving the principal benefit from the transaction.
Facility means any physical property, plant, building, structure, source, or stationary equipment located on one or more contiguous or adjacent properties in actual physical contact or separated solely by a public roadway or other public right-of-way and under common ownership or common control, that emits or may emit any greenhouse gas. Operators of military installations may classify such installations as more than a single facility based on distinct and independent functional groupings within contiguous military properties.
Feed means the prepared and mixed materials, which include but are not limited to materials such as limestone, clay, shale, sand, iron ore, mill scale, cement kiln dust and flyash, that are fed to the kiln. Feed does not include the fuels used in the kiln to produce heat to form the clinker product.
Feedstock means raw material inputs to a process that are transformed by reaction, oxidation, or other chemical or physical methods into products and by-products. Supplemental fuel burned to provide heat or thermal energy is not a feedstock.
Fischer-Tropsch process means a catalyzed chemical reaction in which synthesis gas, a mixture of carbon monoxide and hydrogen, is converted into liquid hydrocarbons of various forms.
Flare means a combustion device, whether at ground level or elevated, that uses an open flame to burn combustible gases with combustion air provided by uncontrolled ambient air around the flame.
Flat glass means glass made of soda-lime recipe and produced into continuous flat sheets and other products listed in NAICS 327211.
Flowmeter means a device that measures the mass or volumetric rate of flow of a gas, liquid, or solid moving through an open or closed conduit (e.g. flowmeters include, but are not limited to, rotameters, turbine meters, coriolis meters, orifice meters, ultra-sonic flowmeters, and vortex flowmeters).
Fluid coking unit means one or more refinery process units in which high molecular weight petroleum derivatives are thermally cracked and petroleum coke is continuously produced in a fluidized bed system. The fluid coking unit includes equipment for controlling air pollutant emissions and for heat recovery on the fluid coking burner exhaust vent. There are two basic types of fluid coking units: A traditional fluid coking unit in which only a small portion of the coke produced in the unit is burned to fuel the unit and the fluid coking burner exhaust vent is directed to the atmosphere (after processing in a CO boiler or other air pollutant control equipment) and a flexicoking unit in which an auxiliary burner is used to partially combust a significant portion of the produced petroleum coke to generate a low value fuel gas that is used as fuel in other combustion sources at the refinery.
Fluorinated acetates means fluorinated GHGs that are composed of an acetate group with one or more valence locations on the methyl group of the acetate occupied by fluorine atoms (e.g., CFH
Fluorinated alcohols other than fluorotelomer alcohols means fluorinated GHGs that include an alcohol functional group (-OH) and that do not meet the definition of fluorotelomer alcohols.
Fluorinated formates means fluorinated GHGs that are composed of a formate group -OCH(O) (carbonyl group with a single-bonded oxygen, and with a hydrogen atom) that is linked on the single-bonded oxygen atom to a hydrocarbon group in which one or more of the hydrogen atoms in the hydrocarbon group is replaced by fluorine atoms; the typical formula for fluorinated formates is F
Fluorinated greenhouse gas means sulfur hexafluoride (SF
Fluorinated greenhouse gas (GHG) group means one of the following sets of fluorinated GHGs: Fully fluorinated GHGs; saturated hydrofluorocarbons with 2 or fewer carbon-hydrogen bonds; saturated hydrofluorocarbons with 3 or more carbon-hydrogen bonds; saturated hydrofluoroethers and hydrochlorofluoroethers with 1 carbon-hydrogen bond; saturated hydrofluoroethers and hydrochlorofluoroethers with 2 carbon-hydrogen bonds; saturated hydrofluoroethers and hydrochlorofluoroethers with 3 or more carbon-hydrogen bonds; fluorinated formates; fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than fluorotelomer alcohols; unsaturated PFCs, unsaturated HFCs, unsaturated HCFCs, unsaturated halogenated ethers, unsaturated halogenated esters, fluorinated aldehydes, and fluorinated ketones; fluorotelomer alcohols; fluorinated GHGs with carbon-iodine bonds; or other fluorinated GHGs.
Fluorotelomer alcohols means fluorinated GHGs with the chemical formula C
Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material, for purpose of creating useful heat.
Fractionators means plants that produce fractionated natural gas liquids (NGLs) extracted from produced natural gas and separate the NGLs individual component products: ethane, propane, butanes and pentane-plus (C5 + ). Plants that only process natural gas but do not fractionate NGLs further into component products are not considered fractionators. Some fractionators do not process production gas, but instead fractionate bulk NGLs received from natural gas processors. Some fractionators both process natural gas and fractionate bulk NGLs received from other plants.
Fuel means solid, liquid or gaseous combustible material.
Fuel gas means gas generated at a petroleum refinery or petrochemical plant and that is combusted separately or in any combination with any type of gas.
Fuel gas system means a system of compressors, piping, knock-out pots, mix drums, and, if necessary, units used to remove sulfur contaminants from the fuel gas (e.g., amine scrubbers) that collects fuel gas from one or more sources for treatment, as necessary, and transport to a stationary combustion unit. A fuel gas system may have an overpressure vent to a flare but the primary purpose for a fuel gas system is to provide fuel to the various combustion units at the refinery or petrochemical plant.
Fully fluorinated GHGs means fluorinated GHGs that contain only single bonds and in which all available valence locations are filled by fluorine atoms. This includes but is not limited to: Saturated perfluorocarbons; SF
Furnace slag means a by-product formed in metal melting furnaces when slagging agents, reducing agents, and/or fluxes (e.g., coke ash, limestone, silicates) are added to remove impurities from the molten metal.
Gas collection system or landfill gas collection system means a system of pipes used to collect landfill gas from different locations in the landfill by means of a fan or similar mechanical draft equipment (forced convection) to a single location for treatment (thermal destruction) or use. Landfill gas collection systems may also include knock-out or separator drums and/or a compressor. A single landfill may have multiple gas collection systems. Landfill gas collection systems do not include “passive” systems, whereby landfill gas flows naturally (without forced convection) to the surface of the landfill where an opening or pipe (vent) is installed to allow for the flow of landfill gas to the atmosphere or to a remote flare installed to combust landfill gas that is passively emitted from the vent. Landfill gas collection systems also do not include “active venting” systems, whereby landfill gas is conveyed to the surface of the landfill using forced convection, but the landfill gas is never recovered or thermally destroyed prior to release to the atmosphere.
Gas conditions mean the actual temperature, volume, and pressure of a gas sample.
Gas-fired unit means a stationary combustion unit that derives more than 50 percent of its annual heat input from the combustion of gaseous fuels, and the remainder of its annual heat input from the combustion of fuel oil or other liquid fuels.
Gas monitor means an instrument that continuously measures the concentration of a particular gaseous species in the effluent of a stationary source.
Gas to oil ratio (GOR) means the ratio of the volume of gas at standard temperature and pressure that is produced from a volume of oil when depressurized to standard temperature and pressure.
Gaseous fuel means a material that is in the gaseous state at standard atmospheric temperature and pressure conditions and that is combusted to produce heat and/or energy.
Gasification means the conversion of a solid or liquid raw material into a gas.
Gasoline – Other is any gasoline that is not defined elsewhere, including GTAB (gasoline treated as blendstock).
Glass melting furnace means a unit comprising a refractory-lined vessel in which raw materials are charged and melted at high temperature to produce molten glass.
Glass produced means the weight of glass exiting a glass melting furnace.
Global warming potential or GWP means the ratio of the time-integrated radiative forcing from the instantaneous release of one kilogram of a trace substance relative to that of one kilogram of a reference gas (i.e., CO
GPA means the Gas Processors Association.
Greenhouse gas or GHG means carbon dioxide (CO
GTBA (gasoline-grade tertiary butyl alcohol, (CH
Heavy Gas Oils are petroleum distillates with an approximate boiling range from 651 °F to 1,000 °F.
Heel means the amount of gas that remains in a shipping container after it is discharged or off-loaded (that is no more than ten percent of the volume of the container).
High-bleed pneumatic devices are automated, continuous bleed flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate in excess of 6 standard cubic feet per hour.
High heat value or HHV means the high or gross heat content of the fuel with the heat of vaporization included. The water is assumed to be in a liquid state.
Hydrofluorocarbons or HFCs means a class of GHGs consisting of hydrogen, fluorine, and carbon.
Import means, to land on, bring into, or introduce into, any place subject to the jurisdiction of the United States whether or not such landing, bringing, or introduction constitutes an importation within the meaning of the customs laws of the United States, with the following exemptions:
(1) Off-loading used or excess fluorinated GHGs or nitrous oxide of U.S. origin from a ship during servicing.
(2) Bringing fluorinated GHGs or nitrous oxide into the U.S. from Mexico where the fluorinated GHGs or nitrous oxide had been admitted into Mexico in bond and were of U.S. origin.
(3) Bringing fluorinated GHGs or nitrous oxide into the U.S. when transported in a consignment of personal or household effects or in a similar non-commercial situation normally exempted from U.S. Customs attention.
(4) Bringing fluorinated GHGs or nitrous into U.S. jurisdiction exclusively for U. S. military purposes.
Importer means any person, company, or organization of record that for any reason brings a product into the United States from a foreign country, excluding introduction into U.S. jurisdiction exclusively for United States military purposes. An importer is the person, company, or organization primarily liable for the payment of any duties on the merchandise or an authorized agent acting on their behalf. The term includes, as appropriate:
(1) The consignee.
(2) The importer of record.
(3) The actual owner.
(4) The transferee, if the right to draw merchandise in a bonded warehouse has been transferred.
Indurating furnace means a furnace where unfired taconite pellets, called green balls, are hardened at high temperatures to produce fired pellets for use in a blast furnace. Types of indurating furnaces include straight gate and grate kiln furnaces.
Industrial greenhouse gases means nitrous oxide or any fluorinated greenhouse gas.
In-line kiln/raw mill means a system in a portland cement production process where a dry kiln system is integrated with the raw mill so that all or a portion of the kiln exhaust gases are used to perform the drying operation of the raw mill, with no auxiliary heat source used. In this system the kiln is capable of operating without the raw mill operating, but the raw mill cannot operate without the kiln gases, and consequently, the raw mill does not generate a separate exhaust gas stream.
Intermittent bleed pneumatic devices mean automated flow control devices powered by pressurized natural gas and used for automatically maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. These are snap-acting or throttling devices that discharge all or a portion of the full volume of the actuator intermittently when control action is necessary, but does not bleed continuously.
Isobutane is a paraffinic branch chain hydrocarbon with molecular formula C
Isobutylene is an olefinic branch chain hydrocarbon with molecular formula C
Kerosene is a light petroleum distillate with a maximum distillation temperature of 400 °F at the 10-percent recovery point, a final maximum boiling point of 572 °F, a minimum flash point of 100 °F, and a maximum freezing point of −22 °F. Included are No. 1-K and No. 2-K, distinguished by maximum sulfur content (0.04 and 0.30 percent of total mass, respectively), as well as all other grades of kerosene called range or stove oil. Excluded is kerosene-type jet fuel (see definition herein).
Kerosene-type jet fuel means a kerosene-based product used in commercial and military turbojet and turboprop aircraft. The product has a maximum distillation temperature of 400 °F at the 10 percent recovery point and a final maximum boiling point of 572 °F. Included are Jet A, Jet A-1, JP-5, and JP-8.
Kiln means an oven, furnace, or heated enclosure used for thermally processing a mineral or mineral-based substance.
Landfill means an area of land or an excavation in which wastes are placed for permanent disposal and that is not a land application unit, surface impoundment, injection well, or waste pile as those terms are defined under 40 CFR 257.2.
Landfill gas means gas produced as a result of anaerobic decomposition of waste materials in the landfill. Landfill gas generally contains 40 to 60 percent methane on a dry basis, typically less than 1 percent non-methane organic chemicals, and the remainder being carbon dioxide.
Liberated means released from coal and surrounding rock strata during the mining process. This includes both methane emitted from the ventilation system and methane drained from degasification systems.
Lime is the generic term for a variety of chemical compounds that are produced by the calcination of limestone or dolomite. These products include but are not limited to calcium oxide, high-calcium quicklime, calcium hydroxide, hydrated lime, dolomitic quicklime, and dolomitic hydrate.
Liquid/Slurry means a manure management component in which manure is stored as excreted or with some minimal addition of water to facilitate handling and is stored in either tanks or earthen ponds, usually for periods less than one year.
Low-bleed pneumatic devices mean automated flow control devices powered by pressurized natural gas and used for maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. Part of the gas power stream that is regulated by the process condition flows to a valve actuator controller where it vents continuously (bleeds) to the atmosphere at a rate equal to or less than six standard cubic feet per hour.
Lubricants include all grades of lubricating oils, from spindle oil to cylinder oil to those used in greases. Petroleum lubricants may be produced from distillates or residues.
Makeup chemicals means carbonate chemicals (e.g., sodium and calcium carbonates) that are added to the chemical recovery areas of chemical pulp mills to replace chemicals lost in the process.
Manure composting means the biological oxidation of a solid waste including manure usually with bedding or another organic carbon source typically at thermophilic temperatures produced by microbial heat production. There are four types of composting employed for manure management: Static, in vessel, intensive windrow and passive windrow. Static composting typically occurs in an enclosed channel, with forced aeration and continuous mixing. In vessel composting occurs in piles with forced aeration but no mixing. Intensive windrow composting occurs in windrows with regular turning for mixing and aeration. Passive windrow composting occurs in windrows with infrequent turning for mixing and aeration.
Maximum rated heat input capacity means the hourly heat input to a unit (in mmBtu/hr), when it combusts the maximum amount of fuel per hour that it is capable of combusting on a steady state basis, as of the initial installation of the unit, as specified by the manufacturer.
Maximum rated input capacity means the maximum charging rate of a municipal waste combustor unit expressed in tons per day of municipal solid waste combusted, calculated according to the procedures under 40 CFR 60.58b(j).
Mcf means thousand cubic feet.
Methane conversion factor means the extent to which the CH
Methane correction factor means an adjustment factor applied to the methane generation rate to account for portions of the landfill that remain aerobic. The methane correction factor can be considered the fraction of the total landfill waste volume that is ultimately disposed of in an anaerobic state. Managed landfills that have soil or other cover materials have a methane correction factor of 1.
Methanol (CH
Midgrade gasoline has an octane rating greater than or equal to 88 and less than or equal to 90. This definition applies to the midgrade categories of Conventional-Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-Winter. For midgrade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB.
Miscellaneous products include all refined petroleum products not defined elsewhere. It includes, but is not limited to, naphtha-type jet fuel (Jet B and JP-4), petrolatum lube refining by-products (aromatic extracts and tars), absorption oils, ram-jet fuel, petroleum rocket fuels, synthetic natural gas feedstocks, waste feedstocks, and specialty oils. It excludes organic waste sludges, tank bottoms, spent catalysts, and sulfuric acid.
MMBtu means million British thermal units.
Motor gasoline (finished) means a complex mixture of volatile hydrocarbons, with or without additives, suitably blended to be used in spark ignition engines. Motor gasoline includes conventional gasoline, reformulated gasoline, and all types of oxygenated gasoline. Gasoline also has seasonal variations in an effort to control ozone levels. This is achieved by lowering the Reid Vapor Pressure (RVP) of gasoline during the summer driving season. Depending on the region of the country the RVP is lowered to below 9.0 psi or 7.8 psi. The RVP may be further lowered by state regulations.
Mscf means thousand standard cubic feet.
MTBE (methyl tertiary butyl ether, (CH
Municipal solid waste landfill or MSW landfill means an entire disposal facility in a contiguous geographical space where household waste is placed in or on land. An MSW landfill may also receive other types of RCRA Subtitle D wastes (40 CFR 257.2) such as commercial solid waste, nonhazardous sludge, conditionally exempt small quantity generator waste, and industrial solid waste. Portions of an MSW landfill may be separated by access roads, public roadways, or other public right-of-ways. An MSW landfill may be publicly or privately owned.
Municipal solid waste or MSW means solid phase household, commercial/retail, and/or institutional waste. Household waste includes material discarded by single and multiple residential dwellings, hotels, motels, and other similar permanent or temporary housing establishments or facilities. Commercial/retail waste includes material discarded by stores, offices, restaurants, warehouses, non-manufacturing activities at industrial facilities, and other similar establishments or facilities. Institutional waste includes material discarded by schools, nonmedical waste discarded by hospitals, material discarded by non-manufacturing activities at prisons and government facilities, and material discarded by other similar establishments or facilities. Household, commercial/retail, and institutional wastes include yard waste, refuse-derived fuel, and motor vehicle maintenance materials. Insofar as there is separate collection, processing and disposal of industrial source waste streams consisting of used oil, wood pallets, construction, renovation, and demolition wastes (which includes, but is not limited to, railroad ties and telephone poles), paper, clean wood, plastics, industrial process or manufacturing wastes, medical waste, motor vehicle parts or vehicle fluff, or used tires that do not contain hazardous waste identified or listed under 42 U.S.C. § 6921, such wastes are not municipal solid waste. However, such wastes qualify as municipal solid waste where they are collected with other municipal solid waste or are otherwise combined with other municipal solid waste for processing and/or disposal.
Municipal wastewater treatment plant means a series of treatment processes used to remove contaminants and pollutants from domestic, business, and industrial wastewater collected in city sewers and transported to a centralized wastewater treatment system such as a publicly owned treatment works (POTW).
N
Naphthas ( is a generic term applied to a petroleum fraction with an approximate boiling range between 122 °F and 400 °F. The naphtha fraction of crude oil is the raw material for gasoline and is composed largely of paraffinic hydrocarbons.
Natural gas means a naturally occurring mixture of hydrocarbon and non-hydrocarbon gases found in geologic formations beneath the earth’s surface, of which the principal constituent is methane. Natural gas may be field quality or pipeline quality.
Natural gas driven pneumatic pump means a pump that uses pressurized natural gas to move a piston or diaphragm, which pumps liquids on the opposite side of the piston or diaphragm.
Natural gas liquids (NGLs) means those hydrocarbons in natural gas that are separated from the gas as liquids through the process of absorption, condensation, adsorption, or other methods. Generally, such liquids consist of ethane, propane, butanes, and pentanes plus. Bulk NGLs refers to mixtures of NGLs that are sold or delivered as undifferentiated product from natural gas processing plants.
Natural gasoline means a mixture of liquid hydrocarbons (mostly pentanes and heavier hydrocarbons) extracted from natural gas. It includes isopentane.
NIST means the United States National Institute of Standards and Technology.
Nitric acid production line means a series of reactors and absorbers used to produce nitric acid.
Nitrogen excreted is the nitrogen that is excreted by livestock in manure and urine.
Non-crude feedstocks means any petroleum product or natural gas liquid that enters the refinery to be further refined or otherwise used on site.
Non-recovery coke oven battery means a group of ovens connected by common walls and operated as a unit, where coal undergoes destructive distillation under negative pressure to produce coke, and which is designed for the combustion of the coke oven gas from which by-products are not recovered.
North American Industry Classification System (NAICS) code(s) means the six-digit code(s) that represents the product(s)/activity(s)/service(s) at a facility or supplier as listed in the
Oil-fired unit means a stationary combustion unit that derives more than 50 percent of its annual heat input from the combustion of fuel oil, and the remainder of its annual heat input from the combustion of natural gas or other gaseous fuels.
Open-ended valve or lines (OELs) means any valve, except pressure relief valves, having one side of the valve seat in contact with process fluid and one side open to atmosphere, either directly or through open piping.
Operating hours means the duration of time in which a process or process unit is utilized; this excludes shutdown, maintenance, and standby.
Operational change means, for purposes of § 98.3(b), a change in the type of feedstock or fuel used, a change in operating hours, or a change in process production rate.
Operator means any person who operates or supervises a facility or supplier.
Other fluorinated GHGs means fluorinated GHGs that are none of the following: Fully fluorinated GHGs; saturated hydrofluorocarbons with 2 or fewer carbon-hydrogen bonds; saturated hydrofluorocarbons with 3 or more carbon-hydrogen bonds; saturated hydrofluoroethers and hydrochlorofluoroethers with 1 carbon-hydrogen bond; saturated hydrofluoroethers and hydrochlorofluoroethers with 2 carbon-hydrogen bonds; saturated hydrofluoroethers and hydrochlorofluoroethers with 3 or more carbon-hydrogen bonds; fluorinated formates; fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than fluorotelomer alcohols; unsaturated PFCs, unsaturated HFCs, unsaturated HCFCs, unsaturated halogenated ethers, unsaturated halogenated esters, fluorinated aldehydes, and fluorinated ketones; fluorotelomer alcohols; or fluorinated GHGs with carbon-iodine bonds.
Other oils (>401 °F) are oils with a boiling range equal to or greater than 401 °F that are generally intended for use as a petrochemical feedstock and are not defined elsewhere.
Outer Continental Shelf means all submerged lands lying seaward and outside of the area of lands beneath navigable waters as defined in 43 U.S.C. 1331, and of which the subsoil and seabed appertain to the United States and are subject to its jurisdiction and control.
Owner means any person who has legal or equitable title to, has a leasehold interest in, or control of a facility or supplier, except a person whose legal or equitable title to or leasehold interest in the facility or supplier arises solely because the person is a limited partner in a partnership that has legal or equitable title to, has a leasehold interest in, or control of the facility or supplier shall not be considered an “owner” of the facility or supplier.
Oxygenates means substances which, when added to gasoline, increase the oxygen content of the gasoline. Common oxygenates are ethanol, methyl tertiary butyl ether (MTBE), ethyl tertiary butyl ether (ETBE), tertiary amyl methyl ether (TAME), diisopropyl ether (DIPE), and methanol.
Pasture/Range/Paddock means the manure from pasture and range grazing animals is allowed to lie as deposited, and is not managed.
Pentanes plus, or C5 + , is a mixture of hydrocarbons that is a liquid at ambient temperature and pressure, and consists mostly of pentanes (five carbon chain) and higher carbon number hydrocarbons. Pentanes plus includes, but is not limited to, normal pentane, isopentane, hexanes-plus (natural gasoline), and plant condensate.
Perfluorocarbons or PFCs means a class of greenhouse gases consisting on the molecular level of carbon and fluorine.
Petrochemical means methanol, acrylonitrile, ethylene, ethylene oxide, ethylene dichloride, and any form of carbon black.
Petrochemical feedstocks means feedstocks derived from petroleum for the manufacture of chemicals, synthetic rubber, and a variety of plastics. This category is usually divided into naphthas less than 401 °F and other oils greater than 401 °F.
Petroleum means oil removed from the earth and the oil derived from tar sands and shale.
Petroleum coke means a black solid residue, obtained mainly by cracking and carbonizing of petroleum derived feedstocks, vacuum bottoms, tar and pitches in processes such as delayed coking or fluid coking. It consists mainly of carbon (90 to 95 percent), has low ash content, and may be used as a feedstock in coke ovens. This product is also known as marketable coke or catalyst coke.
Petroleum product means all refined and semi-refined products that are produced at a refinery by processing crude oil and other petroleum-based feedstocks, including petroleum products derived from co-processing biomass and petroleum feedstock together, but not including plastics or plastic products. Petroleum products may be combusted for energy use, or they may be used either for non-energy processes or as non-energy products. The definition of petroleum product for importers and exporters excludes waxes.
Physical address, with respect to a United States parent company as defined in this section, means the street address, city, state and zip code of that company’s physical location.
Pit storage below animal confinement (deep pits) means the collection and storage of manure typically below a slatted floor in an enclosed animal confinement facility. This usually occurs with little or no added water for periods less than one year.
Plant code means either of the following:
(1) The Plant ID code assigned by the Department of Energy’s Energy Information Administration. The Energy Information Administration Plant ID code is also referred to as the “ORIS code”, “ORISPL code”, “Facility ID”, or “Facility code”, among other names.
(2) If a Plant ID code has not been assigned by the Department of Energy’s Energy Information Administration, then plant code means a code beginning with “88” assigned by the EPA’s Clean Air Markets Division for electronic reporting.
Portable means designed and capable of being carried or moved from one location to another. Indications of portability include but are not limited to wheels, skids, carrying handles, dolly, trailer, or platform. Equipment is not portable if any one of the following conditions exists:
(1) The equipment is attached to a foundation.
(2) The equipment or a replacement resides at the same location for more than 12 consecutive months.
(3) The equipment is located at a seasonal facility and operates during the full annual operating period of the seasonal facility, remains at the facility for at least two years, and operates at that facility for at least three months each year.
(4) The equipment is moved from one location to another in an attempt to circumvent the portable residence time requirements of this definition.
Poultry manure with litter means a manure management system component that is similar to cattle and swine deep bedding except usually not combined with a dry lot or pasture. The system is typically used for poultry breeder flocks and for the production of meat type chickens (broiler) and other fowl.
Poultry manure without litter means a manure management system component that may manage manure in a liquid form, similar to open pits in enclosed animal confinement facilities. These systems may alternatively be designed and operated to dry manure as it accumulates. The latter is known as a high-rise manure management system and is a form of passive windrow manure composting when designed and operated properly.
Precision of a measurement at a specified level (e.g., one percent of full scale or one percent of the value measured) means that 95 percent of repeat measurements made by a device or technique are within the range bounded by the mean of the measurements plus or minus the specified level.
Premium grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than 90. This definition applies to the premium grade categories of Conventional-Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-Winter. For premium grade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB.
Pressed and blown glass means glass which is pressed, blown, or both, into products such as light bulbs, glass fiber, technical glass, and other products listed in NAICS 327212.
Pressure relief device or pressure relief valve or pressure safety valve means a safety device used to prevent operating pressures from exceeding the maximum allowable working pressure of the process equipment. A common pressure relief device is but not limited to a spring-loaded pressure relief valve. Devices that are actuated either by a pressure of less than or equal to 2.5 psig or by a vacuum are not pressure relief devices.
Primary fuel means the fuel that provides the greatest percentage of the annual heat input to a stationary fuel combustion unit.
Process emissions means the emissions from industrial processes (e.g., cement production, ammonia production) involving chemical or physical transformations other than fuel combustion. For example, the calcination of carbonates in a kiln during cement production or the oxidation of methane in an ammonia process results in the release of process CO
Process unit means the equipment assembled and connected by pipes and ducts to process raw materials and to manufacture either a final product or an intermediate used in the onsite production of other products. The process unit also includes the purification of recovered byproducts.
Process vent means means a gas stream that: Is discharged through a conveyance to the atmosphere either directly or after passing through a control device; originates from a unit operation, including but not limited to reactors (including reformers, crackers, and furnaces, and separation equipment for products and recovered byproducts); and contains or has the potential to contain GHG that is generated in the process. Process vent does not include safety device discharges, equipment leaks, gas streams routed to a fuel gas system or to a flare, discharges from storage tanks.
Propane is a paraffinic hydrocarbon with molecular formula C
Propylene is an olefinic hydrocarbon with molecular formula C
Pulp mill lime kiln means the combustion units (e.g., rotary lime kiln or fluidized bed calciner) used at a kraft or soda pulp mill to calcine lime mud, which consists primarily of calcium carbonate, into quicklime, which is calcium oxide.
Pushing means the process of removing the coke from the coke oven at the end of the coking cycle. Pushing begins when coke first begins to fall from the oven into the quench car and ends when the quench car enters the quench tower.
Raw mill means a ball and tube mill, vertical roller mill or other size reduction equipment, that is not part of an in-line kiln/raw mill, used to grind feed to the appropriate size. Moisture may be added or removed from the feed during the grinding operation. If the raw mill is used to remove moisture from feed materials, it is also, by definition, a raw material dryer. The raw mill also includes the air separator associated with the raw mill.
RBOB-Summer (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Reformulated-Summer.
RBOB-Winter (reformulated blendstock for oxygenate blending) means a petroleum product which, when blended with a specified type and percentage of oxygenate, meets the definition of Reformulated-Winter.
Reciprocating compressor means a piece of equipment that increases the pressure of a process natural gas or CO
Reciprocating compressor rod packing means a series of flexible rings in machined metal cups that fit around the reciprocating compressor piston rod to create a seal limiting the amount of compressed natural gas or CO
Re-condenser means heat exchangers that cool compressed boil-off gas to a temperature that will condense natural gas to a liquid.
Reformulated-Summer refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, and summer RVP standards required under 40 CFR 80.27 or as specified by the state. Reformulated gasoline excludes Reformulated Blendstock for Oxygenate Blending (RBOB) as well as other blendstock.
Reformulated-Winter refers to finished gasoline formulated for use in motor vehicles, the composition and properties of which meet the requirements of the reformulated gasoline regulations promulgated by the U.S. Environmental Protection Agency under 40 CFR 80.40 and 40 CFR 80.41, but which do not meet summer RVP standards required under 40 CFR 80.27 or as specified by the state.
Regular grade gasoline is gasoline having an antiknock index, i.e., octane rating, greater than or equal to 85 and less than 88. This definition applies to the regular grade categories of Conventional-Summer, Conventional-Winter, Reformulated-Summer, and Reformulated-Winter. For regular grade categories of RBOB-Summer, RBOB-Winter, CBOB-Summer, and CBOB-Winter, this definition refers to the expected octane rating of the finished gasoline after oxygenate has been added to the RBOB or CBOB.
Rendered animal fat, or tallow, means fats extracted from animals which are generally used as a feedstock in making biodiesel.
Reporting year means the calendar year during which the GHG data are required to be collected for purposes of the annual GHG report. For example, reporting year 2014 is January 1, 2014 through December 31, 2014, and the annual report for reporting year 2014 is submitted to EPA on March 31, 2015.
Research and development means those activities conducted in process units or at laboratory bench-scale settings whose purpose is to conduct research and development for new processes, technologies, or products and whose purpose is not for the manufacture of products for commercial sale, except in a de minimis manner.
Residual Fuel Oil No. 5 (Navy Special) is a classification for the heavier fuel oil generally used in steam powered vessels in government service and inshore power plants. It has a minimum flash point of 131 °F.
Residual Fuel Oil No. 6 (a.k.a. Bunker C) is a classification for the heavier fuel oil generally used for the production of electric power, space heating, vessel bunkering and various industrial purposes. It has a minimum flash point of 140 °F.
Residuum is residue from crude oil after distilling off all but the heaviest components, with a boiling range greater than 1,000 °F.
Road oil is any heavy petroleum oil, including residual asphaltic oil used as a dust palliative and surface treatment on roads and highways. It is generally produced in six grades, from 0, the most liquid, to 5, the most viscous.
Rotary lime kiln means a unit with an inclined rotating drum that is used to produce a lime product from limestone by calcination.
Safety device means a closure device such as a pressure relief valve, frangible disc, fusible plug, or any other type of device which functions exclusively to prevent physical damage or permanent deformation to a unit or its air emission control equipment by venting gases or vapors directly to the atmosphere during unsafe conditions resulting from an unplanned, accidental, or emergency event. A safety device is not used for routine venting of gases or vapors from the vapor headspace underneath a cover such as during filling of the unit or to adjust the pressure in response to normal daily diurnal ambient temperature fluctuations. A safety device is designed to remain in a closed position during normal operations and open only when the internal pressure, or another relevant parameter, exceeds the device threshold setting applicable to the air emission control equipment as determined by the owner or operator based on manufacturer recommendations, applicable regulations, fire protection and prevention codes and practices, or other requirements for the safe handling of flammable, combustible, explosive, reactive, or hazardous materials.
Sales oil means produced crude oil or condensate measured at the production lease automatic custody transfer (LACT) meter or custody transfer tank gauge.
Saturated hydrochlorofluoroethers (HCFEs) means fluorinated GHGs in which two hydrocarbon groups are linked by an oxygen atom; in which two or more, but not all, of the hydrogen atoms in the hydrocarbon groups have been replaced by fluorine atoms and chlorine atoms; and which contain only single bonds.
Saturated hydrofluorocarbons (HFCs) means fluorinated GHGs that are hydrofluorocarbons and that contain only single bonds.
Saturated hydrofluoroethers (HFEs) means fluorinated GHGs in which two hydrocarbon groups are linked by an oxygen atom; in which one or more, but not all, of the hydrogen atoms in the hydrocarbon groups have been replaced by fluorine atoms; and which contain only single bonds.
Semi-refined petroleum product means all oils requiring further processing. Included in this category are unfinished oils which are produced by the partial refining of crude oil and include the following: Naphthas and lighter oils; kerosene and light gas oils; heavy gas oils; and residuum, and all products that require further processing or the addition of blendstocks.
Sendout means, in the context of a local distribution company, the total deliveries of natural gas to customers over a specified time interval (typically hour, day, month, or year). Sendout is the sum of gas received through the city gate, gas withdrawn from on-system storage or peak shaving plants, and gas produced and delivered into the distribution system; and is net of any natural gas injected into on-system storage. It comprises gas sales, exchange, deliveries, gas used by company, and unaccounted for gas. Sendout is measured at the city gate station, and other on-system receipt points from storage, peak shaving, and production.
Sensor means a device that measures a physical quantity/quality or the change in a physical quantity/quality, such as temperature, pressure, flow rate, pH, or liquid level.
SF
Shutdown means the cessation of operation of an emission source for any purpose.
Silicon carbide means an artificial abrasive produced from silica sand or quartz and petroleum coke.
Sinter process means a process that produces a fused aggregate of fine iron-bearing materials suited for use in a blast furnace. The sinter machine is composed of a continuous traveling grate that conveys a bed of ore fines and other finely divided iron-bearing material and fuel (typically coke breeze), a burner at the feed end of the grate for ignition, and a series of downdraft windboxes along the length of the strand to support downdraft combustion and heat sufficient to produce a fused sinter product.
Site means any combination of one or more graded pad sites, gravel pad sites, foundations, platforms, or the immediate physical location upon which equipment is physically located.
Smelting furnace means a furnace in which lead-bearing materials, carbon-containing reducing agents, and fluxes are melted together to form a molten mass of material containing lead and slag.
Solid by-products means plant matter such as vegetable waste, animal materials/wastes, and other solid biomass, except for wood, wood waste, and sulphite lyes (black liquor).
Solid storage is the storage of manure, typically for a period of several months, in unconfined piles or stacks. Manure is able to be stacked due to the presence of a sufficient amount of bedding material or loss of moisture by evaporation.
Sour gas means any gas that contains significant concentrations of hydrogen sulfide. Sour gas may include untreated fuel gas, amine stripper off-gas, or sour water stripper gas.
Sour natural gas means natural gas that contains significant concentrations of hydrogen sulfide (H
Special naphthas means all finished products with the naphtha boiling range (290 ° to 470 °F) that are generally used as paint thinners, cleaners or solvents. These products are refined to a specified flash point. Special naphthas include all commercial hexane and cleaning solvents conforming to ASTM Specification D1836-07, Standard Specification for Commercial Hexanes, and D235-02 (Reapproved 2007), Standard Specification for Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), respectively. Naphthas to be blended or marketed as motor gasoline or aviation gasoline, or that are to be used as petrochemical and synthetic natural gas (SNG) feedstocks are excluded.
Spent liquor solids means the dry weight of the solids in the spent pulping liquor that enters the chemical recovery furnace or chemical recovery combustion unit.
Spent pulping liquor means the residual liquid collected from on-site pulping operations at chemical pulp facilities that is subsequently fired in chemical recovery furnaces at kraft and soda pulp facilities or chemical recovery combustion units at sulfite or semi-chemical pulp facilities.
Standard conditions or standard temperature and pressure (STP), for the purposes of this part, means either 60 or 68 degrees Fahrenheit and 14.7 pounds per square inch absolute.
Steam reforming means a catalytic process that involves a reaction between natural gas or other light hydrocarbons and steam. The result is a mixture of hydrogen, carbon monoxide, carbon dioxide, and water.
Still gas means any form or mixture of gases produced in refineries by distillation, cracking, reforming, and other processes. The principal constituents are methane, ethane, ethylene, normal butane, butylene, propane, and propylene.
Storage tank means a vessel (excluding sumps) that is designed to contain an accumulation of crude oil, condensate, intermediate hydrocarbon liquids, or produced water and that is constructed entirely of non-earthen materials (e.g., wood, concrete, steel, plastic) that provide structural support.
Sulfur recovery plant means all process units which recover sulfur or produce sulfuric acid from hydrogen sulfide (H
Supplemental fuel means a fuel burned within a petrochemical process that is not produced within the process itself.
Supplier means a producer, importer, or exporter in any supply category included in Table A-5 to this subpart, as defined by the corresponding subpart of this part.
Sweet gas is natural gas with low concentrations of hydrogen sulfide (H
Taconite iron ore processing means an industrial process that separates and concentrates iron ore from taconite, a low grade iron ore, and heats the taconite in an indurating furnace to produce taconite pellets that are used as the primary feed material for the production of iron in blast furnaces at integrated iron and steel plants.
TAME means tertiary amyl methyl ether, (CH
Trace concentrations means concentrations of less than 0.1 percent by mass of the process stream.
Transform means to use and entirely consume (except for trace concentrations) nitrous oxide or fluorinated GHGs in the manufacturing of other chemicals for commercial purposes. Transformation does not include burning of nitrous oxide.
Transshipment means the continuous shipment of nitrous oxide or a fluorinated GHG from a foreign state of origin through the United States or its territories to a second foreign state of final destination, as long as the shipment does not enter into United States jurisdiction. A transshipment, as it moves through the United States or its territories, cannot be re-packaged, sorted or otherwise changed in condition.
Trona means the raw material (mineral) used to manufacture soda ash; hydrated sodium bicarbonate carbonate (e.g., Na2CO
Ultimate analysis means the determination of the percentages of carbon, hydrogen, nitrogen, sulfur, and chlorine and (by difference) oxygen in the gaseous products and ash after the complete combustion of a sample of an organic material.
Unfinished oils are all oils requiring further processing, except those requiring only mechanical blending.
United States means the 50 States, the District of Columbia, the Commonwealth of Puerto Rico, American Samoa, the Virgin Islands, Guam, and any other Commonwealth, territory or possession of the United States, as well as the territorial sea as defined by Presidential Proclamation No. 5928.
United States parent company(s) means the highest-level United States company(s) with an ownership interest in the facility or supplier as of December 31 of the year for which data are being reported.
Unsaturated halogenated ethers means fluorinated GHGs in which two hydrocarbon groups are linked by an oxygen atom; in which one or more of the hydrogen atoms in the hydrocarbon groups have been replaced by fluorine atoms; and which contain one or more bonds that are not single bonds. Unsaturated ethers include unsaturated HFEs.
Unsaturated hydrochlorofluorocarbons (HCFCs) means fluorinated GHGs that contain only carbon, chlorine, fluorine, and hydrogen and that contain one or more bonds that are not single bonds.
Unsaturated hydrofluorocarbons (HFCs) means fluorinated GHGs that are hydrofluorocarbons and that contain one or more bonds that are not single bonds.
Unsaturated perfluorocarbons (PFCs) means fluorinated GHGs that are perfluorocarbons and that contain one or more bonds that are not single bonds.
Unstabilized crude oil means, for the purposes of this part, crude oil that is pumped from the well to a pipeline or pressurized storage vessel for transport to the refinery without intermediate storage in a storage tank at atmospheric pressures. Unstabilized crude oil is characterized by having a true vapor pressure of 5 pounds per square inch absolute (psia) or greater.
Used oil means a petroleum-derived or synthetically-derived oil whose physical properties have changed as a result of handling or use, such that the oil cannot be used for its original purpose. Used oil consists primarily of automotive oils (e.g., used motor oil, transmission oil, hydraulic fluids, brake fluid, etc.) and industrial oils (e.g., industrial engine oils, metalworking oils, process oils, industrial grease, etc).
Valve means any device for halting or regulating the flow of a liquid or gas through a passage, pipeline, inlet, outlet, or orifice; including, but not limited to, gate, globe, plug, ball, butterfly and needle valves.
Vapor recovery system means any equipment located at the source of potential gas emissions to the atmosphere or to a flare, that is composed of piping, connections, and, if necessary, flow-inducing devices, and that is used for routing the gas back into the process as a product and/or fuel.
Vaporization unit means a process unit that performs controlled heat input to vaporize LNG to supply transmission and distribution pipelines or consumers with natural gas.
Vegetable oil means oils extracted from vegetation that are generally used as a feedstock in making biodiesel.
Ventilation hole or shaft means a vent hole, shaft, mine portal, adit or other mine entrance or exits employed at an underground coal mine to serve as the outlet or conduit to move air from the ventilation system out of the mine.
Ventilation system means a system that is used to control the concentration of methane and other gases within mine working areas through mine ventilation, rather than a mine degasification system. A ventilation system consists of fans that move air through the mine workings to dilute methane concentrations.
Volatile solids are the organic material in livestock manure and consist of both biodegradable and non-biodegradable fractions.
Waelz kiln means an inclined rotary kiln in which zinc-containing materials are charged together with a carbon reducing agent (e.g., petroleum coke, metallurgical coke, or anthracite coal).
Waxes means a solid or semi-solid material at 77 °F consisting of a mixture of hydrocarbons obtained or derived from petroleum fractions, or through a Fischer-Tropsch type process, in which the straight chained paraffin series predominates. This includes all marketable wax, whether crude or refined, with a congealing point between 80 (or 85) and 240 °F and a maximum oil content of 50 weight percent.
Well completions means the process that allows for the flow of petroleum or natural gas from newly drilled wells to expel drilling and reservoir fluids and test the reservoir flow characteristics, steps which may vent produced gas to the atmosphere via an open pit or tank. Well completion also involves connecting the well bore to the reservoir, which may include treating the formation or installing tubing, packer(s), or lifting equipment, steps that do not significantly vent natural gas to the atmosphere. This process may also include high-rate flowback of injected gas, water, oil, and proppant used to fracture and prop open new fractures in existing lower permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere.
Well workover means the process(es) of performing one or more of a variety of remedial operations on producing petroleum and natural gas wells to try to increase production. This process also includes high-rate flowback of injected gas, water, oil, and proppant used to re-fracture and prop-open new fractures in existing low permeability gas reservoirs, steps that may vent large quantities of produced gas to the atmosphere.
Wellhead means the piping, casing, tubing and connected valves protruding above the earth’s surface for an oil and/or natural gas well. The wellhead ends where the flow line connects to a wellhead valve. Wellhead equipment includes all equipment, permanent and portable, located on the improved land area (i.e. well pad) surrounding one or multiple wellheads.
Wet natural gas means natural gas in which water vapor exceeds the concentration specified for commercially saleable natural gas delivered from transmission and distribution pipelines. This input stream to a natural gas dehydrator is referred to as “wet gas.”
Wood residuals means materials recovered from three principal sources: Municipal solid waste (MSW); construction and demolition debris; and primary timber processing. Wood residuals recovered from MSW include wooden furniture, cabinets, pallets and containers, scrap lumber (from sources other than construction and demolition activities), and urban tree and landscape residues. Wood residuals from construction and demolition debris originate from the construction, repair, remodeling and demolition of houses and non-residential structures. Wood residuals from primary timber processing include bark, sawmill slabs and edgings, sawdust, and peeler log cores. Other sources of wood residuals include, but are not limited to, railroad ties, telephone and utility poles, pier and dock timbers, wastewater process sludge from paper mills, trim, sander dust, and sawdust from wood products manufacturing (including resinated wood product residuals), and logging residues.
Wool fiberglass means fibrous glass of random texture, including fiberglass insulation, and other products listed in NAICS 327993.
Working capacity, for the purposes of subpart TT of this part, means the maximum volume or mass of waste that is actually placed in the landfill from an individual or representative type of container (such as a tank, truck, or roll-off bin) used to convey wastes to the landfill, taking into account that the container may not be able to be 100 percent filled and/or 100 percent emptied for each load.
You means an owner or operator subject to Part 98.
Zinc smelters means a facility engaged in the production of zinc metal, zinc oxide, or zinc alloy products from zinc sulfide ore concentrates, zinc calcine, or zinc-bearing scrap and recycled materials through the use of pyrometallurgical techniques involving the reduction and volatization of zinc-bearing feed materials charged to a furnace.
§ 98.7 What standardized methods are incorporated by reference into this part?
The materials listed in this section are incorporated by reference in the corresponding sections noted. These incorporations by reference were approved by the Director of Federal Register in accordance with 5 U.S.C. 552(a) and 1 CFR part 51. These materials are incorporated as they exist on the date of approval, and a notice of any change in the materials will be published in the
(a)-(b) [Reserved]
(c) The following material is available for purchase from the ASM International, 9639 Kinsman Road, Materials Park, OH 44073, (440) 338-5151, http://www.asminternational.org.
(1) ASM CS-104 UNS No. G10460 – Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content), incorporation by reference (IBR) approved for § 98.174(b).
(2) [Reserved]
(d) The following material is available for purchase from the American Society of Mechanical Engineers (ASME), Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org.
(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi, incorporation by reference (IBR) approved for § 98.124(m)(1), § 98.324(e), § 98.354(d), § 98.354(h), § 98.344(c) and § 98.364(e).
(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters, IBR approved for § 98.124(m)(2), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).
(3) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flow Meters, IBR approved for § 98.124(m)(3) and § 98.354(d).
(4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters, IBR approved for § 98.124(m)(4), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).
(5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles, IBR approved for § 98.124(m)(5), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).
(6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method, IBR approved for § 98.124(m)(6).
(7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters, IBR approved for § 98.124(m)(7), § 98.324(e), § 98.344(c), and § 98.354(h).
(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters, IBR approved for § 98.124(m)(8), § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).
(9) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flow Meters, IBR approved for § 98.354(d).
(10) ASME MFC-18M-2001 Measurement of Fluid Flow Using Variable Area Meters, IBR approved for § 98.324(e), § 98.344(c), § 98.354(h), and § 98.364(e).
(e) The following material is available for purchase from the American Society for Testing and Material (ASTM), 100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org.
(1) ASTM C25-06 Standard Test Method for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime, incorporation by reference (IBR) approved for § 98.114(b), § 98.174(b), § 98.184(b), § 98.194(c), and § 98.334(b).
(2) ASTM C114-09 Standard Test Methods for Chemical Analysis of Hydraulic Cement, IBR approved for § 98.84(a), § 98.84(b), and § 98.84(c).
(3) ASTM D235-02 (Reapproved 2007) Standard Specification for Mineral Spirits (Petroleum Spirits) (Hydrocarbon Dry Cleaning Solvent), IBR approved for § 98.6.
(4) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter, IBR approved for § 98.254(e).
(5) ASTM D388-05 Standard Classification of Coals by Rank, IBR approved for § 98.6.
(6) ASTM D910-07a Standard Specification for Aviation Gasolines, IBR approved for § 98.6.
(7) [Reserved]
(8) ASTM D1826-94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter, IBR approved for § 98.254(e).
(9) ASTM D1836-07 Standard Specification for Commercial Hexanes, IBR approved for § 98.6.
(10) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography, IBR approved for § 98.74(c), § 98.164(b), § 98.244(b), § 98.254(d), § 98.324(d), § 98.354(g), and § 98.344(b).
(11) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography, IBR approved for § 98.74(c), § 98.164(b), § 98.254(d), § 98.324(d), § 98.344(b), § 98.354(g), and § 98.364(c).
(12) ASTM D2013-07 Standard Practice for Preparing Coal Samples for Analysis, IBR approved for § 98.164(b).
(13) ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross Sample of Coal, IBR approved for § 98.164(b).
(14) ASTM D2502-04 Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils From Viscosity Measurements, IBR approved for § 98.74(c).
(15) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure, IBR approved for § 98.74(c) and § 98.254(d)(6).
(16) ASTM D2505-88 (Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography, IBR approved for § 98.244(b).
(17) ASTM D2597-94 (Reapproved 2004) Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography, IBR approved for § 98.164(b).
(18) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke, IBR approved for § 98.74(c), § 98.164(b), § 98.244(b), § 98.254(i), § 98.284(c), § 98.284(d), § 98.314(c), § 98.314(d), and § 98.314(f).
(19) ASTM D3238-95 (Reapproved 2005) Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method, IBR approved for § 98.74(c) and § 98.164(b).
(20) ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels, IBR approved for § 98.254(e).
(21) ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes, IBR approved for § 98.144(b).
(22) ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum and Petroleum Products, IBR approved for § 98.164(b).
(23) ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products, IBR approved for § 98.164(b).
(24) ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method), IBR approved for § 98.254(e).
(25) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion, IBR approved for § 98.254(e) and § 98.324(d).
(26) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants, IBR approved for § 98.74(c), § 98.164(b), § 98.244(b), and § 98.254(i).
(27) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal, IBR approved for § 98.74(c), § 98.114(b), § 98.164(b), § 98.174(b), § 98.184(b), § 98.244(b), § 98.254(i), § 98.274(b), § 98.284(c), § 98.284(d), § 98.314(c), § 98.314(d), § 98.314(f), and § 98.334(b).
(28) [Reserved]
(29) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph, IBR approved for § 98.244(b).
(30) ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy, IBR approved for § 98.54(b), Table I-9 to subpart I of this part, § 98.224(b), and § 98.414(n).
(31) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal, IBR approved for § 98.164(b).
(32) ASTM D6751-08 Standard Specification for Biodiesel Fuel Blend Stock (B100) for Middle Distillate Fuels, IBR approved for § 98.6.
(33) ASTM D6866-16 Standard Test Methods for Determining the Biobased Content of Solid, Liquid, and Gaseous Samples Using Radiocarbon Analysis, approved June 1, 2016, IBR approved for §§ 98.34(d) and (e), and 98.36(e).
(34) ASTM D6883-04 Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles, IBR approved for § 98.164(b).
(35) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of Coal, IBR approved for § 98.164(b).
(36) ASTM D7459-08 Standard Practice for Collection of Integrated Samples for the Speciation of Biomass (Biogenic) and Fossil-Derived Carbon Dioxide Emitted from Stationary Emissions Sources, IBR approved for § 98.34(d), § 98.34(e), and § 98.36(e).
(37) ASTM E359-00 (Reapproved 2005)e1 Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate), IBR approved for § 98.294(a) and § 98.294(b).
(38) ASTM E1019-08 Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques, IBR approved for § 98.174(b).
(39) [Reserved]
(40) ASTM E1915-07a Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry, IBR approved for § 98.174(b).
(41) ASTM E1941-04 Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys, IBR approved for § 98.114(b), § 98.184(b), § 98.334(b).
(42) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography, IBR approved for § 98.164(b), § 98.244(b), § 98.254(d), § 98.324(d), § 98.344(b), and § 98.354(g).
(43) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open Channel Flow Measurement of Water with the Parshall Flume, approved June 15, 2007, IBR approved for § 98.354(d).
(44) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open Channel Flow Measurement of Water with Broad-Crested Weirs, approved October 1, 2008, IBR approved for § 98.354(d).
(45) ASTM D6349-09 Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion of Coal and Coke by Inductively Coupled Plasma – Atomic Emission Spectrometry, IBR approved for § 98.144(b).
(46) ASTM D2879-97 (Reapproved 2007) Standard Test Method for Vapor Pressure-Temperature Relationship and Initial Decomposition Temperature of Liquids by Isoteniscope (ASTM D2879), approved May 1, 2007, IBR approved for § 98.128.
(47) ASTM D7359-08 Standard Test Method for Total Fluorine, Chlorine and Sulfur in Aromatic Hydrocarbons and Their Mixtures by Oxidative Pyrohydrolytic Combustion followed by Ion Chromatography Detection (Combustion Ion Chromatography-CIC) (ASTM D7359), approved October 15, 2008, IBR approved for § 98.124(e)(2).
(48) ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography, approved July 1, 2009, IBR approved for § 98.244(b)(4)(xi).
(49) ASTM D7633-10 Standard Test Method for Carbon Black – Carbon Content, approved May 15, 2010, IBR approved for § 98.244(b)(4)(xii).
(f) The following material is available for purchase from the Gas Processors Association (GPA), 6526 East 60th Street, Tulsa, Oklahoma 74143, (918) 493-3872, http://www.gasprocessors.com.
(1) [Reserved]
(2) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography, IBR approved for § 98.164(b), § 98.254(d), § 98.344(b), and § 98.354(g).
(g) The following material is available for purchase from the International Standards Organization (ISO), 1, ch. de la Voie-Creuse, Case postale 56, CH-1211 Geneva 20, Switzerland, + 41 22 749 01 11, http://www.iso.org/iso/home.htm.
(1) ISO 3170: Petroleum liquids – Manual sampling – Third Edition 2004-02-01, IBR approved for § 98.164(b).
(2) ISO 3171: Petroleum Liquids – Automatic pipeline sampling – Second Edition 1988-12-01, IBR approved for § 98.164(b).
(3) [Reserved]
(4) ISO/CSAPR 15349-1: 1998, Unalloyed steel – Determination of low carbon content. Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation) (1998-10-15) – First Edition, IBR approved for § 98.174(b).
(5) ISO/CSAPR 15349-3: 1998, Unalloyed steel – Determination of low carbon content. Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating) (1998-10-15) – First Edition, IBR approved for § 98.174(b).
(h) The following material is available for purchase from the National Lime Association (NLA), 200 North Glebe Road, Suite 800, Arlington, Virginia 22203, (703) 243-5463, http://www.lime.org.
(1) CO
(2) [Reserved]
(i) The following material is available for purchase from the National Institute of Standards and Technology (NIST), 100 Bureau Drive, Stop 1070, Gaithersburg, MD 20899-1070, (800) 877-8339, http://www.nist.gov/index.html.
(1) Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009), incorporation by reference (IBR) approved for § 98.244(b), § 98.254(h), and § 98.344(a).
(2) [Reserved]
(j) The following material is available for purchase from the Technical Association of the Pulp and Paper Industry (TAPPI), 15 Technology Parkway South, Norcross, GA 30092, (800) 332-8686, http://www.tappi.org.
(1) T650 om-05 Solids Content of Black Liquor, TAPPI, incorporation by reference (IBR) approved for § 98.276(c) and § 98.277(d).
(2) T684 om-06 Gross Heating Value of Black Liquor, TAPPI, incorporation by reference (IBR) approved for § 98.274(b).
(k) The following material is available for purchase from Standard Methods, at http://www.standardmethods.org, (877) 574-1233; or, through a joint publication agreement from the American Public Health Association (APHA), P.O. Box 933019, Atlanta, GA 31193-3019, (888) 320-APHA (2742), http://www.apha.org/publications/pubscontact/.
(1) Method 2540G Total, Fixed, and Volatile Solids in Solid and Semisolid Samples, IBR approved for § 98.464(b).
(2) [Reserved]
(l) The following material is available from the U.S. Department of Labor, Mine Safety and Health Administration, 1100 Wilson Boulevard, 21st Floor, Arlington, VA 22209-3939, (202) 693-9400, http://www.msha.gov.
(1) PH16-V-1, Coal Mine Safety and Health General Inspection Procedures Handbook, June 2016, IBR approved for § 98.324(b).
(2) [Reserved]
(m) The following material is available from the U.S. Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, (202) 272-0167, http://www.epa.gov.
(1) NPDES Compliance Inspection Manual, Chapter 5, Sampling, EPA 305-X-04-001, July 2004, http://www.epa.gov/compliance/monitoring/programs/cwa/npdes.html, IBR approved for § 98.354(c).
(2) U.S. EPA NPDES Permit Writers’ Manual, Section 7.1.3, Sample Collection Methods, EPA 833-B-96-003, December 1996, http://www.epa.gov/npdes/pubs/owm0243.pdf, IBR approved for § 98.354(c).
(3) Protocol for Measuring Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing, Version 1, EPA-430-R-10-003, March 2010 (EPA 430-R-10-003), http://www.epa.gov/semiconductor-pfc/documents/dre_protocol.pdf, IBR approved for § 98.94(f)(4)(i), § 98.94(g)(3), § 98.97(d)(4), § 98.98, Appendix A to subpart I of this part, § 98.124(e)(2), and § 98.414(n)(1).
(4) Emissions Inventory Improvement Program, Volume II: Chapter 16, Methods for Estimating Air Emissions from Chemical Manufacturing Facilities, August 2007, Final, http://www.epa.gov/ttnchie1/eiip/techreport/volume02/index.html, IBR approved for § 98.123(c)(1)(i)(A).
(5) Protocol for Equipment Leak Emission Estimates, EPA-453/R-95-017, November 1995 (EPA-453/R-95-017), http://www.epa.gov/ttnchie1/efdocs/equiplks.pdf, IBR approved for § 98.123(d)(1)(i), § 98.123(d)(1)(ii), § 98.123(d)(1)(iii), and § 98.124(f)(2).
(6) Tracer Gas Protocol for the Determination of Volumetric Flow Rate Through the Ring Pipe of the Xact Multi-Metals Monitoring System, also known as Other Test Method 24 (Tracer Gas Protocol), Eli Lilly and Company Tippecanoe Laboratories, September 2006, http://www.epa.gov/ttn/emc/prelim/otm24.pdf, IBR approved for § 98.124(e)(1)(ii).
(7) Approved Alternative Method 012: An Alternate Procedure for Stack Gas Volumetric Flow Rate Determination (Tracer Gas) (ALT-012), U.S. Environmental Protection Agency Emission Measurement Center, May 23, 1994, http://www.epa.gov/ttn/emc/approalt/alt-012.pdf, IBR approved for § 98.124(e)(1)(ii).
(8) Protocol for Measurement of Tetrafluoromethane (CF
(9) AP 42, Section 5.2, Transportation and Marketing of Petroleum Liquids, July 2008, (AP 42, Section 5.2); http://www.epa.gov/ttn/chief/ap42/ch05/final/c05s02.pdf; in Chapter 5, Petroleum Industry, of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I, IBR approved for § 98.253(n).
(10) Method 9060A, Total Organic Carbon, Revision 1, November 2004 (Method 9060A), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/9060a.pdf; in EPA Publication No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third Edition, IBR approved for § 98.244(b)(4)(viii).
(11) Method 8031, Acrylonitrile By Gas Chromatography, Revision 0, September 1994 (Method 8031), http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8031.pdf; in EPA Publication No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third Edition, IBR approved for § 98.244(b)(4)(viii).
(12) Method 8021B, Aromatic and Halogenated Volatiles By Gas Chromatography Using Photoionization and/or Electrolytic Conductivity Detectors, Revision 2, December 1996 (Method 8021B). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8021b.pdf; in EPA Publication No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third Edition, IBR approved for § 98.244(b)(4)(viii).
(13) Method 8015C, Nonhalogenated Organics By Gas Chromatography, Revision 3, February 2007 (Method 8015C). http://www.epa.gov/osw/hazard/testmethods/sw846/pdfs/8015c.pdf; in EPA Publication No. SW-846, “Test Methods for Evaluating Solid Waste, Physical/Chemical Methods,” Third Edition, IBR approved for § 98.244(b)(4)(viii).
(14) AP 42, Section 7.1, Organic Liquid Storage Tanks, November 2006 (AP 42, Section 7.1), http://www.epa.gov/ttn/chief/ap42/ch07/final/c07s01.pdf; in Chapter 7, Liquid Storage Tanks, of AP 42, Compilation of Air Pollutant Emission Factors, 5th Edition, Volume I, IBR approved for § 98.253(m)(1) and § 98.256(o)(2)(i).
(n)-(o) [Reserved]
(p) The following material is available for purchase from the American Association of Petroleum Geologists, 1444 South Boulder Avenue, Tulsa, Oklahoma 74119, (918) 584-2555, http://www.aapg.org.
(1) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991), pages 1644-1651, IBR approved for § 98.238.
(2) Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in cooperation with the USGS, 1978, IBR approved for § 98.238.
(q) The following material is available from the Energy Information Administration (EIA), 1000 Independence Ave., SW., Washington, DC 20585, (202) 586-8800, http://www.eia.doe.gov/pub/oil_gas/natural_gas/data_publications/field_code_master_list/current/pdf/fcml_all.pdf.
(1) Oil and Gas Field Code Master List 2008, DOE/EIA0370(08), January 2009, IBR approved for § 98.238.
(2) [Reserved]
§ 98.8 What are the compliance and enforcement provisions of this part?
Any violation of any requirement of this part shall be a violation of the Clean Air Act, including section 114 (42 U.S.C. 7414). A violation includes but is not limited to failure to report GHG emissions, failure to collect data needed to calculate GHG emissions, failure to continuously monitor and test as required, failure to retain records needed to verify the amount of GHG emissions, and failure to calculate GHG emissions following the methodologies specified in this part. Each day of a violation constitutes a separate violation.
§ 98.9 Addresses.
All requests, notifications, and communications to the Administrator pursuant to this part must be submitted electronically and in a format as specified by the Administrator. For example, any requests, notifications and communications that can be submitted through the electronic GHG reporting tool, must be submitted through that tool. If not specified, requests, notifications or communications shall be submitted to the following address:
(a) For U.S. mail. Director, Climate Change Division, 1200 Pennsylvania Ave., NW., Mail Code: 6207J, Washington, DC 20460.
(b) For package deliveries. Director, Climate Change Division, 1310 L St, NW., Washington, DC 20005.
Table A-1 to Subpart A of Part 98 – Global Warming Potentials
[100-Year Time Horizon]
Name | CAS No. | Chemical formula | Global warming potential (100 yr.) |
---|---|---|---|
Carbon dioxide | 124-38-9 | CO | 1 |
Methane | 74-82-8 | CH | a 25 |
Nitrous oxide | 10024-97-2 | N | a 298 |
Sulfur hexafluoride | 2551-62-4 | SF | a 22,800 |
Trifluoromethyl sulphur pentafluoride | 373-80-8 | SF | 17,700 |
Nitrogen trifluoride | 7783-54-2 | NF | 17,200 |
PFC-14 (Perfluoromethane) | 75-73-0 | CF | a 7,390 |
PFC-116 (Perfluoroethane) | 76-16-4 | C | a 12,200 |
PFC-218 (Perfluoropropane) | 76-19-7 | C | a 8,830 |
Perfluorocyclopropane | 931-91-9 | C-C | 17,340 |
PFC-3-1-10 (Perfluorobutane) | 355-25-9 | C | a 8,860 |
PFC-318 (Perfluorocyclobutane) | 115-25-3 | C-C | a 10,300 |
PFC-4-1-12 (Perfluoropentane) | 678-26-2 | C | a 9,160 |
PFC-5-1-14 (Perfluorohexane, FC-72) | 355-42-0 | C | a 9,300 |
PFC-6-1-12 | 335-57-9 | C | b 7,820 |
PFC-7-1-18 | 307-34-6 | C | b 7,620 |
PFC-9-1-18 | 306-94-5 | C | 7,500 |
PFPMIE (HT-70) | NA | CF | 10,300 |
Perfluorodecalin (cis) | 60433-11-6 | Z-C | b 7,236 |
Perfluorodecalin (trans) | 60433-12-7 | E-C | b 6,288 |
HFC-23 | 75-46-7 | CHF | a 14,800 |
HFC-32 | 75-10-5 | CH | a 675 |
HFC-125 | 354-33-6 | C | a 3,500 |
HFC-134 | 359-35-3 | C | a 1,100 |
HFC-134a | 811-97-2 | CH | a 1,430 |
HFC-227ca | 2252-84-8 | CF | b 2640 |
HFC-227ea | 431-89-0 | C | a 3,220 |
HFC-236cb | 677-56-5 | CH | 1,340 |
HFC-236ea | 431-63-0 | CHF | 1,370 |
HFC-236fa | 690-39-1 | C | a 9,810 |
HFC-329p | 375-17-7 | CHF | b 2360 |
HFC-43-10mee | 138495-42-8 | CF | a 1,640 |
HFC-41 | 593-53-3 | CH | a 92 |
HFC-143 | 430-66-0 | C | a 353 |
HFC-143a | 420-46-2 | C | a 4,470 |
HFC-152 | 624-72-6 | CH | 53 |
HFC-152a | 75-37-6 | CH | a 124 |
HFC-161 | 353-36-6 | CH | 12 |
HFC-245ca | 679-86-7 | C | a 693 |
HFC-245cb | 1814-88-6 | CF | b 4620 |
HFC-245ea | 24270-66-4 | CHF | b 235 |
HFC-245eb | 431-31-2 | CH | b 290 |
HFC-245fa | 460-73-1 | CHF | 1,030 |
HFC-263fb | 421-07-8 | CH | b 76 |
HFC-272ca | 420-45-1 | CH | b 144 |
HFC-365mfc | 406-58-6 | CH | 794 |
HFE-125 | 3822-68-2 | CHF | 14,900 |
HFE-227ea | 2356-62-9 | CF | 1,540 |
HFE-329mcc2 | 134769-21-4 | CF | 919 |
HFE-329me3 | 428454-68-6 | CF | b 4,550 |
1,1,1,2,2,3,3-Heptafluoro-3-(1,2,2,2-tetrafluoroethoxy)-propane | 3330-15-2 | CF | b 6,490 |
HFE-134 (HG-00) | 1691-17-4 | CHF | 6,320 |
HFE-236ca | 32778-11-3 | CHF | b 4,240 |
HFE-236ca12 (HG-10) | 78522-47-1 | CHF | 2,800 |
HFE-236ea2 (Desflurane) | 57041-67-5 | CHF | 989 |
HFE-236fa | 20193-67-3 | CF | 487 |
HFE-338mcf2 | 156053-88-2 | CF | 552 |
HFE-338mmz1 | 26103-08-2 | CHF | 380 |
HFE-338pcc13 (HG-01) | 188690-78-0 | CHF | 1,500 |
HFE-43-10pccc (H-Galden 1040x, HG-11) | E1730133 | CHF | 1,870 |
HCFE-235ca2 (Enflurane) | 13838-16-9 | CHF | b 583 |
HCFE-235da2 (Isoflurane) | 26675-46-7 | CHF | 350 |
HG-02 | 205367-61-9 | HF | b 3,825 |
HG-03 | 173350-37-3 | HF | b 3,670 |
HG-20 | 249932-25-0 | HF | b 5,300 |
HG-21 | 249932-26-1 | HF | b 3,890 |
HG-30 | 188690-77-9 | HF | b 7,330 |
1,1,3,3,4,4,6,6,7,7,9,9,10,10,12,12,13,13,15,15-eicosafluoro-2,5,8,11,14-Pentaoxapentadecane | 173350-38-4 | HCF | b 3,630 |
1,1,2-Trifluoro-2-(trifluoromethoxy)-ethane | 84011-06-3 | CHF | b 1,240 |
Trifluoro(fluoromethoxy)methane | 2261-01-0 | CH | b 751 |
HFE-143a | 421-14-7 | CH | 756 |
HFE-245cb2 | 22410-44-2 | CH | 708 |
HFE-245fa1 | 84011-15-4 | CHF | 286 |
HFE-245fa2 | 1885-48-9 | CHF | 659 |
HFE-254cb2 | 425-88-7 | CH | 359 |
HFE-263fb2 | 460-43-5 | CF | 11 |
HFE-263m1; R-E-143a | 690-22-2 | CF | b 29 |
HFE-347mcc3 (HFE-7000) | 375-03-1 | CH | 575 |
HFE-347mcf2 | 171182-95-9 | CF | 374 |
HFE-347mmy1 | 22052-84-2 | CH | 343 |
HFE-347mmz1 (Sevoflurane) | 28523-86-6 | (CF | c 216 |
HFE-347pcf2 | 406-78-0 | CHF | 580 |
HFE-356mec3 | 382-34-3 | CH | 101 |
HFE-356mff2 | 333-36-8 | CF | b 17 |
HFE-356mmz1 | 13171-18-1 | (CF | 27 |
HFE-356pcc3 | 160620-20-2 | CH | 110 |
HFE-356pcf2 | 50807-77-7 | CHF | 265 |
HFE-356pcf3 | 35042-99-0 | CHF | 502 |
HFE-365mcf2 | 22052-81-9 | CF | b 58 |
HFE-365mcf3 | 378-16-5 | CF | 11 |
HFE-374pc2 | 512-51-6 | CH | 557 |
HFE-449s1 (HFE-7100) Chemical blend | 163702-07-6 | C | 297 |
163702-08-7 | (CF | ||
HFE-569sf2 (HFE-7200) Chemical blend | 163702-05-4 | C | 59 |
163702-06-5 | (CF | ||
HG’-01 | 73287-23-7 | CH | b 222 |
HG’-02 | 485399-46-0 | CH | b 236 |
HG’-03 | 485399-48-2 | CH | b 221 |
Difluoro(methoxy)methane | 359-15-9 | CH | b 144 |
2-Chloro-1,1,2-trifluoro-1-methoxyethane | 425-87-6 | CH | b 122 |
1-Ethoxy-1,1,2,2,3,3,3-heptafluoropropane | 22052-86-4 | CF | b 61 |
2-Ethoxy-3,3,4,4,5-pentafluorotetrahydro-2,5-bis[1,2,2,2-tetrafluoro-1-(trifluoromethyl)ethyl]-furan | 920979-28-8 | C | b 56 |
1-Ethoxy-1,1,2,3,3,3-hexafluoropropane | 380-34-7 | CF | b 23 |
Fluoro(methoxy)methane | 460-22-0 | CH | b 13 |
1,1,2,2-Tetrafluoro-3-methoxy-propane; Methyl 2,2,3,3-tetrafluoropropyl ether | 60598-17-6 | CHF | b 0.5 |
1,1,2,2-Tetrafluoro-1-(fluoromethoxy)ethane | 37031-31-5 | CH | b 871 |
Difluoro(fluoromethoxy)methane | 461-63-2 | CH | b 617 |
Fluoro(fluoromethoxy)methane | 462-51-1 | CH | b 130 |
Trifluoromethyl formate | 85358-65-2 | HCOOCF | b 588 |
Perfluoroethyl formate | 313064-40-3 | HCOOCF | b 580 |
1,2,2,2-Tetrafluoroethyl formate | 481631-19-0 | HCOOCHFCF | b 470 |
Perfluorobutyl formate | 197218-56-7 | HCOOCF | b 392 |
Perfluoropropyl formate | 271257-42-2 | HCOOCF | b 376 |
1,1,1,3,3,3-Hexafluoropropan-2-yl formate | 856766-70-6 | HCOOCH(CF | b 333 |
2,2,2-Trifluoroethyl formate | 32042-38-9 | HCOOCH | b 33 |
3,3,3-Trifluoropropyl formate | 1344118-09-7 | HCOOCH | b 17 |
Methyl 2,2,2-trifluoroacetate | 431-47-0 | CF | b 52 |
1,1-Difluoroethyl 2,2,2-trifluoroacetate | 1344118-13-3 | CF | b 31 |
Difluoromethyl 2,2,2-trifluoroacetate | 2024-86-4 | CF | b 27 |
2,2,2-Trifluoroethyl 2,2,2-trifluoroacetate | 407-38-5 | CF | b 7 |
Methyl 2,2-difluoroacetate | 433-53-4 | HCF | b 3 |
Perfluoroethyl acetate | 343269-97-6 | CH | b 2.1 |
Trifluoromethyl acetate | 74123-20-9 | CH | b 2.0 |
Perfluoropropyl acetate | 1344118-10-0 | CH | b 1.8 |
Perfluorobutyl acetate | 209597-28-4 | CH | b 1.6 |
Ethyl 2,2,2-trifluoroacetate | 383-63-1 | CF | b 1.3 |
Methyl carbonofluoridate | 1538-06-3 | FCOOCH | b 95 |
1,1-Difluoroethyl carbonofluoridate | 1344118-11-1 | FCOOCF | b 27 |
Bis(trifluoromethyl)-methanol | 920-66-1 | (CF | 195 |
(Octafluorotetramethy-lene) hydroxymethyl group | NA | X-(CF | 73 |
2,2,3,3,3-Pentafluoropropanol | 422-05-9 | CF | 42 |
2,2,3,3,4,4,4-Heptafluorobutan-1-ol | 375-01-9 | C | b 25 |
2,2,2-Trifluoroethanol | 75-89-8 | CF | b 20 |
2,2,3,4,4,4-Hexafluoro-1-butanol | 382-31-0 | CF | b 17 |
2,2,3,3-Tetrafluoro-1-propanol | 76-37-9 | CHF | b 13 |
2,2-Difluoroethanol | 359-13-7 | CHF | b 3 |
2-Fluoroethanol | 371-62-0 | CH | b 1.1 |
4,4,4-Trifluorobutan-1-ol | 461-18-7 | CF | b 0.05 |
PFC-1114; TFE | 116-14-3 | CF | b 0.004 |
PFC-1216; Dyneon HFP | 116-15-4 | C | b 0.05 |
PFC C-1418 | 559-40-0 | c-C | b 1.97 |
Perfluorobut-2-ene | 360-89-4 | CF | b 1.82 |
Perfluorobut-1-ene | 357-26-6 | CF | b 0.10 |
Perfluorobuta-1,3-diene | 685-63-2 | CF | b 0.003 |
HFC-1132a; VF2 | 75-38-7 | C | b 0.04 |
HFC-1141; VF | 75-02-5 | C | b 0.02 |
(E)-HFC-1225ye | 5595-10-8 | CF | b 0.06 |
(Z)-HFC-1225ye | 5528-43-8 | CF | b 0.22 |
Solstice 1233zd(E) | 102687-65-0 | C | b 1.34 |
HFC-1234yf; HFO-1234yf | 754-12-1 | C | b 0.31 |
HFC-1234ze(E) | 1645-83-6 | C | b 0.97 |
HFC-1234ze(Z) | 29118-25-0 | C | b 0.29 |
HFC-1243zf; TFP | 677-21-4 | C | b 0.12 |
(Z)-HFC-1336 | 692-49-9 | CF | b 1.58 |
HFC-1345zfc | 374-27-6 | C | b 0.09 |
Capstone 42-U | 19430-93-4 | C | b 0.16 |
Capstone 62-U | 25291-17-2 | C | b 0.11 |
Capstone 82-U | 21652-58-4 | C | b 0.09 |
PMVE; HFE-216 | 1187-93-5 | CF | b 0.17 |
Fluoroxene | 406-90-6 | CF | b 0.05 |
3,3,3-Trifluoro-propanal | 460-40-2 | CF | b 0.01 |
Novec 1230 (perfluoro (2-methyl-3-pentanone)) | 756-13-8 | CF | b 0.1 |
3,3,4,4,5,5,6,6,7,7,7-Undecafluoroheptan-1-ol | 185689-57-0 | CF | b 0.43 |
3,3,3-Trifluoropropan-1-ol | 2240-88-2 | CF | b 0.35 |
3,3,4,4,5,5,6,6,7,7,8,8,9,9,9-Pentadecafluorononan-1-ol | 755-02-2 | CF | b 0.33 |
3,3,4,4,5,5,6,6,7,7,8,8,9,9,10,10,11,11,11-Nonadecafluoroundecan-1-ol | 87017-97-8 | CF | b 0.19 |
Trifluoroiodomethane | 2314-97-8 | CF | b 0.4 |
Dibromodifluoromethane (Halon 1202) | 75-61-6 | CBR | b 231 |
2-Bromo-2-chloro-1,1,1-trifluoroethane (Halon-2311/Halothane) | 151-67-7 | CHBrClCF | b 41 |
Fluorinated GHG Group d | Global warming potential (100 yr.) |
---|---|
Fully fluorinated GHGs | 10,000 |
Saturated hydrofluorocarbons (HFCs) with 2 or fewer carbon-hydrogen bonds | 3,700 |
Saturated HFCs with 3 or more carbon-hydrogen bonds | 930 |
Saturated hydrofluoroethers (HFEs) and hydrochlorofluoroethers (HCFEs) with 1 carbon-hydrogen bond | 5,700 |
Saturated HFEs and HCFEs with 2 carbon-hydrogen bonds | 2,600 |
Saturated HFEs and HCFEs with 3 or more carbon-hydrogen bonds | 270 |
Fluorinated formates | 350 |
Fluorinated acetates, carbonofluoridates, and fluorinated alcohols other than fluorotelomer alcohols | 30 |
Unsaturated perfluorocarbons (PFCs), unsaturated HFCs, unsaturated hydrochlorofluorocarbons (HCFCs), unsaturated halogenated ethers, unsaturated halogenated esters, fluorinated aldehydes, and fluorinated ketones | 1 |
Fluorotelomer alcohols | 1 |
Fluorinated GHGs with carbon-iodine bond(s) | 1 |
Other fluorinated GHGs | 2,000 |
a The GWP for this compound was updated in the final rule published on November 29, 2013 [78 FR 71904] and effective on January 1, 2014.
b This compound was added to Table A-1 in the final rule published on December 11, 2014, and effective on January 1, 2015.
c The GWP for this compound was updated in the final rule published on December 11, 2014, and effective on January 1, 2015 .
d For electronics manufacturing (as defined in § 98.90), the term “fluorinated GHGs” in the definition of each fluorinated GHG group in § 98.6 shall include fluorinated heat transfer fluids (as defined in § 98.98), whether or not they are also fluorinated GHGs.
Table A-2 to Subpart A of Part 98 – Units of Measure Conversions
To convert from | To | Multiply by |
---|---|---|
Kilograms (kg) | Pounds (lbs) | 2.20462 |
Pounds (lbs) | Kilograms (kg) | 0.45359 |
Pounds (lbs) | Metric tons | 4.53592 × 10 |
Short tons | Pounds (lbs) | 2,000 |
Short tons | Metric tons | 0.90718 |
Metric tons | Short tons | 1.10231 |
Metric tons | Kilograms (kg) | 1,000 |
Cubic meters (m 3) | Cubic feet (ft 3) | 35.31467 |
Cubic feet (ft 3) | Cubic meters (m 3) | 0.028317 |
Gallons (liquid, US) | Liters (l) | 3.78541 |
Liters (l) | Gallons (liquid, US) | 0.26417 |
Barrels of Liquid Fuel (bbl) | Cubic meters (m 3) | 0.15891 |
Cubic meters (m 3) | Barrels of Liquid Fuel (bbl) | 6.289 |
Barrels of Liquid Fuel (bbl) | Gallons (liquid, US) | 42 |
Gallons (liquid, US) | Barrels of Liquid Fuel (bbl) | 0.023810 |
Gallons (liquid, US) | Cubic meters (m 3) | 0.0037854 |
Liters (l) | Cubic meters (m 3) | 0.001 |
Feet (ft) | Meters (m) | 0.3048 |
Meters (m) | Feet (ft) | 3.28084 |
Miles (mi) | Kilometers (km) | 1.60934 |
Kilometers (km) | Miles (mi) | 0.62137 |
Square feet (ft 2) | Acres | 2.29568 × 10 |
Square meters (m 2) | Acres | 2.47105 × 10 |
Square miles (mi 2) | Square kilometers (km 2) | 2.58999 |
Degrees Celsius (°C) | Degrees Fahrenheit (°F) | °C = ( |
Degrees Fahrenheit (°F) | Degrees Celsius (°C) | °F = ( |
Degrees Celsius (°C) | Kelvin (K) | K = °C + 273.15 |
Kelvin (K) | Degrees Rankine (°R) | 1.8 |
Joules | Btu | 9.47817 × 10 |
Btu | MMBtu | 1 × 10 |
Pascals (Pa) | Inches of Mercury (in Hg) | 2.95334 × 10 |
Inches of Mercury (inHg) | Pounds per square inch (psi) | 0.49110 |
Pounds per square inch (psi) | Inches of Mercury (in Hg) | 2.03625 |
Table A-3 to Subpart A of Part 98 – Source Category List for § 98.2(a )(1)
Source Category List for § 98.2(
Source Categories a Applicable in Reporting Year 2010 and Future Years |
Electricity generation units that report CO |
Adipic acid production (subpart E). |
Aluminum production (subpart F). |
Ammonia manufacturing (subpart G). |
Cement production (subpart H). |
HCFC-22 production (subpart O). |
HFC-23 destruction processes that are not collocated with a HCFC-22 production facility and that destroy more than 2.14 metric tons of HFC-23 per year (subpart O). |
Lime manufacturing (subpart S). |
Nitric acid production (subpart V). |
Petrochemical production (subpart X). |
Petroleum refineries (subpart Y). |
Phosphoric acid production (subpart Z). |
Silicon carbide production (subpart BB). |
Soda ash production (subpart CC). |
Titanium dioxide production (subpart EE). |
Municipal solid waste landfills that generate CH |
Manure management systems with combined CH |
Additional Source Categories a Applicable in Reporting Year 2011 and Future Years |
Electrical transmission and distribution equipment use at facilities where the total nameplate capacity of SF |
Underground coal mines liberating 36,500,000 actual cubic feet of CH |
Geologic sequestration of carbon dioxide (subpart RR). |
Electrical transmission and distribution equipment manufacture or refurbishment (subpart SS). |
Injection of carbon dioxide (subpart UU). |
a Source categories are defined in each applicable subpart.
Table A-4 to Subpart A of Part 98 – Source Category List for § 98.2(a )(2)
Source Categories a Applicable in Reporting Year 2010 and Future Years |
Ferroalloy production (subpart K). |
Glass production (subpart N). |
Hydrogen production (subpart P). |
Iron and steel production (subpart Q). |
Lead production (subpart R). |
Pulp and paper manufacturing (subpart AA). |
Zinc production (subpart GG). |
Additional Source Categories a Applicable in Reporting Year 2011 and Future Years |
Electronics manufacturing (subpart I) |
Fluorinated gas production (subpart L) |
Magnesium production (subpart T). |
Petroleum and Natural Gas Systems (subpart W) |
Industrial wastewater treatment (subpart II). |
Industrial waste landfills (subpart TT). |
a Source categories are defined in each applicable subpart.
Table A-5 to Subpart A of Part 98 – Supplier Category List for § 98.2(a )(4)
Supplier Categories a Applicable in Reporting Year 2010 and Future Years |
Coal-to-liquids suppliers (subpart LL): |
(A) All producers of coal-to-liquid products. |
(B) Importers of an annual quantity of coal-to-liquid products that is equivalent to 25,000 metric tons CO |
(C) Exporters of an annual quantity of coal-to-liquid products that is equivalent to 25,000 metric tons CO |
Petroleum product suppliers (subpart MM): |
(A) All petroleum refineries that distill crude oil. |
(B) Importers of an annual quantity of petroleum products and natural gas liquids that is equivalent to 25,000 metric tons CO |
(C) Exporters of an annual quantity of petroleum products and natural gas liquids that is equivalent to 25,000 metric tons CO |
Natural gas and natural gas liquids suppliers (subpart NN): |
(A) All fractionators. |
(B) Local natural gas distribution companies that deliver 460,000 thousand standard cubic feet or more of natural gas per year. |
Industrial greenhouse gas suppliers (subpart OO): |
(A) All producers of industrial greenhouse gases. |
(B) Importers of industrial greenhouse gases with annual bulk imports of N |
(C) Exporters of industrial greenhouse gases with annual bulk exports of N |
(D) Starting with reporting year 2018, all producers of fluorinated heat transfer fluids. |
(E) Starting with reporting year 2018, importers of fluorinated heat transfer fluids with annual bulk imports of N |
(F) Starting with reporting year 2018, exporters of fluorinated heat transfer fluids with annual bulk exports of N |
(G) Starting with reporting year 2018, facilities that destroy 25,000 mtCO |
Carbon dioxide suppliers (subpart PP): |
(A) All producers of CO |
(B) Importers of CO |
(C) Exporters of CO |
Additional Supplier Categories Applicable a in Reporting Year 2011 and Future Years |
Importers and exporters of fluorinated greenhouse gases contained in pre-charged equipment or closed-cell foams (subpart QQ): |
(A) Importers of an annual quantity of fluorinated greenhouse gases contained in pre-charged equipment or closed-cell foams that is equivalent to 25,000 metric tons CO |
(B) Exporters of an annual quantity of fluorinated greenhouse gases contained in pre-charged equipment or closed-cell foams that is equivalent to 25,000 metric tons CO |
a Suppliers are defined in each applicable subpart.
Table A-6 to Subpart A of Part 98 – Data Elements That Are Inputs to Emission Equations and for Which the Reporting Deadline Is March 31, 2013
Subpart | Rule citation (40 CFR part 98) | Specific data elements for which reporting date is March 31, 2013 (“All” means all data elements in the cited paragraph are not required to be reported until March 31, 2013) |
---|---|---|
C | 98.36(d)(1)(iv) | All. |
C | 98.36(d)(2)(ii)(G) | All. |
C | 98.36(d)(2)(iii)(G) | All. |
C | 98.36(e)(2)(iv)(G) | All. |
C | 98.36(e)(2)(viii)(A) | All. |
C | 98.36(e)(2)(viii)(B) | All. |
C | 98.36(e)(2)(viii)(C) | All. |
C | 98.36(e)(2)(x)(A) | All. |
C | 98.36(e)(2)(xi) | All. |
DD | 98.306(a)(2) | All. |
DD | 98.306(a)(3) | All. |
DD | 98.306(d) | All. |
DD | 98.306(e) | All. |
DD | 98.306(f) | All. |
DD | 98.306(g) | All. |
DD | 98.306(h) | All. |
DD | 98.306(i) | All. |
DD | 98.306(j) | All. |
DD | 98.306(k) | All. |
DD | 98.306(l) | All. |
FF | 98.326(a) | All. |
FF | 98.326(b) | All. |
FF | 98.326(c) | All. |
FF | 98.326(f) | Only quarterly volumetric flow rate. |
FF | 98.326(g) | Only quarterly CH |
FF | 98.326(h) | Only weekly volumetric flow used to calculate CH |
FF | 98.326(j) | All. |
FF | 98.326(k) | All. |
FF | 98.326(o) | All. |
FF | 98.326(p) | Only assumed destruction efficiency for the primary destruction device and assumed destruction efficiency for the backup destruction device. |
HH | 98.346(a) | Only year in which landfill first accepted waste, last year the landfill accepted waste (if used as an input in Equation HH-3), capacity of the landfill (if used as an input in Equation HH-3), and waste disposal quantity for each year of landfilling. |
HH | 98.346(b) | Only quantity of waste determined using the methods in § 98.343(a)(3)(i), quantity of waste determined using the methods in § 98.343(a)(3)(ii), population served by the landfill for each year, and the value of landfill capacity (LFC) used in the calculation. |
HH | 98.346(c) | All. |
HH | 98.346(d)(1) | Only degradable organic carbon (DOC) value, and fraction of DOC dissimilated (DOCF) values. |
HH | 98.346(d)(2) | All. |
HH | 98.346(e) | Only fraction of CH |
HH | 98.346(f) | Only surface area associated with each cover type. |
HH | 98.346(g) | All. |
HH | 98.346(i)(5) | Only annual operating hours for the destruction devices located at the landfill facility, and the destruction efficiency for the destruction devices associated with that measurement location. |
HH | 98.346(i)(6) | All. |
HH | 98.346(i)(7) | Only surface area specified in Table HH-3, estimated gas collection system efficiency, and annual operating hours of the gas collection system for each measurement locations. |
HH | 98.346(i)(9) | Only CH |
II | 98.356(b)(1) | All. |
II | 98.356(b)(2) | All. |
II | 98.356(b)(3) | All. |
II | 98.356(b)(4) | All. |
II | 98.356(b)(5) | All. |
II | 98.356(d)(1) | All. |
II | 98.356(d)(7) | All. |
II | 98.356(d)(8) | Only annual operating hours for the primary destruction device, annual operating hours for the backup destruction device, destruction efficiency of the primary destruction device, and destruction efficiency of the backup destruction device. |
SS | 98.456(a) | All. |
SS | 98.456(b) | All. |
SS | 98.456(c) | All. |
SS | 98.456(d) | All. |
SS | 98.456(e) | All. |
SS | 98.456(f) | All. |
SS | 98.456(g) | All. |
SS | 98.456(h) | All. |
SS | 98.456(i) | All. |
SS | 98.456(j) | All. |
SS | 98.456(m) | All. |
SS | 98.456(n) | All. |
SS | 98.456(o) | All. |
SS | 98.456(q) | All. |
SS | 98.456(r) | All. |
SS | 98.456(s) | All. |
SS | 98.456(t) | Only for any missing data the substitute parameters used to estimate emissions in their absence. |
TT | 98.466(a)(2) | All. |
TT | 98.466(a)(3) | Only last year the landfill accepted waste (for closed landfills using Equation TT-4). |
TT | 98.466(a)(4) | Only capacity of the landfill in metric tons (for closed landfills using Equation TT-4). |
TT | 98.466(b)(3) | Only fraction of CH |
TT | 98.466(b)(4) | Only the methane correction factor (MCF) value used in the calculations. |
TT | 98.466(c)(4)(i) | All. |
TT | 98.466(c)(4)(ii) | All. |
TT | 98.466(c)(4)(iii) | All. |
TT | 98.466(d)(2) | All. |
TT | 98.466(d)(3) | Only degradable organic carbon (DOCx) value for each waste stream used in calculations. |
TT | 98.466(e)(2) | Only surface area (in square meters) at the start of the reporting year for the landfill sections that contain waste and that are associated with the selected cover type (for facilities using a landfill gas collection system). |
TT | 98.466(f) | All. |
Table A-7 to Subpart A of Part 98 – Data Elements That Are Inputs to Emission Equations and for Which the Reporting Deadline Is March 31, 2015
Subpart | Rule citation (40 CFR part 98) | Specific data elements for which reporting date is March 31, 2015 (“All” means all data elements in the cited paragraph are not required to be reported until March 31, 2015) |
---|---|---|
A | 98.3(d)(3)(v) | All. a |
C | 98.36(b)(9)(iii) | Only estimate of the heat input. a |
C | 98.36(c)(2)(ix) | Only estimate of the heat input from each type of fuel listed in Table C-2. a |
C | 98.36(e)(2)(i) | All. a |
C | 98.36(e)(2)(ii)(A) | All. a |
C | 98.36(e)(2)(ii)(C) | Only HHV value for each calendar month in which HHV determination is required. a |
C | 98.36(e)(2)(ii)(D) | All. a |
C | 98.36(e)(2)(iv)(A) | All. a |
C | 98.36(e)(2)(iv)(C) | All. a |
C | 98.36(e)(2)(iv)(F) | All. a |
C | 98.36(e)(2)(ix)(D) | All. a |
C | 98.36(e)(2)(ix)(E) | All. a |
C | 98.36(e)(2)(ix)(F) | All. a |
E | 98.56(g) | All. |
E | 98.56(h) | All. |
E | 98.56(j)(4) | All. |
E | 98.56(j)(5) | All. |
E | 98.56(j)(6) | All. |
E | 98.56(l) | All. |
H | 98.86(b)(11) | All. |
H | 98.86(b)(13) | Name of raw kiln feed or raw material. |
O | 98.156(d)(2) | All. |
O | 98.156(d)(3) | All. |
O | 98.156(d)(4) | All. |
Q | 98.176(f)(1) | All. |
W | 98.236(c)(1)(i) | All. |
W | 98.236(c)(1)(ii) | All. |
W | 98.236(c)(1)(iii) | All. |
W | 98.236(c)(2)(i) | All. |
W | 98.236(c)(3)(i) | All. |
W | 98.236(c)(3)(ii) | Only Calculation Methodology 2. |
W | 98.236(c)(3)(iii) | All. |
W | 98.236(c)(3)(iv) | All. |
W | 98.236(c)(4)(i)(A) | All. |
W | 98.236(c)(4)(i)(B) | All. |
W | 98.236(c)(4)(i)(C) | All. |
W | 98.236(c)(4)(i)(D) | All. |
W | 98.236(c)(4)(i)(E) | All. |
W | 98.236(c)(4)(i)(F) | All. |
W | 98.236(c)(4)(i)(G) | All. |
W | 98.236(c)(4)(i)(H) | All. |
W | 98.236(c)(4)(ii)(A) | All. |
W | 98.236(c)(5)(i)(D) | All. |
W | 98.236(c)(5)(ii)(C) | All. |
W | 98.236(c)(6)(i)(B) | All. b |
W | 98.236(c)(6)(i)(D) | All. b |
W | 98.236(c)(6)(i)(E) | All. b |
W | 98.236(c)(6)(i)(F) | All. b |
W | 98.236(c)(6)(i)(G) | Only the amount of natural gas required. |
W | 98.236(c)(6)(i)(H) | Only the amount of natural gas required. |
W | 98.236(c)(6)(ii)(A) | All. |
W | 98.236(c)(6)(ii)(B) | All. |
W | 98.236(c)(7)(i)(A) | Only for Equation W-14A. |
W | 98.236(c)(8)(i)(F) | All. b |
W | 98.236(c)(8)(i)(K) | All. |
W | 98.236(c)(8)(ii)(A) | All. b |
W | 98.236(c)(8)(ii)(H) | All. |
W | 98.236(c)(8)(iii)(A) | All. |
W | 98.236(c)(8)(iii)(B) | All. |
W | 98.236(c)(8)(iii)(G) | All. |
W | 98.236(c)(12)(ii) | All. |
W | 98.236(c)(12)(v) | All. |
W | 98.236(c)(13)(i)(E) | All. |
W | 98.236(c)(13)(i)(F) | All. |
W | 98.236(c)(13)(ii)(A) | All. |
W | 98.236(c)(13)(ii)(B) | All. |
W | 98.236(c)(13)(iii)(A) | All. |
W | 98.236(c)(13)(iii)(B) | All. |
W | 98.236(c)(13)(v)(A) | All. |
W | 98.236(c)(14)(i)(B) | All. |
W | 98.236(c)(14)(ii)(A) | All. |
W | 98.236(c)(14)(ii)(B) | All. |
W | 98.236(c)(14)(iii)(A) | All. |
W | 98.236(c)(14)(iii)(B) | All. |
W | 98.236(c)(14)(v)(A) | All. |
W | 98.236(c)(15)(ii)(A) | All. |
W | 98.236(c)(15)(ii)(B) | All. |
W | 98.236(c)(16)(viii) | All. |
W | 98.236(c)(16)(ix) | All. |
W | 98.236(c)(16)(x) | All. |
W | 98.236(c)(16)(xi) | All. |
W | 98.236(c)(16)(xii) | All. |
W | 98.236(c)(16)(xiii) | All. |
W | 98.236(c)(16)(xiv) | All. |
W | 98.236(c)(16)(xv) | All. |
W | 98.236(c)(16)(xvi) | All. |
W | 98.236(c)(17)(ii) | All. |
W | 98.236(c)(17)(iii) | All. |
W | 98.236(c)(17)(iv) | All. |
W | 98.236(c)(18)(i) | All. |
W | 98.236(c)(18)(ii) | All. |
W | 98.236(c)(19)(iv) | All. |
W | 98.236(c)(19)(vii) | All. |
Y | 98.256(h)(5)(i) | Only value of the correction. |
Y | 98.256(k)(4) | Only mole fraction of methane in coking gas. |
Y | 98.256(n)(3) | All (if used in Equation Y-21 to calculate emissions from equipment leaks). |
Y | 98.256(o)(4)(vi) | Only tank-specific methane composition data and gas generation rate data. |
AA | 98.276(e) | All. |
CC | 98.296(b)(10)(i) | All. |
CC | 98.296(b)(10)(ii) | All. |
CC | 98.296(b)(10)(iii) | All. |
CC | 98.296(b)(10)(iv) | All. |
CC | 98.296(b)(10)(v) | All. |
CC | 98.296(b)(10)(vi) | All. |
II | 98.356(d)(2) | All (if conducting weekly sampling). |
II | 98.356(d)(3) | All (if conducting weekly sampling). |
II | 98.356(d)(4) | Only weekly average temperature (if conducting weekly sampling). |
II | 98.356(d)(5) | Only weekly average moisture content (if conducting weekly sampling). |
II | 98.356(d)(6) | Only weekly average pressure (if conducting weekly sampling). |
a Required to be reported only by: (1) Stationary fuel combustion sources (
b This rule citation provides an option to delay reporting of this data element for certain wildcat wells and/or delineation wells.
Subpart B [Reserved]
Subpart C – General Stationary Fuel Combustion Sources
§ 98.30 Definition of the source category.
(a) Stationary fuel combustion sources are devices that combust solid, liquid, or gaseous fuel, generally for the purposes of producing electricity, generating steam, or providing useful heat or energy for industrial, commercial, or institutional use, or reducing the volume of waste by removing combustible matter. Stationary fuel combustion sources include, but are not limited to, boilers, simple and combined-cycle combustion turbines, engines, incinerators, and process heaters.
(b) This source category does not include:
(1) Portable equipment, as defined in § 98.6.
(2) Emergency generators and emergency equipment, as defined in § 98.6.
(3) Irrigation pumps at agricultural operations.
(4) Flares, unless otherwise required by provisions of another subpart of this part to use methodologies in this subpart.
(5) Electricity generating units that are subject to subpart D of this part.
(c) For a unit that combusts hazardous waste (as defined in § 261.3 of this chapter), reporting of GHG emissions is not required unless either of the following conditions apply:
(1) Continuous emission monitors (CEMS) are used to quantify CO
(2) Any fuel listed in Table C-1 of this subpart is also combusted in the unit. In this case, report GHG emissions from combustion of all fuels listed in Table C-1 of this subpart.
(d) You are not required to report GHG emissions from pilot lights. A pilot light is a small auxiliary flame that ignites the burner of a combustion device when the control valve opens.
§ 98.31 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains one or more stationary fuel combustion sources and the facility meets the applicability requirements of either §§ 98.2(a)(1), 98.2(a)(2), or 98.2(a)(3).
§ 98.32 GHGs to report.
You must report CO
§ 98.33 Calculating GHG emissions.
You must calculate CO
(a) CO
(1) Tier 1 Calculation Methodology. Calculate the annual CO
(i) Use Equation C-1 except when natural gas billing records are used to quantify fuel usage and gas consumption is expressed in units of therms or million Btu. In that case, use Equation C-1a or C-1b, as applicable.
(ii) If natural gas consumption is obtained from billing records and fuel usage is expressed in therms, use Equation C-1a.
(iii) If natural gas consumption is obtained from billing records and fuel usage is expressed in mmBtu, use Equation C-1b.
(2) Tier 2 Calculation Methodology. Calculate the annual CO
(i) Equation C-2a of this section applies to any type of fuel listed in Table C-1 of the subpart, except for municipal solid waste (MSW). For MSW combustion, use Equation C-2c of this section.
(ii) The minimum required sampling frequency for determining the annual average HHV (e.g., monthly, quarterly, semi-annually, or by lot) is specified in § 98.34. The method for computing the annual average HHV is a function of unit size and how frequently you perform or receive from the fuel supplier the results of fuel sampling for HHV. The method is specified in paragraph (a)(2)(ii)(A) or (a)(2)(ii)(B) of this section, as applicable.
(A) If the results of fuel sampling are received monthly or more frequently, then for each unit with a maximum rated heat input capacity greater than or equal to 100 mmBtu/hr (or for a group of units that includes at least one unit of that size), the annual average HHV shall be calculated using Equation C-2b of this section. If multiple HHV determinations are made in any month, average the values for the month arithmetically.
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(B) If the results of fuel sampling are received less frequently than monthly, or, for a unit with a maximum rated heat input capacity less than 100 mmBtu/hr (or a group of such units) regardless of the HHV sampling frequency, the annual average HHV shall either be computed according to paragraph (a)(2)(ii)(A) of this section or as the arithmetic average HHV for all values for the year (including valid samples and substitute data values under § 98.35).
(iii) For units that combust municipal solid waste (MSW) and that produce steam, use Equation C-2c of this section. Equation C-2c of this section may also be used for any other solid fuel listed in Table C-1 of this subpart provided that steam is generated by the unit.
(3) Tier 3 Calculation Methodology. Calculate the annual CO
(i) For a solid fuel, use Equation C-3 of this section.
(ii) For a liquid fuel, use Equation C-4 of this section.
(iii) For a gaseous fuel, use Equation C-5 of this section.
(iv) Fuel flow meters that measure mass flow rates may be used for liquid or gaseous fuels, provided that the fuel density is used to convert the readings to volumetric flow rates. The density shall be measured at the same frequency as the carbon content. You must measure the density using one of the following appropriate methods. You may use a method published by a consensus-based standards organization, if such a method exists, or you may use industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA), 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). The method(s) used shall be documented in the GHG Monitoring Plan required under § 98.3(g)(5).
(v) The following default density values may be used for fuel oil, in lieu of using the methods in paragraph (a)(3)(iv) of this section: 6.8 lb/gal for No. 1 oil; 7.2 lb/gal for No. 2 oil; 8.1 lb/gal for No. 6 oil.
(4) Tier 4 Calculation Methodology. Calculate the annual CO
(i) This methodology requires a CO
(ii) When the CO
(iii) If the CO
(iv) An oxygen (O
(v) Each hourly CO
(vi) The hourly CO
(vii) If both biomass and fossil fuel are combusted during the year, determine and report the biogenic CO
(viii) If a portion of the flue gases generated by a unit subject to Tier 4 (e.g., a slip stream) is continuously diverted from the main flue gas exhaust system for the purpose of heat recovery or some other similar process, and then exhausts through a stack that is not equipped with the continuous emission monitors to measure CO
(A) At least once a year, use EPA Methods 2 and 3A, and (if necessary) Method 4 in appendices A-2 and A-3 to part 60 of this chapter to perform emissions testing at a set point that best represents normal, stable process operating conditions. A minimum of three one-hour Method 3A tests are required, to determine the CO
(B) Calculate a CO
(C) The results of each annual stack test shall be used in the GHG emissions calculations for the year of the test.
(D) If, for the majority of the operating hours during the year, the diverted stream is withdrawn at a steady rate at or near the tested set point (as evidenced by fan and damper settings and/or other parameters), you may use the calculated CO
(E) If the flow rate of the diverted stream varies significantly throughout the year, except as provided below, repeat the stack test and emission rate calculation procedures described in paragraphs (c)(4)(viii)(A) and (c)(4)(viii)(B) of this section at a minimum of two more set points across the range of typical operating conditions to develop a correlation between CO
(F) Calculate the annual CO
(G) Finally, add the CO
(H) The exact method and procedures used to estimate the CO
(5) Alternative methods for certain units subject to Part 75 of this chapter. Certain units that are not subject to subpart D of this part and that report data to EPA according to part 75 of this chapter may qualify to use the alternative methods in this paragraph (a)(5), in lieu of using any of the four calculation methodology tiers.
(i) For a unit that combusts only natural gas and/or fuel oil, is not subject to subpart D of this part, monitors and reports heat input data year-round according to appendix D to part 75 of this chapter, but is not required by the applicable part 75 program to report CO
(A) Use the hourly heat input data from appendix D to part 75 of this chapter, together with Equation G-4 in appendix G to part 75 of this chapter to determine the hourly CO
(B) Use Equations F-12 and F-13 in appendix F to part 75 of this chapter to calculate the quarterly and cumulative annual CO
(C) Divide the cumulative annual CO
(ii) For a unit that combusts only natural gas and/or fuel oil, is not subject to subpart D of this part, monitors and reports heat input data year-round according to § 75.19 of this chapter but is not required by the applicable part 75 program to report CO
(A) Calculate the hourly CO
(B) Sum the hourly CO
(C) Divide the cumulative annual CO
(iii) For a unit that is not subject to subpart D of this part, uses flow rate and CO
(A) Use Equation F-11 or F-2 (as applicable) in appendix F to part 75 of this chapter to calculate the hourly CO
(B) Use Equations F-12 and F-13 in appendix F to part 75 of this chapter to calculate the quarterly and cumulative annual CO
(C) Divide the cumulative annual CO
(iv) For units that qualify to use the alternative CO
(b) Use of the four tiers. Use of the four tiers of CO
(1) The Tier 1 Calculation Methodology:
(i) May be used for any fuel listed in Table C-1 of this subpart that is combusted in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less.
(ii) May be used for MSW in a unit of any size that does not produce steam, if the use of Tier 4 is not required.
(iii) May be used for solid, gaseous, or liquid biomass fuels in a unit of any size provided that the fuel is listed in Table C-1 of this subpart.
(iv) May not be used if you routinely perform fuel sampling and analysis for the fuel high heat value (HHV) or routinely receive the results of HHV sampling and analysis from the fuel supplier at the minimum frequency specified in § 98.34(a), or at a greater frequency. In such cases, Tier 2 shall be used. This restriction does not apply to paragraphs (b)(1)(ii), (b)(1)(v), (b)(1)(vi), and (b)(1)(vii) of this section.
(v) May be used for natural gas combustion in a unit of any size, in cases where the annual natural gas consumption is obtained from fuel billing records in units of therms or mmBtu.
(vi) May be used for MSW combustion in a small, batch incinerator that burns no more than 1,000 tons per year of MSW.
(vii) May be used for the combustion of MSW and/or tires in a unit, provided that no more than 10 percent of the unit’s annual heat input is derived from those fuels, combined. Notwithstanding this requirement, if a unit combusts both MSW and tires and the reporter elects not to separately calculate and report biogenic CO
(viii) May be used for the combustion of a fuel listed in Table C-1 if the fuel is combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr (or, pursuant to § 98.36(c)(3), in a group of units served by a common supply pipe, having at least one unit with a maximum rated heat input capacity greater than 250 mmBtu/hr), provided that both of the following conditions apply:
(A) The use of Tier 4 is not required.
(B) The fuel provides less than 10 percent of the annual heat input to the unit, or if § 98.36(c)(3) applies, to the group of units served by a common supply pipe.
(2) The Tier 2 Calculation Methodology:
(i) May be used for the combustion of any type of fuel in a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less provided that the fuel is listed in Table C-1 of this subpart.
(ii) May be used in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr for the combustion of natural gas and/or distillate fuel oil.
(iii) May be used for MSW in a unit of any size that produces steam, if the use of Tier 4 is not required.
(3) The Tier 3 Calculation Methodology:
(i) May be used for a unit of any size that combusts any type of fuel listed in Table C-1 of this subpart (except for MSW), unless the use of Tier 4 is required.
(ii) Shall be used for a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr that combusts any type of fuel listed in Table C-1 of this subpart (except MSW), unless either of the following conditions apply:
(A) The use of Tier 1 or 2 is permitted, as described in paragraphs (b)(1)(iii), (b)(1)(v), (b)(1)(viii), and (b)(2)(ii) of this section.
(B) The use of Tier 4 is required.
(iii) Shall be used for a fuel not listed in Table C-1 of this subpart if the fuel is combusted in a unit with a maximum rated heat input capacity greater than 250 mmBtu/hr (or, pursuant to § 98.36(c)(3), in a group of units served by a common supply pipe, having at least one unit with a maximum rated heat input capacity greater than 250 mmBtu/hr), provided that both of the following conditions apply:
(A) The use of Tier 4 is not required.
(B) The fuel provides 10% or more of the annual heat input to the unit or, if § 98.36(c)(3) applies, to the group of units served by a common supply pipe.
(iv) Shall be used when specified in another applicable subpart of this part, regardless of unit size.
(4) The Tier 4 Calculation Methodology:
(i) May be used for a unit of any size, combusting any type of fuel. Tier 4 may also be used for any group of stationary fuel combustion units, process units, or manufacturing units that share a common stack or duct.
(ii) Shall be used if the unit meets all six of the conditions specified in paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(F) of this section:
(A) The unit has a maximum rated heat input capacity greater than 250 mmBtu/hr, or if the unit combusts municipal solid waste and has a maximum rated input capacity greater than 600 tons per day of MSW.
(B) The unit combusts solid fossil fuel or MSW as the primary fuel.
(C) The unit has operated for more than 1,000 hours in any calendar year since 2005.
(D) The unit has installed CEMS that are required either by an applicable Federal or State regulation or the unit’s operating permit.
(E) The installed CEMS include a gas monitor of any kind or a stack gas volumetric flow rate monitor, or both and the monitors have been certified, either in accordance with the requirements of part 75 of this chapter, part 60 of this chapter, or an applicable State continuous monitoring program.
(F) The installed gas or stack gas volumetric flow rate monitors are required, either by an applicable Federal or State regulation or by the unit’s operating permit, to undergo periodic quality assurance testing in accordance with either appendix B to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State continuous monitoring program.
(iii) Shall be used for a unit with a maximum rated heat input capacity of 250 mmBtu/hr or less and for a unit that combusts municipal solid waste with a maximum rated input capacity of 600 tons of MSW per day or less, if the unit meets all of the following three conditions:
(A) The unit has both a stack gas volumetric flow rate monitor and a CO
(B) The unit meets the conditions specified in paragraphs (b)(4)(ii)(B) through (b)(4)(ii)(D) of this section.
(C) The CO
(iv) May apply to common stack or duct configurations where:
(A) The combined effluent gas streams from two or more stationary fuel combustion units are vented through a monitored common stack or duct. In this case, Tier 4 shall be used if all of the conditions in paragraph (b)(4)(iv)(A)(1) of this section or if the conditions in paragraph (b)(4)(iv)(A)(2) of this section are met.
(1) At least one of the units meets the requirements of paragraphs (b)(4)(ii)(A) through (b)(4)(ii)(C) of this section, and the CEMS installed at the common stack (or duct) meet the requirements of paragraphs (b)(4)(ii)(D) through (b)(4)(ii)(F) of this section.
(2) At least one of the units and the monitors installed at the common stack or duct meet the requirements of paragraph (b)(4)(iii) of this section.
(B) The combined effluent gas streams from a process or manufacturing unit and a stationary fuel combustion unit are vented through a monitored common stack or duct. In this case, Tier 4 shall be used if the combustion unit and the monitors installed at the common stack or duct meet the applicability criteria specified in paragraph (b)(4)(iv)(A)(1), or (b)(4)(iv)(A)(2) of this section.
(C) The combined effluent gas streams from two or more manufacturing or process units are vented through a common stack or duct. In this case, if any of the units is required by an applicable subpart of this part to use Tier 4, the CO
(5) The Tier 4 Calculation Methodology shall be used:
(i) Starting on January 1, 2010, for a unit that is required to report CO
(ii) No later than January 1, 2011, for a unit that is required to report CO
(A) The certification tests are passed in sequence, with no test failures.
(B) No unscheduled maintenance or repair of the CEMS is performed during the certification test period.
(iii) No later than 180 days following the date on which a change is made that triggers Tier 4 applicability under paragraph (b)(4)(ii) or (b)(4)(iii) of this section (e.g., a change in the primary fuel, manner of unit operation, or installed continuous monitoring equipment).
(6) You may elect to use any applicable higher tier for one or more of the fuels combusted in a unit. For example, if a 100 mmBtu/hr unit combusts natural gas and distillate fuel oil, you may elect to use Tier 1 for natural gas and Tier 3 for the fuel oil, even though Tier 1 could have been used for both fuels. However, for units that use either the Tier 4 or the alternative calculation methodology specified in paragraph (a)(5)(iii) of this section, CO
(c) Calculation of CH
(1) Use Equation C-8 of this section to estimate CH
(i) Use Equation C-8a to calculate CH
(ii) Use Equation C-8b to calculate CH
CH
(2) Use Equation C-9a of this section to estimate CH
(3) Use Equation C-9b of this section to estimate CH
(4) Use Equation C-10 of this section for: units subject to subpart D of this part; units that qualify for and elect to use the alternative CO
(i) If only one type of fuel listed in Table C-2 of this subpart is combusted during the reporting year, substitute the cumulative annual heat input from combustion of the fuel into Equation C-10 of this section to calculate the annual CH
(ii) If more than one type of fuel listed in Table C-2 of this subpart is combusted during the reporting year, use Equation C-10 of this section separately for each type of fuel, except as provided in paragraph (c)(4)(ii)(B) of this section. Determine the appropriate values of (HI)
(A) For units in the Acid Rain Program and other units that report heat input data to EPA year-round according to part 75 of this chapter, obtain (HI)
(B) For a unit that uses CEMS to monitor hourly heat input according to part 75 of this chapter, the value of (HI)
(C) For Tier 4 units, use the best available information (e.g., fuel feed rate measurements, fuel heating values, engineering analysis) to estimate the value of (HI)
(D) Units in the Acid Rain Program and other units that report heat input data to EPA year-round according to part 75 of this chapter may use the best available information described in paragraph (c)(4)(ii)(C) of this section, to estimate (HI)
(5) When multiple fuels are combusted during the reporting year, sum the fuel-specific results from Equations C-8, C-8a, C-8b, C-9a, C-9b, or C-10 of this section (as applicable) to obtain the total annual CH
(6) Calculate the annual CH
(i) If the mass or volume of each component fuel in the blend is measured before the fuels are mixed and combusted, calculate and report CH
(ii) If the mass or volume of each component fuel in the blend is not measured before the fuels are mixed and combusted, a reasonable estimate of the percentage composition of the blend, based on best available information, is required. Perform the following calculations for each component fuel “i” that is listed in Table C-2:
(A) Multiply (% Fuel)
(B) Multiply the result from paragraph (c)(6)(ii)(A) of this section by the HHV of the fuel (default value or, if available, the measured annual average value), to obtain an estimate of the annual heat input from component “i”;
(C) Calculate the annual CH
(D) Sum the annual CH
(d) Calculation of CO
(2) The total annual CO
(e) Biogenic CO
(1) You may use Equation C-1 of this subpart to calculate the annual CO
(i) Company records.
(ii) The procedures in paragraph (e)(4) of this section.
(iii) The best available information for premixed fuels that contain biomass and fossil fuels (e.g., liquid fuel mixtures containing biodiesel).
(2) You may use the procedures of this paragraph if the following three conditions are met: First, a CO
(i) For each operating hour, use Equation C-12 of this section to determine the volume of CO
(ii) Sum all of the hourly V
(iii) Calculate the annual volume of CO
(iv) Subtract V
(v) Calculate the biogenic percentage of the annual CO
(vi) Calculate the annual biogenic CO
(A) Under paragraph (a)(4)(vi) of this section, for units using the Tier 4 Calculation Methodology.
(B) Under paragraph (a)(5)(iii)(B) of this section, for units using the alternative calculation methodology specified in paragraph (a)(5)(iii).
(C) From the electronic data report required under § 75.64 of this chapter, for units in the Acid Rain Program and other units using CEMS to monitor and report CO
(3) You must use the procedures in paragraphs (e)(3)(i) through (e)(3)(iii) of this section to determine the annual biogenic CO
(i) Use an applicable CO
(ii) Determine the relative proportions of biogenic and non-biogenic CO
(iii) Determine the annual biogenic CO
(iv) If the combustion of MSW and/or tires provides no more than 10 percent of the annual heat input to a unit, or if a small, batch incinerator combusts no more than 1,000 tons per year of MSW, you may estimate the annual biogenic CO
(A) Calculate the total annual CO
(B) Multiply the result from paragraph (e)(3)(iv)(A) of this section by the appropriate default factor to determine the annual biogenic CO
(4) If Equation C-1 or Equation C-2a of this section is selected to calculate the annual biogenic mass emissions for wood, wood waste, or other solid biomass-derived fuel, Equation C-15 of this section may be used to quantify biogenic fuel consumption, provided that all of the required input parameters are accurately quantified. Similar equations and calculation methodologies based on steam generation and boiler efficiency may be used, provided that they are documented in the GHG Monitoring Plan required by § 98.3(g)(5).
(5) For units subject to subpart D of this part and for units that use the methods in part 75 of this chapter to quantify CO
CO
§ 98.34 Monitoring and QA/QC requirements.
The CO
(a) For the Tier 2 Calculation Methodology:
(1) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or the supplier of the fuel.
(2) The minimum required frequency of the HHV sampling and analysis for each type of fuel or fuel mixture (blend) is specified in this paragraph. When the specified frequency for a particular fuel or blend is based on a specified time period (e.g., week, month, quarter, or half-year), fuel sampling and analysis is required only for those time periods in which the fuel or blend is combusted. The owner or operator may perform fuel sampling and analysis more often than the minimum required frequency, in order to obtain a more representative annual average HHV.
(i) For natural gas, semiannual sampling and analysis is required (i.e., twice in a calendar year, with consecutive samples taken at least four months apart).
(ii) For coal and fuel oil, and for any other solid or liquid fuel that is delivered in lots, analysis of at least one representative sample from each fuel lot is required. For fuel oil, as an alternative to sampling each fuel lot, a sample may be taken upon each addition of oil to the unit’s storage tank. Flow proportional sampling, continuous drip sampling, or daily manual oil sampling may also be used, in lieu of sampling each fuel lot. If the daily manual oil sampling option is selected, sampling from a particular tank is required only on days when oil from the tank is combusted by the unit (or units) served by the tank. If you elect to sample from the storage tank upon each addition of oil to the tank, you must take at least one sample from each tank that is currently in service and whenever oil is added to the tank, for as long as the tank remains in service. You need not take any samples from a storage tank while it is out of service. Rather, take a sample when the tank is brought into service and whenever oil is added to the tank, for as long as the tank remains in service. If multiple additions of oil are made to a particular in-service tank on a given day (e.g., from multiple deliveries), one sample taken after the final addition of oil is sufficient. For the purposes of this section, a fuel lot is defined as a shipment or delivery of a single type of fuel (e.g., ship load, barge load, group of trucks, group of railroad cars, oil delivery via pipeline from a tank farm, etc.). However, if multiple deliveries of a particular type of fuel are received from the same supply source in a given calendar month, the deliveries for that month may be considered, collectively, to comprise a fuel lot, requiring only one representative sample, subject to the following conditions:
(A) For coal, the “type” of fuel means the rank of the coal (i.e., anthracite, bituminous, sub-bituminous, or lignite). For fuel oil, the “type” of fuel means the grade number or classification of the oil (e.g., No. 1 oil, No. 2 oil, kerosene, Jet A fuel, etc.).
(B) The owner or operator shall document in the monitoring plan under § 98.3(g)(5) how the monthly sampling of each type of fuel is performed.
(iii) For liquid fuels other than fuel oil, and for gaseous fuels other than natural gas (including biogas), sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart.
(iv) For other solid fuels (except MSW), weekly sampling is required to obtain composite samples, which are then analyzed monthly.
(v) For fuel blends that are received already mixed, or that are mixed on-site without measuring the exact amount of each component, as described in paragraph (a)(3)(ii) of this section, determine the HHV of the blend as follows. For blends of solid fuels (except MSW), weekly sampling is required to obtain composite samples, which are analyzed monthly. For blends of liquid or gaseous fuels, sampling and analysis is required at least once per calendar quarter. More frequent sampling is recommended if the composition of the blend varies significantly during the year.
(3) Special considerations for blending of fuels. In situations where different types of fuel listed in Table C-1 of this subpart (for example, different ranks of coal or different grades of fuel oil) are in the same state of matter (i.e., solid, liquid, or gas), and are blended prior to combustion, use the following procedures to determine the appropriate CO
(i) If the fuels to be blended are received separately, and if the quantity (mass or volume) of each fuel is measured before the fuels are mixed and combusted, then, for each component of the blend, calculate the CO
(ii) If the fuel is received as a blend (i.e., already mixed) or if the components are mixed on site without precisely measuring the mass or volume of each one individually, a reasonable estimate of the relative proportions of the components of the blend must be made, using the best available information (e.g., the approximate annual average mass or volume percentage of each fuel, based on the typical or expected range of values). Determine the appropriate CO
(A) Consider the blend to be the “fuel type,” measure its HHV at the frequency prescribed in paragraph (a)(2)(v) of this section, and determine the annual average HHV value for the blend according to § 98.33(a)(2)(ii).
(B) Calculate a heat-weighted CO
(C) Substitute into Equation C-2a of this subpart, the annual average HHV for the blend (from paragraph (a)(3)(ii)(A) of this section) and the calculated value of (EF)
(iii) Note that for the case described in paragraph (a)(3)(ii) of this section, if measured HHV values for the individual fuels in the blend or for the blend itself are not routinely received at the minimum frequency prescribed in paragraph (a)(2) of this section (or at a greater frequency), and if the unit qualifies to use Tier 1, calculate (HHV)
(iv) If the fuel blend described in paragraph (a)(3)(ii) of this section consists of a mixture of fuel(s) listed in Table C-1 of this subpart and one or more fuels not listed in Table C-1, calculate CO
(A) In Equation C-17, apply the term (Fuel)
(B) In Equation C-1, the term “Fuel” will be equal to the total mass or volume of the blended fuel combusted during the year multiplied by the sum of the mass or volume percentages of the Table C-1 fuels in the blend. For the example in paragraph (a)(3)(iv)(A) of this section, “Fuel” = (Annual volume of the blend combusted)(0.80).
(4) If, for a particular type of fuel, HHV sampling and analysis is performed more often than the minimum frequency specified in paragraph (a)(2) of this section, the results of all valid fuel analyses shall be used in the GHG emission calculations.
(5) If, for a particular type of fuel, valid HHV values are obtained at less than the minimum frequency specifed in paragraph (a)(2) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with missing data procedures of § 98.35.
(6) You must use one of the following appropriate fuel sampling and analysis methods. The HHV may be calculated using chromatographic analysis together with standard heating values of the fuel constituents, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions. Alternatively, you may use a method published by a consensus-based standards organization if such a method exists, or you may use industry standard practice to determine the high heat values. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). The method(s) used shall be documented in the Monitoring Plan required under § 98.3(g)(5).
(b) For the Tier 3 Calculation Methodology:
(1) You must calibrate each oil and gas flow meter according to § 98.3(i) and the provisions of this paragraph (b)(1).
(i) Perform calibrations using any of the test methods and procedures in this paragraph (b)(1)(i). The method(s) used shall be documented in the Monitoring Plan required under § 98.3(g)(5).
(A) You may use the calibration procedures specified by the flow meter manufacturer.
(B) You may use an appropriate flow meter calibration method published by a consensus-based standards organization, if such a method exists. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
(C) You may use an industry-accepted practice.
(ii) In addition to the initial calibration required by § 98.3(i), recalibrate each fuel flow meter (except as otherwise provided in paragraph (b)(1)(iii) of this section) according to one of the following. You may recalibrate annually, at the minimum frequency specified by the manufacturer, or at the interval specified by industry standard practice.
(iii) Fuel billing meters are exempted from the initial and ongoing calibration requirements of this paragraph and from the Monitoring Plan and recordkeeping requirements of §§ 98.3(g)(5)(i)(C), (g)(6), and (g)(7), provided that the fuel supplier and the unit combusting the fuel do not have any common owners and are not owned by subsidiaries or affiliates of the same company. Meters used exclusively to measure the flow rates of fuels that are only used for unit startup are also exempted from the initial and ongoing calibration requirements of this paragraph.
(iv) For the initial calibration of an orifice, nozzle, or venturi meter; in-situ calibration of the transmitters is sufficient. A primary element inspection (PEI) shall be performed at least once every three years.
(v) For the continuously-operating units and processes described in § 98.3(i)(6), the required flow meter recalibrations and, if necessary, the PEIs may be postponed until the next scheduled maintenance outage.
(vi) If a mixture of liquid or gaseous fuels is transported by a common pipe, you may either separately meter each of the fuels prior to mixing, using flow meters calibrated according to § 98.3(i), or consider the fuel mixture to be the “fuel type” and meter the mixed fuel, using a flow meter calibrated according to § 98.3(i).
(2) Oil tank drop measurements (if used to determine liquid fuel use volume) shall be performed according to any an appropriate method published by a consensus-based standards organization (e.g., the American Petroleum Institute).
(3) The carbon content and, if applicable, molecular weight of the fuels shall be determined according to the procedures in this paragraph (b)(3).
(i) All fuel samples shall be taken at a location in the fuel handling system that provides a sample representative of the fuel combusted. The fuel sampling and analysis may be performed by either the owner or operator or by the supplier of the fuel.
(ii) For each type of fuel, the minimum required frequency for collecting and analyzing samples for carbon content and (if applicable) molecular weight is specified in this paragraph. When the sampling frequency is based on a specified time period (e.g., week, month, quarter, or half-year), fuel sampling and analysis is required for only those time periods in which the fuel is combusted.
(A) For natural gas, semiannual sampling and analysis is required (i.e., twice in a calendar year, with consecutive samples taken at least four months apart).
(B) For coal and fuel oil and for any other solid or liquid fuel that is delivered in lots, analysis of at least one representative sample from each fuel lot is required. For fuel oil, as an alternative to sampling each fuel lot, a sample may be taken upon each addition of oil to the storage tank. Flow proportional sampling, continuous drip sampling, or daily manual oil sampling may also be used, in lieu of sampling each fuel lot. If the daily manual oil sampling option is selected, sampling from a particular tank is required only on days when oil from the tank is combusted by the unit (or units) served by the tank. If you elect to sample from the storage tank upon each addition of oil to the tank, you must take at least one sample from each tank that is currently in service and whenever oil is added to the tank, for as long as the tank remains in service. You need not take any samples from a storage tank while it is out of service. Rather, take a sample when the tank is brought into service and whenever oil is added to the tank, for as long as the tank remains in service. If multiple additions of oil are made to a particular in service tank on a given day (e.g., from multiple deliveries), one sample taken after the final addition of oil is sufficient. For the purposes of this section, a fuel lot is defined as a shipment or delivery of a single type of fuel (e.g., ship load, barge load, group of trucks, group of railroad cars, oil delivery via pipeline from a tank farm, etc.). However, if multiple deliveries of a particular type of fuel are received from the same supply source in a given calendar month, the deliveries for that month may be considered, collectively, to comprise a fuel lot, requiring only one representative sample, subject to the following conditions:
(1) For coal, the “type” of fuel means the rank of the coal (i.e., anthracite, bituminous, sub-bituminous, or lignite). For fuel oil, the “type” of fuel means the grade number or classification of the oil (e.g., No. 1 oil, No. 2 oil, kerosene, Jet A fuel, etc.).
(2) The owner or operator shall document in the monitoring plan under § 98.3(g)(5) how the monthly sampling of each type of fuel is performed.
(C) For liquid fuels other than fuel oil and for biogas, sampling and analysis is required at least once per calendar quarter. To the extent practicable, consecutive quarterly samples shall be taken at least 30 days apart.
(D) For other solid fuels (except MSW), weekly sampling is required to obtain composite samples, which are then analyzed monthly.
(E) For gaseous fuels other than natural gas and biogas (e.g., process gas), daily sampling and analysis to determine the carbon content and molecular weight of the fuel is required if continuous, on-line equipment, such as a gas chromatograph, is in place to make these measurements. Otherwise, weekly sampling and analysis shall be performed.
(F) For mixtures (blends) of solid fuels, weekly sampling is required to obtain composite samples, which are analyzed monthly. For blends of liquid fuels, and for gas mixtures consisting only of natural gas and biogas, sampling and analysis is required at least once per calendar quarter. For gas mixtures that contain gases other than natural gas (including biogas), daily sampling and analysis to determine the carbon content and molecular weight of the fuel is required if continuous, on-line equipment is in place to make these measurements. Otherwise, weekly sampling and analysis shall be performed.
(iii) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed more often than the minimum frequency specified in paragraph (b)(3) of this section, the results of all valid fuel analyses shall be used in the GHG emission calculations.
(iv) If, for a particular type of fuel, sampling and analysis for carbon content and molecular weight is performed at less than the minimum frequency specified in paragraph (b)(3) of this section, appropriate substitute data values shall be used in the emissions calculations, in accordance with the missing data procedures of § 98.35.
(v) To calculate the CO
(A) Apply Equation C-3, C-4 or C-5 of this subpart (as applicable) to each component of the blend, if the mass or volume, the carbon content, and (if applicable), the molecular weight of each component are accurately measured prior to blending; or
(B) Consider the blend to be the “fuel type.” Then, at the frequency specified in paragraph (b)(3)(ii)(F) of this section, measure the carbon content and, if applicable, the molecular weight of the blend and calculate the annual average value of each parameter in the manner described in § 98.33(a)(2)(ii). Also measure the mass or volume of the blended fuel combusted during the reporting year. Substitute these measured values into Equation C-3, C-4, or C-5 of this subpart (as applicable).
(4) You must use one of the following appropriate fuel sampling and analysis methods. The results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions. Alternatively, you may use a method published by a consensus-based standards organization if such a method exists, or you may use industry standard practice to determine the carbon content and molecular weight (for gaseous fuel) of the fuel. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). The method(s) used shall be documented in the Monitoring Plan required under § 98.3(g)(5).
(c) For the Tier 4 Calculation Methodology, the CO
(1) For initial certification, you may use any one of the following three procedures in this paragraph.
(i) §§ 75.20(c)(2), (c)(4), and (c)(5) through (c)(7) of this chapter and appendix A to part 75 of this chapter.
(ii) The calibration drift test and relative accuracy test audit (RATA) procedures of Performance Specification 3 in appendix B to part 60 of this chapter (for the CO
(iii) The provisions of an applicable State continuous monitoring program.
(2) If an O
(3) For ongoing quality assurance, follow the applicable procedures in either appendix B to part 75 of this chapter, appendix F to part 60 of this chapter, or an applicable State continuous monitoring program. If appendix F to part 60 of this chapter is selected for on-going quality assurance, perform daily calibration drift assessments for both the CO
(4) For the purposes of this part, the stack gas volumetric flow rate monitor RATAs required by appendix B to part 75 of this chapter and the annual RATAs of the CERMS required by appendix F to part 60 of this chapter need only be done at one operating level, representing normal load or normal process operating conditions, both for initial certification and for ongoing quality assurance.
(5) If, for any source operating hour, quality assured data are not obtained with a CO
(6) For certain applications where combined process emissions and combustion emissions are measured, the CO
(7) Hourly average data from the CEMS shall be validated in a manner consistent with one of the following: §§ 60.13(h)(2)(i) through (h)(2)(vi) of this chapter; § 75.10(d)(1) of this chapter; or the hourly data validation requirements of an applicable State CEM regulation.
(d) Except as otherwise provided in § 98.33(b)(1)(vi) and (vii), when municipal solid waste (MSW) is either the primary fuel combusted in a unit or the only fuel with a biogenic component combusted in the unit, determine the biogenic portion of the CO
(e) For other units that combust combinations of biomass fuel(s) (or heterogeneous fuels that have a biomass component, e.g., tires) and fossil (or other non-biogenic) fuel(s), in any proportions, ASTM D6866-16 and ASTM D7459-08 (both incorporated by reference, see § 98.7) may be used to determine the biogenic portion of the CO
(f) The records required under § 98.3(g)(2)(i) shall include an explanation of how the following parameters are determined from company records (or, if applicable, from the best available information):
(1) Fuel consumption, when the Tier 1 and Tier 2 Calculation Methodologies are used, including cases where § 98.36(c)(4) applies.
(2) Fuel consumption, when solid fuel is combusted and the Tier 3 Calculation Methodology is used.
(3) Fossil fuel consumption when § 98.33(e)(2) applies to a unit that uses CEMS to quantify CO
(4) Sorbent usage, when § 98.33(d) applies.
(5) Quantity of steam generated by a unit when § 98.33(a)(2)(iii) applies.
(6) Biogenic fuel consumption and high heating value, as applicable, under §§ 98.33(e)(5) and (e)(6).
(7) Fuel usage for CH
(8) Mass of biomass combusted, for premixed fuels that contain biomass and fossil fuels under § 98.33(e)(1)(iii).
§ 98.35 Procedures for estimating missing data.
Whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations.
(a) For all units subject to the requirements of the Acid Rain Program, and all other stationary combustion units subject to the requirements of this part that monitor and report emissions and heat input data year-round in accordance with part 75 of this chapter, the missing data substitution procedures in part 75 of this chapter shall be followed for CO
(b) For units that use the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies, perform missing data substitution as follows for each parameter:
(1) For each missing value of the high heating value, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value has not been obtained by the time that the GHG emissions report is due, you may use the “before” value for missing data substitution or the best available estimate of the parameter, based on all available process data (e.g., electrical load, steam production, operating hours). If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(2) For missing records of CO
§ 98.36 Data reporting requirements.
(a) In addition to the facility-level information required under § 98.3, the annual GHG emissions report shall contain the unit-level or process-level data specified in paragraphs (b) through (f) of this section, as applicable, for each stationary fuel combustion source (e.g., individual unit, aggregation of units, common pipe, or common stack) except as otherwise provided in this paragraph (a). For the data specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), (e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iv)(A), (e)(2)(iv)(C), (e)(2)(iv)(F), and (e)(2)(ix)(D) through (F) of this section, the owner or operator of a stationary fuel combustion source that does not meet the criteria specified in paragraph (f) of this section may elect either to report the data specified in this sentence in the annual report or to use verification software according to § 98.5(b) in lieu of reporting these data. If you elect to use this verification software, you must use the verification software according to § 98.5(b) for all of these data that apply to the stationary fuel combustion source.
(b) Units that use the four tiers. You shall report the following information for stationary combustion units that use the Tier 1, Tier 2, Tier 3, or Tier 4 methodology in § 98.33(a) to calculate CO
(1) The unit ID number.
(2) A code representing the type of unit.
(3) Maximum rated heat input capacity of the unit, in mmBtu/hr.
(4) Each type of fuel combusted in the unit during the report year.
(5) The methodology (i.e., tier) used to calculate the CO
(6) The methodology start date, for each fuel type.
(7) The methodology end date, for each fuel type.
(8) For a unit that uses Tiers 1, 2, or 3:
(i) The annual CO
(ii) Metric tons of biogenic CO
(9) For a unit that uses Tier 4:
(i) If the total annual CO
(ii) Report the total annual CO
(iii) An estimate of the heat input from each type of fuel listed in Table C-2 of this subpart that was combusted in the unit during the report year.
(iv) The annual CH
(10) Annual CO
(11) If applicable, the plant code (as defined in § 98.6).
(c) Reporting alternatives for units using the four Tiers. You may use any of the applicable reporting alternatives of this paragraph to simplify the unit-level reporting required under paragraph (b) of this section:
(1) Aggregation of units. If a facility contains two or more units (e.g., boilers or combustion turbines), each of which has a maximum rated heat input capacity of 250 mmBtu/hr or less, you may report the combined GHG emissions for the group of units in lieu of reporting GHG emissions from the individual units, provided that the use of Tier 4 is not required or elected for any of the units and the units use the same tier for any common fuels combusted. If this option is selected, the following information shall be reported instead of the information in paragraph (b) of this section:
(i) Group ID number, beginning with the prefix “GP”.
(ii) [Reserved]
(iii) Cumulative maximum rated heat input capacity of the group (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the sum of the maximum rated heat input capacities for all units in the group, excluding units less than 10 (mmBtu/hr).
(iv) The highest maximum rated heat input capacity of any unit in the group (mmBtu/hr).
(v) Each type of fuel combusted in the group of units during the reporting year.
(vi) Annual CO
(vii) The methodology (i.e., tier) used to calculate the CO
(viii) The methodology start date, for each fuel type.
(ix) The methodology end date, for each fuel type.
(x) The calculated CO
(xi) If applicable, the plant code (as defined in § 98.6).
(2) Monitored common stack or duct configurations. When the flue gases from two or more stationary fuel combustion units at a facility are combined together in a common stack or duct before exiting to the atmosphere and if CEMS are used to continuously monitor CO
(i) Common stack or duct identification number, beginning with the prefix “CS”.
(ii) Number of units sharing the common stack or duct. Report “1” when the flue gas flowing through the common stack or duct includes combustion products and/or process off-gases, and all of the effluent comes from a single unit (e.g., a furnace, kiln, petrochemical production unit, or smelter).
(iii) Combined maximum rated heat input capacity of the units sharing the common stack or duct (mmBtu/hr). This data element is required only when all of the units sharing the common stack are stationary fuel combustion units.
(iv) Each type of fuel combusted in the units during the year.
(v) The methodology (tier) used to calculate the CO
(vi) The methodology start date.
(vii) The methodology end date.
(viii) Total annual CO
(ix) An estimate of the heat input from each type of fuel listed in Table C-2 of this subpart that was combusted in the units sharing the common stack or duct during the report year.
(x) For each type of fuel listed in Table C-2 of this subpart that was combusted during the report year in the units sharing the common stack or duct during the report year, the annual CH
(xi) If applicable, the plant code (as defined in § 98.6).
(3) Common pipe configurations. When two or more stationary combustion units at a facility combust the same type of liquid or gaseous fuel and the fuel is fed to the individual units through a common supply line or pipe, you may report the combined emissions from the units served by the common supply line, in lieu of separately reporting the GHG emissions from the individual units, provided that the total amount of fuel combusted by the units is accurately measured at the common pipe or supply line using a fuel flow meter, or, for natural gas, the amount of fuel combusted may be obtained from gas billing records. For Tier 3 applications, the flow meter shall be calibrated in accordance with § 98.34(b). If a portion of the fuel measured (or obtained from gas billing records) at the main supply line is diverted to either: A flare; or another stationary fuel combustion unit (or units), including units that use a CO
(i) Common pipe identification number, beginning with the prefix “CP”.
(ii) Cumulative maximum rated heat input capacity of the units served by the common pipe (mmBtu/hr). The cumulative maximum rated heat input capacity shall be determined as the sum of the maximum rated heat input capacities for all units served by the common pipe, excluding units less than 10 (mmBtu/hr).
(iii) The highest maximum rated heat input capacity of any unit served by the common pipe (mmBtu/hr).
(iv) The fuels combusted in the units during the reporting year.
(v) The methodology used to calculate the CO
(vi) If the any of the units burns both fossil fuels and biomass, the annual CO
(vii) Annual CO
(viii) Methodology start date.
(ix) Methodology end date.
(x) If applicable, the plant code (as defined in § 98.6).
(4) The following alternative reporting option applies to facilities at which a common liquid or gaseous fuel supply is shared between one or more large combustion units, such as boilers or combustion turbines (including units subject to subpart D of this part and other units subject to part 75 of this chapter) and small combustion sources, including, but not limited to, space heaters, hot water heaters, and lab burners. In this case, you may simplify reporting by attributing all of the GHG emissions from combustion of the shared fuel to the large combustion unit(s), provided that:
(i) The total quantity of the fuel combusted during the report year in the units sharing the fuel supply is measured, either at the “gate” to the facility or at a point inside the facility, using a fuel flow meter, billing meter, or tank drop measurements (as applicable);
(ii) On an annual basis, at least 95 percent (by mass or volume) of the shared fuel is combusted in the large combustion unit(s), and the remainder is combusted in the small combustion sources. Company records may be used to determine the percentage distribution of the shared fuel to the large and small units; and
(iii) The use of this reporting option is documented in the Monitoring Plan required under § 98.3(g)(5). Indicate in the Monitoring Plan which units share the common fuel supply and the method used to demonstrate that this alternative reporting option applies. For the small combustion sources, a description of the types of units and the approximate number of units is sufficient.
(d) Units subject to part 75 of this chapter. (1) For stationary combustion units that are subject to subpart D of this part, you shall report the following unit-level information:
(i) Unit or stack identification numbers. Use exact same unit, common stack, common pipe, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are reported under § 75.64 of this chapter.
(ii) Annual CO
(iii) Annual CH
(iv) The total heat input from each fuel listed in Table C-2 that was combusted during the year (except as otherwise provided in § 98.33(c)(4)(ii)(B)), expressed in mmBtu.
(v) Identification of the Part 75 methodology used to determine the CO
(vi) Methodology start date.
(vii) Methodology end date.
(viii) Acid Rain Program indicator.
(ix) Annual CO
(x) If applicable, the plant code (as defined in § 98.6).
(2) For units that use the alternative CO
(i) Unit, stack, or pipe ID numbers. Use exact same unit, common stack, common pipe, or multiple stack identification numbers that represent the monitored locations (e.g., 1, 2, CS001, MS1A, CP001, etc.) that are reported under § 75.64 of this chapter.
(ii) For units that use the alternative methods specified in § 98.33(a)(5)(i) and (ii) to monitor and report heat input data year-round according to appendix D to part 75 of this chapter or § 75.19 of this chapter:
(A) Each type of fuel combusted in the unit during the reporting year.
(B) The methodology used to calculate the CO
(C) Methodology start date.
(D) Methodology end date.
(E) A code or flag to indicate whether heat input is calculated according to appendix D to part 75 of this chapter or § 75.19 of this chapter.
(F) Annual CO
(G) Annual heat input from each type of fuel listed in Table C-2 of this subpart that was combusted during the reporting year, expressed in mmBtu.
(H) Annual CH
(I) Annual CO
(J) If applicable, the plant code (as defined in § 98.6).
(iii) For units with continuous monitoring systems that use the alternative method for units with continuous monitoring systems in § 98.33(a)(5)(iii) to monitor heat input year-round according to part 75 of this chapter:
(A) Each type of fuel combusted during the reporting year.
(B) Methodology used to calculate the CO
(C) Methodology start date.
(D) Methodology end date.
(E) A code or flag to indicate that the heat input data is derived from CEMS measurements.
(F) The total annual CO
(G) Annual heat input from each type of fuel listed in Table C-2 of this subpart that was combusted during the reporting year, expressed in mmBtu.
(H) Annual CH
(I) Annual CO
(J) If applicable, the plant code (as defined in § 98.6).
(e) Verification data. You must keep on file, in a format suitable for inspection and auditing, sufficient data to verify the reported GHG emissions. This data and information must, where indicated in this paragraph (e), be included in the annual GHG emissions report.
(1) The applicable verification data specified in this paragraph (e) are not required to be kept on file or reported for units that meet any one of the three following conditions:
(i) Are subject to the Acid Rain Program.
(ii) Use the alternative methods for units with continuous monitoring systems provided in § 98.33(a)(5).
(iii) Are not in the Acid Rain Program, but are required to monitor and report CO
(2) For stationary combustion sources using the Tier 1, Tier 2, Tier 3, and Tier 4 Calculation Methodologies in § 98.33(a) to quantify CO
(i) For the Tier 1 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during the reporting year, in short tons for solid fuels, gallons for liquid fuels and standard cubic feet for gaseous fuels, or, if applicable, therms or mmBtu for natural gas.
(B) If applicable, the moisture content used to calculate the wood and wood residuals wet basis HHV for use in Equations C-1 and C-8 of this subpart, in percent.
(ii) For the Tier 2 Calculation Methodology, report:
(A) The total quantity of each type of fuel combusted in the unit or group of aggregated units (as applicable) during each month of the reporting year. Express the quantity of each fuel combusted during the measurement period in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
(B) The frequency of the HHV determinations (e.g., once a month, once per fuel lot).
(C) The high heat values used in the CO
(D) If Equation C-2c of this subpart is used to calculate CO
(E) For each HHV used in the CO
(iii) For the Tier 2 Calculation Methodology, keep records of the methods used to determine the HHV for each type of fuel combusted and the date on which each fuel sample was taken, except where fuel sampling data are received from the fuel supplier. In that case, keep records of the dates on which the results of the fuel analyses for HHV are received.
(iv) For the Tier 3 Calculation Methodology, report:
(A) The quantity of each type of fuel combusted in the unit or group of units (as applicable) during each month of the reporting year, in short tons for solid fuels, gallons for liquid fuels, and scf for gaseous fuels.
(B) The frequency of carbon content and, if applicable, molecular weight determinations for each type of fuel for the reporting year (e.g., daily, weekly, monthly, semiannually, once per fuel lot).
(C) The carbon content and, if applicable, gas molecular weight values used in the emission calculations (including both valid and substitute data values). For each calendar month of the reporting year in which carbon content and, if applicable, molecular weight determination is required, report a value of each parameter. If multiple values of a parameter are obtained in a given month, report the arithmetic average value for the month. Express carbon content as a decimal fraction for solid fuels, kg C per gallon for liquid fuels, and kg C per kg of fuel for gaseous fuels. Express the gas molecular weights in units of kg per kg-mole.
(D) The total number of valid carbon content determinations and, if applicable, molecular weight determinations made during the reporting year, for each fuel type.
(E) The number of substitute data values used for carbon content and, if applicable, molecular weight used in the annual GHG emissions calculations.
(F) The annual average HHV, when measured HHV data, rather than a default HHV from Table C-1 of this subpart, are used to calculate CH
(G) The value of the molar volume constant (MVC) used in Equation C-5 (if applicable).
(v) For the Tier 3 Calculation Methodology, keep records of the following:
(A) For liquid and gaseous fuel combustion, the dates and results of the initial calibrations and periodic recalibrations of the required fuel flow meters.
(B) For fuel oil combustion, the method from § 98.34(b) used to make tank drop measurements (if applicable).
(C) The methods used to determine the carbon content and (if applicable) the molecular weight of each type of fuel combusted.
(D) The methods used to calibrate the fuel flow meters).
(E) The date on which each fuel sample was taken, except where fuel sampling data are received from the fuel supplier. In that case, keep records of the dates on which the results of the fuel analyses for carbon content and (if applicable) molecular weight are received.
(vi) For the Tier 4 Calculation Methodology, report:
(A) The total number of source operating hours in the reporting year.
(B) The cumulative CO
(C) For CO
(vii) For the Tier 4 Calculation Methodology, keep records of:
(A) Whether the CEMS certification and quality assurance procedures of part 75 of this chapter, part 60 of this chapter, or an applicable State continuous monitoring program were used.
(B) The dates and results of the initial certification tests of the CEMS.
(C) The dates and results of the major quality assurance tests performed on the CEMS during the reporting year, i.e., linearity checks, cylinder gas audits, and relative accuracy test audits (RATAs).
(viii) If CO
(A) The total amount of sorbent used during the report year, in short tons.
(B) The molecular weight of the sorbent.
(C) The ratio (“R”) in Equation C-11 of this subpart.
(ix) For units that combust both fossil fuel and biomass, when biogenic CO
(A) The annual volume of CO
(B) The annual volume of CO
(C) The annual volume of CO
(D) The carbon-based F-factor used in Equation C-13 of this subpart, for each type of fossil fuel combusted, in scf CO
(E) The annual average HHV value used in Equation C-13 of this subpart, for each type of fossil fuel combusted, in Btu/lb, Btu/gal, or Btu/scf, as appropriate.
(F) The total quantity of each type of fossil fuel combusted during the reporting year, in lb, gallons, or scf, as appropriate.
(G) Annual biogenic CO
(x) When ASTM methods D7459-08 and D6866-16 (both incorporated by reference, see § 98.7) are used to determine the biogenic portion of the annual CO
(A) The results of each quarterly sample analysis, expressed as a decimal fraction (e.g., if the biogenic fraction of the CO
(B) The annual biogenic CO
(xi) When ASTM methods D7459-08 and D6866-16 (both incorporated by reference, see § 98.7) are used in accordance with § 98.34(e) to determine the biogenic portion of the annual CO
(3) Within 30 days of receipt of a written request from the Administrator, you shall submit explanations of the following:
(i) An explanation of how company records are used to quantify fuel consumption, if the Tier 1 or Tier 2 Calculation Methodology is used to calculate CO
(ii) An explanation of how company records are used to quantify fuel consumption, if solid fuel is combusted and the Tier 3 Calculation Methodology is used to calculate CO
(iii) An explanation of how sorbent usage is quantified.
(iv) An explanation of how company records are used to quantify fossil fuel consumption in units that uses CEMS to quantify CO
(v) An explanation of how company records are used to measure steam production, when it is used to calculate CO
(4) Within 30 days of receipt of a written request from the Administrator, you shall submit the verification data and information described in paragraphs (e)(2)(iii), (e)(2)(v), and (e)(2)(vii) of this section.
(f) Each stationary fuel combustion source (e.g., individual unit, aggregation of units, common pipe, or common stack) subject to reporting under paragraph (b) or (c) of this section must indicate if both of the following two conditions are met:
(1) The stationary fuel combustion source contains at least one combustion unit connected to a fuel-fired electric generator owned or operated by an entity that is subject to regulation of customer billing rates by the public utility commission (excluding generators that are connected to combustion units that are subject to subpart D of this part).
(2) The stationary fuel combustion source is located at a facility for which the sum of the nameplate capacities for all electric generators specified in paragraph (f)(1) of this section is greater than or equal to 1 megawatt electric output.
§ 98.37 Records that must be retained.
In addition to the requirements of § 98.3(g), you must retain:
(a) The applicable records specified in §§ 98.34(f), 98.35(b), and 98.36(e).
(b) Verification software records. For each stationary fuel combustion source that elects to use the verification software specified in § 98.5(b) rather than report data specified in paragraphs (b)(9)(iii), (c)(2)(ix), (e)(2)(i), (e)(2)(ii)(A), (e)(2)(ii)(C), (e)(2)(ii)(D), (e)(2)(iv)(A), (e)(2)(iv)(C), (e)(2)(iv)(F), and (e)(2)(ix)(D) through (F) of this section, you must keep a record of the file generated by the verification software for the applicable data specified in paragraphs (b)(1) through (36) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) through (36) of this section.
(1) Mass of each solid fuel combusted (tons/year) (Equation C-1 of § 98.33).
(2) Volume of each liquid fuel combusted (gallons/year) (Equation C-1).
(3) Volume of each gaseous fuel combusted (scf/year) (Equation C-1).
(4) Annual natural gas usage (therms/year) (Equation C-1a of § 98.33).
(5) Annual natural gas usage (mmBtu/year) (Equation C-1b of § 98.33).
(6) Mass of each solid fuel combusted (tons/year) (Equation C-2a of § 98.33).
(7) Volume of each liquid fuel combusted (gallons/year) (Equation C-2a).
(8) Volume of each gaseous fuel combusted (scf/year) (Equation C-2a).
(9) Measured high heat value of each solid fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per ton) (Equation C-2b of § 98.33).
(10) Measured high heat value of each liquid fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per gallons) (Equation C-2b).
(11) Measured high heat value of each gaseous fuel, for month (which may be the arithmetic average of multiple determinations), or, if applicable, an appropriate substitute data value (mmBtu per scf) (Equation C-2b).
(12) Mass of each solid fuel combusted during month (tons) (Equation C-2b).
(13) Volume of each liquid fuel combusted during month (gallons) (Equation C-2b).
(14) Volume of each gaseous fuel combusted during month (scf) (Equation C-2b).
(15) Total mass of steam generated by municipal solid waste or each solid fuel combustion during the reporting year (pounds steam) (Equation C-2c of § 98.33).
(16) Ratio of the boiler’s maximum rated heat input capacity to its design rated steam output capacity (MMBtu/pounds steam) (Equation C-2c).
(17) Annual mass of each solid fuel combusted (short tons/year) (Equation C-3 of § 98.33).
(18) Annual average carbon content of each solid fuel (percent by weight, expressed as a decimal fraction) (Equation C-3).
(19) Annual volume of each liquid fuel combusted (gallons/year) (Equation C-4 of § 98.33).
(20) Annual average carbon content of each liquid fuel (kg C per gallon of fuel) (Equation C-4).
(21) Annual volume of each gaseous fuel combusted (scf/year) (Equation C-5 of § 98.33).
(22) Annual average carbon content of each gaseous fuel (kg C per kg of fuel) (Equation C-5).
(23) Annual average molecular weight of each gaseous fuel (kg/kg-mole) (Equation C-5).
(24) Molar volume conversion factor at standard conditions, as defined in § 98.6 (scf per kg-mole) (Equation C-5).
(25) Identify for each fuel if you will use the default high heat value from Table C-1 of this subpart, or actual high heat value data (Equation C-8 of § 98.33).
(26) High heat value of each solid fuel (mmBtu/tons) (Equation C-8).
(27) High heat value of each liquid fuel (mmBtu/gallon) (Equation C-8).
(28) High heat value of each gaseous fuel (mmBtu/scf) (Equation C-8).
(29) Cumulative annual heat input from combustion of each fuel (mmBtu) (Equation C-10 of § 98.33).
(30) Total quantity of each solid fossil fuel combusted in the reporting year, as defined in § 98.6 (pounds) (Equation C-13 of § 98.33).
(31) Total quantity of each liquid fossil fuel combusted in the reporting year, as defined in § 98.6 (gallons) (Equation C-13).
(32) Total quantity of each gaseous fossil fuel combusted in the reporting year, as defined in § 98.6 (scf) (Equation C-13).
(33) High heat value of the each solid fossil fuel (Btu/lb) (Equation C-13).
(34) High heat value of the each liquid fossil fuel (Btu/gallons) (Equation C-13).
(35) High heat value of the each gaseous fossil fuel (Btu/scf) (Equation C-13).
(36) Fuel-specific carbon based F-factor per fuel (scf CO
(37) Moisture content used to calculate the wood and wood residuals wet basis HHV (percent), if applicable (Equations C-1 and C-8 of this subpart).
§ 98.38 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table C-1 to Subpart C of Part 98 – Default CO2 Emission Factors and High Heat Values for Various Types of Fuel
Default CO
Fuel type | Default high heat value | Default CO emission factor |
---|---|---|
Coal and coke | mmBtu/short ton | kg CO |
Anthracite | 25.09 | 103.69 |
Bituminous | 24.93 | 93.28 |
Subbituminous | 17.25 | 97.17 |
Lignite | 14.21 | 97.72 |
Coal Coke | 24.80 | 113.67 |
Mixed (Commercial sector) | 21.39 | 94.27 |
Mixed (Industrial coking) | 26.28 | 93.90 |
Mixed (Industrial sector) | 22.35 | 94.67 |
Mixed (Electric Power sector) | 19.73 | 95.52 |
Natural gas | mmBtu/scf | kg CO |
(Weighted U.S. Average) | 1.026 × 10 | 53.06 |
Petroleum products – liquid | mmBtu/gallon | kg CO |
Distillate Fuel Oil No. 1 | 0.139 | 73.25 |
Distillate Fuel Oil No. 2 | 0.138 | 73.96 |
Distillate Fuel Oil No. 4 | 0.146 | 75.04 |
Residual Fuel Oil No. 5 | 0.140 | 72.93 |
Residual Fuel Oil No. 6 | 0.150 | 75.10 |
Used Oil | 0.138 | 74.00 |
Kerosene | 0.135 | 75.20 |
Liquefied petroleum gases (LPG) 1 | 0.092 | 61.71 |
Propane 1 | 0.091 | 62.87 |
Propylene 2 | 0.091 | 67.77 |
Ethane 1 | 0.068 | 59.60 |
Ethanol | 0.084 | 68.44 |
Ethylene 2 | 0.058 | 65.96 |
Isobutane 1 | 0.099 | 64.94 |
Isobutylene 1 | 0.103 | 68.86 |
Butane 1 | 0.103 | 64.77 |
Butylene 1 | 0.105 | 68.72 |
Naphtha ( | 0.125 | 68.02 |
Natural Gasoline | 0.110 | 66.88 |
Other Oil (>401 deg F) | 0.139 | 76.22 |
Pentanes Plus | 0.110 | 70.02 |
Petrochemical Feedstocks | 0.125 | 71.02 |
Special Naphtha | 0.125 | 72.34 |
Unfinished Oils | 0.139 | 74.54 |
Heavy Gas Oils | 0.148 | 74.92 |
Lubricants | 0.144 | 74.27 |
Motor Gasoline | 0.125 | 70.22 |
Aviation Gasoline | 0.120 | 69.25 |
Kerosene-Type Jet Fuel | 0.135 | 72.22 |
Asphalt and Road Oil | 0.158 | 75.36 |
Crude Oil | 0.138 | 74.54 |
Petroleum products – solid | mmBtu/short ton | kg CO |
Petroleum Coke | 30.00 | 102.41. |
Petroleum products – gaseous | mmBtu/scf | kg CO |
Propane Gas | 2.516 × 10 | 61.46. |
Other fuels – solid | mmBtu/short ton | kg CO |
Municipal Solid Waste | 9.95 3 | 90.7 |
Tires | 28.00 | 85.97 |
Plastics | 38.00 | 75.00 |
Other fuels – gaseous | mmBtu/scf | kg CO |
Blast Furnace Gas | 0.092 × 10 | 274.32 |
Coke Oven Gas | 0.599 × 10 | 46.85 |
Fuel Gas 4 | 1.388 × 10 | 59.00 |
Biomass fuels – solid | mmBtu/short ton | kg CO |
Wood and Wood Residuals (dry basis) 5 | 17.48 | 93.80 |
Agricultural Byproducts | 8.25 | 118.17 |
Peat | 8.00 | 111.84 |
Solid Byproducts | 10.39 | 105.51 |
Biomass fuels – gaseous | mmBtu/scf | kg CO |
Landfill Gas | 0.485 × 10 | 52.07 |
Other Biomass Gases | 0.655 × 10 | 52.07 |
Biomass Fuels – Liquid | mmBtu/gallon | kg CO |
Ethanol | 0.084 | 68.44 |
Biodiesel (100%) | 0.128 | 73.84 |
Rendered Animal Fat | 0.125 | 71.06 |
Vegetable Oil | 0.120 | 81.55 |
1 The HHV for components of LPG determined at 60 °F and saturation pressure with the exception of ethylene.
2 Ethylene HHV determined at 41 °F (5 °C) and saturation pressure.
3 Use of this default HHV is allowed only for: (a) Units that combust MSW, do not generate steam, and are allowed to use Tier 1; (b) units that derive no more than 10 percent of their annual heat input from MSW and/or tires; and (c) small batch incinerators that combust no more than 1,000 tons of MSW per year.
4 Reporters subject to subpart X of this part that are complying with § 98.243(d) or subpart Y of this part may only use the default HHV and the default CO
5 Use the following formula to calculate a wet basis HHV for use in Equation C-1: HHV
Table C-2 to Subpart C of Part 98 – Default CH4 and N2 O Emission Factors for Various Types of Fuel
Fuel type | Default CH | Default N |
---|---|---|
Coal and Coke (All fuel types in Table C-1) | 1.1 × 10 | 1.6 × 10 |
Natural Gas | 1.0 × 10 | 1.0 × 10 |
Petroleum Products (All fuel types in Table C-1) | 3.0 × 10 | 6.0 × 10 |
Fuel Gas | 3.0 × 10 | 6.0 × 10 |
Other Fuels – Solid | 3.2 × 10 | 4.2 × 10 |
Blast Furnace Gas | 2.2 × 10 | 1.0 × 10 |
Coke Oven Gas | 4.8 × 10 | 1.0 × 10 |
Biomass Fuels – Solid (All fuel types in Table C-1, except wood and wood residuals) | 3.2 × 10 | 4.2 × 10 |
Wood and wood residuals | 7.2 × 10 | 3.6 × 10 |
Biomass Fuels – Gaseous (All fuel types in Table C-1) | 3.2 × 10 | 6.3 × 10 |
Biomass Fuels – Liquid (All fuel types in Table C-1) | 1.1 × 10 | 1.1 × 10 |
Note: Those employing this table are assumed to fall under the IPCC definitions of the “Energy Industry” or “Manufacturing Industries and Construction”. In all fuels except for coal the values for these two categories are identical. For coal combustion, those who fall within the IPCC “Energy Industry” category may employ a value of 1g of CH
Subpart D – Electricity Generation
§ 98.40 Definition of the source category.
(a) The electricity generation source category comprises electricity generating units that are subject to the requirements of the Acid Rain Program and any other electricity generating units that are required to monitor and report to EPA CO
(b) This source category does not include portable equipment, emergency equipment, or emergency generators, as defined in § 98.6.
§ 98.41 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains one or more electricity generating units and the facility meets the requirements of § 98.2(a)(1).
§ 98.42 GHGs to report.
(a) For each electricity generating unit that is subject to the requirements of the Acid Rain Program or is otherwise required to monitor and report to EPA CO
(b) For each electricity generating unit that is not subject to the Acid Rain Program or otherwise required to monitor and report to EPA CO
(c) For each stationary fuel combustion unit that does not generate electricity, you must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
§ 98.43 Calculating GHG emissions.
(a) Except as provided in paragraph (b) of this section, continue to monitor and report CO
(1) Convert the cumulative annual CO
(2) Calculate and report annual CH
(b) Calculate and report biogenic CO
§ 98.44 Monitoring and QA/QC requirements.
Follow the applicable quality assurance procedures for CO
§ 98.45 Procedures for estimating missing data.
Follow the applicable missing data substitution procedures in 40 CFR part 75 for CO
§ 98.46 Data reporting requirements.
The annual report shall comply with the data reporting requirements specified in § 98.36(d)(1).
§ 98.47 Records that must be retained.
You shall comply with the recordkeeping requirements of §§ 98.3(g) and 98.37. Records retained under § 75.57(h) of this chapter for missing data events satisfy the recordkeeping requirements of § 98.3(g)(4) for those same events.
§ 98.48 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart E – Adipic Acid Production
§ 98.50 Definition of source category.
The adipic acid production source category consists of all adipic acid production facilities that use oxidation to produce adipic acid.
§ 98.51 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an adipic acid production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.52 GHGs to report.
(a) You must report N
(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
§ 98.53 Calculating GHG emissions.
(a) You must determine annual N
(1) Use a site-specific emission factor and production data according to paragraphs (b) through (i) of this section.
(2) Request Administrator approval for an alternative method of determining N
(i) If you received Administrator approval for an alternative method of determining N
(ii) You must notify the EPA of your use of a previously approved alternative method in your annual report.
(iii) Otherwise, you must submit the request within 45 days following promulgation of this subpart or within the first 30 days of each subsequent reporting year.
(iv) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine the N
(b) You must conduct an annual performance test according to paragraphs (b)(1) through (3) of this section.
(1) You must conduct the test on the vent stream from the nitric acid oxidation step of the process, referred to as the test point, according to the methods specified in § 98.54(b) through (f). If multiple adipic acid production units exhaust to a common abatement technology and/or emission point, you must sample each process in the ducts before the emissions are combined, sample each process when only one process is operating, or sample the combined emissions when multiple processes are operating and base the site-specific emission factor on the combined production rate of the multiple adipic acid production units.
(2) You must conduct the performance test under normal process operating conditions.
(3) You must measure the adipic acid production rate during the test and calculate the production rate for the test period in tons per hour.
(c) Using the results of the performance test in paragraph (b) of this section, you must calculate an emission factor for each adipic acid unit according to Equation E-1 of this section:
(d) If the adipic acid production unit exhausts to any N
(1) Use the manufacturer’s specified destruction efficiency.
(2) Estimate the destruction efficiency through process knowledge. Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still relevant to the current vent stream conditions. You must document how process knowledge was used to determine the destruction efficiency.
(3) Calculate the destruction efficiency by conducting an additional performance test on the vent stream following the N
(e) If the adipic acid production unit exhausts to any N
(f) You must determine the annual amount of adipic acid produced according to § 98.54(f).
(g) You must calculate N
(1) If one N
(2) If multiple N
(3) If multiple N
(4) If no N
(h) You must determine the emissions for the facility by summing the unit level emissions according to Equation E-4 of this section.
(i) You must determine the amount of process N
§ 98.54 Monitoring and QA/QC requirements.
(a) You must conduct a new performance test and calculate a new emissions factor for each adipic acid production unit according to the frequency specified in paragraphs (a)(1) through (3) of this section.
(1) Conduct the performance test annually. The test must be conducted at a point during production that is representative of the average emissions rate from your process. You must document the methods used to determine the representative point.
(2) Conduct the performance test when your adipic acid production process is changed either by altering the ratio of cyclohexanone to cyclohexanol or by installing abatement equipment.
(3) If you requested Administrator approval for an alternative method of determining N
(b) You must measure the N
(1) EPA Method 320, Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy in 40 CFR part 63, Appendix A;
(2) ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference, see § 98.7); or
(3) An equivalent method, with Administrator approval.
(c) You must determine the adipic acid production rate during the performance test according to paragraph (c)(1) or (c)(2) of this section.
(1) Direct measurement (such as using flow meters or weigh scales).
(2) Existing plant procedures used for accounting purposes.
(d) You must determine the volumetric flow rate during the performance test in conjunction with the applicable EPA methods in 40 CFR part 60, appendices A-1 through A-4. Conduct three emissions test runs of 1 hour each. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emissions factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section:
(1) Analysis of samples, determination of emissions, and raw data.
(2) All information and data used to derive the emissions factor.
(3) The production rate(s) during the performance test and how each production rate was determined.
(e) You must determine the monthly amount of adipic acid produced. You must also determine the monthly amount of adipic acid produced during which N
(f) You must determine the annual amount of adipic acid produced. You must also determine the annual amount of adipic acid produced during which N
§ 98.55 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section.
(a) For each missing value of monthly adipic acid production, the substitute data shall be the best available estimate based on all available process data or data used for accounting purposes (such as sales records).
(b) For missing values related to the performance test, including emission factors, production rate, and N
§ 98.56 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (n) of this section at the facility level.
(a) Annual process N
(b)-(c) [Reserved]
(d) Annual process N
(e) Number of abatement technologies (if applicable).
(f) Types of abatement technologies used and date of installation for each (if applicable).
(g) Abatement technology destruction efficiency for each abatement technology (percent destruction).
(h) Abatement utilization factor for each abatement technology (fraction of annual production that abatement technology is operating).
(i) Number of times in the reporting year that missing data procedures were followed to measure adipic acid production (months).
(j) If you conducted a performance test and calculated a site-specific emissions factor according to § 98.53(a)(1), each annual report must also contain the information specified in paragraphs (j)(1) through (7) of this section for each adipic acid production unit.
(1) [Reserved]
(2) Test method used for performance test.
(3) [Reserved]
(4) N
(5) Volumetric flow rate per test run during performance test (dscf/hr).
(6) Number of test runs.
(7) Number of times in the reporting year that a performance test had to be repeated (number).
(k) If you requested Administrator approval for an alternative method of determining N
(1) Name of alternative method.
(2) Description of alternative method.
(3) Request date.
(4) Approval date.
(l) Fraction control factor for each abatement technology (percent of total emissions from the production unit that are sent to the abatement technology) if equation E-3c is used.
(m) If only cyclohexane is oxidized to produce adipic acid and the quantity is known, report the information specified in paragraph (m)(1) of this section. If materials other than cyclohexane are oxidized to produce adipic acid, report the information specified in paragraph (m)(2) of this section.
(1) Annual quantity of cyclohexane (tons) used to produce adipic acid.
(2) Annual quantity of cyclohexanone and cyclohexanol mixture (tons) used to produce adipic acid.
(n) Annual percent N
§ 98.57 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (i) of this section at the facility level:
(a) Annual adipic acid production capacity (tons).
(b) Records of significant changes to process.
(c) Number of facility and unit operating hours in calendar year.
(d) Documentation of how accounting procedures were used to estimate production rate.
(e) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency.
(f) Performance test reports.
(g) Measurements, records and calculations used to determine reported parameters.
(h) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(i) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (i)(1) through (3) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (i)(1) through (3) of this section.
(1) Annual adipic acid production from each adipic acid production unit (tons) (Equations E-2, E-3a, E-3b, E-3c, and E-3d of § 98.53).
(2) Production rate per test run during the performance test for each production unit test run (tons adipic acid produced/hr) (Equation E-1 of § 98.53).
(3) Annual adipic acid production per N
§ 98.58 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart F – Aluminum Production
§ 98.60 Definition of the source category.
(a) A primary aluminum production facility manufactures primary aluminum using the Hall-Héroult manufacturing process. The primary aluminum manufacturing process comprises the following operations:
(1) Electrolysis in prebake and Søderberg cells.
(2) Anode baking for prebake cells.
(b) This source category does not include experimental cells or research and development process units.
§ 98.61 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an aluminum production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.62 GHGs to report.
You must report:
(a) Perfluoromethane (CF
(b) CO
(c) CO
(d) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
§ 98.63 Calculating GHG emissions.
(a) The annual value of each PFC compound (CF
(b) Use Equation F-2 of this section to estimate CF
(c) You must calculate and report the annual process CO
(d) Calculate and report under this subpart the process CO
(e) Use the following procedures to calculate CO
(1) For Prebake cells: you must calculate CO
(2) For Søderberg cells you must calculate CO
(f) Use the following procedures to calculate CO
(1) Use Equation F-7 of this section to calculate emissions from pitch volatiles combustion.
(2) Use Equation F-8 of this section to calculate emissions from bake furnace packing material.
(g) If process CO
§ 98.64 Monitoring and QA/QC requirements.
(a) Effective December 31, 2010 for smelters with no prior measurement or effective December 31, 2012, for facilities with historic measurements, the smelter-specific slope coefficients, overvoltage emission factors, and weight fractions used in Equations F-2, F-3, and F-4 of this subpart must be measured in accordance with the recommendations of the EPA/IAI Protocol for Measurement of Tetrafluoromethane (CF
(b) The minimum frequency of the measurement and analysis is annually except as follows:
(1) Monthly for anode effect minutes per cell day (or anode effect overvoltage and current efficiency).
(2) Monthly for aluminum production.
(3) Smelter-specific slope coefficients, overvoltage emission factors, and weight fractions according to paragraph (a) of this section.
(c) Sources may use either smelter-specific values from annual measurements of parameters needed to complete the equations in § 98.63 (e.g., sulfur, ash, and hydrogen contents) or the default values shown in Table F-2 of this subpart.
§ 98.65 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample measurement is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:
(a) Where anode or paste consumption data are missing, CO
(b) For other parameters, use the average of the two most recent data points after the missing data.
§ 98.66 Data reporting requirements.
In addition to the information required by § 98.3(c), you must report the following information at the facility level:
(a) [Reserved]
(b) Type of smelter technology used.
(c) The following PFC-specific information on an annual basis:
(1) Perfluoromethane emissions and perfluoroethane emissions from anode effects in all prebake and all Søderberg electrolysis cells combined.
(2) Anode effect minutes per cell-day (AE-mins/cell-day), anode effect frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF4/metric ton Al)/(mV/cell day)), potline overvoltage (mV/cell day), current efficiency (%)).
(3) Smelter-specific slope coefficients (or overvoltage emission factors) and the last date when the smelter-specific slope coefficients (or overvoltage emission factors) were measured.
(d) Method used to measure the frequency and duration of anode effects (or overvoltage).
(e) The following CO
(1) Annual anode consumption if using the method in § 98.63(g).
(2) Annual CO
(f) The following CO
(1) Annual paste consumption if using the method in § 98.63(g).
(2) Annual CO
(g) [Reserved]
(h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or Søderberg) and process control technology (e.g., Pechiney or other).
§ 98.67 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the following records:
(a) Monthly aluminum production in metric tons.
(b) Type of smelter technology used.
(c) The following PFC-specific information on a monthly basis:
(1) Perfluoromethane and perfluoroethane emissions from anode effects in prebake and Søderberg electolysis cells.
(2) Anode effect minutes per cell-day (AE-mins/cell-day), anode effect frequency (AE/cell-day), anode effect duration (minutes). (Or anode effect overvoltage factor ((kg CF
(3) Smelter-specific slope coefficients and the last date when the smelter-specific-slope coefficients were measured.
(d) Method used to measure the frequency and duration of anode effects (or to measure anode effect overvoltage and current efficiency).
(e) The following CO
(1) Annual anode consumption.
(2) Annual CO
(f) The following CO
(1) Annual paste consumption.
(2) Annual CO
(g) Smelter-specific inputs to the CO
(h) Exact data elements required will vary depending on smelter technology (e.g., point-feed prebake or Søderberg) and process control technology (e.g., Pechiney or other).
(i) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (i)(1) through (30) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (i)(1) through (30) of this section.
(1) Slope coefficient per potline per month (kg CF
(2) Anode effect minutes per cell-day per potline per month (AE-Mins/cell-day) (Equation F-2).
(3) Anode effect frequency per potline per month (AE/cell-day) (Equation F-2).
(4) Anode effect duration per potline per month (minutes) (Equation F-2).
(5) Metal production of aluminum per potline per month (metric tons) (Equation F-2).
(6) Overvoltage emission factor per potline per month (kg CF4/metric ton Al) (Equation F-3 of § 98.63).
(7) Metal production of aluminum per potline per month (metric tons) (Equation F-3).
(8) Weight fraction of C
(9) Net annual prebaked anode consumption (metric tons C/metric tons Al) (Equation F-5 of § 98.63).
(10) Annual metal production of aluminum (metric tons) (Equation F-5).
(11) Sulfur content in baked anode (weight percent) (Equation F-5).
(12) Ash content in baked anode (weight percent) (Equation F-5).
(13) Annual paste consumption (metric ton/metric ton Al) (Equation F-6 of § 98.63).
(14) Annual metal production of aluminum (metric tons) (Equation F-6).
(15) Annual emissions of cyclohexane soluble matter (kg/metric ton Al) (Equation F-6).
(16) Binder content of paste (weight percent) (Equation F-6).
(17) Sulfur content of pitch (weight percent) (Equation F-6).
(18) Ash content of pitch (weight percent) (Equation F-6).
(19) Hydrogen content of pitch (weight percent) (Equation F-6).
(20) Sulfur content in calcined coke (weight percent) (Equation F-6).
(21) Ash content in calcined coke (weight percent) (Equation F-6).
(22) Carbon in skimmed dust from Søderberg cells (metric ton C/metric ton Al) (Equation F-6).
(23) Initial weight of green anodes (metric tons) (Equation F-7 of § 98.63).
(24) Annual hydrogen content in green anodes (metric tons) (Equation F-7).
(25) Annual baked anode production (metric tons) (Equation F-7).
(26) Annual waste tar collected (metric tons) (Equation F-7).
(27) Annual packing coke consumption (metric tons/metric ton baked anode) (Equation F-8 of § 98.63).
(28) Annual baked anode production (metric tons) (Equation F-8).
(29) Sulfur content in packing coke (weight percent) (Equation F-8).
(30) Ash content in packing coke (weight percent) (Equation F-8).
§ 98.68 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table F-1 to Subpart F of Part 98 – Slope and Overvoltage Coefficients for the Calculation of PFC Emissions From Aluminum Production
Technology | CF [(kg CF | CF [(kg CF | Weight fraction C [(kg C |
---|---|---|---|
Center Worked Prebake (CWPB) | 0.143 | 1.16 | 0.121 |
Side Worked Prebake (SWPB) | 0.272 | 3.65 | 0.252 |
Vertical Stud Søderberg (VSS) | 0.092 | NA | 0.053 |
Horizontal Stud Søderberg (HSS) | 0.099 | NA | 0.085 |
Table F-2 to Subpart F of Part 98 – Default Data Sources for Parameters Used for CO2 Emissions
Parameter | Data source |
---|---|
CO | |
MP: metal production (metric tons Al) | Individual facility records. |
NAC: net annual prebaked anode consumption per metric ton Al (metric tons C/metric tons Al) | Individual facility records. |
S | 2.0. |
Ash | 0.4. |
CO | |
MP: metal production (metric tons Al) | Individual facility records. |
PC: annual paste consumption (metric ton/metric ton Al) | Individual facility records. |
CSM: annual emissions of cyclohexane soluble matter (kg/metric ton Al) | HSS: 4.0. VSS: 0.5. |
BC: binder content of paste (percent weight) | Dry Paste: 24. Wet Paste: 27. |
S | 0.6. |
Ash | 0.2. |
H | 3.3. |
S | 1.9. |
Ash | 0.2. |
CD: carbon in skimmed dust from Søderberg cells (metric ton C/metric ton Al) | 0.01. |
CO | |
GA: initial weight of green anodes (metric tons) | Individual facility records. |
H | 0.005 × GA. |
BA: annual baked anode production (metric tons) | Individual facility records. |
WT: annual waste tar collected (metric tons) | (a) 0.005 × GA. |
(a) Riedhammer furnaces | (b) insignificant. |
(b) all other furnaces | |
CO | |
PCC: annual packing coke consumption (metric tons/metric ton baked anode) | 0.015. |
BA: annual baked anode production (metric tons) | Individual facility records. |
S | 2. |
Ash | 2.5. |
Subpart G – Ammonia Manufacturing
§ 98.70 Definition of source category.
The ammonia manufacturing source category comprises the process units listed in paragraphs (a) and (b) of this section.
(a) Ammonia manufacturing processes in which ammonia is manufactured from a fossil-based feedstock produced via steam reforming of a hydrocarbon.
(b) Ammonia manufacturing processes in which ammonia is manufactured through the gasification of solid and liquid raw material.
§ 98.71 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an ammonia manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.72 GHGs to report.
You must report:
(a) CO
(b) CO
(c) CO
§ 98.73 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process CO
(b) Calculate and report under this subpart process CO
(1) Gaseous feedstock. You must calculate, from each ammonia manufacturing unit, the CO
(2) Liquid feedstock. You must calculate, from each ammonia manufacturing unit, the CO
(3) Solid feedstock. You must calculate, from each ammonia manufacturing unit, the CO
(4) You must calculate the annual process CO
(5) You must determine the combined CO
(c) If GHG emissions from an ammonia manufacturing unit are vented through the same stack as any combustion unit or process equipment that reports CO
§ 98.74 Monitoring and QA/QC requirements.
(a) You must continuously measure the quantity of gaseous or liquid feedstock consumed using a flow meter. The quantity of solid feedstock consumed can be obtained from company records and aggregated on a monthly basis.
(b) You must document the procedures used to ensure the accuracy of the estimates of feedstock consumption.
(c) You must determine monthly carbon contents and the average molecular weight of each feedstock consumed from reports from your supplier. As an alternative to using supplier information on carbon contents, you can also collect a sample of each feedstock on a monthly basis and analyze the carbon content and molecular weight of the fuel using any of the following methods listed in paragraphs (c)(1) through (c)(8) of this section, as applicable.
(1) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(2) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(3) ASTM D2502-04 (Reapproved 2002) Standard Test Method for Estimation of Mean Relative Molecular Mass of Petroleum Oils from Viscosity Measurements (incorporated by reference, see § 98.7).
(4) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see § 98.7).
(5) ASTM D3238-95 (Reapproved 2005) Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method (incorporated by reference, see § 98.7).
(6) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7).
(7) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7).
(8) ASTM D5373-08 Standard Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).
(d) Calibrate all oil and gas flow meters that are used to measure liquid and gaseous feedstock volumes and flow rates (except for gas billing meters) according to the monitoring and QA/QC requirements for the Tier 3 methodology in § 98.34(b)(1). Perform oil tank drop measurements (if used to quantify feedstock volumes) according to § 98.34(b)(2).
(e) For quality assurance and quality control of the supplier data, on an annual basis, you must measure the carbon contents of a representative sample of the feedstocks consumed using the appropriate ASTM Method as listed in paragraphs (c)(1) through (c)(8) of this section.
(f) You may use company records or an engineering estimate to determine the annual ammonia production and the annual methanol production.
(g) If CO
§ 98.75 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever the monitoring and quality assurance procedures in § 98.74 cannot be followed (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter shall be used in the calculations following paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.
(a) For missing data on monthly carbon contents of feedstock, the substitute data value shall be the arithmetic average of the quality-assured values of that carbon content in the month preceding and the month immediately following the missing data incident. If no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon content obtained in the month after the missing data period.
(b) For missing feedstock supply rates used to determine monthly feedstock consumption, you must determine the best available estimate(s) of the parameter(s), based on all available process data.
§ 98.76 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable for each ammonia manufacturing process unit.
(a) If a CEMS is used to measure CO
(1) Annual quantity of each type of feedstock consumed for ammonia manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock).
(2) Method used for determining quantity of feedstock used.
(3) Annual ammonia production (metric tons, sum of all process units reported within subpart G of this part).
(b) If a CEMS is not used to measure emissions, then you must report all of the following information in this paragraph (b):
(1) Annual CO
(2) Annual quantity of each type of feedstock consumed for ammonia manufacturing (scf of feedstock or gallons of feedstock or kg of feedstock).
(3) Method used for determining quantity of monthly feedstock used.
(4) Whether carbon content for each feedstock for month n is based on reports from the supplier or analysis of carbon content.
(5) If carbon content of feedstock for month n is based on analysis, the test method used.
(6) Sampling analysis results of carbon content of feedstock as determined for QA/QC of supplier data under § 98.74(e).
(7) Annual average carbon content of each type of feedstock consumed.
(8)-(11) [Reserved]
(12) Annual urea production (metric tons) and method used to determine urea production.
(13) Annual CO
(14) Annual ammonia production (metric tons, sum of all process units reported within subpart G).
(15) Annual quantity of methanol intentionally produced as a desired product, for each process unit (metric tons).
§ 98.77 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the following records specified in paragraphs (a) through (c) of this section for each ammonia manufacturing unit.
(a) If a CEMS is used to measure emissions, retain records of all feedstock purchases in addition to the requirements in § 98.37 for the Tier 4 Calculation Methodology.
(b) If a CEMS is not used to measure process CO
(1) Records of all analyses and calculations conducted for reported data as listed in § 98.76(b).
(2) Monthly records of carbon content of feedstock from supplier and/or all analyses conducted of carbon content.
(c) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) through (7) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (7) of this section.
(1) Volume of each gaseous feedstock used in month (scf of feedstock) (in Equation G-1 of § 98.73).
(2) Carbon content of each gaseous feedstock, for month (kg C per kg of feedstock) (in Equation G-1).
(3) Molecular weight of each gaseous feedstock per ammonia manufacturing unit with gaseous feedstock (kg/kg-mole) (Equation G-1).
(4) Volume of each liquid feedstock used in month (gallons of feedstock) (Equation G-2 of § 98.73).
(5) Carbon content of each liquid feedstock, for month (kg C per gallon of feedstock) (Equation G-2).
(6) Mass of each solid feedstock used in month (kg of feedstock) (Equation G-3 of § 98.73).
(7) Carbon content of each solid feedstock, for month (kg C per kg of feedstock) (Equation G-3).
§ 98.78 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart H – Cement Production
§ 98.80 Definition of the source category.
The cement production source category consists of each kiln and each in-line kiln/raw mill at any portland cement manufacturing facility including alkali bypasses, and includes kilns and in-line kiln/raw mills that burn hazardous waste.
§ 98.81 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a cement production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.82 GHGs to report.
You must report:
(a) CO
(b) CO
(c) CH
(d) CO
§ 98.83 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) For each cement kiln that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO
(b) For each kiln that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO
(c) Calculate and report under this subpart the combined process and combustion CO
(d) Calculate and report process and combustion CO
(1) Calculate CO
(2) CO
(i) Kiln-Specific Clinker Emission Factor. (A) Calculate the kiln-specific clinker emission factor using Equation H-3 of this section.
(B) Non-calcined CaO is CaO that remains in the clinker in the form of CaCO
(ii) Kiln-Specific CKD Emission Factor. (A) Calculate the kiln-specific CKD emission factor for CKD not recycled to the kiln using Equation H-4 of this section.
(B) Non-calcined CaO is CaO that remains in the CKD in the form of CaCO
(3) CO
(4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO
§ 98.84 Monitoring and QA/QC requirements.
(a) You must determine the weight fraction of total CaO and total MgO in CKD not recycled to the kiln from each kiln using ASTM C114-09, Standard Test Methods for Chemical Analysis of Hydraulic Cement (incoporated by reference, see § 98.7). The monitoring must be conducted quarterly for each kiln from a CKD sample drawn either as CKD is exiting the kiln or from bulk CKD storage.
(b) You must determine the weight fraction of total CaO and total MgO in clinker from each kiln using ASTM C114-09 Standard Test Methods for Chemical Analysis of Hydraulic Cement (incorporated by reference, see § 98.7). The monitoring must be conducted monthly for each kiln from a monthly clinker sample drawn from bulk clinker storage if storage is dedicated to the specific kiln, or from a monthly arithmetic average of daily clinker samples drawn from the clinker conveying systems exiting each kiln.
(c) The total organic carbon content (dry basis) of raw materials must be determined annually using ASTM C114-09 Standard Test Methods for Chemical Analysis of Hydraulic Cement (incorporated by reference, see § 98.7) or a similar industry standard practice or method approved for total organic carbon determination in raw mineral materials. The analysis must be conducted either on sample material drawn from bulk raw kiln feed storage or on sample material drawn from bulk raw material storage for each category of raw material (i.e., limestone, sand, shale, iron oxide, and alumina). Facilities that opt to use the default total organic carbon factor provided in § 98.83(d)(3), are not required to monitor for TOC.
(d) The quantity of clinker produced monthly by each kiln must be determined by direct weight measurement of clinker using the same plant techniques used for accounting purposes, such as reconciling weigh hopper or belt weigh feeder measurements against inventory measurements. As an alternative, facilities may also determine clinker production by direct measurement of raw kiln feed and application of a kiln-specific feed-to-clinker factor. Facilities that opt to use a feed-to-clinker factor must verify the accuracy of this factor on a monthly basis.
(e) The quantity of CKD not recycled to the kiln generated by each kiln must be determined quarterly using the same plant techniques used for accounting purposes, such as direct weight measurement using weigh hoppers, truck weigh scales, or belt weigh feeders.
(f) The annual quantity of raw kiln feed or annual quantity of each category of raw materials consumed by the facility (e.g., limestone, sand, shale, iron oxide, and alumina) must be determined monthly by direct weight measurement using the same plant instruments used for accounting purposes, such as weigh hoppers, truck weigh scales, or belt weigh feeders.
(g) The monthly non-calcined CaO and MgO that remains in the clinker in the form of CaCO
(h) The quarterly non-calcined CaO and MgO that remains in the CKD in the form of CaCO
§ 98.85 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations in § 98.83 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations. The owner or operator must document and keep records of the procedures used for all such estimates.
(a) If the CEMS approach is used to determine combined process and combustion CO
(b) For CO
(c) For each missing value of monthly clinker production the substitute data value must be the best available estimate of the monthly clinker production based on information used for accounting purposes, or use the maximum tons per day capacity of the system and the number of days per month.
(d) For each missing value of monthly raw material consumption the substitute data value must be the best available estimate of the monthly raw material consumption based on information used for accounting purposes (such as purchase records), or use the maximum tons per day raw material throughput of the kiln and the number of days per month.
§ 98.86 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as appropriate.
(a) If a CEMS is used to measure CO
(1) Monthly clinker production from each kiln at the facility.
(2) Annual facility cement production.
(3) Number of kilns and number of operating kilns.
(b) If a CEMS is not used to measure CO
(1) Kiln identification number.
(2) [Reserved]
(3) Annual cement production at the facility.
(4) Number of kilns and number of operating kilns.
(5)-(6) [Reserved]
(7) Method used to determine non-calcined CaO and non-calcined MgO in clinker.
(8) [Reserved]
(9) Method used to determine non-calcined CaO and non-calcined MgO in CKD.
(10) [Reserved]
(11) Quarterly kiln-specific CKD CO
(12) [Reserved]
(13) Name of raw kiln feed or raw material.
(14) Number of times missing data procedures were used to determine the following information:
(i) Clinker production (number of months).
(ii) Carbonate contents of clinker (number of months).
(iii) Non-calcined content of clinker (number of months).
(iv) CKD not recycled to kiln (number of quarters).
(v) Non-calcined content of CKD (number of quarters)
(vi) Organic carbon contents of raw materials (number of times).
(vii) Raw material consumption (number of months).
(15) Method used to determine the monthly clinker production from each kiln.
(16) Annual clinker production (metric tons).
(17) Annual average clinker CO
(18) Annual average CKD CO
§ 98.87 Records that must be retained.
(a) If a CEMS is used to measure CO
(b) If a CEMS is not used to measure CO
(1) Documentation of monthly calculated kiln-specific clinker CO
(2) Documentation of quarterly calculated kiln-specific CKD CO
(3) Measurements, records and calculations used to determine reported parameters.
(c) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) through (17) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (17) of this section.
(1) Identify per kiln per month if clinker is measured directly, or is calculated from raw feed (Equation H-2 of § 98.83 and the method in § 98.84(d)).
(2) Quantity of raw kiln feed in month from kiln (tons) (Equation H-2 and the method in § 98.84(d)).
(3) Kiln-specific factor per kiln per month (ton clinker per ton raw feed) (Equation H-2 and the method in § 98.84(d)).
(4) Quantity of clinker produced in month from kiln (tons) (Equation H-2 and the method in § 98.84(d)).
(5) Cement kiln dust (CKD) not recycled to the kiln in quarter from kiln (tons) (Equation H-2 and the method in § 98.84(d)).
(6) Monthly total CaO content of clinker per kiln (weight fraction) (Equation H-3 of § 98.83).
(7) Monthly non-calcined CaO content of clinker per kiln (weight fraction) (Equation H-3).
(8) Monthly total MgO content of clinker per kiln (weight fraction) (Equation H-3).
(9) Monthly non-calcined MgO content of clinker per kiln (weight fraction) (Equation H-3).
(10) Quarterly total CaO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4 of § 98.83).
(11) Quarterly non-calcined CaO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4).
(12) Quarterly total MgO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4).
(13) Quarterly non-calcined MgO content of cement kiln dust not recycled to each kiln (weight fraction) (Equation H-4).
(14) The amount of each raw material consumed annually per kiln (tons/yr (dry basis)) (Equation H-5 of § 98.83).
(15) The amount of each raw kiln feed consumed annually per kiln (tons/yr (dry basis)) (Equation H-5).
(16) Organic carbon content of each raw material per kiln, as determined in § 98.84(c). Default value is 0.002 weight fraction (Equation H-5).
(17) Organic carbon content of combined raw kiln feed per kiln, as determined in § 98.84(c). Default value is 0.002 weight fraction (Equation H-5).
§ 98.88 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart I – Electronics Manufacturing
§ 98.90 Definition of the source category.
(a) The electronics manufacturing source category consists of any of the production processes listed in paragraphs (a)(1) through (a)(5) of this section that use fluorinated GHGs or N
(1) Any electronics production process in which the etching process uses plasma-generated fluorine atoms and other reactive fluorine-containing fragments, that chemically react with exposed thin-films (e.g., dielectric, metals) or substrate (e.g., silicon) to selectively remove portions of material.
(2) Any electronics production process in which chambers used for depositing thin films are cleaned periodically using plasma-generated fluorine atoms and other reactive fluorine-containing fragments.
(3) Any electronics production process in which wafers are cleaned using plasma generated fluorine atoms or other reactive fluorine-containing fragments to remove residual material from wafer surfaces, including the wafer edge.
(4) Any electronics production process in which the chemical vapor deposition (CVD) process or other manufacturing processes use N
(5) Any electronics manufacturing production process in which fluorinated heat transfer fluids are used to cool process equipment, to control temperature during device testing, to clean substrate surfaces and other parts, and for soldering (e.g., vapor phase reflow).
§ 98.91 Reporting threshold.
(a) You must report GHG emissions under this subpart if electronics manufacturing production processes, as defined in § 98.90, are performed at your facility and your facility meets the requirements of either § 98.2(a)(1) or (a)(2). To calculate total annual GHG emissions for comparison to the 25,000 metric ton CO
(1) If you manufacture semiconductors or MEMS you must calculate annual production process emissions of each input gas i for threshold applicability purposes using the default emission factors shown in Table I-1 to this subpart and Equation I-1 of this subpart.
(2) If you manufacture LCDs, you must calculate annual production process emissions of each input gas i for threshold applicability purposes using the default emission factors shown in Table I-1 to this subpart and Equation I-2 of this subpart.
(3) If you manufacture PVs, you must calculate annual production process emissions of each input gas i for threshold applicability purposes using gas-appropriate GWP values shown in Table A-1 to subpart A of this part and Equation I-3 of this subpart.
(4) You must calculate total annual production process emissions for threshold applicability purposes using Equation I-4 of this subpart.
(b) You must calculate annual manufacturing capacity of a facility using Equation I-5 of this subpart.
§ 98.92 GHGs to report.
(a) You must report emissions of fluorinated GHGs (as defined in § 98.6), N
(1) Fluorinated GHGs emitted.
(2)-(3) [Reserved]
(4) N
(5) Emissions of fluorinated heat transfer fluids.
(6) All fluorinated GHGs and N
(b) CO
§ 98.93 Calculating GHG emissions.
(a) You must calculate total annual emissions of each fluorinated GHG emitted by electronics manufacturing production processes from each fab (as defined in § 98.98) at your facility, including each input gas and each by-product gas. You must use either default gas utilization rates and by-product formations rates according to the procedures in paragraph (a)(1), (a)(2), or (a)(6) of this section, as appropriate, or the stack test method according to paragraph (i) of this section, to calculate emissions of each input gas and each by-product gas.
(1) If you manufacture semiconductors, you must adhere to the procedures in paragraphs (a)(1)(i) through (iii) of this section. You must calculate annual emissions of each input gas and of each by-product gas using Equations I-6 and I-7 of this subpart, respectively. If your fab uses less than 50 kg of a fluorinated GHG in one reporting year, you may calculate emissions as equal to your fab’s annual consumption for that specific gas as calculated in Equation I-11 of this subpart, plus any by-product emissions of that gas calculated under paragraph (a) of this section.
(i) You must calculate annual fab-level emissions of each fluorinated GHG used for the plasma etching/wafer cleaning process type using default utilization and by-product formation rates as shown in Table I-3 or I-4 of this subpart, and by using Equations I-8 and I-9 of this subpart.
(ii) You must calculate annual fab-level emissions of each fluorinated GHG used for each of the process sub-types associated with the chamber cleaning process type, including in-situ plasma chamber clean, remote plasma chamber clean, and in-situ thermal chamber clean, using default utilization and by-product formation rates as shown in Table I-3 or I-4 of this subpart, and by using Equations I-8 and I-9 of this subpart.
(iii) If default values are not available for a particular input gas and process type or sub-type combination in Tables I-3 or I-4, you must follow the procedures in paragraph (a)(6) of this section.
(2) If you manufacture MEMS, LCDs, or PVs, you must calculate annual fab-level emissions of each fluorinated GHG used for the plasma etching and chamber cleaning process types using default utilization and by-product formation rates as shown in Table I-5, I-6, or I-7 of this subpart, as appropriate, and by using Equations I-8 and I-9 of this subpart. If default values are not available for a particular input gas and process type or sub-type combination in Tables I-5, I-6, or I-7, you must follow the procedures in paragraph (a)(6) of this section. If your fab uses less than 50 kg of a fluorinated GHG in one reporting year, you may calculate emissions as equal to your fab’s annual consumption for that specific gas as calculated in Equation I-11 of this subpart, plus any by-product emissions of that gas calculated under this paragraph (a).
(3)-(5) [Reserved]
(6) If you are required, or elect, to perform calculations using default emission factors for gas utilization and by-product formation rates according to the procedures in paragraphs (a)(1) or (a)(2) of this section, and default values are not available for a particular input gas and process type or sub-type combination in Tables I-3, I-4, I-5, I-6, or I-7, you must use the utilization and by-product formation rates of zero and use Equations I-8 and I-9 of this subpart.
(b) You must calculate annual fab-level N
Where:
(1) You must use the factor for N
(2) You must use the factor for N
(c) You must calculate total annual input gas i consumption on a fab basis for each fluorinated GHG and N
(d) You must calculate disbursements of input gas i using fab-wide gas-specific heel factors, as determined in § 98.94(b), and by using Equation I-12 of this subpart. Where a gas supply system serves more than one fab, Equation I-12 is applied to that gas which has been apportioned to each fab served by that system using the apportioning factors determined in accordance with § 98.94(c).
(e) You must calculate the amount of input gas i consumed, on a fab basis, for each process sub-type or process type j, using Equation I-13 of this subpart. Where a gas supply system serves more than one fab, Equation I-13 is applied to that gas which has been apportioned to each fab served by that system using the apportioning factors determined in accordance with § 98.94(c). If you elect to calculate emissions using the stack test method in paragraph (i) of this section, you must calculate the amount of input gas i consumed on the applicable basis by using an appropriate apportioning factor. For example, when calculating fab-level emissions of each fluorinated GHG consumed using Equation I-21 of this section, you must substitute the term fij with the appropriate apportioning factor to calculate the total consumption of each fluorinated GHG in tools that are vented to stack systems that are tested.
(f) [Reserved]
(g) If you report controlled emissions pursuant to § 98.94(f), you must calculate the uptime of all the abatement systems for each combination of input gas or by-product gas, and process sub-type or process type, by using Equation I-15 of this subpart.
(h) If you use fluorinated heat transfer fluids, you must calculate the annual emissions of fluorinated heat transfer fluids on a fab basis using the mass balance approach described in Equation I-16 of this subpart.
(1) If you use a fluorinated chemical both as a fluorinated heat transfer fluid and in other applications, you may calculate and report either emissions from all applications or from only those specified in the definition of fluorinated heat transfer fluids in § 98.98.
(2) [Reserved]
(i) Stack Test Method. As an alternative to the default emission factor method in paragraph (a) of this section, you may calculate fab-level fluorinated GHG emissions using fab-specific emission factors developed from stack testing. To use the method in this paragraph, you must first make a preliminary estimate of the fluorinated GHG emissions from each stack system in the fab under paragraph (i)(1) of this section. You must then compare the preliminary estimate for each stack system to the criteria in paragraph (i)(2) of this section to determine whether the stack system meets the criteria for using the stack test method described in paragraph (i)(3) of this section or whether the stack system meets the criteria for using the method described in paragraph (i)(4) of this section to estimate emissions from the stack systems that are not tested.
(1) Preliminary estimate of emissions by stack system in the fab. You must calculate a preliminary estimate of the total annual emissions, on a metric ton CO
(i) When you are calculating preliminary estimates for the purpose of this paragraph (i)(1), you must consider the subscript “j” in Equations I-8 and I-9, and I-13 of this subpart to mean “stack system” instead of “process sub-type or process type.” For the value of a
(ii) You must use representative data from the previous reporting year to estimate the consumption of input gas i as calculated in Equation I-13 of this subpart and the fraction of input gas i and by-product gas k destroyed in abatement systems for each stack system as calculated by Equations I-24A and I-24B of this subpart. If you were not required to submit an annual report under subpart I for the previous reporting year and data from the previous reporting year are not available, you may estimate the consumption of input gas i and the fraction of input gas i destroyed in abatement systems based on representative operating data from a period of at least 30 days in the current reporting year. When calculating the consumption of input gas i using Equation I-13 of this subpart, the term “f
(iii) You must use representative data from the previous reporting year to estimate the total uptime of all abatement systems for the stack system as calculated by Equation I-23 of this subpart, instead of using Equation I-15 of this subpart to calculate the average uptime factor. If you were not required to submit an annual report under subpart I for the previous reporting year and data from the previous reporting year are not available, you may estimate the total uptime of all abatement systems for the stack system based on representative operating data from a period of at least 30 days in the current reporting year.
(iv) If you anticipate an increase or decrease in annual consumption or emissions of any fluorinated GHG, or the number of tools connected to abatement systems greater than 10 percent for the current reporting year compared to the previous reporting year, you must account for the anticipated change in your preliminary estimate. You may account for such a change using a quantifiable metric (e.g., the ratio of the number of tools that are expected to be vented to the stack system in the current year as compared to the previous reporting year, ratio of the expected number of wafer starts in the current reporting year as compared to the previous reporting year), engineering judgment, or other industry standard practice.
(2) Method selection for stack systems in the fab. If the calculations under paragraph (i)(1) of this section, as well as any subsequent annual measurements and calculations under this subpart, indicate that the stack system meets the criteria in paragraph (i)(2)(i) through (iii) of this section, then you may comply with either paragraph (i)(3) of this section (stack test method) or paragraph (i)(4) of this section (method to estimate emissions from the stack systems that are not tested). If the stack system does not meet all three criteria in paragraph (i)(2)(i) through (iii) of this section, then you must comply with the stack test method specified in paragraph (i)(3) of this section.
(i) The sum of annual emissions of fluorinated GHGs from all of the combined stack systems that are not tested in the fab must be less than 10,000 metric ton CO
(ii) When all stack systems in the fab are ordered from lowest to highest emitting in metric ton CO
(iii) Fluorinated GHG emissions from each of the stack systems that is not tested can only be attributed to particular process tools during the test (that is, the stack system that is not tested cannot be used as an alternative emission point or bypass stack system from other process tools not attributed to the untested stack system).
(3) Stack system stack test method. For each stack system in the fab for which testing is required, measure the emissions of each fluorinated GHG from the stack system by conducting an emission test. In addition, measure the fab-specific consumption of each fluorinated GHG by the tools that are vented to the stack systems tested. Measure emissions and consumption of each fluorinated GHG as specified in § 98.94(j). Develop fab-specific emission factors and calculate fab-level fluorinated GHG emissions using the procedures specified in paragraph (i)(3)(i) through (viii) of this section. All emissions test data and procedures used in developing emission factors must be documented and recorded according to § 98.97.
(i) You must measure, and, if applicable, apportion the fab-specific fluorinated GHG consumption of the tools that are vented to the stack systems that are tested during the emission test as specified in § 98.94(j)(3). Calculate the consumption for each fluorinated GHG for the test period.
(ii) You must calculate the emissions of each fluorinated GHG consumed as an input gas using Equation I-17 of this subpart and each fluorinated GHG formed as a by-product gas using Equation I-18 of this subpart and the procedures specified in paragraphs (i)(3)(ii)(A) through (E) of this section. If a stack system is comprised of multiple stacks, you must sum the emissions from each stack in the stack system when using Equation I-17 or Equation I-18 of this subpart.
(A) If a fluorinated GHG is consumed during the sampling period, but emissions are not detected, use one-half of the field detection limit you determined for that fluorinated GHG according to § 98.94(j)(2) for the value of “X
(B) If a fluorinated GHG is consumed during the sampling period and detected intermittently during the sampling period, use the detected concentration for the value of “X
(C) If an expected or possible by-product, as listed in Table I-17 of this subpart, is detected intermittently during the sampling period, use the measured concentration for “X
(D) If a fluorinated GHG is not consumed during the sampling period and is an expected by-product gas as listed in Table I-17 of this subpart and is not detected during the sampling period, use one-half of the field detection limit you determined for that fluorinated GHG according to § 98.94(j)(2) for the value of “X
(E) If a fluorinated GHG is not consumed during the sampling period and is a possible by-product gas as listed in Table I-17 of this subpart, and is not detected during the sampling period, then assume zero emissions for that fluorinated GHG for the tested stack system.
(iii) You must calculate a fab-specific emission factor for each fluorinated GHG input gas consumed (in kg of fluorinated GHG emitted per kg of input gas i consumed) in the tools that vent to stack systems that are tested, as applicable, using Equation I-19 of this subpart. If the emissions of input gas i exceed the consumption of input gas i during the sampling period, then equate “E
(iv) You must calculate a fab-specific emission factor for each fluorinated GHG formed as a by-product (in kg of fluorinated GHG per kg of total fluorinated GHG consumed) in the tools vented to stack systems that are tested, as applicable, using Equation I-20 of this subpart. When calculating the by-product emission factor for an input gas for which emissions exceeded its consumption, exclude the consumption of that input gas from the term “∑(Activity
(v) You must calculate annual fab-level emissions of each fluorinated GHG consumed using Equation I-21 of this section.
(vi) You must calculate annual fab-level emissions of each fluorinated GHG by-product formed using Equation I-22 of this section.
(vii) When using the stack testing method described in this paragraph (i), you must calculate abatement system uptime on a fab basis using Equation I-23 of this subpart. When calculating abatement system uptime for use in Equation I-19 and I-20 of this subpart, you must evaluate the variables “Td
(viii) When using the stack testing option described in paragraph (i) of this section, you must calculate the weighted-average fraction of each fluorinated input gas i and each fluorinated byproduct gas k destroyed or removed in abatement systems for each fab f, as applicable, by using Equation I-24A (for input gases) and Equation I-24B (for by-product gases) of this subpart.
(4) Method to calculate emissions from stack systems that are not tested. You must calculate annual fab-level emissions of each fluorinated GHG input gas and byproduct gas for those fluorinated GHG listed in paragraphs (i)(4)(i) and (ii) of this section using default utilization and by-product formation rates as shown in Table I-11, I-12, I-13, I-14, or I-15 of this subpart, as applicable, and by using Equations I-8, I-9, and I-13 of this subpart. When using Equations I-8, I-9, and I-13 to fulfill the requirements of this paragraph, you must use, in place of the term C
(i) Calculate emissions from consumption of each intermittent low-use fluorinated GHG as defined in § 98.98 of this subpart using the default utilization and by-product formation rates and equations specified in paragraph (i)(4) of this section. If a fluorinated GHG was not being used during the stack testing and does not meet the definition of intermittent low-use fluorinated GHG in § 98.98, then you must test the stack systems associated with the use of that fluorinated GHG at a time when that gas is in use at a magnitude that would allow you to determine an emission factor for that gas according to the procedures specified in paragraph (i)(3) of this section.
(ii) Calculate emissions from consumption of each fluorinated GHG used in tools vented to stack systems that meet the criteria specified in paragraphs (i)(2)(i) through (i)(2)(iii) of this section, and were not tested according to the procedures in paragraph (i)(3) of this section. Calculate emissions using the default utilization and by-product formation rates and equations specified in paragraph (i)(4) of this section. If you are using a fluorinated GHG not listed in Tables I-11, I-12, I-13, I-14, or I-15 of this subpart, then you must assume utilization and by-product formation rates of zero for that fluorinated GHG.
(5) To determine the total emissions of each fluorinated GHG from each fab under this stack testing option, you must sum the emissions of each fluorinated GHG determined from the procedures in paragraph (i)(3) of this section with the emissions of the same fluorinated GHG determined from the procedures in paragraph (i)(4) of this section. Sum the total emissions of each fluorinated GHG from all fabs at your facility to determine the facility-level emissions of each fluorinated GHG.
§ 98.94 Monitoring and QA/QC requirements.
(a) [Reserved]
(b) For purposes of Equation I-12 of this subpart, you must estimate fab-wide gas-specific heel factors for each container type for each gas used, according to the procedures in paragraphs (b)(1) through (b)(5) of this section. This paragraph (b) does not apply to fluorinated GHGs or N
(1) Base your fab-wide gas-specific heel factors on the trigger point for change out of a container for each container size and type for each gas used. Fab-wide gas-specific heel factors must be expressed as the ratio of the trigger point for change out, in terms of mass, to the initial mass in the container, as determined by paragraphs (b)(2) and (3) of this section.
(2) The trigger points for change out you use to calculate fab-wide gas-specific heel factors in paragraph (b)(1) of this section must be determined by monitoring the mass or the pressure of your containers. If you monitor the pressure, convert the pressure to mass using the ideal gas law, as displayed in Equation I-25 of this subpart, with the appropriate Z value selected based upon the properties of the gas.
(3) The initial mass you use to calculate a fab-wide gas-specific heel factor in paragraph (b)(1) of this section may be based on the weight of the gas provided to you in gas supplier documents; however, you remain responsible for the accuracy of these masses and weights under this subpart.
(4) If a container is changed in an exceptional circumstance, as specified in paragraphs (b)(4)(i) and (ii) of this section, you must weigh that container or measure the pressure of that container with a pressure gauge, in place of using a heel factor to determine the residual weight of gas. When using mass-based trigger points for change out, you must determine if an exceptional circumstance has occurred based on the net weight of gas in the container, excluding the tare weight of the container.
(i) For containers with a maximum storage capacity of less than 9.08 kg (20 lbs) of gas, an exceptional circumstance is a change out point that differs by more than 50 percent from the trigger point for change out used to calculate your fab-wide gas-specific heel factor for that gas and container type.
(ii) For all other containers, an exceptional circumstance is a change out point that differs by more than 20 percent from the trigger point for change out used to calculate your fab-wide gas-specific heel factor for that gas and container type.
(5) You must re-calculate a fab-wide gas-specific heel factor if you execute a process change to modify the trigger point for change out for a gas and container type that differs by more than 5 percent from the previously used trigger point for change out for that gas and container type.
(c) You must develop apportioning factors for fluorinated GHG and N
(1) You must demonstrate that the fluorinated GHG and N
(2) You must demonstrate the accuracy of your fab-specific model by comparing the actual amount of input gas i consumed and the modeled amount of input gas i consumed in the fab, as follows:
(i) You must analyze actual and modeled gas consumption for a period when the fab is at a representative operating level (as defined in § 98.98) lasting at least 30 days but no more than the reporting year.
(ii) You must compare the actual gas consumed to the modeled gas consumed for one fluorinated GHG reported under this subpart for the fab. You must certify that the fluorinated GHG selected for comparison corresponds to the largest quantity, on a mass basis, of fluorinated GHG consumed at the fab during the reporting year for which you are required to apportion following the procedures specified in § 98.93(a), (b), or (i). You may compare the actual gas consumed to the modeled gas consumed for two fluorinated GHGs and demonstrate conformance according to paragraph (c)(2)(iii) of this section on an aggregate use basis for both fluorinated GHGs if one of the fluorinated GHGs selected for comparison corresponds to the largest quantity, on a mass basis, of fluorinated GHGs used at each fab that requires apportionment during the reporting year.
(iii) You must demonstrate that the comparison performed for the largest quantity of gas(es), on a mass basis, consumed in the fab in paragraph (c)(2)(ii) of this section, does not result in a difference between the actual and modeled gas consumption that exceeds 20 percent relative to actual gas consumption, reported to two significant figures using standard rounding conventions.
(iv) If you are required to apportion gas consumption and you use the procedures in § 98.93(i) to calculate annual emissions from a fab, you must verify your apportioning factors using the procedures in paragraphs (c)(2)(ii) and (iii) of this section such that the time period specified in paragraph (c)(2)(i) of this section and the last day you perform the sampling events specified under § 98.93(i)(3) occur in the same accounting month.
(v) If your facility has multiple fabs with a single centralized fluorinated-GHG supply system, you must verify that your apportioning model can apportion fluorinated GHG consumption among the fabs by adhering to the procedures in paragraphs (c)(2)(ii) through (c)(2)(iv) of this section.
(3) As an alternative to developing apportioning factors for fluorinated GHG and N
(d)-(e) [Reserved]
(f) If your fab employs abatement systems and you elect to reflect emission reductions due to these systems, or if your fab employs abatement systems designed for fluorinated GHG abatement and you elect to calculate fluorinated GHG emissions using the stack test method under § 98.93(i), you must comply with the requirements of paragraphs (f)(1) through (3) of this section. If you use an average of properly measured destruction or removal efficiencies for a gas and process sub-type or process type combination, as applicable, in your emission calculations under § 98.93(a), (b), and/or (i), you must also adhere to procedures in paragraph (f)(4) of this section.
(1) You must certify and document that the abatement systems are properly installed, operated, and maintained according to the site maintenance plan for abatement systems that is developed and maintained in your records as specified in § 98.97(d)(9).
(2) You must calculate and document the uptime of abatement systems using Equation I-15 or I-23 of this subpart, as applicable.
(3) If you use default destruction and removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i), you must certify and document that the abatement systems at your facility for which you use default destruction or removal efficiency values are specifically designed for fluorinated GHG or N
(4) If you do not use the default destruction or removal efficiency values in Table I-16 of this subpart to calculate and report controlled emissions, including situations in which your fab employs abatement systems not specifically designed for fluorinated GHG or N
(i) A properly measured destruction or removal efficiency value must be determined in accordance with EPA 430-R-10-003 (incorporated by reference, see § 98.7), or according to an alternative method approved by the Administrator (or authorized representative) as specified in paragraph (k) of this section. If you are measuring destruction or removal efficiency according to EPA 430-R-10-003 (incorporated by reference, see § 98.7), you may follow the alternative procedures specified in Appendix A to this subpart.
(ii) You must select and properly measure the destruction or removal efficiency for a random sample of abatement systems to include in a random sampling abatement system testing program in accordance with procedures in paragraphs (f)(4)(ii)(A) and (B) of this section.
(A) For the first 2 years for which your fab is required to report emissions of fluorinated GHG and N
(B) If testing of a randomly selected abatement system would be disruptive to production, you may replace that system with another randomly selected system for testing and return the system to the sampling pool for subsequent testing. Any one abatement system must not be replaced by another randomly selected system for more than three consecutive selections. When you have to replace a system in one year, you may select that specific system to be tested in one of the next two sampling years so that you may plan testing of that abatement system to avoid disrupting production.
(iii) If you elect to take credit for abatement system destruction or removal efficiency before completing testing on 20 percent of the abatement systems for that gas and process sub-type or process type combination, as applicable, you must use default destruction or removal efficiencies for a gas and process type combination. You must not use a default value from Table I-16 of this subpart for any abatement system not specifically designed for fluorinated GHG and N
(iv) If a measured destruction or removal efficiency is below the manufacturer-claimed fluorinated GHG or N
(v) If a measured destruction or removal efficiency is below the manufacturer-claimed fluorinated GHG or N
(vi) If your fab uses redundant abatement systems, you may account for the total abatement system uptime (that is, the time that at least one abatement system is in operational mode) calculated for a specific exhaust stream during the reporting year.
(g) You must adhere to the QA/QC procedures of this paragraph when calculating fluorinated GHG and N
(1)-(2) [Reserved]
(3) Follow the QA/QC procedures in accordance with those in EPA 430-R-10-003 (incorporated by reference, see § 98.7), or the applicable QA/QC procedures specified in an alternative method approved by the Administrator (or authorized representative) according to paragraph (k) of this section, when calculating abatement systems destruction or removal efficiencies. If you are measuring destruction or removal efficiency according to EPA 430-R-10-003 (incorporated by reference, see § 98.7), and you elect to follow the alternative procedures specified in Appendix A to this subpart according to paragraph (f)(4)(i) of this section, you must follow any additional QA/QC procedures specified in Appendix A to this subpart.
(4) As part of normal operations for each fab, the inventory of gas stored in containers at the beginning of the reporting year must be the same as the inventory of gas stored in containers at the end of the previous reporting year. You must maintain records documenting the year end and year beginning inventories under § 98.97(a).
(h) You must adhere to the QA/QC procedures of this paragraph (h) when calculating annual gas consumption for each fluorinated GHG and N
(1) Review all inputs to Equations I-11 and I-16 of this subpart to ensure that all inputs and outputs are accounted for.
(2) Do not enter negative inputs into the mass balance Equations I-11 and I-16 of this subpart and ensure that no negative emissions are calculated.
(3) Ensure that the inventory at the beginning of one reporting year is identical to the inventory at the end of the previous reporting year. You must maintain records documenting the year end and year beginning inventories under § 98.97(a) and (r).
(4) Ensure that the total quantity of gas i in containers in service at the end of a reporting year is accounted for as if the in-service containers were full for Equation I-11 of this subpart. Ensure also that the same quantity is accounted for in the inventory of input gas i stored in containers at the beginning of the subsequent reporting year.
(i) All flow meters, weigh scales, pressure gauges, and thermometers used to measure quantities that are monitored under this section or used in calculations under § 98.93 must meet the calibration and accuracy requirements specified in § 98.3(i).
(j) Stack test methodology. For each fab for which you calculate annual emissions for any fluorinated GHG emitted from your facility using the stack test method according to the procedure specified in § 98.93(i)(3), you must adhere to the requirements in paragraphs (j)(1) through (8) of this section. You may request approval to use an alternative stack test method and procedure according to paragraph (k) of this section.
(1) Stack system testing. Conduct an emissions test for each applicable stack system according to the procedures in paragraphs (j)(1)(i) through (iv) of this section.
(i) You must conduct an emission test during which the fab is operating at a representative operating level, as defined in § 98.98, and with the abatement systems connected to the stack system being tested operating with at least 90 percent uptime, averaged over all abatement systems, during the 8-hour (or longer) period for each stack system, or at no less than 90 percent of the abatement system uptime rate measured over the previous reporting year, averaged over all abatement systems.
(ii) You must measure for the expected and possible by-products identified in Table I-17 of this subpart and those fluorinated GHGs used as input fluorinated GHG in process tools vented to the stack system, except for any intermittent low-use fluorinated GHG as defined in § 98.98. You must calculate annual emissions of intermittent low-use fluorinated GHGs by adhering to the procedures in § 98.93(i)(4)(i).
(iii) If a fluorinated GHG being consumed in the reporting year was not being consumed during the stack testing and does not meet the definition of intermittent low-use fluorinated GHG in § 98.98, then you must test the stack systems associated with the use of that fluorinated GHG at a time when that gas is in use at a magnitude that would allow you to determine an emission factor for that gas. If a fluorinated GHG consumed in the reporting year was not being consumed during the stack testing and is no longer in use by your fab (e.g., use of the gas has become obsolete or has been discontinued), then you must calculate annual emissions for that fluorinated GHG according to the procedure specified in § 98.93(i)(4).
(iv) Although all applicable stack systems are not required to be tested simultaneously, you must certify that no significant changes in stack flow configuration occur between tests conducted for any particular fab in a reporting year. You must certify that no more than 10 percent of the total number of fluorinated GHG emitting process tools are connected or disconnected from a stack system during testing. You must also certify that no process tools that were in operation at the start of the test period have been moved to a different stack system during the test period (i.e., during or in between testing of individual stack systems) and that no point-of-use abatement systems have been permanently removed from service during the test period. You must document any changes in stack flow configuration in the emissions test data and report required to be kept as records under § 98.97(i)(4).
(2) Test methods and procedures. You must adhere to the applicable test methods and procedures specified in Table I-9 to this subpart, or adhere to an alternative method approved by the Administrator (or authorized representative) according to paragraph (k) of this section. If you select Method 320 of 40 CFR part 63, Appendix A to measure the concentration of each fluorinated GHG in the stack system, you must complete a method validation according to Section 13 of Method 320 of 40 CFR part 63, Appendix A for each FTIR system (hardware and software) and each tester (testing company). Method 320 validation is necessary when any change occurs in instrumentation, tester (i.e., testing company), or stack condition (e.g., acid gas vs. base). Measurement of new compounds require validation for those compounds according to Section 13 of Method 320 of 40 CFR part 63, Appendix A. The field detection limits achieved under your test methods and procedures must fall at or below the maximum field detection limits specified in Table I-10 to this subpart.
(3) Fab-specific fluorinated GHG consumption measurements. You must determine the amount of each fluorinated GHG consumed by each fab during the sampling period for all process tools connected to the stack systems tested under § 98.93(i)(3), according to the procedures in paragraphs (j)(3)(i) and (ii) of this section. This determination must include apportioning gas consumption between stack systems that are being tested and those that are not tested under § 98.93(i)(2).
(i) Measure fluorinated GHG consumption using gas flow meters, scales, or pressure measurements. Measure the mass or pressure, as applicable, at the beginning and end of the sampling period and when containers are changed out. If you elect to measure gas consumption using pressure (i.e., because the gas is stored in a location above its critical temperature) you must estimate consumption as specified in paragraphs (j)(3)(i)(A) and (B) of this section.
(A) For each fluorinated GHG, you must either measure the temperature of the fluorinated GHG container(s) when the sampling periods begin and end and when containers are changed out, or measure the temperature of the fluorinated GHG container(s) every hour for the duration of the sampling period. Temperature measurements of the immediate vicinity of the containers (e.g., in the same room, near the containers) shall be considered temperature measurements of the containers.
(B) Convert the sampling period-beginning, sampling period-ending, and container change-out pressures to masses using Equation I-25 of this subpart, with the appropriate Z value selected based upon the properties of the gas (e.g., the Z value yielded by the Redlich, Kwong, Soave equation of state with appropriate values for that gas). Apply the temperatures measured at or nearest to the beginning and end of the sampling period and to the time(s) when containers are changed out, as applicable. For each gas, the consumption during the sampling period is the difference between the masses of the containers of that gas at the beginning and at the end of the sampling period, summed across containers, including containers that are changed out.
(ii) For each fluorinated GHG gas for which consumption is too low to be accurately measured during the sampling period using gas flow meters, scales, or pressure measurements as specified in paragraph (j)(3)(i) of this section, you must follow at least one of the procedures listed in paragraph (j)(3)(ii)(A) through (C) of this section to obtain a consumption measurement.
(A) Draw the gas from a single gas container if it is normally supplied from multiple containers connected by a shared manifold.
(B) Calculate consumption from pro-rated long-term consumption data (for example, calculate and use hourly consumption rates from monthly consumption data).
(C) Increase the duration of the sampling period for consumption measurement beyond the minimum duration specified in Table I-9 of this subpart.
(4) Emission test results. The results of an emission test must include the analysis of samples, number of test runs, the average emission factor for each fluorinated GHG measured, the analytical method used, calculation of emissions, the fluorinated GHGs consumed during the sampling period, an identification of the stack systems tested, and the fluorinated GHGs that were included in the test. The emissions test report must contain all information and data used to derive the fab-specific emission factor.
(5) Emissions testing frequency. You must conduct emissions testing to develop fab-specific emission factors on a frequency according to the procedures in paragraph (j)(5)(i) or (ii) of this section.
(i) Annual testing. You must conduct an annual emissions test for each stack system for which emissions testing is required under § 98.93(i)(3), unless you meet the criteria in paragraph (j)(5)(ii) of this section to skip annual testing. Each set of emissions testing for a stack system must be separated by a period of at least 2 months.
(ii) Criteria to test less frequently. After the first 3 years of annual testing, you may calculate the relative standard deviation of the emission factors for each fluorinated GHG included in the test and use that analysis to determine the frequency of any future testing. As an alternative, you may conduct all three tests in less than 3 calendar years for purposes of this paragraph (j)(5)(ii), but this does not relieve you of the obligation to conduct subsequent annual testing if you do not meet the criteria to test less frequently. If the criteria specified in paragraphs (j)(5)(ii)(A) and (B) of this section are met, you may use the arithmetic average of the three emission factors for each fluorinated GHG and fluorinated GHG byproduct for the current year and the next 4 years with no further testing unless your fab operations are changed in a way that triggers the re-test criteria in paragraph (j)(8) of this section. In the fifth year following the last stack test included in the previous average, you must test each of the stack systems for which testing is required and repeat the relative standard deviation analysis using the results of the most recent three tests (i.e., the new test and the two previous tests conducted prior to the 4-year period). If the criteria specified in paragraphs (j)(5)(ii)(A) and (B) of this section are not met, you must use the emission factors developed from the most recent testing and continue annual testing. You may conduct more than one test in the same year, but each set of emissions testing for a stack system must be separated by a period of at least 2 months. You may repeat the relative standard deviation analysis using the most recent three tests, including those tests conducted prior to the 4-year period, to determine if you are exempt from testing for the next 4 years.
(B) The relative standard deviation for all single fluorinated GHGs that individually accounted for 5 percent or more of CO
(6) Subsequent measurements. You must make an annual determination of each stack system’s exemption status under § 98.93(i)(2) by March 31 each year. If a stack system that was previously not required to be tested per § 98.93(i)(2), no longer meets the criteria in § 98.93(i)(2), you must conduct the emissions testing for the stack system during the current reporting and develop the fab-specific emission factor from the emissions testing.
(7) Previous measurements. You may include the results of emissions testing conducted on or after January 1, 2011 for use in the relative standard deviation calculation in paragraph (j)(5)(ii) of this section if the previous results were determined using a method meeting the requirements in paragraph (j)(2) of this section. You may request approval to use results of emissions testing conducted between January 1, 2011 and January 1, 2014 using a method that deviated from the requirements in paragraph (j)(2) of this section by adhering to the requirements in paragraphs (j)(7)(i) through (j)(7)(iv) of this section.
(i) Notify the Administrator (or an authorized representative) of your intention to use the results of the previous emissions testing. You must include in the notification the data and results you intend to use for meeting either reporting or recordkeeping requirements, a description of the method, and any deviations from the requirements in paragraph (j)(2) of this section. Your description must include an explanation of how any deviations do not affect the quality of the data collected.
(ii) The Administrator will review the information submitted under paragraph (j)(7)(i) and determine whether the results of the previous emissions testing are adequate and issue an approval or disapproval of the use of the results within 120 days of the date on which you submit the notification specified in paragraph (j)(7)(i) of this section.
(iii) If the Administrator finds reasonable grounds to disapprove the results of the previous emissions testing, the Administrator may request that you provide additional information to support the use of the results of the previous emissions testing. Failure to respond to any request made by the Administrator does not affect the 120 day deadline specified in paragraph (j)(7)(ii) of this section.
(iv) Neither the approval process nor the failure to obtain approval for the use of results from previous emissions testing shall abrogate your responsibility to comply with the requirements of this subpart.
(8) Scenarios that require a stack system to be re-tested. By March 31 of each reporting year, you must evaluate and determine whether any changes to your fab operations meet the criteria specified in paragraphs (j)(8)(i) through (vi) of this section. If any of the scenarios specified in paragraph (j)(8)(i) through (vi) of this section occur, you must perform a re-test of any applicable stack system, irrespective of whether you have met the criteria for less frequent testing in paragraph (j)(5)(ii) of this section, before the end of the year in which the evaluation was completed. You must adhere to the methods and procedures specified in § 98.93(i)(3) for performing a stack system emissions test and calculating emissions. If you meet the criteria for less frequent testing in paragraph (j)(5)(ii), and you are required to perform a re-test as specified in paragraph (j)(8)(i) through (vi) of this section, the requirement to perform a re-test does not extend the date of the next scheduled test that was established prior to meeting the requirement to perform a re-test. If the criteria specified in paragraph (j)(5)(ii) of this section are not met using the results from the re-test and the two most recent stack tests, you must use the emission factors developed from the most recent testing to calculate emissions and resume annual testing. You may resume testing less frequently according to your original schedule if the criteria specified in paragraph (j)(5)(ii) of this section are met using the most recent three tests.
(i) Annual consumption of a fluorinated GHG used during the most recent emissions test (expressed in CO
(ii) A change in the consumption of an intermittent low-use fluorinated GHG (as defined in § 98.98) that was not used during the emissions test and not reflected in the fab-specific emission factor, such that it no longer meets the definition of an intermittent low-use fluorinated GHG.
(iii) A decrease by more than 10 percent in the fraction of tools with abatement systems, compared to the number during the most recent emissions test.
(iv) A change in the wafer size manufactured by the fab since the most recent emissions test.
(v) A stack system that formerly met the criteria specified under § 98.93(i)(2) for not being subject to testing no longer meets those criteria.
(vi) If a fluorinated GHG being consumed in the reporting year was not being consumed during the stack test and does not meet the definition of intermittent, low-use fluorinated GHG in § 98.98, then you must test the stack systems associated with the use of that fluorinated GHG at a time when that gas is in use as required in paragraph (j)(1)(iii) of this section.
(k) You may request approval to use an alternative stack test method and procedure or to use an alternative method to determine abatement system destruction or removal efficiency by adhering to the requirements in paragraphs (k)(1) through (6) of this section. An alternative method is any method of sampling and analyzing for a fluorinated GHG or N
(1) You may use an alternative method from that specified in this subpart provided that you:
(i) Notify the Administrator (or an authorized representative) of your intention to use an alternative method. You must include in the notification a site-specific test plan describing the alternative method and procedures (the alternative test plan), the range of test conditions over which the validation is intended to be applicable, and an alternative means of calculating the fab-level fluorinated GHG or N
(ii) Use Method 301 in appendix A of part 63 of this chapter to validate the alternative method. This may include the use of only portions of specific procedures of Method 301 if use of such procedures are sufficient to validate the alternative method; and
(iii) Submit the results of the Method 301 validation process along with the notification of intention and the rationale for not using the specified method.
(2) The Administrator will determine whether the validation of the proposed alternative method is adequate and issue an approval or disapproval of the alternative test plan within 120 days of the date on which you submit the notification and alternative test plan specified in paragraph (k)(1) of this section. If the Administrator approves the alternative test plan, you are authorized to use the alternative method(s) in place of the methods described in paragraph (f)(4)(i) of this section for measuring destruction or removal efficiency or paragraph (j) of this section for conducting the stack test, as applicable, taking into account the Administrator’s comments on the alternative test plan. Notwithstanding the requirement in the preceding sentence, you may at any time prior to the Administrator’s approval or disapproval proceed to conduct the stack test using the methods specified in paragraph (j) of this section or the destruction or removal efficiency determination specified in (f)(4)(i) of this section if you use a method specified in this subpart instead of the requested alternative. If an alternative test plan is not approved and you still want to use an alternative method, you must recommence the process to have an alternative test method approved starting with the notification of intent to use an alternative test method specified in paragraph (k)(1)(i) of this section.
(3) You must report the results of stack testing or destruction or removal efficiency determination using the alternative method and procedure specified in the approved alternative test plan. You must include in your report for an alternative stack test method and for an alternative abatement system destruction or removal efficiency determination the information specified in paragraph (j)(4) of this section, including all methods, calculations and data used to determine the fluorinated GHG emission factor or the abatement system destruction or removal efficiency. The Administrator will review the results of the test using the alternative methods and procedure and then approve or deny the use of the results of the alternative test method and procedure no later than 120 days after they are submitted to EPA.
(4) If the Administrator finds reasonable grounds to dispute the results obtained by an alternative method for the purposes of determining fluorinated GHG emissions or destruction or removal efficiency of an abatement system, the Administrator may require the use of another method specified in this subpart.
(5) Once the Administrator has approved the use of the alternative method for the purposes of determining fluorinated GHG emissions for specific fluorinated GHGs and types of stack systems or abatement system destruction or removal efficiency, that method may be used at any other facility for the same fluorinated GHGs and types of stack systems, or fluorinated GHGs and abatement systems, if the approved conditions apply to that facility. In granting approval, the Administrator may limit the range of test conditions and emission characteristics for which that approval is granted and under which the alternative method may be used without seeking approval under paragraphs (k)(1) through (4) of this section. The Administrator will specify those limitations, if any, in the approval of the alternative method.
(6) Neither the validation and approval process nor the failure to validate or obtain approval of an alternative method shall abrogate your responsibility to comply with the requirements of this subpart.
§ 98.95 Procedures for estimating missing data.
(a) Except as provided in paragraph (b) of this section, a complete record of all measured parameters used in the fluorinated GHG and N
(b) If you use fluorinated heat transfer fluids at your facility and are missing data for one or more of the parameters in Equation I-16 of this subpart, you must estimate fluorinated heat transfer fluid emissions using the arithmetic average of the emission rates for the reporting year immediately preceding the period of missing data and the months immediately following the period of missing data. Alternatively, you may estimate missing information using records from the fluorinated heat transfer fluid supplier. You must document the method used and values used for all missing data values.
§ 98.96 Data reporting requirements.
In addition to the information required by § 98.3(c), you must include in each annual report the following information for each electronics manufacturing facility:
(a) Annual manufacturing capacity of each fab at your facility used to determine the annual manufacturing capacity of your facility in Equation I-5 of this subpart.
(b) For facilities that manufacture semiconductors, the diameter of wafers manufactured at each fab at your facility (mm).
(c) Annual emissions, on a fab basis as described in paragraph (c)(1) through (5) of this section.
(1) When you use the procedures specified in § 98.93(a) of this subpart, each fluorinated GHG emitted from each process type for which your fab is required to calculate emissions as calculated in Equations I-6 and I-7 of this subpart.
(2) When you use the procedures specified in § 98.93(a), each fluorinated GHG emitted from each process type or process sub-type as calculated in Equations I-8 and I-9 of this subpart, as applicable.
(3) N
(4) Each fluorinated heat transfer fluid emitted as calculated in Equation 1-16 of this subpart.
(5) When you use the procedures specified in § 98.93(i) of this subpart, annual emissions of each fluorinated GHG, on a fab basis.
(d) The method of emissions calculation used in § 98.93 for each fab.
(e) Annual production in terms of substrate surface area (e.g., silicon, PV-cell, glass) for each fab, including specification of the substrate.
(f)-(l) [Reserved]
(m) For the fab-specific apportioning model used to apportion fluorinated GHG and N
(1) Identification of the quantifiable metric used in your fab-specific engineering model to apportion gas consumption for each fab, and/or an indication if direct measurements were used in addition to, or instead of, a quantifiable metric.
(2) The start and end dates selected under § 98.94(c)(2)(i).
(3) Certification that the gas(es) you selected under § 98.94(c)(2)(ii) for each fab corresponds to the largest quantity(ies) consumed, on a mass basis, of fluorinated GHG used at your fab during the reporting year for which you are required to apportion.
(4) The result of the calculation comparing the actual and modeled gas consumption under § 98.94(c)(2)(iii) and (iv), as applicable.
(5) If you are required to apportion fluorinated GHG consumption between fabs as required by § 98.94(c)(2)(v), certification that the gas(es) you selected under § 98.94(c)(2)(ii) corresponds to the largest quantity(ies) consumed on a mass basis, of fluorinated GHG used at your facility during the reporting year for which you are required to apportion.
(n)-(o) [Reserved]
(p) Inventory and description of all abatement systems through which fluorinated GHGs or N
(1) The number of abatement systems controlling emissions for each process sub-type, or process type, as applicable, for each gas used in the process sub-type or process type.
(2) The basis of the destruction or removal efficiency being used (default or site specific measurement according to § 98.94(f)(4)(i)) for each process sub-type or process type and for each gas.
(q) For all abatement systems through which fluorinated GHGs or N
(1) Certification that all abatement systems at the facility have been installed, maintained, and operated in accordance with the site maintenance plan for abatement systems that is developed and maintained in your records as specified in § 98.97(d)(9).
(2) If you use default destruction or removal efficiency values in your emissions calculations under § 98.93(a), (b), or (i), certification that the site maintenance plan for abatement systems for which emissions are being reported contains manufacturer’s recommendations and specifications for installation, operation, and maintenance for each abatement system.
(3) If you use default destruction or removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i), certification that the abatement systems for which emissions are being reported were specifically designed for fluorinated GHG or N
(4) For all stack systems for which you calculate fluorinated GHG emissions according to the procedures specified in § 98.93(i)(3), certification that you have included and accounted for all abatement systems and any respective downtime in your emissions calculations under § 98.93(i)(3).
(r) You must report an effective fab-wide destruction or removal efficiency value for each fab at your facility calculated using Equation I-26, I-27, and I-28 of this subpart, as appropriate.
(1) Use Equation I-27 of this subpart to calculate total unabated emissions, in metric tons CO
(2) Use Equation I-28 to calculate total unabated emissions, in metric ton CO
(s) Where missing data procedures were used to estimate inputs into the fluorinated heat transfer fluid mass balance equation under § 98.95(b), the number of times missing data procedures were followed in the reporting year and the method used to estimate the missing data.
(t)-(v) [Reserved]
(w) If you elect to calculate fab-level emissions of fluorinated GHG using the stack test methods specified in § 98.93(i), you must report the following in paragraphs (w)(1) and (2) for each stack system, in addition to the relevant data in paragraphs (a) through (v) of this section:
(1) The date of any stack testing conducted during the reporting year, and the identity of the stack system tested.
(2) An inventory of all stack systems from which process fluorinated GHG are emitted. For each stack system, indicate whether the stack system is among those for which stack testing was performed as per § 98.93(i)(3) or not performed as per § 98.93(i)(2).
(x) If the emissions you report under paragraph (c) of this section include emissions from research and development activities, as defined in § 98.6, report the approximate percentage of total GHG emissions, on a metric ton CO
(y) If your semiconductor manufacturing facility emits more than 40,000 metric ton CO
(1) The first report must be submitted with the annual GHG emissions report that is due no later than March 31, 2017, and subsequent reports must be delivered every 3 years no later than March 31 of the year in which it is due.
(2) The report must include the information described in paragraphs (y)(2)(i) through (v) of this section.
(i) It must describe how the gases and technologies used in semiconductor manufacturing using 200 mm and 300 mm wafers in the United States have changed in the past 3 years and whether any of the identified changes are likely to have affected the emissions characteristics of semiconductor manufacturing processes in such a way that the default utilization and by-product formation rates or default destruction or removal efficiency factors of this subpart may need to be updated.
(ii) It must describe the effect on emissions of the implementation of new process technologies and/or finer line width processes in 200 mm and 300 mm technologies, the introduction of new tool platforms, and the introduction of new processes on previously tested platforms.
(iii) It must describe the status of implementing 450 mm wafer technology and the potential need to create or update default emission factors compared to 300 mm technology.
(iv) It must provide any utilization and byproduct formation rates and/or destruction or removal efficiency data that have been collected in the previous 3 years that support the changes in semiconductor manufacturing processes described in the report. For any utilization or byproduct formation rate data submitted, the report must include the input gases used and measured, the utilization rates measured, the byproduct formation rates measured, the process type, the process subtype for chamber clean processes, the wafer size, and the methods used for the measurements. For any destruction or removal efficiency data submitted, the report must include the input gases used and measured, the destruction and removal efficiency measured, the process type, and the methods used for the measurements.
(v) It must describe the use of a new gas, use of an existing gas in a new process type or sub-type, or a fundamental change in process technology.
(3) If, on the basis of the information reported in paragraph (y)(2) of this section, the report indicates that GHG emissions from semiconductor manufacturing may have changed from those represented by the default utilization and by-product formation rates in Tables I-3 or I-4, or the default destruction or removal efficiency values in Table I-16 of this subpart, the report must lay out a data gathering and analysis plan focused on the areas of potential change. The plan must describe the elements in paragraphs (y)(3)(i) and (ii).
(i) The testing of tools to determine the potential effect on current utilization and by-product formation rates and destruction or removal efficiency values under the new conditions.
(ii) A planned analysis of the effect on overall facility emissions using a representative gas-use profile for a 200 mm, 300 mm, or 450 mm fab (depending on which technology is under consideration).
(4) Multiple semiconductor manufacturing facilities may submit a single consolidated 3-year report as long as the facility identifying information in § 98.3(c)(1) and the certification statement in § 98.3(c)(9) is provided for each facility for which the consolidated report is submitted.
(5) The Administrator will review the report received and determine whether it is necessary to update the default utilization rates and by-product formation rates in Tables I-3, I-4, I-11, and I-12 of this subpart and default destruction or removal efficiency values in Table I-16 of this subpart based on the following:
(i) Whether the revised default utilization and by-product formation rates and destruction or removal efficiency values will result in a projected shift in emissions of 10 percent or greater.
(ii) Whether new platforms, processes, or facilities that are not captured in current default utilization and by-product formation rates and destruction or removal efficiency values should be included in revised values.
(iii) Whether new data are available that could expand the existing data set to include new gases, tools, or processes not included in the existing data set (i.e. gases, tools, or processes for which no data are currently available).
(6) The Administrator will review the reports within 120 days and will notify you of a determination whether it is necessary to update any default utilization and by-product formation rates and/or destruction or removal efficiency values. If the Administrator determines it is necessary to update default utilization and by-product formation rates and/or destruction or removal efficiency values, you will then have 180 days from the date you receive notice of the determination to execute the data collection and analysis plan described in the report and submit those data to the Administrator.
§ 98.97 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the following records:
(a) All data used and copies of calculations made as part of estimating gas consumption and emissions, including all spreadsheets.
(b) [Reserved]
(c) Documentation for the fab-specific engineering model used to apportion fluorinated GHG and N
(1) A clear, detailed description of the fab-specific model, including how it was developed; the quantifiable metric used in the model; all sources of information, equations, and formulas, each with clear definitions of terms and variables; all apportioning factors used to apportion fluorinated GHG and N
(2) Sample calculations used for developing the gas apportioning factors (f
(3) If you develop apportioning factors through the use of direct measurement according to § 98.94(c)(3), calculations and data used to develop each gas apportioning factor.
(4) Calculations and data used to determine and document that the fab was operating at representative operating levels, as defined in § 98.98, during the apportioning model verification specified in § 98.94(c).
(d) For all abatement systems through which fluorinated GHGs or N
(1) Records of the information in paragraphs (d)(1)(i) though (iv) of this section:
(i) Documentation to certify that each abatement system or group of abatement systems is installed, maintained, and operated in accordance with the site maintenance plan for abatement systems that is specified in paragraph (d)(9) of this section.
(ii) Documentation from the abatement system supplier describing the abatement system’s designed purpose and emission control capabilities for fluorinated GHG and N
(iii) If you use default destruction or removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i), certification that the abatement systems for which emissions are being reported were specifically designed for fluorinated GHG and N
(iv) Certification that you have included and accounted for all abatement systems and any respective downtime in your emissions calculations under § 98.93(i)(3), as required under § 98.94(f)(3).
(2) Abatement system calibration and maintenance records.
(3) Where the default destruction or removal efficiency value is used, documentation from the abatement system supplier describing the equipment’s designed purpose and emission control capabilities for fluorinated GHG and N
(4) Where properly measured site-specific destruction or removal efficiencies are used to report emissions, the information in paragraphs (d)(4)(i) though (vi) of this section:
(i) Dated certification by the technician who made the measurement that the destruction or removal efficiency is calculated in accordance with methods in EPA 430-R-10-003 (incorporated by reference, see § 98.7) and, if applicable Appendix A of this subpart, or an alternative method approved by the Administrator as specified in § 98.94(k), complete documentation of the results of any initial and subsequent tests, the final report as specified in EPA 430-R-10-003 (incorporated by reference, see § 98.7) and, if applicable, the records and documentation specified in Appendix A of this subpart including the information required in paragraph (b)(7) of Appendix A of this subpart, or a final report as specified in an alternative method approved by the Administrator as specified in § 98.94(k).
(ii) The average destruction or removal efficiency of the abatement systems operating during the reporting year for each process type and gas combination.
(iii) A description of the calculation used to determine the average destruction or removal efficiency for each process type and gas combination, including all inputs to the calculation.
(iv) The records of destruction or removal efficiency measurements for abatement systems for all tests that have been used to determine the site-specific destruction or removal efficiencies currently being used.
(v) A description of the method used for randomly selecting abatement systems for testing.
(vi) The total number of systems for which destruction or removal efficiency was properly measured for each process type and gas combination for the reporting year.
(5) In addition to the inventory specified in § 98.96(p), the information in paragraphs (d)(5)(i) through (iii) of this section:
(i) The number of abatement systems of each manufacturer, and model numbers, and the manufacturer’s claimed fluorinated GHG and N
(ii) Records of destruction or removal efficiency measurements over the in-use life of each abatement system.
(iii) A description of the tool, with the process type or sub-type, for which the abatement system treats exhaust.
(6) Records of all inputs and results of calculations made accounting for the uptime of abatement systems used during the reporting year, in accordance with Equations I-15 or I-23 of this subpart, as applicable. The inputs should include an indication of whether each value for destruction or removal efficiency is a default value or a measured site-specific value.
(7) Records of all inputs and results of calculations made to determine the average weighted fraction of each gas destroyed or removed in the abatement systems for each stack system using Equations I-24A and I-24B of this subpart, if applicable. The inputs should include an indication of whether each value for destruction or removal efficiency is a default value or a measured site-specific value.
(8) Records of all inputs and the results of the calculation of the facility-wide emission destruction or removal efficiency factor calculated according to Equations I-26, I-27, and I-28 of this subpart.
(9) A site maintenance plan for abatement systems, which must be maintained on-site at the facility as part of the facility’s GHG Monitoring Plan as described in § 98.3(g)(5), and be developed and implemented according to paragraphs (d)(9)(i) through (iii) of this section.
(i) The site maintenance plan for abatement systems must be based on the abatement system manufacturer’s recommendations and specifications for installation, operation, and maintenance if you use default destruction and removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i). If the manufacturer’s recommendations and specifications for installation, operation, and maintenance are not available, you cannot use default destruction and removal efficiency values in your emissions calculations under § 98.93(a), (b), and/or (i). If you use an average of properly measured destruction or removal efficiencies determined in accordance with the procedures in § 98.94(f)(4)(i) through (vi), the site maintenance plan for abatement systems must be based on the abatement system manufacturer’s recommendations and specifications for installation, operation, and maintenance, where available. If you deviate from the manufacturer’s recommendations and specifications, you must include documentation that demonstrates how the deviations do not negatively affect the performance or destruction or removal efficiency of the abatement systems.
(ii) The site maintenance plan for abatement systems must include a defined preventative maintenance process and checklist.
(iii) The site maintenance plan for abatement systems must include a corrective action process that you must follow whenever an abatement system is found to be not operating properly.
(e) Purchase records for gas purchased.
(f) Invoices for gas purchases and sales.
(g) Documents and records used to monitor and calculate abatement system uptime.
(h) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. You must update your GHG Monitoring Plan to comply with § 98.94(c) consistent with the requirements in § 98.3(g)(5)(iii).
(i) Retain the following records for each fab for which you elect to calculate fab-level emissions of fluorinated GHG using the procedures specified in § 98.93(i)(3) or (4).
(1) Document all stack systems with emissions of fluorinated GHG that are less than 10,000 metric tons of CO
(2) For each stack system, identify the method used to calculate annual emissions; either § 98.93(i)(3) or (4).
(3) The identity and total annual consumption of each gas identified as an intermittent low use fluorinated GHG as specified in § 98.93(i)(4)(i) and defined in § 98.98.
(4) The emissions test data and reports (see § 98.94(j)(4)) and the calculations used to determine the fab-specific emission factor, including the actual fab-specific emission factor, the average hourly emission rate of each fluorinated GHG from the stack system during the test and the stack system activity rate during the test. The report must also contain any changes in the stack system configuration during or between tests in a reporting year.
(5) The fab-specific emission factor and the calculations and data used to determine the fab-specific emission factor for each fluorinated GHG and by-product, as calculated using Equations I-19 and I-20 of § 98.93(i)(3).
(6) Calculations and data used to determine annual emissions of each fluorinated GHG for each fab.
(7) Calculations and data used to determine and document that the fab was operating at representative operating levels, as defined in § 98.98, during the stack testing period.
(8) A copy of the certification that no significant changes in stack system flow configuration occurred between tests conducted for any particular fab in a reporting year, as required by § 98.94(j)(1)(iv) and any calculations and data supporting the certification.
(9) The number of tools vented to each stack system in the fab.
(j) If you report the approximate percentage of total GHG emissions from research and development activities under § 98.96(x), documentation for the determination of the percentage of total emissions of each fluorinated GHG and/or N
(k) Annual gas consumption for each fluorinated GHG and N
(l) All inputs used to calculate gas consumption in Equation I-11 of this subpart, for each fluorinated GHG and N
(m) Annual amount of each fluorinated GHG consumed for process sub-type, process type, stack system, or fab, as appropriate, and the annual amount of N
(n) Disbursements for each fluorinated GHG and N
(o) Fraction of each fluorinated GHG or N
(p) Fraction of each fluorinated GHG or N
(q) All inputs and results of calculations made accounting for the uptime of abatement systems used during the reporting year, or during an emissions sampling period, in accordance with Equations I-15 and/or I-23 of this subpart, as applicable.
(r) For fluorinated heat transfer fluid emissions, inputs to the fluorinated heat transfer fluid mass balance equation, Equation I-16 of this subpart, for each fluorinated heat transfer fluid used.
(s) Where missing data procedures were used to estimate inputs into the fluorinated heat transfer fluid mass balance equation under § 98.95(b), the estimates of those data.
§ 98.98 Definitions.
Except as provided in this section, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart takes precedence for the reporting requirements in this subpart.
Abatement system means a device or equipment that is designed to destroy or remove fluorinated GHGs or N
Actual gas consumption means the quantity of gas used during wafer/substrate processing over some period based on a measured change in gas container weight or gas container pressure or on a measured volume of gas.
By-product formation means the creation of fluorinated GHGs during electronics manufacturing production processes or the creation of fluorinated GHGs by an abatement system. Where the procedures in § 98.93(a) are used to calculate annual emissions, by-product formation is the ratio of the mass of the by-product formed to the mass flow of the input gas. Where the procedures in § 98.93(i) are used to calculate annual emissions, by-product formation is the ratio of the mass of the by-product formed to the total mass flow of all fluorinated GHG input gases.
Chamber cleaning is a process type that consists of the process sub-types defined in paragraphs (1) through (3) of this definition.
(1) In situ plasma process sub-type consists of the cleaning of thin-film production chambers, after processing substrates, with a fluorinated GHG cleaning reagent that is dissociated into its cleaning constituents by a plasma generated inside the chamber where the film is produced.
(2) Remote plasma process sub-type consists of the cleaning of thin-film production chambers, after processing substrates, with a fluorinated GHG cleaning reagent dissociated by a remotely located plasma source.
(3) In situ thermal process sub-type consists of the cleaning of thin-film production chambers, after processing substrates, with a fluorinated GHG cleaning reagent that is thermally dissociated into its cleaning constituents inside the chamber where thin films are produced.
Controlled emissions means the quantity of emissions that are released to the atmosphere after application of an emission control device (e.g., abatement system).
Destruction or removal efficiency (DRE) means the efficiency of an abatement system to destroy or remove fluorinated GHGs, N
Fab means the portion of an electronics manufacturing facility located in a separate physical structure that began manufacturing on a certain date.
Fluorinated heat transfer fluids means fluorinated GHGs used for temperature control, device testing, cleaning substrate surfaces and other parts, and soldering in certain types of electronics manufacturing production processes. Fluorinated heat transfer fluids do not include fluorinated GHGs used as lubricants or surfactants. For fluorinated heat transfer fluids under this subpart I, the lower vapor pressure limit of 1 mm Hg in absolute at 25 °C in the definition of Fluorinated greenhouse gas in § 98.6 shall not apply. Fluorinated heat transfer fluids used in the electronics manufacturing sector include, but are not limited to, perfluoropolyethers, perfluoroalkanes, perfluoroethers, tertiary perfluoroamines, and perfluorocyclic ethers.
Fully fluorinated GHGs means fluorinated GHGs that contain only single bonds and in which all available valence locations are filled by fluorine atoms. This includes, but is not limited to, saturated perfluorocarbons, SF
Gas utilization means the fraction of input N
Heel means the amount of gas that remains in a gas container after it is discharged or off-loaded; heel may vary by container type.
Input gas means a fluorinated GHG or N
Intermittent low-use fluorinated GHG, for the purposes of determining fluorinated GHG emissions using the stack testing method, means a fluorinated GHG that meets all of the following:
(1) The fluorinated GHG is used by the fab but is not used during the period of stack testing for the fab/stack system.
(2) The emissions of the fluorinated GHG, estimated using the methods in § 98.93(i)(4) do not constitute more than 5 percent of the total fluorinated GHG emissions from the fab on a CO
(3) The sum of the emissions of all fluorinated GHGs that are considered intermittent low use gases does not exceed 10,000 metric tons CO
(4) The fluorinated GHG is not an expected or possible by-product identified in Table I-17 of this subpart.
Maximum substrate starts means for the purposes of Equation I-5 of this subpart, the maximum quantity of substrates, expressed as surface area, that could be started each month during a reporting year based on the equipment installed in that facility and assuming that the installed equipment were fully utilized. Manufacturing equipment is considered installed when it is on the manufacturing floor and connected to required utilities.
Modeled gas consumed means the quantity of gas used during wafer/substrate processing over some period based on a verified facility-specific engineering model used to apportion gas consumption.
Nameplate capacity means the full and proper charge of chemical specified by the equipment manufacturer to achieve the equipment’s specified performance. The nameplate capacity is typically indicated on the equipment’s nameplate; it is not necessarily the actual charge, which may be influenced by leakage and other emissions.
Operational mode means the time in which an abatement system is properly installed, maintained, and operated according to the site maintenance plan for abatement systems as required in § 98.94(f)(1) and defined in § 98.97(d)(9). This includes being properly operated within the range of parameters as specified in the site maintenance plan for abatement systems.
Plasma etching is a process type that consists of any production process using fluorinated GHG reagents to selectively remove materials from a substrate during electronics manufacturing. The materials removed may include SiO
Process sub-type is a set of similar manufacturing steps, more closely related within a broad process type. For example, the chamber cleaning process type includes in-situ plasma chamber cleaning, remote plasma chamber cleaning, and in-situ thermal chamber cleaning sub-types.
Process types are broad groups of manufacturing steps used at a facility associated with substrate (e.g., wafer) processing during device manufacture for which fluorinated GHG emissions and fluorinated GHG consumption is calculated and reported. The process types are Plasma etching/Wafer Cleaning and Chamber cleaning.
Properly measured destruction or removal efficiency means destruction or removal efficiencies measured in accordance with EPA 430-R-10-003 (incorporated by reference, see § 98.7), and, if applicable, Appendix A to this subpart, or by an alternative method approved by the Administrator as specified in § 98.94(k).
The Random Sampling Abatement System Testing Program (RSASTP) means the required frequency for measuring the destruction or removal efficiencies of abatement systems in order to apply properly measured destruction or removal efficiencies to report controlled emissions.
Redundant abatement systems means a system that is specifically designed, installed and operated for the purpose of destroying fluorinated GHGs and N
Repeatable means that the variables used in the formulas for the facility’s engineering model for gas apportioning factors are based on observable and measurable quantities that govern gas consumption rather than engineering judgment about those quantities or gas consumption.
Representative operating levels means (for purposes of verification of the apportionment model or for determining the appropriate conditions for stack testing) operating the fab, in terms of substrate starts for the period of testing or monitoring, at no less than 50 percent of installed production capacity or no less than 70 percent of the average production rate for the reporting year, where production rate for the reporting year is represented in average monthly substrate starts. For the purposes of stack testing, the period for determining the representative operating level must be the period ending on the same date on which testing is concluded.
Stack system means one or more stacks that are connected by a common header or manifold, through which a fluorinated GHG-containing gas stream originating from one or more fab processes is, or has the potential to be, released to the atmosphere. For purposes of this subpart, stack systems do not include emergency vents or bypass stacks through which emissions are not usually vented under typical operating conditions.
Trigger point for change out means the residual weight or pressure of a gas container type that a facility uses as an indicator that operators need to change out that gas container with a full container. The trigger point is not the actual residual weight or pressure of the gas remaining in the cylinder that has been replaced.
Unabated emissions means a gas stream containing fluorinated GHG or N
Uptime means the ratio of the total time during which the abatement system is in an operational mode, to the total time during which production process tool(s) connected to that abatement system are normally in operation.
Wafer cleaning is a process type that consists of any production process using fluorinated GHG reagents to clean wafers at any step during production.
Wafer passes is a count of the number of times a wafer substrate is processed in a specific process sub-type, or type. The total number of wafer passes over a reporting year is the number of wafer passes per tool multiplied by the number of operational process tools in use during the reporting year.
Wafer starts means the number of fresh wafers that are introduced into the fabrication sequence each month. It includes test wafers, which means wafers that are exposed to all of the conditions of process characterization, including but not limited to actual etch conditions or actual film deposition conditions.
Table I-1 to Subpart I of Part 98 – Default Emission Factors for Threshold Applicability Determination
Product type | Emission factors EF | |||||
---|---|---|---|---|---|---|
CF | C | CHF | C | NF | SF | |
Semiconductors (kg/m 2) | 0.90 | 1.00 | 0.04 | 0.05 | 0.04 | 0.20 |
LCD (g/m 2) | 0.50 | NA | NA | NA | 0.90 | 4.00 |
MEMS (kg/m 2) | NA | NA | NA | NA | NA | 1.02 |
Table I-2 to Subpart I of Part 98 – Examples of Fluorinated GHGs Used by the Electronics Industry
Product type | Fluorinated GHGs and fluorinated heat transfer fluids used during manufacture |
---|---|
Electronics | CF |
Table I-3 to Subpart I of Part 98 – Default Emission Factors (1-Uij ) for Gas Utilization Rates (Uij ) and By-Product Formation Rates (Bijk ) for Semiconductor Manufacturing for 150 mm and 200 mm Wafer Sizes
Table I-3 to Subpart I of Part 98 – Default Emission Factors (1-U
Process type/sub-type | Process gas i | ||||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|---|
CF | C | CHF | CH | C | CH | C | C | NF | SF | C | C | C | |
1-U | 0.81 | 0.72 | 0.51 | 0.13 | 0.064 | 0.70 | NA | 0.14 | 0.19 | 0.55 | 0.17 | 0.072 | NA |
BCF | NA | 0.10 | 0.085 | 0.079 | 0.077 | NA | NA | 0.11 | 0.0040 | 0.13 | 0.13 | NA | NA |
BC | 0.046 | NA | 0.030 | 0.025 | 0.024 | 0.0034 | NA | 0.037 | 0.025 | 0.11 | 0.11 | 0.014 | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BC | 0.0012 | NA | 0.0012 | NA | NA | NA | NA | 0.0086 | NA | NA | NA | NA | NA |
BCHF | 0.10 | 0.047 | NA | 0.049 | NA | NA | NA | 0.040 | NA | 0.0012 | 0.066 | 0.0039 | NA |
In situ plasma cleaning: | |||||||||||||
1-U | 0.92 | 0.55 | NA | NA | NA | NA | 0.40 | 0.10 | 0.18 | NA | NA | NA | 0.14 |
BCF | NA | 0.21 | NA | NA | NA | NA | 0.20 | 0.11 | 0.050 | NA | NA | NA | 0.13 |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | 0.045 |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
Remote plasma cleaning: | |||||||||||||
1-U | NA | NA | NA | NA | NA | NA | NA | NA | 0.017 | NA | NA | NA | NA |
BCF | NA | NA | NA | NA | NA | NA | NA | NA | 0.015 | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
In situ thermal cleaning: | |||||||||||||
1-U | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BCF | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
Table I-4 to Subpart I of Part 98 –
Default Emission Factors (1-U
Table I-4 to Subpart I of Part 98 – Default Emission Factors (1-U
Process type/sub-type | Process gas i | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
CF | C | CHF | CH | CH | C | C | NF | SF | C | C | C | |
1-U | 0.65 | 0.80 | 0.42 | 0.21 | 0.33 | 0.30 | 0.18 | 0.15 | 0.32 | 0.15 | 0.10 | NA |
BCF | NA | 0.21 | 0.095 | 0.049 | 0.045 | 0.21 | 0.045 | 0.046 | 0.040 | 0.059 | 0.11 | NA |
BC | 0.079 | NA | 0.064 | 0.052 | 0.00087 | 0.18 | 0.031 | 0.045 | 0.044 | 0.074 | 0.083 | NA |
BC | NA | NA | 0.00010 | NA | NA | NA | 0.018 | NA | NA | NA | NA | NA |
BC | 0.00063 | NA | 0.00080 | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | 0.00012 | NA |
BCHF | 0.011 | NA | NA | 0.050 | 0.0057 | 0.012 | 0.027 | 0.025 | 0.0037 | 0.019 | 0.0069 | NA |
BCH | NA | NA | 0.0036 | NA | 0.0023 | NA | 0.0015 | 0.00086 | 0.000029 | 0.000030 | NA | NA |
BCH | 0.0080 | NA | 0.0080 | 0.0080 | NA | 0.00073 | NA | 0.0080 | NA | NA | NA | NA |
In situ plasma cleaning: | ||||||||||||
1-U | NA | NA | NA | NA | NA | NA | NA | 0.23 | NA | NA | NA | NA |
BCF | NA | NA | NA | NA | NA | NA | NA | 0.037 | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
Remote Plasma Cleaning: | ||||||||||||
1-U | NA | NA | NA | NA | NA | 0.063 | NA | 0.017 | NA | NA | NA | NA |
BCF | NA | NA | NA | NA | NA | NA | NA | 0.075 | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
In Situ Thermal Cleaning: | ||||||||||||
1-U | NA | NA | NA | NA | NA | NA | NA | 0.28 | NA | NA | NA | NA |
BCF | NA | NA | NA | NA | NA | NA | NA | 0.010 | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA |
Table I-5 to Subpart I of Part 98 – Default Emission Factors (1-Uij ) for Gas Utilization Rates (Uij ) and By-Product Formation Rates (Bijk ) for MEMS Manufacturing
Process type factors | Process gas i | |||||||||||
---|---|---|---|---|---|---|---|---|---|---|---|---|
CF | C | CHF | CH | C | c− C | NF Remote | NF | SF | C | C | C | |
Etch 1-U | 0.7 | 10.4 | 10.4 | 10.06 | NA | 10.2 | NA | 0.2 | 0.2 | 0.1 | 0.2 | NA |
Etch BCF | NA | 10.4 | 10.07 | 10.08 | NA | 0.2 | NA | NA | NA | 10.3 | 0.2 | NA |
Etch BC | NA | NA | NA | NA | NA | 0.2 | NA | NA | NA | 10.2 | 0.2 | NA |
CVD Chamber Cleaning 1-U | 0.9 | 0.6 | NA | NA | 0.4 | 0.1 | 0.02 | 0.2 | NA | NA | 0.1 | 0.1 |
CVD Chamber Cleaning BCF | NA | 0.1 | NA | NA | 0.1 | 0.1 | 20.02 | 20.1 | NA | NA | 0.1 | 0.1 |
CVD Chamber Cleaning BC | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | NA | 0.4 |
1 Estimate includes multi-gas etch processes.
2 Estimate reflects presence of low-k, carbide and multi-gas etch processes that may contain a C-containing fluorinated GHG additive.
Table I-6 to Subpart I of Part 98 – Default Emission Factors (1-Uij ) for Gas Utilization Rates (Uij ) and By-Product Formation Rates (Bijk ) for LCD Manufacturing
Process type factors | Process gas i | ||||||||
---|---|---|---|---|---|---|---|---|---|
CF | C | CHF | CH | C | c− C | NF Remote | NF | SF | |
Etch 1-U | 0.6 | NA | 0.2 | NA | NA | 0.1 | NA | NA | 0.3 |
Etch BCF | NA | NA | 0.07 | NA | NA | 0.009 | NA | NA | NA |
Etch BCHF | NA | NA | NA | NA | NA | 0.02 | NA | NA | NA |
Etch BC | NA | NA | 0.05 | NA | NA | NA | NA | NA | NA |
CVD Chamber Cleaning 1-U | NA | NA | NA | NA | NA | NA | 0.03 | 0.3 | 0.9 |
Table I-7 To Subpart I of Part 98 – Default Emission Factors (1-Uij ) for Gas Utilization Rates (Uij ) and By-Product Formation Rates (Bijk ) for PV Manufacturing
Process type factors | Process gas i | ||||||||
---|---|---|---|---|---|---|---|---|---|
CF | C | CHF | CH | C | c− C | NF Remote | NF | SF | |
Etch 1-U | 0.7 | 0.4 | 0.4 | NA | NA | 0.2 | NA | NA | 0.4 |
Etch BCF | NA | 0.2 | NA | NA | NA | 0.1 | NA | NA | NA |
Etch BC | NA | NA | NA | NA | NA | 0.1 | NA | NA | NA |
CVD Chamber Cleaning 1-U | NA | 0.6 | NA | NA | 0.1 | 0.1 | NA | 0.3 | 0.4 |
CVD Chamber Cleaning BCF | NA | 0.2 | NA | NA | 0.2 | 0.1 | NA | NA | NA |
Table I-8 to Subpart I of Part 98 – Default Emission Factors (1-UN2O,j ) for N2 O Utilization (UN2O,j )
Process type factors | N |
---|---|
CVD 1-U | 0.8 |
Other Manufacturing Process 1-U | 1.0 |
Table I-9 to Subpart I of Part 98 – Methods and Procedures for Conducting Emissions Test for Stack Systems
Table I-10 to Subpart I of Part 98 – Maximum Field Detection Limits Applicable to Fluorinated GHG Concentration Measurements for Stack Systems
Fluorinated GHG Analyte | Maximum field detection limit (ppbv) |
---|---|
CF | 20 |
C | 20 |
C | 20 |
C | 20 |
C | 20 |
c-C | 20 |
CH | 40 |
CH | 40 |
CHF | 20 |
NF | 20 |
SF | 4 |
Other fully fluorinated GHGs | 20 |
Other fluorinated GHGs | 40 |
ppbv – Parts per billion by volume.
Table I-11 to Subpart I of Part 98 – Default Emission Factors (1-Uij ) for Gas Utilization Rates (Uij ) and By-Product Formation Rates (Bijk ) for Semiconductor Manufacturing for Use With the Stack Test Method (150 mm and 200 mm Wafers)
Table I-12 to Subpart I of Part 98 – Default Emission Factors (1-Uij ) for Gas Utilization Rates (Uij ) and By-Product Formation Rates (Bijk ) for Semiconductor Manufacturing for Use With the Stack Test Method (300 mm and 450 mm Wafers)
Table I-13 to Subpart I of Part 98 – Default Emission Factors (1-Uij ) for Gas Utilization Rates (Uij ) and By-Product Formation Rates (Bijk ) for LCD Manufacturing for Use With the Stack Test Method
Table I-14 to Subpart I of Part 98 – Default Emission Factors (1-Uij ) for Gas Utilization Rates (Uij ) and By-Product Formation Rates (Bijk ) for PV Manufacturing for Use With the Stack Test Method
Table I-15 to Subpart I of Part 98 – Default Emission Factors (1-Uij ) for Gas Utilization Rates (Uij ) and By-Product Formation Rates (Bijk ) for MEMS Manufacturing for Use With the Stack Test Method
Table I-16 to Subpart I of Part 98 – Default Emission Destruction or Removal Efficiency (DRE) Factors for Electronics Manufacturing
Manufacturing type/process type/gas | Default DRE (percent) |
---|---|
MEMS, LCDs, and PV Manufacturing | 60 |
Semiconductor Manufacturing: | |
Plasma Etch/Wafer Clean Process Type: | |
CF | 75 |
CH | 97 |
CHF | 97 |
CH | 97 |
C | 97 |
C | 97 |
C | 97 |
C | 97 |
C | 97 |
SF | 97 |
NF | 96 |
All other carbon-based plasma etch/wafer clean fluorinated GHG | 60 |
Chamber Clean Process Type: | |
NF | 88 |
All other chamber clean fluorinated GHG | 60 |
N | |
CVD and all other N | 60 |
Table I-17 to Subpart I of Part 98 – Expected and Possible By-Products for Electronics Manufacturinglg
For each stack system for which you use the “stack test method” to calculate annual emissions, you must measure the following: | If emissions are detected intermittently, use the following procedures: | If emissions are not detected, use the following procedures: |
---|---|---|
Expected By-products: CF C CHF CH CH | Use the measured concentration for “X | Use one-half of the field detection limit you determined for the fluorinated GHG according to § 98.94(j)(2) for the value of “X |
Possible By-products: C C c-C C | Use the measured concentration for “X | Assume zero emissions for that fluorinated GHG for the tested stack system. |
Appendix A to Subpart I of Part 98 – Alternative Procedures for Measuring Point-of-Use Abatement Device Destruction or Removal Efficiency
If you are measuring destruction or removal efficiency of a point-of-use abatement device according to EPA 430-R-10-003 (incorporated by reference, see § 98.7) as specified in § 98.94(f)(4), you may follow the alternative procedures specified in paragraphs (a) through (c) of this appendix.
(a) In place of the Quadrupole Mass Spectrometry protocol requirements specified in section 2.2.4 of EPA 430-R-10-003 (incorporated by reference, see § 98.7), you must conduct mass spectrometry testing in accordance with the provisions in paragraph (a)(1) through (a)(15) of this appendix.
(1) Detection limits. The mass spectrometer chosen for this application must have the necessary sensitivity to detect the selected effluent species at or below the maximum field detection limits specified in Table 3 of section 2.2.7 of EPA 430-R-10-003 (incorporated by reference, see § 98.7).
(2) Sampling location. The sample at the inlet of the point-of-use abatement device must be taken downstream of the process tool and pump package. The sample exhaust must be vented back into the corrosive house ventilation system at a point downstream of the sample inlet location.
(3) Sampling conditions. For etch processes, destruction or removal efficiencies must be determined while etching a substrate (product, dummy, or test). For chemical vapor deposition processes, destruction or removal efficiencies must be determined during a chamber clean after deposition (destruction or removal efficiencies must not be determined in a clean chamber). All sampling must be performed non-intrusively during wafer processing. Samples must be drawn through the mass spectrometer source by an external sample pump. Because of the volatility, vapor pressure, stability and inertness of CF
(4) Mass spectrometer parameters. The specific mass spectrometer operating conditions such as electron energy, secondary electron multiplier voltage, emission current, and ion focusing voltage must be selected according to the specifications provided by the mass spectrometer manufacturer, the mass spectrometer system manual, basic mass spectrometer textbook, or other such sources. The mass spectrometer responses to each of the target analytes must all be calibrated under the same mass spectrometer operating conditions.
(5) Flow rates. A sample flow rate of 0.5-1.5 standard liters per minute (slm) must be drawn from the process tool exhaust stream under study.
(6) Sample frequency. The mass spectrometer sampling frequency for etch processes must be in the range of 0.5 to 1 cycles per second, and for chemical vapor deposition processes must be in the range of 0.25 to 0.5 cycles per second. As an alternative you may use the sampling frequencies specified in section 2.2.4 of EPA 430-R-10-003 (incorporated by reference, see § 98.7).
(7) Dynamic dilution calibration parameters. The quadrupole mass spectrometer must be calibrated for both mass location and response to analytes. A dynamic dilution calibration system may be used to perform both types of mass spectrometer system calibrations using two mass flow controllers. Use one mass flow controller to regulate the flow rate of the standard component used to calibrate the system and the second mass flow controller to regulate the amount of diluent gas used to mix with the standard to generate the calibration curve for each compound of interest. The mass flow controller must be calibrated using the single component gas being used with them, for example, nitrogen (N
(8) Mass location calibration. A mixture containing 1 percent He, Ar, Kr, and Xe in a balance gas of nitrogen must be used to assure the alignment of the quadrupole mass filter (see EPA Method 205 at 40 CFR part 51, appendix M as reference). The mass spectrometer must be chosen so that the mass range is sufficient to detect the predominant peaks of the components under study.
(9) Quadrupole mass spectrometer response calibration. A calibration curve must be generated for each compound of interest.
(10) Calibration frequency. The mass spectrometer must be calibrated at the start of testing a given process. The calibration must be checked at the end of testing.
(11) Calibration range. The mass spectrometer must be calibrated over the expected concentration range of analytes using a minimum of five concentrations including a zero. The zero point is defined as diluent containing no added analyte.
(12) Operating procedures. You must follow the operating procedures specified in paragraphs (a)(12)(i) through (v) of this appendix.
(i) You must perform a qualitative mass calibration by running a standard (or by flowing chamber gases under non-process conditions) containing stable components such as Ar, Kr, and Xe that provide predominant signals at m/e values distributed throughout the mass range to be used. You must adjust the quadrupole mass filter as needed to align with the inert gas fragments.
(ii) You must quantitatively calibrate the quadrupole mass spectrometer for each analyte of interest. The analyte concentrations during calibration must include the expected concentrations in the process effluent. The calibration must be performed under the same operating conditions, such as inlet pressure, as when sampling process exhaust. If the calibration inlet pressure differs from the sampling inlet pressure then the relationship between inlet pressure and quadrupole mass spectrometer signal response must be empirically determined and applied to correct for any differences between calibration and process emissions monitoring data.
(iii) To determine the response time of the instrument to changes in a process, a process gas such as C
(iv) You must sample the process effluent through the quadrupole mass spectrometer and acquire data for the required amount of time to track the process, as determined in paragraph (a)(12)(iii) of this appendix. You must set the sample frequency to monitor the changes in the process as specified in paragraph (a)(6) of this appendix. You must repeat this for at least five substrates on the same process and calculate the average and standard deviation of the analyte concentration.
(v) You must repeat the quantitative calibration at the conclusion of sampling to identify any drifts in quadrupole mass spectrometer sensitivity. If drift is observed, you must use an internal standard to correct for changes in sensitivity.
(13) Sample analysis. To determine the concentration of a specific component in the sample, you must divide the ion intensity of the sample response by the calibrated response factor for each component.
(14) Deconvolution of interfering peaks. The effects of interfering peaks must be deconvoluted from the mass spectra for each target analyte.
(15) Calculations. Plot ion intensity versus analyte concentration for a given compound obtained when calibrating the analytical system. Determine the slope and intercept for each calibrated species to obtain response factors with which to calculate concentrations in the sample. For an acceptable calibration, the R
(b) In place of the Fourier Transform Infrared Spectroscopy protocol requirements specified in section 2.2.4 of EPA 430-R-10-003 (incorporated by reference, see § 98.7), you may conduct Fourier Transform Infrared Spectroscopy testing in accordance with the provisions in paragraph (b)(1) through (17) of this appendix, including the laboratory study phase described in paragraphs (b)(1) through (7), and the field study phase described in paragraphs (b)(8) through (17) of this appendix.
(1) Conformance with provisions associated with the Calibration Transfer Standard. This procedure calls for the use of a calibration transfer standard in a number of instances. The use of a calibration transfer standard is necessary to validate optical pathlength and detector response for spectrometers where cell temperature, cell pressure, and cell optical pathlength are potentially variable. For fixed pathlength spectrometers capable of controlling cell temperature and pressure to within ±10 percent of a desired set point, the use of a calibration transfer standard, as described in paragraphs (b)(2) to (17) this appendix is not required.
(2) Defining spectroscopic conditions. Define a set of spectroscopic conditions under which the field studies and subsequent field applications are to be carried out. These include the minimum instrumental line-width, spectrometer wave number range, sample gas temperature, sample gas pressure, absorption pathlength, maximum sampling system volume (including the absorption cell), minimum sample flow rate, and maximum allowable time between consecutive infrared analyses of the effluent.
(3) Criteria for reference spectral libraries. On the basis of previous emissions test results and/or process knowledge (including the documentation of results of any initial and subsequent tests, and the final reports required in § 98.97(d)(4)(i)), estimate the maximum concentrations of all of the analytes in the effluent and their minimum concentrations of interest (those concentrations below which the measurement of the compounds is of no importance to the analysis). Values between the maximum expected concentration and the minimum concentration of interest are referred to below as the “expected concentration range.” A minimum of three reference spectra is sufficient for a small expected concentration range (e.g., a difference of 30 percent of the range between the low and high ends of the range), but a minimum of four spectra are needed where the range is greater, especially for concentration ranges that may differ by orders of magnitude. If the measurement method is not linear then multiple linear ranges may be necessary. If this approach is adopted, then linear range must be demonstrated to pass the required quality control. When the set of spectra is ordered according to absorbance, the absorbance levels of adjacent reference spectra should not differ by more than a factor of six. Reference spectra for each analyte should be available at absorbance levels that bracket the analyte’s expected concentration range; minimally, the spectrum whose absorbance exceeds each analyte’s expected maximum concentration or is within 30 percent of it must be available. The reference spectra must be collected at or near the same temperature and pressure at which the sample is to be analyzed under. The gas sample pressure and temperature must be continuously monitored during field testing and you must correct for differences in temperature and pressure between the sample and reference spectra. Differences between the sample and reference spectra conditions must not exceed 50 percent for pressure and 40 °C for temperature.
(4) Spectra without reference libraries. If reference spectral libraries meeting the criteria in paragraph (b)(3) of this appendix do not exist for all the analytes and interferants or cannot be accurately generated from existing libraries exhibiting lower minimum instrumental line-width values than those proposed for the testing, prepare the required spectra according to the procedures specified in paragraphs (b)(4)(i) and (ii) of this appendix.
(i) Reference spectra at the same absorbance level (to within 10 percent) of independently prepared samples must be recorded. The reference samples must be prepared from neat forms of the analyte or from gas standards of the highest quality commonly available from commercial sources. Either barometric or volumetric methods may be used to dilute the reference samples to the required concentrations, and the equipment used must be independently calibrated to ensure suitable accuracy. Dynamic and static reference sample preparation methods are acceptable, but dynamic preparations must be used for reactive analytes. Any well characterized absorption pathlength may be employed in recording reference spectra, but the temperature and pressure of the reference samples should match as closely as possible those of the proposed spectroscopic conditions.
(ii) If a mercury cadmium telluride or other potentially non-linear detector (i.e., a detector whose response vs. total infrared power is not a linear function over the range of responses employed) is used for recording the reference spectra, you must correct for the effects of this type of response on the resulting concentration values. As needed, spectra of a calibration transfer standard must be recorded with the laboratory spectrometer system to verify the absorption pathlength and other aspects of the system performance. All reference spectral data must be recorded in interferometric form and stored digitally.
(5) Sampling system preparation. Construct a sampling system suitable for delivering the proposed sample flow rate from the effluent source to the infrared absorption cell. For the compounds of interest, the surfaces of the system exposed to the effluent stream may need to be stainless steel or Teflon; because of the potential for generation of inorganic automated gases, glass surfaces within the sampling system and absorption cell may need to be Teflon-coated. The sampling system should be able to deliver a volume of sample that results in a necessary response time.
(6) Preliminary analytical routines. For the proposed absorption pathlength to be used in actual emissions testing, you must prepare an analysis method containing of all the effluent compounds at their expected maximum concentrations plus the field calibration transfer standard compound at 20 percent of its full concentration as needed.
(7) Documentation. The laboratory techniques used to generate reference spectra and to convert sample spectral information to compound concentrations must be documented. The required level of detail for the documentation is that which allows an independent analyst to reproduce the results from the documentation and the stored interferometric data.
(8) Spectroscopic system performance. The performance of the proposed spectroscopic system, sampling system, and analytical method must be rigorously examined during and after a field study. Several iterations of the analysis method may need to be applied depending on observed concentrations, absorbance intensities, and interferences. During the field study, all the sampling and analytical procedures envisioned for future field applications must be documented. Additional procedures not required during routine field applications, notably dynamic spiking studies of the analyte gases, may be performed during the field study. These additional procedures need to be performed only once if the results are acceptable and if the effluent sources in future field applications prove suitably similar to those chosen for the field study. If changes in the effluent sources in future applications are noted and require substantial changes to the analytical equipment and/or conditions, a separate field study must be performed for the new set of effluent source conditions. All data recorded during the study must be retained and documented, and all spectral information must be permanently stored in interferometric form.
(9) System installation. The spectroscopic and sampling sub-systems must be assembled and installed according to the manufacturers’ recommendations. For the field study, the length of the sample lines used must not be less than the maximum length envisioned for future field applications. The system must be given sufficient time to stabilize before testing begins.
(10) Pre-Test calibration. Record a suitable background spectrum using pure nitrogen gas; alternatively, if the analytes of interest are in a sample matrix consistent with ambient air, it is beneficial to use an ambient air background to control interferences from water and carbon dioxide. For variable pathlength Fourier Transform Infrared Spectrometers, introduce a sample of the calibration transfer standard gas directly into the absorption cell at the expected sample pressure and record its absorbance spectrum (the “initial field calibration transfer standard spectrum”). Compare it to the laboratory calibration transfer standard spectra to determine the effective absorption pathlength. If possible, record spectra of field calibration gas standards (single component standards of the analyte compounds) and determine their concentrations using the reference spectra and analytical routines developed in paragraphs (b)(2) through (7) of this appendix; these spectra may be used instead of the reference spectra in actual concentration and uncertainty calculations.
(11) Deriving the calibration transfer standard gas from tool chamber gases. The calibration transfer standard gas may be derived by flowing appropriate semiconductor tool chamber gases under non-process conditions (no thermal or plasma conditions and with no wafer(s) present) if compressed gas standards cannot be brought on-site.
(12) Reactivity and response time checks. While sampling ambient air and continuously recording absorbance spectra, suddenly replace the ambient air flow with calibration transfer standard gas introduced as close as possible to the probe tip. Examine the subsequent spectra to determine whether the flow rate and sample volume allow the system to respond quickly enough to changes in the sampled gas. Should a corrosive or reactive gas be of interest in the sample matrix it would be beneficial to determine the reactivity in a similar fashion, if practical. Examine the subsequent spectra to ensure that the reactivities of the analytes with the exposed surfaces of the sampling system do not limit the time response of the analytical system. If a pressure correction routine is not automated, monitor the absorption cell temperature and pressure; verify that the (absolute) pressure remains within 2 percent of the pressure specified in the proposed system conditions.
(13) Analyte spiking. Analyte spiking must be performed. While sampling actual source effluent, introduce a known flow rate of calibration transfer standard gas into the sample stream as close as possible to the probe tip or between the probe and extraction line. Measure and monitor the total sample flow rate, and adjust the spike flow rate until it represents 10 percent to 20 percent of the total flow rate. After waiting until at least four absorption cell volumes have been sampled, record four spectra of the spiked effluent, terminate the calibration transfer standard spike flow, pause until at least four cell volumes are sampled, and then record four (unspiked) spectra. Repeat this process until 12 spiked and 12 unspiked spectra have been obtained. If a pressure correction routine is not automated, monitor the absorption cell temperature and pressure; verify that the pressure remains within 2 percent of the pressure specified in the proposed system conditions. Calculate the expected calibration transfer standard compound concentrations in the spectra and compare them to the values observed in the spectrum. This procedure is best performed using a spectroscopic tracer to calculate dilution (as opposed to measured flow rates) of the injected calibration transfer standard (or analyte). The spectroscopic tracer should be a component not in the gas matrix that is easily detectable and maintains a linear absorbance over a large concentration range. Repeat this spiking process with all effluent compounds that are potentially reactive with either the sampling system components or with other effluent compounds. The gas spike is delivered by a mass flow controller, and the expected concentration of analyte of interest (AOITheoretical) is calculated as follows:
(14) Post-test calibration. At the end of a sampling run and at the end of the field study, record the spectrum of the calibration transfer standard gas. The resulting “final field calibration transfer standard spectrum” must be compared to the initial field calibration transfer standard spectrum to verify suitable stability of the spectroscopic system throughout the course of the field study.
(15) Amendment of analytical routines. The presence of unanticipated interferant compounds and/or the observation of compounds at concentrations outside their expected concentration ranges may necessitate the repetition of portions of the procedures in paragraphs (b)(2) through (14) of this appendix. Such amendments are allowable before final analysis of the data, but must be represented in the documentation required in paragraph (b)(16) of this appendix.
(16) Documentation. The sampling and spiking techniques used to generate the field study spectra and to convert sample spectral information to concentrations must be documented at a level of detail that allows an independent analyst to reproduce the results from the documentation and the stored interferometric data.
(17) Method application. When the required laboratory and field studies have been completed and if the results indicate a suitable degree of accuracy, the methods developed may be applied to practical field measurement tasks. During field applications, the procedures demonstrated in the field study specified in paragraphs (b)(8) through (16) of this appendix must be adhered to as closely as possible, with the following exceptions specified in paragraphs (b)(17)(i) through (iii) of this appendix:
(i) The sampling lines employed should be as short as practically possible and not longer than those used in the field study.
(ii) Analyte spiking and reactivity checks are required after the installation of or major repair to the sampling system or major change in sample matrix. In these cases, perform three spiked/unspiked samples with calibration transfer standard or a surrogate analyte on a daily basis if time permits and gas standards are easy to obtain and get on-site.
(iii) Sampling and other operational data must be recorded and documented as during the field study, but only the interferometric data needed to sufficiently reproduce actual test and spiking data must be stored permanently. The format of this data does not need to be interferograms but may be absorbance spectra or single beams.
(c) When using the flow and dilution measurement protocol specified in section 2.2.6 of EPA 430-R-10-003 (incorporated by reference, see § 98.7), you may determine point-of-use abatement device total volume flow with the modifications specified in paragraphs (c)(1) through (3) of this appendix.
(1) You may introduce the non-reactive, non-native gas used for determining total volume flow and dilution across the point-of-use abatement device at a location in the exhaust of the point-of-use abatement device. For abatement systems operating in a mode where specific F-GHG are not readily abated, you may introduce the non-reactive, non-native gas used for determining total volume flow and dilution across the point-of-use abatement device prior to the point-of-use abatement system; in this case, the tracer must be more difficult to destroy than the target compounds being measured based on the thermal stability of the tracer and target.
(2) You may select a location for downstream non-reactive, non-native gas analysis that complies with the requirements in this paragraph (c)(2) of this appendix. The sampling location should be traversed with the sampling probe measuring the non-reactive, non-native gas concentrations to ensure homogeneity of the non-reactive gas and point-of-use abatement device effluent (i.e., stratification test). To test for stratification, measure the non-reactive, non-native gas concentrations at three points on a line passing through the centroidal area. Space the three points at 16.7, 50.0, and 83.3 percent of the measurement line. Sample for a minimum of twice the system response time, determined according to paragraph (c)(3) of this appendix, at each traverse point. Calculate the individual point and mean non-reactive, non-native gas concentrations. If the non-reactive, non-native gas concentration at each traverse point differs from the mean concentration for all traverse points by no more than ±5.0 percent of the mean concentration, the gas stream is considered unstratified and you may collect samples from a single point that most closely matches the mean. If the 5.0 percent criterion is not met, but the concentration at each traverse point differs from the mean concentration for all traverse points by no more than ±10.0 percent of the mean, you may take samples from two points and use the average of the two measurements. Space the two points at 16.7, 50.0, or 83.3 percent of the measurement line. If the concentration at each traverse point differs from the mean concentration for all traverse points by more than ±10.0 percent of the mean but less than 20.0 percent, take samples from three points at 16.7, 50.0, and 83.3 percent of the measurement line and use the average of the three measurements. If the gas stream is found to be stratified because the 20.0 percent criterion for a 3-point test is not met, locate and sample the non-reactive, non-native gas from traverse points for the test in accordance with Sections 11.2 and 11.3 of EPA Method 1 in 40 CFR part 60, Appendix A-1. A minimum of 40 non-reactive gas concentration measurements will be collected at three to five different injected non-reactive gas flow rates for determination of point-of-use abatement device effluent flow. The total volume flow of the point-of-use abatement device exhaust will be calculated consistent with the EPA 430-R-10-003 (incorporated by reference, see § 98.7) Equations 1 through 7.
(3) You must determine the measurement system response time according to paragraphs (c)(3)(i) through (iii) of this appendix.
(i) Before sampling begins, introduce ambient air at the probe upstream of all sample condition components in system calibration mode. Record the time it takes for the measured concentration of a selected compound (for example, carbon dioxide) to reach steady state.
(ii) Introduce nitrogen in the system calibration mode and record the time required for the concentration of the selected compound to reach steady state.
(iii) Observe the time required to achieve 95 percent of a stable response for both nitrogen and ambient air. The longer interval is the measurement system response time.
Subpart J [Reserved]
Subpart K – Ferroalloy Production
§ 98.110 Definition of the source category.
The ferroalloy production source category consists of any facility that uses pyrometallurgical techniques to produce any of the following metals: ferrochromium, ferromanganese, ferromolybdenum, ferronickel, ferrosilicon, ferrotitanium, ferrotungsten, ferrovanadium, silicomanganese, or silicon metal.
§ 98.111 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a ferroalloy production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.112 GHGs to report.
You must report:
(a) Process CO
(b) CO
§ 98.113 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process CO
(b) Calculate and report under this subpart the annual process CO
(1) Calculate and report under this subpart the annual process CO
(2) Calculate and report under this subpart the annual process CO
(i) For each EAF, determine the annual mass of carbon in each carbon-containing input and output material for the EAF and estimate annual process CO
(ii) Determine the combined annual process CO
(c) If GHG emissions from an EAF are vented through the same stack as any combustion unit or process equipment that reports CO
(d) For the EAFs at your facility used for the production of any ferroalloy listed in Table K-1 of this subpart, you must calculate and report the annual CH
(1) For each EAF, determine the annual CH
(2) Determine the combined process CH
§ 98.114 Monitoring and QA/QC requirements.
If you determine annual process CO
(a) Determine the annual mass for each material used for the calculations of annual process CO
(b) For each material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed, used, or produced in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.
(1) Information provided by your material supplier.
(2) Collecting and analyzing at least three representative samples of the material inputs and outputs each year. The carbon content of the material must be analyzed at least annually using the standard methods (and their QA/QC procedures) specified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable.
(i) ASTM E1941-04, Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see § 98.7) for analysis of metal ore and alloy product.
(ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7), for analysis of carbonaceous reducing agents and carbon electrodes.
(iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7) for analysis of flux materials such as limestone or dolomite.
§ 98.115 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations in § 98.113 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.
(a) If you determine CO
(b) For missing records of the monthly mass of carbon-containing inputs and outputs, the substitute data value must be based on the best available estimate of the mass of the inputs and outputs from on all available process data or data used for accounting purposes, such as purchase records.
(c) If you are required to calculate CH
§ 98.116 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (e) of this section, as applicable:
(a) Annual facility ferroalloy product production capacity (tons).
(b) If a CEMS is used to measure CO
(c) Total number of EAFs at facility used for production of ferroalloy products.
(d) If a CEMS is used to measure CO
(1) Annual process CO
(2) Annual process CH
(3) Identification number of each EAF.
(e) If a CEMS is not used to measure CO
(1) Annual process CO
(2) Annual process CH
(3) Identification number for each material.
(4)-(5) [Reserved]
(6) List the method used for the determination of carbon content for each material included for the calculation of annual process CO
(7) If you use the missing data procedures in § 98.115(b), you must report how monthly mass of carbon-containing inputs and outputs with missing data was determined and the number of months the missing data procedures were used.
§ 98.117 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section for each EAF, as applicable.
(a) If a CEMS is used to measure CO
(1) Monthly EAF production quantity for each ferroalloy product (tons).
(2) Number of EAF operating hours each month.
(3) Number of EAF operating hours in a calendar year.
(b) If the carbon mass balance procedure is used to determine CO
(1) Monthly EAF production quantity for each ferroalloy product (tons).
(2) Number of EAF operating hours each month.
(3) Number of EAF operating hours in a calendar year.
(4) Monthly material quantity consumed, used, or produced for each material included for the calculations of annual process CO
(5) Average carbon content determined and records of the supplier provided information or analyses used for the determination for each material included for the calculations of annual process CO
(c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input and output to each EAF, including documentation of specific input or output materials excluded from Equation K-1 of this subpart that contribute less than 1 percent of the total carbon into or out of the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an EAF including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(d) If you are required to calculate CH
(e) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (e)(1) through (13) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (e)(1) through (13) of this section.
(1) Carbon content in reducing agent (percent by weight, expressed as a decimal fraction) (Equation K-1 of § 98.113).
(2) Annual mass of reducing agent fed, charged, or otherwise introduced into the EAF (tons) (Equation K-1).
(3) Carbon content of carbon electrode (percent by weight, expressed as a decimal fraction) (Equation K-1).
(4) Annual mass of carbon electrode consumed in the EAF (tons) (Equation K-1).
(5) Carbon content in ore (percent by weight, expressed as a decimal fraction) (Equation K-1).
(6) Annual mass of ore charged to the EAF (tons) (Equation K-1).
(7) Carbon content in flux material (percent by weight, expressed as a decimal fraction) (Equation K-1).
(8) Annual mass of flux material fed, charged, or otherwise introduced into the EAF to facilitate slag formation (tons) (Equation K-1).
(9) Carbon content in alloy product (percent by weight, expressed as a decimal fraction) (Equation K-1).
(10) Annual mass of alloy product produced/tapped in the EAF (tons) (Equation K-1).
(11) Carbon content in non-product outgoing material (percent by weight, expressed as a decimal fraction) (Equation K-1).
(12) Annual mass of non-product outgoing material removed from EAF (tons) (Equation K-1).
(13) CH
§ 98.118 Definitions.
All terms used of this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table K-1 to Subpart K of Part 98 – Electric Arc Furnace (EAF) CH4 Emission Factors
Alloy product produced in EAF | CH (kg CH | ||
---|---|---|---|
EAF Operation | |||
Batch-charging | Sprinkle-charging a | Sprinkle-charging and >750 °C b | |
Silicon metal | 1.5 | 1.2 | 0.7 |
Ferrosilicon 90% | 1.4 | 1.1 | 0.6 |
Ferrosilicon 75% | 1.3 | 1.0 | 0.5 |
Ferrosilicon 65% | 1.3 | 1.0 | 0.5 |
a Sprinkle-charging is charging intermittently every minute.
b Temperature measured in off-gas channel downstream of the furnace hood.
Subpart L – Fluorinated Gas Production
§ 98.120 Definition of the source category.
(a) The fluorinated gas production source category consists of processes that produce a fluorinated gas from any raw material or feedstock chemical, except for processes that generate HFC-23 during the production of HCFC-22.
(b) To produce a fluorinated gas means to manufacture a fluorinated gas from any raw material or feedstock chemical. Producing a fluorinated gas includes producing a fluorinated GHG as defined at § 98.410(b). Producing a fluorinated gas also includes the manufacture of a chlorofluorocarbon (CFC) or hydrochlorofluorocarbon (HCFC) from any raw material or feedstock chemical, including manufacture of a CFC or HCFC as an isolated intermediate for use in a process that will result in the transformation of the CFC or HCFC either at or outside of the production facility. Producing a fluorinated gas does not include the reuse or recycling of a fluorinated gas, the creation of HFC-23 during the production of HCFC-22, the creation of intermediates that are created and transformed in a single process with no storage of the intermediates, or the creation of fluorinated GHGs that are released or destroyed at the production facility before the production measurement in § 98.414(a).
§ 98.121 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a fluorinated gas production process that generates or emits fluorinated GHG and the facility meets the requirements of either § 98.2(a)(1) or (a)(2). To calculate GHG emissions for comparison to the 25,000 metric ton CO
§ 98.122 GHGs to report.
(a) You must report CO
(b) You must report under subpart O of this part (HCFC-22 Production and HFC-23 Destruction) the emissions of HFC-23 from HCFC-22 production processes and HFC-23 destruction processes. Do not report the generation and emissions of HFC-23 from HCFC-22 production under this subpart.
(c) Emissions from production and transformation processes, process level. You must report, for each fluorinated GHG group, the total GWP-weighted mass of all fluorinated GHGs in that group (in metric tons CO
(1) Each fluorinated gas production process.
(2) Each fluorinated gas transformation process that is not part of a fluorinated gas production process and where no fluorinated GHG reactant is produced at another facility.
(3) Each fluorinated gas transformation process that is not part of a fluorinated gas production process and where one or more fluorinated GHG reactants are produced at another facility.
(d) Emissions from production and transformation processes, facility level, multiple products. If your facility produces more than one fluorinated gas product, you must report the emissions (in metric tons) from production and transformation processes, totaled across the facility as a whole, of each fluorinated GHG that is emitted in quantities of 1,000 metric tons of CO
(e) Emissions from production and transformation processes, facility level, one product only. If your facility produces only one fluorinated gas product, aggregate and report the GWP-weighted emissions from production and transformation processes of fluorinated GHGs by fluorinated GHG group for the facility as a whole, in metric tons CO
(f) Emissions from destruction processes and venting of containers. You must report the total mass of each fluorinated GHG emitted (in metric tons) from:
(1) Each fluorinated gas destruction process that is not part of a fluorinated gas production process or a fluorinated gas transformation process and all such fluorinated gas destruction processes combined.
(2) Venting of residual fluorinated GHGs from containers returned from the field.
§ 98.123 Calculating GHG emissions.
For fluorinated gas production and transformation processes, you must calculate the fluorinated GHG emissions from each process using the emission factor or emission calculation factor method specified in paragraphs (c), (d), and (e) of this section, as appropriate. For destruction processes that destroy fluorinated GHGs that were previously “produced” as defined at § 98.410(b), you must calculate emissions using the procedures in paragraph (f) of this section. For venting of residual gas from containers (e.g., cylinder heels), you must calculate emissions using the procedures in paragraph (g) of this section.
(a) [Reserved]
(b) Mass balance method. The mass balance method was available for reporting years 2011, 2012, 2013, and 2014 only. See paragraph 1 of appendix A of this subpart for the former mass balance method.
(c) Emission factor and emission calculation factor methods. To use the method in this paragraph for batch processes, you must comply with either paragraph (c)(3) of this section (Emission Factor approach) or paragraph (c)(4) of this section (Emission Calculation Factor approach). To use the method in this paragraph for continuous processes, you must first make a preliminary estimate of the emissions from each individual continuous process vent under paragraph (c)(1) of this section. If your continuous process operates under different conditions as part of normal operations, you must also define the different operating scenarios and make a preliminary estimate of the emissions from the vent for each operating scenario. Then, compare the preliminary estimate for each continuous process vent (summed across operating scenarios) to the criteria in paragraph (c)(2) of this section to determine whether the process vent meets the criteria for using the emission factor method described in paragraph (c)(3) of this section or whether the process vent meets the criteria for using the emission calculation factor method described in paragraph (c)(4) of this section. For continuous process vents that meet the criteria for using the emission factor method described in paragraph (c)(3) of this section and that have more than one operating scenario, compare the preliminary estimate for each operating scenario to the criteria in (c)(3)(ii) to determine whether an emission factor must be developed for that operating scenario.
(1) Preliminary estimate of emissions by process vent. You must estimate the annual CO
(i) Engineering calculations. For process vent emission calculations, you may use any of paragraphs (c)(1)(i)(A), (c)(1)(i)(B), or (c)(1)(i)(C) of this section.
(A) U.S. Environmental Protection Agency, Emission Inventory Improvement Program, Volume II: Chapter 16, Methods for Estimating Air Emissions from Chemical Manufacturing Facilities, August 2007, Final (incorporated by reference, see § 98.7).
(B) You may determine the fluorinated GHG emissions from any process vent within the process using the procedures specified in § 63.1257(d)(2)(i) and (d)(3)(i)(B) of this chapter, except as specified in paragraphs (c)(1)(i)(B)(1) through (c)(1)(i)(B)(4) of this section. For the purposes of this subpart, use of the term “HAP” in § 63.1257(d)(2)(i) and (d)(3)(i)(B) of this chapter means “fluorinated GHG”.
(1) To calculate emissions caused by the heating of a vessel without a process condenser to a temperature lower than the boiling point, you must use the procedures in § 63.1257(d)(2)(i)(C)(3) of this chapter.
(2) To calculate emissions from depressurization of a vessel without a process condenser, you must use the procedures in § 63.1257(d)(2)(i)(D)(10) of this chapter.
(3) To calculate emissions from vacuum systems, the terms used in Equation 33 to § 63.1257(d)(2)(i)(E) of this chapter are defined as follows:
(i) P
(ii) P
(iii) P
(iv) MW
(4) To calculate emissions when a vessel is equipped with a process condenser or a control condenser, you must use the procedures in § 63.1257(d)(3)(i)(B) of this chapter, except as follows:
(i) You must determine the flowrate of gas (or volume of gas), partial pressures of condensables, temperature (T), and fluorinated GHG molecular weight (MW
(ii) You must assume that all of the components contained in the condenser exit vent stream are in equilibrium with the same components in the exit condensate stream (except for noncondensables).
(iii) You must perform a material balance for each component, if the condensate receiver composition is not known.
(iv) For the emissions from gas evolution, the term for time, t, must be used in Equation 12 to § 63.1257(d)(2)(i)(B) of this chapter.
(v) Emissions from empty vessel purging must be calculated using Equation 36 to § 63.1257(d)(2)(i)(H) of this chapter and the exit temperature and exit pressure conditions of the condenser or the conditions of the dedicated receiver.
(C) Commercial software products that follow chemical engineering principles (e.g., including the calculation methodologies in paragraphs (c)(1)(i)(A) and (c)(1)(i)(B) of this section).
(ii) Engineering assessments. For process vent emissions determinations, you may conduct an engineering assessment to calculate uncontrolled emissions. An engineering assessment includes, but is not limited to, the following:
(A) Previous test results, provided the tests are representative of current operating practices of the process.
(B) Bench-scale or pilot-scale test data representative of the process operating conditions.
(C) Maximum flow rate, fluorinated GHG emission rate, concentration, or other relevant parameters specified or implied within a permit limit applicable to the process vent.
(D) Design analysis based on chemical engineering principles, measureable process parameters, or physical or chemical laws or properties.
(iii) Impact of destruction for the preliminary estimate. If the process vent is vented to a destruction device, you may reflect the impact of the destruction device on emissions. In your emissions estimate, account for the following:
(A) The destruction efficiencies of the device that have been demonstrated for the fluorinated GHGs in the vent stream for periods when the process vent is vented to the destruction device.
(B) Any periods when the process vent is not vented to the destruction device.
(iv) Use of typical recent values. In the calculations in paragraphs (c)(1)(i), (c)(1)(ii), and (c)(1)(iii) of this section, the values used for the expected process activity and for the expected fraction of that activity whose emissions will be vented to the properly functioning destruction device must be based on either typical recent values for the process or values that would overestimate emissions from the process, unless there is a compelling reason to adopt a different value (e.g., installation of a destruction device for a previously uncontrolled process). If there is such a reason, it must be documented in the GHG Monitoring Plan.
(v) GWPs. To convert the fluorinated GHG emissions to CO
(vi) [Reserved]
(2) Method selection for continuous process vents.
(i) If the calculations under paragraph (c)(1) of this section, as well as any subsequent measurements and calculations under this subpart, indicate that the continuous process vent has fluorinated GHG emissions of less than 10,000 metric ton CO
(ii) If the continuous process vent does not meet the criteria in paragraph (c)(2)(i) of this section, then you must comply with the emission factor method specified in paragraph (c)(3) (Emission Factor approach) of this section.
(A) You must conduct emission testing for process-vent-specific emission factor development before the destruction device unless the calculations you performed under paragraph (c)(1)(iii) of this section indicate that the uncontrolled fluorinated GHG emissions that occur during periods when the process vent is not vented to the properly functioning destruction device are less than 10,000 metric tons CO
(B) Regardless of the level of uncontrolled emissions, the emission testing for process-vent-specific emission factor development may be conducted on the outlet side of a wet scrubber in place for acid gas reduction, if one is in place, as long as there is no appreciable reduction in the fluorinated GHG.
(3) Process-vent-specific emission factor method. For each process vent, conduct an emission test and measure fluorinated GHG emissions from the process and measure the process activity, such as the feed rate, production rate, or other process activity rate, during the test as described in this paragraph (c)(3). Conduct the emission test according to the procedures in § 98.124. All emissions test data and procedures used in developing emission factors must be documented according to § 98.127. If more than one operating scenario applies to the process that contains the subject process vent, you must comply with either paragraph (3)(i) or paragraph (3)(ii) of this section.
(i) Conduct a separate emissions test for operation under each operating scenario.
(ii) Conduct an emissions test for the operating scenario that is expected to have the largest emissions in terms of CO
(iii) You must measure the process activity, such as the process feed rate, process production rate, or other process activity rate, as applicable, during the emission test and calculate the rate for the test period, in kg (or another appropriate metric) per hour.
(iv) For continuous processes, you must calculate the hourly emission rate of each fluorinated GHG using Equation L-19 of this section and determine the hourly emission rate of each fluorinated GHG per process vent (and per operating scenario, as applicable) for the test run.
(v) You must calculate a site-specific, process-vent-specific emission factor for each fluorinated GHG for each process vent and each operating scenario, in kg of fluorinated GHG per process activity rate (e.g., kg of feed or production), as applicable, using Equation L-20 of this section. For continuous processes, divide the hourly fluorinated GHG emission rate during the test by the hourly process activity rate during the test runs.
(vi) If you conducted emissions testing after the destruction device, you must calculate the emissions of each fluorinated GHG for the process vent (and operating scenario, as applicable) using Equation L-21 of this section. You must also develop a process-vent-specific emission calculation factor based on paragraph (c)(4) of this section for the periods when the process vent is not venting to the destruction device.
(vii) If you conducted emissions testing before the destruction device, apply the destruction efficiencies of the device that have been demonstrated for the fluorinated GHGs in the vent stream to the fluorinated GHG emissions for the process vent (and operating scenario, as applicable), using Equation L-22 of this section. You may apply the destruction efficiency only to the portion of the process activity during which emissions are vented to the properly functioning destruction device (i.e., controlled).
(viii) Adjusted process-vent-specific emission factors for other operating scenarios. For process vents from processes with multiple operating scenarios, use Equation L-23 of this section to develop an adjusted process-vent-specific emission factor for each operating scenario from which the vent is estimated to emit less than 10,000 metric tons CO
(ix) Sum the emissions of each fluorinated GHG from all process vents in each operating scenario and all operating scenarios in the process for the year to estimate the total process vent emissions of each fluorinated GHG from the process, using Equation L-24 of this section.
(4) Process-vent-specific emission calculation factor method. For each process vent within an operating scenario, determine fluorinated GHG emissions by calculations and determine the process activity rate, such as the feed rate, production rate, or other process activity rate, associated with the emission rate.
(i) You must calculate uncontrolled emissions of fluorinated GHG by individual process vent, E
(ii) You must calculate a site-specific, process-vent-specific emission calculation factor for each process vent, each operating scenario, and each fluorinated GHG, in kg of fluorinated GHG per activity rate (e.g., kg of feed or production) as applicable, using Equation L-25 of this section.
(iii) You must calculate emissions of each fluorinated GHG for the process vent (and operating scenario, as applicable) for the year by multiplying the process-vent-specific emission calculation factor by the total process activity, as applicable, for the year, using Equation L-26 of this section.
(iv) If the process vent is vented to a destruction device, apply the demonstrated destruction efficiency of the device to the fluorinated GHG emissions for the process vent (and operating scenario, as applicable), using Equation L-27 of this section. Apply the destruction efficiency only to the portion of the process activity that is vented to the properly functioning destruction device (i.e., controlled).
(v) Sum the emissions of each fluorinated GHG from all process vents in each operating scenario and all operating scenarios in the process for the year to estimate the total process vent emissions of each fluorinated GHG from the process, using Equation L-28 of this section.
(d) Calculate fluorinated GHG emissions for equipment leaks (EL). If you comply with paragraph (c) of this section, you must calculate the fluorinated GHG emissions from pieces of equipment associated with processes covered under this subpart and in fluorinated GHG service. If you conduct monitoring of equipment in fluorinated GHG service, monitoring must be conducted for those in light liquid and in gas and vapor service. If you conduct monitoring of equipment in fluorinated GHG service, you may exclude from monitoring each piece of equipment that is difficult-to-monitor, that is unsafe-to-monitor, that is insulated, or that is in heavy liquid service; you may exclude from monitoring each pump with dual mechanical seals, agitator with dual mechanical seals, pump with no external shaft, agitator with no external shaft; you may exclude from monitoring each pressure relief device in gas and vapor service with upstream rupture disk, each sampling connection system with closed-loop or closed-purge systems, and any pieces of equipment where leaks are routed through a closed vent system to a destruction device. You must estimate emissions using another approach for those pieces of equipment excluded from monitoring. Equipment that is in fluorinated GHG service for less than 300 hr/yr; equipment that is in vacuum service; pressure relief devices that are in light liquid service; and instrumentation systems are exempted from these requirements.
(1) The emissions from equipment leaks must be calculated using any of the procedures in paragraphs (d)(1)(i), (d)(1)(ii), (d)(1)(iii), or (d)(1)(iv) of this section.
(i) Use of Average Emission Factor Approach in EPA Protocol for Equipment Leak Emission Estimates. The emissions from equipment leaks may be calculated using the default Average Emission Factor Approach in EPA-453/R-95-017 (incorporated by reference, see § 98.7).
(ii) Use of Other Approaches in EPA Protocol for Equipment Leak Emission Estimates in conjunction with EPA Method 21 at 40 CFR part 60, appendix A-7. The emissions from equipment leaks may be calculated using one of the following methods in EPA-453/R-95-017 (incorporated by reference, see § 98.7): The Screening Ranges Approach; the EPA Correlation Approach; or the Unit-Specific Correlation Approach. If you determine that EPA Method 21 at 40 CFR part 60, appendix A-7 is appropriate for monitoring a fluorinated GHG, and if you calibrate your instrument with a compound different from one or more of the fluorinated GHGs or surrogates to be measured, you must develop response factors for each fluorinated GHG or for each surrogate to be measured using EPA Method 21 at 40 CFR part 60, appendix A-7. For each fluorinated GHG or surrogate measured, the response factor must be less than 10. The response factor is the ratio of the known concentration of a fluorinated GHG or surrogate to the observed meter reading when measured using an instrument calibrated with the reference compound.
(iii) Use of Other Approaches in EPA Protocol for Equipment Leak Emission Estimates in conjunction with site-specific leak monitoring methods. The emissions from equipment leaks may be calculated using one of the following methods in EPA-453/R-95-017 (incorporated by reference, see § 98.7): The Screening Ranges Approach; the EPA Correlation Approach; or the Unit-Specific Correlation Approach. You may develop a site-specific leak monitoring method appropriate for monitoring fluorinated GHGs or surrogates to use along with these three approaches. The site-specific leak monitoring method must meet the requirements in § 98.124(f)(1).
(iv) Use of site-specific leak monitoring methods. The emissions from equipment leaks may be calculated using a site-specific leak monitoring method. The site-specific leak monitoring method must meet the requirements in § 98.124(f)(1).
(2) You must collect information on the number of each type of equipment; the service of each piece of equipment (gas, light liquid, heavy liquid); the concentration of each fluorinated GHG in the stream; and the time period each piece of equipment was in service. Depending on which approach you follow, you may be required to collect information for equipment on the associated screening data concentrations for greater than or equal to 10,000 ppmv and associated screening data concentrations for less than 10,000 ppmv; associated actual screening data concentrations; or associated screening data and leak rate data (i.e., bagging) used to develop a unit-specific correlation.
(3) Calculate and sum the emissions of each fluorinated GHG in metric tons per year for equipment pieces for each process, E
(e) Calculate total fluorinated GHG emissions for each process and for production or transformation processes at the facility. (1) Estimate annually the total mass of each fluorinated GHG emitted from each process, including emissions from process vents in paragraphs (c)(3) and (c)(4) of this section, as appropriate, and from equipment leaks in paragraph (d), using Equation L-29 of this section.
(2) Estimate annually the total mass of each fluorinated GHG emitted from each type of production or transformation process at the facility using Equation L-30 of this section. Develop separate totals for fluorinated gas production processes, transformation processes that transform fluorinated gases produced at the facility, and transformation processes that transform fluorinated gases produced at another facility.
(f) Calculate fluorinated GHG emissions from destruction of fluorinated GHGs that were previously “produced”. Estimate annually the total mass of fluorinated GHGs emitted from destruction of fluorinated GHGs that were previously “produced” as defined at § 98.410(b) using Equation L-31 of this section:
(g) Emissions from venting of residual fluorinated GHGs in containers. If you vent residual fluorinated GHGs from containers, you must either measure the residual fluorinated GHGs vented from each container or develop a heel factor for each combination of fluorinated GHG, container size, and container type that you vent. You do not need to estimate de minimis emissions associated with good-faith attempts to recycle or recover residual fluorinated GHGs in or from containers.
(1) Measuring contents of each container. If you weigh or otherwise measure the contents of each container before venting the residual fluorinated GHGs, use Equation L-32 of this section to calculate annual emissions of each fluorinated GHG from venting of residual fluorinated GHG from containers. Convert pressures to masses as directed in paragraph (g)(2)(ii) of this section.
(2) Developing and applying heel factors. If you use heel factors to estimate emissions of residual fluorinated GHGs vented from containers, you must annually develop these factors based on representative samples of the containers received by your facility from fluorinated GHG users.
(i) Sample size. For each combination of fluorinated GHG, container size, and container type that you vent, select a representative sample of containers that reflects the full range of quantities of residual gas returned in that container size and type. This sample must reflect the full range of the industries and a broad range of the customers that use and return the fluorinated GHG, container size, and container type. The minimum sample size for each combination of fluorinated GHG, container size, and container type must be 30, unless this is greater than the number of containers returned within that combination annually, in which case the contents of every container returned must be measured.
(ii) Measurement of residual gas. The residual weight or pressure you use for paragraph (g)(1) of this section must be determined by monitoring the mass or the pressure of your cylinders/containers according to § 98.124(k). If you monitor the pressure, convert the pressure to mass using a form of the ideal gas law, as displayed in Equation L-33 of this section, with an appropriately selected Z value.
(iii) Heel factor calculation. To determine the heel factor h
(iv) Calculate annual emissions of each fluorinated GHG from venting of residual fluorinated GHG from containers using Equation L-34 of this section.
(h) Effective destruction efficiency for each process. If you used the emission factor or emission calculation factor method to calculate emissions from the process, use Equation L-35 to calculate the effective destruction efficiency for the process, including each process vent:
§ 98.124 Monitoring and QA/QC requirements.
(a) Initial scoping speciation to identify fluorinated GHGs. You must conduct an initial scoping speciation to identify all fluorinated GHGs that may be generated from processes that are subject to this subpart and that have at least one process vent with uncontrolled emissions of 1.0 metric ton or more of fluorinated GHGs per year based on the preliminary estimate of emissions in § 98.123(c)(1). You are not required to quantify emissions under this initial scoping speciation. Only fluorinated GHG products and by-products that occur in greater than trace concentrations in at least one stream must be identified under this paragraph.
(1) Procedure. To conduct the scoping speciation, select the stream(s) (including process streams or destroyed streams) or process vent(s) that would be expected to individually or collectively contain all of the fluorinated GHG by-products of the process at their maximum concentrations and sample and analyze the contents of these selected streams or process vents. For example, if fluorinated GHG by-products are separated into one low-boiling-point and one high-boiling-point stream, sample and analyze both of these streams. Alternatively, you may sample and analyze streams where fluorinated GHG by-products occur at less than their maximum concentrations, but you must ensure that the sensitivity of the analysis is sufficient to compensate for the expected difference in concentration. For example, if you sample and analyze streams where fluorinated GHG by-products are expected to occur at one half their maximum concentrations elsewhere in the process, you must ensure that the sensitivity of the analysis is sufficient to detect fluorinated GHG by-products that occur at concentrations of 0.05 percent or higher. You do not have to sample and analyze every stream or process vent, i.e., you do not have to sample and analyze a stream or process vent that contains only fluorinated GHGs that are contained in other streams or process vents that are being sampled and analyzed. Sampling and analysis must be conducted according to the procedures in paragraph (e) of this section.
(2) Previous measurements. If you have conducted testing of streams (including process streams or destroyed streams) or process vents less than 10 years before December 31, 2010, and the testing meets the requirements in paragraph (a)(1) of this section, you may use the previous testing to satisfy this requirement.
(b) Mass balance monitoring. Mass balance monitoring was available for reporting years 2011, 2012, 2013, and 2014 only. See paragraph 2 of Appendix A of this subpart for the former mass balance method.
(c) Emission factor testing. If you determine fluorinated GHG emissions using the site-specific process-vent-specific emission factor, you must meet the requirements in paragraphs (c)(1) through (c)(8) of this section.
(1) Process vent testing. Conduct an emissions test that is based on representative performance of the process or operating scenario(s) of the process, as applicable. For process vents for which you performed an initial scoping speciation, include in the emission test any fluorinated GHG that was identified in the initial scoping speciation. For process vents for which you did not perform an initial scoping speciation, include in the emission test any fluorinated greenhouse gas that occurs in more than trace concentrations in the vent stream or, where a destruction device is used, in the inlet to the destruction device. You may include startup and shutdown events if the testing is sufficiently long or comprehensive to ensure that such events are not overrepresented in the emission factor. Malfunction events must not be included in the testing. If you do not detect a fluorinated GHG that was identified in the scoping speciation or that occurs in more than trace concentrations in the vent stream or in the inlet to the destruction device, assume that fluorinated GHG was emitted at one half of the detection limit.
(2) Number of runs. For continuous processes, sample the process vent for a minimum of three runs of 1 hour each. If the relative standard deviation (RSD) of the emission factor calculated based on the first three runs is greater than or equal to 0.15 for the emission factor, continue to sample the process vent for an additional three runs of 1 hour each. If more than one fluorinated GHG is measured, the RSD must be expressed in terms of total CO
(3) Process activity measurements. Determine the mass rate of process feed, process production, or other process activity as applicable during the test using flow meters, weigh scales, or other measurement devices or instruments with an accuracy and precision of ±1 percent of full scale or better. These devices may be the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, combination of volume measurements and bulk density, etc.) if these devices or procedures meet the requirement. For monitoring ongoing process activity, use flow meters, weigh scales, or other measurement devices or instruments with an accuracy and precision of ±1 percent of full scale or better.
(4) Sample each process. If process vents from separate processes are manifolded together to a common vent or to a common destruction device, you must follow paragraph (c)(4)(i), (c)(4)(ii), or (c)(4)(iii) of this section.
(i) You may sample emissions from each process in the ducts before the emissions are combined.
(ii) You may sample in the common duct or at the outlet of the destruction device when only one process is operating.
(iii) You may sample the combined emissions and use engineering calculations and assessments as specified in § 98.123(c)(4) to allocate the emissions to each manifolded process vent, provided the sum of the calculated fluorinated GHG emissions across the individual process vents is within 20 percent of the total fluorinated GHG emissions measured during the manifolded testing.
(5) Emission test results. The results of an emission test must include the analysis of samples, number of test runs, the results of the RSD analysis, the analytical method used, determination of emissions, the process activity, and raw data and must identify the process, the operating scenario, the process vents tested, and the fluorinated GHGs that were included in the test. The emissions test report must contain all information and data used to derive the process-vent-specific emission factor, as well as key process conditions during the test. Key process conditions include those that are normally monitored for process control purposes and may include but are not limited to yields, pressures, temperatures, etc. (e.g., of reactor vessels, distillation columns).
(6) Emissions testing frequency. You must conduct emissions testing to develop the process-vent-specific emission factor under paragraph (c)(7)(i) or (c)(7)(ii) of this section, whichever occurs first:
(i) 10-year revision. Conduct an emissions test every 10 years. In the calculations under § 98.123, apply the revised process-vent-specific emission factor to the process activity that occurs after the revision.
(ii) Operating scenario change that affects the emission factor. For planned operating scenario changes, you must estimate and compare the emission calculation factors for the changed operating scenario and for the original operating scenario whose process vent specific emission factor was measured. Use the calculation methods in § 98.123(c)(4). If the emission calculation factor for the changed operating scenario is 15 percent or more different from the emission calculation factor for the previous operating scenario (this includes the cumulative change in the emission calculation factor since the last emissions test), you must conduct an emissions test to update the process-vent-specific emission factor, unless the difference between the operating scenarios is solely due to the application of a destruction device to emissions under the changed operating scenario. Conduct the test before February 28 of the year that immediately follows the change. In the calculations under § 98.123, apply the revised process-vent-specific emission factor to the process activity that occurs after the operating scenario change.
(7) Subsequent measurements. If a continuous process vent with fluorinated GHG emissions less than 10,000 metric tons CO
(8) Previous measurements. If you have conducted an emissions test less than 10 years before December 31, 2010, and the emissions testing meets the requirements in paragraphs (c)(1) through (c)(8) of this section, you may use the previous emissions testing to develop process-vent-specific emission factors. For purposes of paragraph (c)(7)(i) of this section, the date of the previous emissions test rather than December 31, 2010 shall constitute the beginning of the 10-year re-measurement cycle.
(d) Emission calculation factor monitoring. If you determine fluorinated GHG emissions using the site-specific process-vent-specific emission calculation factor, you must meet the requirements in paragraphs (d)(1) through (d)(4) of this section.
(1) Operating scenario. Perform the emissions calculation for the process vent based on representative performance of the operating scenario of the process. If more than one operating scenario applies to the process that contains the subject process vent, you must conduct a separate emissions calculation for operation under each operating scenario. For each continuous process vent that contains more than trace concentrations of any fluorinated GHG and for each batch process vent that contains more than trace concentrations of any fluorinated GHG, develop the process-vent-specific emission calculation factor for each operating scenario. For continuous process vents, determine the emissions based on the process activity for the representative performance of the operating scenario. For batch process vents, determine emissions based on the process activity for each typical batch operating scenario.
(2) Process activity measurements. Use flow meters, weigh scales, or other measurement devices or instruments with an accuracy and precision of ±1 percent of full scale or better for monitoring ongoing process activity.
(3) Emission calculation results. The emission calculation must be documented by identifying the process, the operating scenario, and the process vents. The documentation must contain the information and data used to calculate the process-vent-specific emission calculation factor.
(4) Operating scenario change that affects the emission calculation factor. For planned operating scenario changes that are expected to change the process-vent-specific emission calculation factor, you must conduct an emissions calculation to update the process-vent-specific emission calculation factor. In the calculations under § 98.123, apply the revised emission calculation factor to the process activity that occurs after the operating scenario change.
(5) Previous calculations. If you have performed an emissions calculation for the process vent and operating scenario less than 10 years before December 31, 2010, and the emissions calculation meets the requirements in paragraphs (d)(1) through (d)(4) of this section and in § 98.123(c)(4)(i) and (c)(4)(ii), you may use the previous calculation to develop the site-specific process-vent-specific emission calculation factor.
(e) Emission and stream testing, including analytical methods. Select and document testing and analytical methods as follows:
(1) Sampling and mass measurement for emission testing. For emission testing in process vents or at the stack, use methods for sampling, measuring volumetric flow rates, non-fluorinated-GHG gas analysis, and measuring stack gas moisture that have been validated using a scientifically sound validation protocol.
(i) Sample and velocity traverses. Acceptable methods include but are not limited to EPA Method 1 or 1A in Appendix A-1 of 40 CFR part 60.
(ii) Velocity and volumetric flow rates. Acceptable methods include but are not limited to EPA Method 2, 2A, 2B, 2C, 2D, 2F, or 2G in Appendix A-1 of 40 CFR part 60. Alternatives that may be used for determining flow rates include OTM-24 (incorporated by reference, see § 98.7) and ALT-012 (incorporated by reference, see § 98.7).
(iii) Non-fluorinated-GHG gas analysis. Acceptable methods include but are not limited to EPA Method 3, 3A, or 3B in Appendix A-1 of 40 CFR part 60.
(iv) Stack gas moisture. Acceptable methods include but are not limited to EPA Method 4 in Appendix A-1 of 40 CFR part 60.
(2) Analytical methods. Use a quality-assured analytical measurement technology capable of detecting the analyte of interest at the concentration of interest and use a sampling and analytical procedure validated with the analyte of interest at the concentration of interest. Where calibration standards for the analyte are not available, a chemically similar surrogate may be used. Acceptable analytical measurement technologies include but are not limited to gas chromatography (GC) with an appropriate detector, infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic resonance (NMR). Acceptable methods for determining fluorinated GHGs include EPA Method 18 in appendix A-1 of 40 CFR part 60, EPA Method 320 in appendix A of 40 CFR part 63, EPA 430-R-10-003 (incorporated by reference, see § 98.7), ASTM D6348-03 (incorporated by reference, see § 98.7), or other analytical methods validated using EPA Method 301 at 40 CFR part 63, appendix A or some other scientifically sound validation protocol. Acceptable methods for determining total fluorine concentrations for fluorine-containing compounds in streams under paragraph (b)(3) of this section include ASTM D7359-08 (incorporated by reference, see § 98.7), or other analytical methods validated using EPA Method 301 at 40 CFR part 63, appendix A or some other scientifically sound validation protocol. The validation protocol may include analytical technology manufacturer specifications or recommendations.
(3) Documentation in GHG Monitoring Plan. Describe the sampling, measurement, and analytical method(s) used under paragraphs (e)(1) and (e)(2) of this section in the GHG Monitoring Plan as required under § 98.3(g)(5). Identify the methods used to obtain the samples and measurements listed under paragraphs (e)(1)(i) through (e)(1)(iv) of this section. At a minimum, include in the description of the analytical method a description of the analytical measurement equipment and procedures, quantitative estimates of the method’s accuracy and precision for the analytes of interest at the concentrations of interest, as well as a description of how these accuracies and precisions were estimated, including the validation protocol used.
(f) Emission monitoring for pieces of equipment. If you conduct a site-specific leak detection method or monitoring approach for pieces of equipment, follow paragraph (f)(1) or (f)(2) of this section and follow paragraph (f)(3) of this section.
(1) Site-specific leak monitoring approach. You may develop a site-specific leak monitoring approach. You must validate the leak monitoring method and describe the method and the validation in the GHG Monitoring Plan. To validate the site-specific method, you may, for example, release a known rate of the fluorinated GHGs or surrogates of interest, or you may compare the results of the site-specific method to those of a method that has been validated for the fluorinated GHGs or surrogates of interest. In the description of the leak detection method and its validation, include a detailed description of the method, including the procedures and equipment used and any sampling strategies. Also include the rationale behind the method, including why the method is expected to result in an unbiased estimate of emissions from equipment leaks. If the method is based on methods that are used to detect or quantify leaks or other emissions in other regulations, standards, or guidelines, identify and describe the regulations, standards, or guidelines and why their methods are applicable to emissions of fluorinated GHGs or surrogates from leaks. Account for possible sources of error in the method, e.g., instrument detection limits, measurement biases, and sampling biases. Describe validation efforts, including but not limited to any comparisons against standard leaks or concentrations, any comparisons against other methods, and their results. If you use the Screening Ranges Approach, the EPA Correlation Approach, or the Unit-Specific Correlation Approach with a monitoring instrument that does not meet all of the specifications in EPA Method 21 at 40 CFR part 60, appendix A-7, then explain how and why the monitoring instrument, as used at your facility, would nevertheless be expected to accurately detect and quantify emissions of fluorinated GHGs or surrogates from process equipment, and describe how you verified its accuracy. For all methods, provide a quantitative estimate of the accuracy and precision of the method.
(2) EPA Method 21 monitoring. If you determine that EPA Method 21 at 40 CFR part 60, appendix A-7 is appropriate for monitoring a fluorinated GHG, conduct the screening value concentration measurements using EPA Method 21 at 40 CFR part 60, appendix A-7 to determine the screening range data or the actual screening value data for the Screening Ranges Approach, EPA Correlation Approach, or the Unit-Specific Correlation Approach. For the one-time testing to develop the Unit-Specific Correlation equations in EPA-453/R-95-017 (incorporated by reference, see § 98.7), conduct the screening value concentration measurements using EPA Method 21 at 40 CFR part 60, appendix A-7 and the bagging procedures to measure mass emissions. Concentration measurements of bagged samples must be conducted using gas chromatography following EPA Method 18 analytical procedures or other method according to § 98.124(e). Use methane or other appropriate compound as the calibration gas.
(3) Frequency of measurement and sampling. If you estimate emissions based on monitoring of equipment, conduct monitoring at least annually. Sample at least one-third of equipment annually (except for equipment that is unsafe-to-monitor, difficult-to-monitor, insulated, or in heavy liquid service, pumps with dual mechanical seals, agitators with dual mechanical seals, pumps with no external shaft, agitators with no external shaft, pressure relief devices in gas and vapor service with an upstream rupture disk, sampling connection systems with closed-loop or closed purge systems, and pieces of equipment whose leaks are routed through a closed vent system to a destruction device), changing the sample each year such that at the end of three years, all equipment in the process has been monitored. If you estimate emissions based on a sample of the equipment in the process, ensure that the sample is representative of the equipment in the process. If you have multiple processes that have similar types of equipment in similar service, and that produce or transform similar fluorinated GHGs (in terms of chemical composition, molecular weight, and vapor pressure) at similar pressures and concentrations, then you may annually sample all of the equipment in one third of these processes rather than one third of the equipment in each process.
(g) Destruction device performance testing. If you vent or otherwise feed fluorinated GHGs into a destruction device and apply the destruction efficiency of the device to one or more fluorinated GHGs in § 98.123, you must conduct emissions testing to determine the destruction efficiency for each fluorinated GHG to which you apply the destruction efficiency. You must either determine the destruction efficiency for the most-difficult-to-destroy fluorinated GHG fed into the device (or a surrogate that is still more difficult to destroy) and apply that destruction efficiency to all the fluorinated GHGs fed into the device or alternatively determine different destruction efficiencies for different groups of fluorinated GHGs using the most-difficult-to-destroy fluorinated GHG of each group (or a surrogate that is still more difficult to destroy).
(1) Destruction efficiency testing. You must sample the inlet and outlet of the destruction device for a minimum of three runs of 1 hour each to determine the destruction efficiency. You must conduct the emissions testing using the methods in paragraph (e) of this section. To determine the destruction efficiency, emission testing must be conducted when operating at high loads reasonably expected to occur (i.e., representative of high total fluorinated GHG load that will be sent to the device) and when destroying the most-difficult-to-destroy fluorinated GHG (or a surrogate that is still more difficult to destroy) that is fed into the device from the processes subject to this subpart or that belongs to the group of fluorinated GHGs for which you wish to establish a DE. If the outlet concentration of a fluorinated GHG that is fed into the device is below the detection limit of the method, you may use a concentration of one-half the detection limit to estimate the destruction efficiency.
(i) If perfluoromethane (CF
(ii) If sulfur hexafluoride (SF
(iii) If saturated perfluorocarbons other than CF
(iv) For all other fluorinated GHGs that are vented to the destruction device in any stream in more than trace concentrations, you must test and determine the destruction efficiency achieved for the most-difficult-to-destroy fluorinated GHG or surrogate vented to the destruction device. Examples of acceptable surrogates include the Class 1 compounds (ranked 1 through 34) in Appendix D, Table D-1 of “Guidance on Setting Permit Conditions and Reporting Trial Burn Results; Volume II of the Hazardous Waste Incineration Guidance Series,” January 1989, EPA Publication EPA 625/6-89/019. You can obtain a copy of this publication by contacting the Environmental Protection Agency, 1200 Pennsylvania Avenue, NW., Washington, DC 20460, (202) 272-0167, http://www.epa.gov.
(2) Destruction efficiency testing frequency. You must conduct emissions testing to determine the destruction efficiency as provided in paragraphs (g)(2)(i) or (ii) of this section, whichever occurs first:
(i) Conduct an emissions test every 10 years. In the calculations under § 98.123, apply the updated destruction efficiency to the destruction that occurs after the test.
(ii) Destruction device changes that affect the destruction efficiency. If you make a change to the destruction device that would be expected to affect the destruction efficiency, you must conduct an emissions test to update the destruction efficiency. Conduct the test before the February 28 of the year that immediately follows the change. In the calculations under § 98.123, apply the updated destruction efficiency to the destruction that occurs after the change to the device.
(3) Previous testing .If you have conducted an emissions test within the 10 years prior to December 31, 2010, and the emissions testing meets the requirements in paragraph (g)(1) of this section, you may use the destruction efficiency determined during this previous emissions testing. For purposes of paragraph (g)(2)(i) of this section, the date of the previous emissions test rather than December 31, 2010 shall constitute the beginning of the 10-year re-measurement cycle.
(4) Hazardous Waste Combustor testing. If a destruction device used to destroy fluorinated GHG is subject to subpart EEE of part 63 of this chapter or any portion of parts 260-270 of this chapter, you may apply the destruction efficiency specifically determined for CF
(h) Mass of previously produced fluorinated GHGs fed into destruction device. You must measure the mass of each fluorinated GHG that is fed into the destruction device in more than trace concentrations and that was previously produced as defined at § 98.410(b). Such fluorinated GHGs include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed. You must use flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of ±1 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG being destroyed, you must measure the concentration of the fluorinated GHG being destroyed. You must multiply this concentration (mass fraction) by the mass measurement to obtain the mass of the fluorinated GHG fed into the destruction device.
(i) Emissions due to malfunctions of destruction device. In their estimates of the mass of fluorinated GHG destroyed, fluorinated gas production facilities that destroy fluorinated GHGs must account for any temporary reductions in the destruction efficiency that result from any malfunctions of the destruction device, including periods of operation outside of the operating conditions defined in operating permit requirements and/or destruction device manufacturer specifications.
(j) Emissions due to process startup, shutdown, or malfunctions. Fluorinated GHG production facilities must account for fluorinated GHG emissions that occur as a result of startups, shutdowns, and malfunctions, either recording fluorinated GHG emissions during these events, or documenting that these events do not result in significant fluorinated GHG emissions. Facilities may use the calculation methods in § 98.123(c)(1) to estimate emissions during startups, shutdowns, and malfunctions.
(k) Monitoring for venting residual fluorinated GHG in containers. Measure the residual fluorinated GHG in containers received by the facility either using scales or using pressure and temperature measurements. You may use pressure and temperature measurements only in cases where no liquid fluorinated GHG is present in the container. Scales must have an accuracy and precision of ±1 percent or better of the filled weight (gas plus tare) of the containers of fluorinated GHGs that are typically weighed on the scale. For example, for scales that are generally used to weigh cylinders that contain 115 pounds of gas when full and that have a tare weight of 115 pounds, this equates to ±1 percent of 230 pounds, or ±2.3 pounds. Pressure gauges and thermometers used to measure quantities that are monitored under this paragraph must have an accuracy and precision of ±1 percent of full scale or better.
(l) Initial scoping speciations, emissions testing, emission factor development, emission calculation factor development, emission characterization development, and destruction efficiency determinations must be completed by February 29, 2012 for processes and operating scenarios that operate between December 31, 2010 and December 31, 2011. For other processes and operating scenarios, initial scoping speciations, emissions testing, emission factor development, emission calculation factor development, emission characterization development, and destruction efficiency determinations must be complete by February 28 of the year following the year in which the process or operating scenario commences or recommences.
(m) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures using monitoring instruments traceable to the International System of Units (SI) through the National Institute of Standards and Technology (NIST) or other recognized national measurement institute. Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. Use any of the following applicable flow meter test methods or the calibration procedures specified by the flow meter, weigh-scale, or other volumetric or density measure manufacturer.
(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).
(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).
(3) ASME-MFC-5M-1985, (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference, see § 98.7).
(4) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).
(5) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).
(6) ASME MFC-9M-1988 (Reaffirmed 2001) Measurement of Liquid Flow in Closed Conduits by Weighing Method (incorporated by reference, see § 98.7).
(7) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7).
(8) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).
(n) All analytical equipment used to determine the concentration of fluorinated GHGs, including but not limited to gas chromatographs and associated detectors, infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic resonance (NMR) devices, must be calibrated at a frequency needed to support the type of analysis specified in the GHG Monitoring Plan as required under § 98.124(e)(3) and 93.3(g)(5). Quality assurance samples at the concentrations of concern must be used for the calibration. Such quality assurance samples must consist of or be prepared from certified standards of the analytes of concern where available; if not available, calibration must be performed by a method specified in the GHG Monitoring Plan.
(o) Special provisions for estimating 2011 and subsequent year emissions.
(1) Best available monitoring methods. To estimate emissions that occur from January 1, 2011 through June 30, 2011, owners or operators may use best available monitoring methods for any parameter that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart. The owner or operator must use the calculation methodologies and equations in § 98.123, but may use the best available monitoring method for any parameter for which it is not reasonably feasible to acquire, install, or operate a required piece of monitoring equipment, to procure measurement services from necessary providers, or to gain physical access to make required measurements in a facility by January 1, 2011. Starting no later than July 1, 2011, the owner or operator must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as provided in paragraphs (o)(2) through (o)(4) of this section. Best available monitoring methods means any of the following methods specified in this paragraph:
(i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations or assessments.
(iv) Other company records.
(2) Requests for extension of the use of best available monitoring methods to estimate 2011 emissions: parameters other than scoping speciations, emission factors, and emission characterizations. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods for parameters other than scoping speciations, emission factors, or emission characterizations to estimate emissions that occur between July 1, 2011 and December 31, 2011.
(i) Timing of request. The extension request must be submitted to EPA no later than February 28, 2011.
(ii) Content of request. Requests must contain the following information:
(A) A list of specific items of monitoring equipment and measurement services for which the request is being made and the locations (e.g., processes and vents) where each piece of monitoring equipment will be installed and where each measurement service will be provided.
(B) Identification of the specific rule requirements for which the monitoring equipment or measurement service is needed.
(C) A description of the reasons why the needed equipment could not be obtained, installed, or operated or why the needed measurement service could not be provided before July 1, 2011. The owner or operator must consider all of the data collection and emission calculation options outlined in the rule for a specific emissions source before claiming that a specific safety, technical, logistical, or legal barrier exists.
(D) If the reason for the extension is that the equipment cannot be purchased, delivered, or installed before July 1, 2011, include supporting documentation such as the date the monitoring equipment was ordered, investigation of alternative suppliers, the dates by which alternative vendors promised delivery or installation, backorder notices or unexpected delays, descriptions of actions taken to expedite delivery or installation, and the current expected date of delivery or installation.
(E) If the reason for the extension is that service providers were unable to provide necessary measurement services, include supporting documentation demonstrating that these services could not be acquired before July 1, 2011. This documentation must include written correspondence to and from at least two service providers stating that they will not be able to provide the necessary services before July 1, 2011.
(F) If the reason for the extension is that the process is operating continuously without process shutdown, include supporting documentation showing that it is not practicable to isolate the process equipment or unit and install the measurement device without a full shutdown or a hot tap, and that there is no opportunity before July 1, 2011 to install the device. Include the date of the three most recent shutdowns for each relevant process equipment or unit, the frequency of shutdowns for each relevant process equipment or unit, and the date of the next planned process equipment or unit shutdown.
(G) If the reason for the extension is that access to process streams, emissions streams, or destroyed streams, as applicable, could not be gained before July 1, 2011 for reasons other than the continuous operation of the process without shutdown, include illustrative documentation such as photographs and engineering diagrams demonstrating that access could not be gained.
(H) A description of the best available monitoring methods that will be used and how their results will be applied (i.e., which calculation method will be used) to develop the emission estimate. Where the proposed best available monitoring method is the use of current monitoring data in the mass-balance approach, include the estimated relative and absolute errors of the mass-balance approach using the current monitoring data.
(I) A description of the specific actions the owner or operator will take to comply with monitoring requirements by January 1, 2012.
(3) Requests for extension of the use of best available monitoring methods to estimate 2011 emissions: scoping speciations, emission factors, and emission characterizations. The owner or operator may submit a request to the Administrator to use one or more best available monitoring methods for scoping speciations, emission factors, and emission characterizations to estimate emissions that occur between July 1, 2011 and December 31, 2011.
(i) Timing of request. The extension request must be submitted to EPA no later than June 30, 2011.
(ii) Content of request. Requests must contain the information outlined in paragraph (o)(2)(ii) of this section, substituting March 1, 2012 for July 1, 2011 and substituting March 1, 2013 for January 1, 2012.
(iii) Reporting of 2011 emissions using scoping speciations, emission factors, and emission characterizations developed after February 29, 2012. Facilities that are approved to use best available monitoring methods in 2011 for scoping speciations, emission factors, or emission characterizations for certain processes must submit, by March 31, 2013, revised 2011 emission estimates that reflect the scoping speciations, emission factors, and emission characterizations that are measured for those processes after February 29, 2012. If the operating scenario for 2011 is different from all of the operating scenarios for which emission factors are developed after February 29, 2012, use Equation L-23 at § 98.123(c)(3)(viii) to adjust the emission factor(s) or emission characterizations measured for the post-February 29, 2012 operating scenario(s) to account for the differences.
(4) Requests for extension of the use of best available monitoring methods to estimate emissions that occur after 2011. EPA does not anticipate approving the use of best available monitoring methods to estimate emissions that occur beyond December 31, 2011; however, EPA reserves the right to review requests for unique and extreme circumstances which include safety, technical infeasibility, or inconsistency with other local, State or Federal regulations.
(i) Timing of request. The extension request must be submitted to EPA no later than June 30, 2011.
(ii) Content of request. Requests must contain the following information:
(A) The information outlined in paragraph (o)(2)(ii) of this section. For scoping speciations, emission factors, and emission characterizations, substitute March 1, 2013 for July 1, 2011 and substitute March 1, 2014 for January 1, 2012. For other parameters, substitute January 1, 2012 for July 1, 2011 and substitute January 1, 2013 for January 1, 2012.
(B) A detailed outline of the unique circumstances necessitating an extension, including specific data collection issues that do not meet safety regulations, technical infeasibility or specific laws or regulations that conflict with data collection. The owner or operator must consider all the data collection and emission calculation options outlined in the rule for a specific emissions source before claiming that a specific safety, technical or legal barrier exists.
(C) A detailed explanation and supporting documentation of how and when the owner or operator will receive the required data and/or services to comply with the reporting requirements of this subpart in the future.
(E) The Administrator reserves the right to require that the owner or operator provide additional documentation.
(iii) Reporting of 2011 and subsequent year emissions using scoping speciations, emission factors, and emission characterizations developed after approval to use best available monitoring methods expires. Facilities that are approved to use best available monitoring methods in 2011 and subsequent years for scoping speciations, emission factors, or emission characterizations for certain processes must submit, by March 31 of the year that begins one year after their approval to use best available monitoring method(s) expires, revised emission estimates for 2011 and subsequent years that reflect the scoping speciations, emission factors, and emission characterizations that are measured for those processes in 2013 or subsequent years. If the operating scenario for 2011 or subsequent years is different from all of the operating scenarios for which emission factors or emission characterizations are developed in 2013 or subsequent years, use Equation L-23 of § 98.123(c)(3)(viii) to adjust the emission factor(s) or emission characterization(s) measured for the new operating scenario(s) to account for the differences.
(5) Approval criteria. To obtain approval, the owner or operator must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to acquire, install, or operate the required piece of monitoring equipment, to procure measurement services from necessary providers, or to gain physical access to make required measurements in a facility according to the requirements of this subpart by the dates specified in paragraphs (o)(2), (3), and (4) of this section for any of the reasons described in paragraph (o)(2)(ii) of this section, or, for requests under paragraph (o)(4) of this section, any of the reasons described in paragraph (o)(4)(ii)(B) of this section.
§ 98.125 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations in § 98.123 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in the calculations as specified in the paragraphs (b) and (c) of this section. You must document and keep records of the procedures used for all such estimates.
(b) For each missing value of the fluorinated GHG concentration or fluorine-containing compound concentration, the substitute data value must be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident.
(c) For each missing value of the mass produced, fed into the production process, fed into the transformation process, or fed into destruction devices, the substitute value of that parameter must be a secondary mass measurement where such a measurement is available. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product. Where a secondary mass measurement is not available, the substitute value of the parameter must be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the mass flow rate into the destruction device.
§ 98.126 Data reporting requirements.
(a) All facilities. In addition to the information required by § 98.3(c), you must report the information in paragraphs (a)(2) through (6) of this section according to the schedule in paragraph (a)(1) of this section, except as otherwise provided in paragraph (j) of this section or in § 98.3(c)(4)(vii) and Table A-7 of subpart A of this part.
(1) Frequency of reporting under paragraph (a) of this section. The information in paragraphs (a)(2) through (6) of this section must be reported annually.
(2) Generically-identified process. For each production and transformation process at the facility, you must:
(i) Provide a number, letter, or other identifier for the process. This identifier must be consistent from year to year.
(ii) Indicate whether the process is a fluorinated gas production process, a fluorinated gas transformation process where no fluorinated GHG reactant is produced at another facility, or a fluorinated gas transformation process where one or more fluorinated GHG reactants are produced at another facility.
(iii) Indicate whether the process could be characterized as reaction, distillation, or packaging (include all that apply).
(iv) For each generically-identified process and each fluorinated GHG group, report the method(s) used to determine the mass emissions of that fluorinated GHG group from that process from vents (i.e., mass balance (for reporting years 2011, 2012, 2013, and 2014 only), process-vent-specific emission factor, or process-vent-specific emission calculation factor).
(v) For each generically-identified process and each fluorinated GHG group, report the method(s) used to determine the mass emissions of that fluorinated GHG group from that process from equipment leaks, unless you used the mass balance method (for reporting years 2011, 2012, 2013, and 2014 only) for that process.
(3) Emissions from production and transformation processes, process level, multiple products. If your facility produces more than one fluorinated gas product, for each generically-identified process and each fluorinated GHG group, you must report the total GWP-weighted emissions of all fluorinated GHGs in that group from the process, in metric tons CO
(4) Emissions from production and transformation processes, facility level, multiple products. If your facility produces more than one fluorinated gas product, you must report the information in paragraphs (a)(4)(i) and (ii) of this section, as applicable, for emissions from production and transformation processes.
(i) For each fluorinated GHG with emissions of 1,000 metric tons of CO
(ii) For all other fluorinated GHGs emitted from production and transformation processes, you must report the total GWP-weighted emissions from production and transformation processes of those fluorinated GHGs by fluorinated GHG group, summed across the facility as a whole, in metric tons of CO
(5) Emissions from production and transformation processes, facility level, one product only. If your facility produces only one fluorinated gas product, aggregate and report the total GWP-weighted emissions from production and transformation processes of fluorinated GHGs by fluorinated GHG group for the facility as a whole, in metric tons of CO
(6) Effective destruction efficiency. For each generically-identified process, use Table L-1 of this subpart to report the range that encompasses the effective destruction efficiency, DE
(b) Reporting for mass balance method for reporting years 2011, 2012, 2013, and 2014. If you used the mass balance method to calculate emissions for any of the reporting years 2011, 2012, 2013, or 2014, you must conduct mass balance reporting for that reporting year. For processes whose emissions were determined using the mass balance method under the former § 98.123(b), as included in paragraph 1 of Appendix A of this subpart, you must report the information listed in paragraphs (b)(1) and (b)(2) of this section for each process on an annual basis.
(1) If you calculated the relative and absolute errors under the former § 98.123(b)(1), the overall absolute and relative errors calculated for the process under the former § 98.123(b)(1), in metric tons CO
(2) The method used to estimate the total mass of fluorine in destroyed or recaptured streams (specify the former § 98.123(b)(4) or (15), as included in paragraph 1 of Appendix A of this subpart).
(c) Reporting for emission factor and emission calculation factor approach. For processes whose emissions are determined using the emission factor approach under § 98.123(c)(3) or the emission calculation factor under § 98.123(c)(4), you must report the following for each generically-identified process.
(1) [Reserved]
(2) [Reserved]
(3) For each fluorinated GHG group, the total GWP-weighted mass of all fluorinated GHGs in that group emitted from all process vents combined, in metric tons of CO
(4) For each fluorinated GHG group, the total GWP-weighted mass of all fluorinated GHGs in that group emitted from equipment leaks, in metric tons of CO
(d) Reporting for missing data. Where missing data have been estimated pursuant to § 98.125, you must report:
(1) The generically-identified process for which the data were missing.
(2) The reason the data were missing, the length of time the data were missing, and the method used to estimate the missing data.
(3) Estimates of the missing data for all missing data associated with data elements required to be reported in this section.
(e) Reporting of destruction device excess emissions data. Each fluorinated gas production facility that destroys fluorinated GHGs must report the excess emissions that result from malfunctions of the destruction device, and these excess emissions must be reflected in the fluorinated GHG estimates in the former § 98.123(b) as included in paragraph 1 of Appendix A of this subpart for the former mass balance method, and in § 98.123(c). Such excess emissions would occur if the destruction efficiency was reduced due to the malfunction.
(f) Reporting of destruction device testing. By March 31, 2012 or by March 31 of the year immediately following the year in which it begins fluorinated GHG destruction, each fluorinated gas production facility that destroys fluorinated GHGs must submit a report containing the information in paragraphs (f)(1) through (f)(4) of this section. This report is one-time unless you make a change to the destruction device that would be expected to affect its destruction efficiencies.
(1) [Reserved]
(2) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine destruction efficiency, including surrogates, and information on why the surrogate is sufficient to demonstrate the destruction efficiency for each fluorinated GHG, consistent with requirements in § 98.124(g)(1), vented to the destruction device.
(3) Date of the most recent destruction device test.
(4) Name of all applicable Federal or State regulations that may apply to the destruction process.
(5) [Reserved]
(g) Reporting for destruction of previously produced fluorinated GHGs. Each fluorinated gas production facility that destroys fluorinated GHGs must report, separately from the fluorinated GHG emissions reported under paragraphs (b) or (c) of this section, the following for each previously produced fluorinated GHG destroyed:
(1) [Reserved]
(2) The mass of the fluorinated GHG emitted from the destruction device (metric tons).
(h) Reporting of emissions from venting of residual fluorinated GHGs from containers. Each fluorinated gas production facility that vents residual fluorinated GHGs from containers must report the following for each fluorinated GHG vented:
(1) The mass of the residual fluorinated GHG vented from containers annually (metric tons).
(2) [Reserved]
(i) Reporting of fluorinated GHG products of incomplete combustion (PICs) of fluorinated gases. Each fluorinated gas production facility that destroys fluorinated gases must submit a one-time report by June 30, 2011, that describes any measurements, research, or analysis that it has performed or obtained that relate to the formation of products of incomplete combustion that are fluorinated GHGs during the destruction of fluorinated gases. The report must include the methods and results of any measurement or modeling studies, including the products of incomplete combustion for which the exhaust stream was analyzed, as well as copies of relevant scientific papers, if available, or citations of the papers, if they are not. No new testing is required to fulfill this requirement.
(j) Special provisions for reporting years 2011, 2012, and 2013 only. For reporting years 2011, 2012, and 2013, the owner or operator of a facility must comply with paragraphs (j)(1), (j)(2), and (j)(3) of this section.
(1) Timing. The owner or operator of a facility is not required to report the data elements at § 98.3(c)(4)(iii) and paragraphs (a)(2), (a)(3), (a)(4), (a)(6), (b), (c), (d), (e), (f), (g), and (h) of this section until the later of March 31, 2015 or the date set forth for that data element at § 98.3(c)(4)(vii) and Table A-7 of Subpart A of this part.
(2) Excess emissions. Excess emissions of fluorinated GHGs resulting from destruction device malfunctions must be reflected in the reported facility-wide CO
(3) Calculation and reporting of CO
(i) If you choose to use a default GWP rather than your best estimate of the GWP for fluorinated GHGs whose GWPs are not listed in Table A-1 of Subpart A of this part, use a default GWP of 10,000 for fluorinated GHGs that are fully fluorinated GHGs and use a default GWP of 2000 for other fluorinated GHGs.
(ii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO
(iii) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO
(iv) Provide the total annual emissions across fluorinated GHGs for the entire facility, in metric tons of CO
(k) Submission of complete reporting year 2011, 2012, and 2013 GHG reports. By March 31, 2015, you must submit annual GHG reports for reporting years 2011, 2012, and 2013 that contain the information specified in paragraphs (a) through (i) of this section. The reports must calculate CO
§ 98.127 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the dated records specified in paragraphs (a) through (l) of this section, as applicable.
(a) Process information records. (1) Identify all products and processes subject to this subpart. Include the unit identification as appropriate, the generic process identification reported for the process under § 98.126(a)(2)(i) through (iii), and the product with which the process is associated.
(2) Monthly and annual records, as applicable, of all analyses and calculations conducted as required under § 98.123, including the data monitored under § 98.124, and all information reported as required under § 98.126.
(3) Identify all fluorinated GHGs with emissions of 1,000 metric tons CO
(4) Calculations used to determine the total GWP-weighted emissions of fluorinated GHGs by fluorinated GHG group for each process, in metric tons CO
(b) Scoping speciation. Retain records documenting the information collected under § 98.124(a).
(c) Mass balance method. Retain the following records for each process for which the mass balance method was used to estimate emissions in reporting years 2011, 2012, 2013, or 2014. If you used an element other than fluorine in the mass balance equation pursuant to the former § 98.123(b)(3) as included in paragraph 1 of Appendix A of this subpart for the former mass balance method, substitute that element for fluorine in the recordkeeping requirements of this paragraph.
(1) The data and calculations used to estimate the absolute and relative errors associated with use of the mass-balance approach.
(2) The data and calculations used to estimate the mass of fluorine emitted from the process.
(3) The data and calculations used to determine the fractions of the mass emitted consisting of each reactant (FER
(d) Emission factor and emission calculation factor method. Retain the following records for each process for which the emission factor or emission calculation factor method was used to estimate emissions.
(1) Identify all continuous process vents with emissions of fluorinated GHGs that are less than 10,000 metric tons CO
(2) Identify all batch process vents.
(3) For each vent, identify the method used to develop the factor (i.e., emission factor by emissions test or emission calculation factor).
(4) The emissions test data and reports (see § 98.124(c)(5)) and the calculations used to determine the process-vent-specific emission factor, including the actual process-vent-specific emission factor, the average hourly emission rate of each fluorinated GHG from the process vent during the test and the process feed rate, process production rate, or other process activity rate during the test.
(5) The process-vent-specific emission calculation factor and the calculations used to determine the process-vent-specific emission calculation factor.
(6) The annual process production quantity or other process activity information in the appropriate units, along with the dates and time period during which the process was operating and dates and time periods the process vents are vented to the destruction device. As an alternative to date and time periods when process vents are vented to the destruction device, a facility may track dates and time periods that process vents by-pass the destruction device.
(7) Calculations used to determine annual emissions of each fluorinated GHG for each process and the total fluorinated GHG emissions for all processes, i.e., total for facility.
(e) Destruction efficiency testing. A fluorinated GHG production facility that destroys fluorinated GHGs and reflects this destruction in § 98.123 must retain the emissions performance testing reports (including revised reports) for each destruction device. The emissions performance testing report must contain all information and data used to derive the destruction efficiency for each fluorinated GHG whose destruction the facility reflects in § 98.123, as well as the key process and device conditions during the test. This information includes the following:
(1) Destruction efficiency (DE) determined for each fluorinated GHG whose destruction the facility reflects in § 98.123, in accordance with § 98.124(g)(1)(i) through (iv).
(2) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine destruction efficiency, including surrogates, and information on why the surrogate is sufficient to demonstrate destruction efficiency for each fluorinated GHG, consistent with requirements in § 98.124(g)(1)(i) through (iv), vented to the destruction device.
(3) Mass flow rate of the stream containing the fluorinated GHG(s) or surrogate into the device during the test.
(4) Concentration (mass fraction) of each fluorinated GHG or surrogate in the stream flowing into the device during the test.
(5) Concentration (mass fraction) of each fluorinated GHG or surrogate at the outlet of the destruction device during the test.
(6) Mass flow rate at the outlet of the destruction device during the test.
(7) Test methods and analytical methods used to determine the mass flow rates and fluorinated GHG (or surrogate) concentrations of the streams flowing into and out of the destruction device during the test.
(8) Destruction device conditions that are normally monitored for device control, such as temperature, total mass flow rates into the device, and CO or O
(9) Name of all applicable Federal or State regulations that may apply to the destruction process.
(f) Equipment leak records. If you are subject to § 98.123(d) of this subpart, you must maintain information on the number of each type of equipment; the service of each piece of equipment (gas, light liquid, heavy liquid); the concentration of each fluorinated GHG in the stream; each piece of equipment excluded from monitoring requirement; the time period each piece of equipment was in service, and the emission calculations for each fluorinated GHG for all processes. Depending on which equipment leak monitoring approach you follow, you must maintain information for equipment on the associated screening data concentrations for greater than or equal to 10,000 ppmv and associated screening data concentrations for less than 10,000 ppmv; associated actual screening data concentrations; and associated screening data and leak rate data (i.e., bagging) used to develop a unit-specific correlation. If you developed and follow a site-specific leak detection approach, provide the records for monitoring events and the emissions estimation calculations, as appropriate, consistent with the approach for equipment leak emission estimation in your GHG Monitoring Plan.
(g) Container heel records. If you vent residual fluorinated GHGs from containers, maintain the following records of the measurements and calculations used to estimate emissions of residual fluorinated GHGs from containers.
(i) If you measure the contents of each container, maintain records of these measurements and the calculations used to estimate emissions of each fluorinated GHG from each container size and type.
(ii) If you develop and apply container heel factors to estimate emissions, maintain records of the measurements and calculations used to develop the heel factor for each fluorinated GHG and each container size and type and of the number of containers of each fluorinated GHG and of each container size and type returned to your facility.
(h) Missing data records. Where missing data have been estimated pursuant to § 98.125, you must record the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data.
(i) All facilities. Dated records documenting the initial and periodic calibration of all analytical equipment used to determine the concentration of fluorinated GHGs, including but not limited to gas chromatographs, gas chromatography-mass spectrometry (GC/MS), gas chromatograph-electron capture detector (GC/ECD), fourier transform infrared (FTIR), and nuclear magnetic resonance (NMR) devices, and all mass measurement equipment such as weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the industry standards or manufacturer directions used for calibration pursuant to § 98.124(e), (f), (g), (m), and (n).
(j) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
(k) For fluorinated GHGs whose GWPs are not listed in Table A-1 to subpart A of this part, maintain records of the GWPs used to calculate facility-wide CO
(l) Verification software records. For reporting year 2015 and thereafter, you must enter into verification software specified in § 98.5(b) the data specified in paragraphs (l)(1) through (15) of this section. The data specified in paragraphs (l)(1) through (11) must be entered for each process and each process vent, as applicable. The data specified in paragraphs (l)(1) through (15) must be entered for each fluorinated GHG, as applicable. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (l)(1) through (15) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (l)(1) through (15) of this section.
(1) The identity of the process vent (e.g., name or number assigned by the facility).
(2) The equation used to estimate emissions from the process vent (Equations L-21, L-22, L-26, or L-27).
(3) The type of process activity used to estimate emissions from the process vent (e.g., product of process or reactant consumed by process) (Activity, Activity
(4) The quantities of the process activity used to estimate controlled and uncontrolled emissions, respectively, for the process vent, Activity, Activity
(5) The site-specific, process-vent-specific emission factor, EF
(6) The site-specific, process-vent-specific emission calculation factor, ECF
(7) The site-specific, process-vent-specific emission factor(s), EF
(8) The site-specific, process-vent-specific emission calculation factor for the process vent, ECF
(9) Destruction efficiency, DE, of each destruction device for each fluorinated GHG whose destruction the facility reflects in § 98.123, in accordance with § 98.124(g)(1)(i) through (iv) (weight fraction) (Equations L-22, L-27, L-31).
(10) Emissions of each fluorinated GHG for equipment pieces for the process, E
(11) The mass of the fluorinated GHG previously produced and fed into the destruction device, RE
(12) If applicable, the heel factor, h
(13) If applicable, the number of containers of size and type j returned to the fluorinated gas production facility, N
(14) If applicable, the full capacity of containers of size and type j containing fluorinated GHG f, F
(15) For fluorinated GHGs that do not have a chemical-specific GWP on Table A-1 of subpart A of this part, the fluorinated GHG group of which the fluorinated GHG is a member, as applicable (to permit look-up of global warming potential, GWP
§ 98.128 Definitions.
Except as provided in this section, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart shall take precedence for the reporting requirements in this subpart.
Batch process or batch operation means a noncontinuous operation involving intermittent or discontinuous feed into equipment, and, in general, involves the emptying of the equipment after the batch operation ceases and prior to beginning a new operation. Addition of raw material and withdrawal of product do not occur simultaneously in a batch operation.
Batch emission episode means a discrete venting episode associated with a vessel in a process; a vessel may have more than one batch emission episode. For example, a displacement of vapor resulting from the charging of a vessel with a feed material will result in a discrete emission episode that will last through the duration of the charge and will have an average flow rate equal to the rate of the charge. If the vessel is then heated, there will also be another discrete emission episode resulting from the expulsion of expanded vapor. Other emission episodes also may occur from the same vessel and other vessels in the process, depending on process operations.
By-product means a chemical that is produced coincidentally during the production of another chemical.
Completely destroyed means destroyed with a destruction efficiency of 99.99 percent or greater.
Completely recaptured means 99.99 percent or greater of each fluorinated GHG is removed from a stream.
Continuous process or operation means a process where the inputs and outputs flow continuously throughout the duration of the process. Continuous processes are typically steady state.
Destruction device means any device used to destroy fluorinated GHG.
Destruction process means a process used to destroy fluorinated GHG in a destruction device such as a thermal incinerator or catalytic oxidizer.
Difficult-to-monitor means the equipment piece may not be monitored without elevating the monitoring personnel more than 2 meters (7 feet) above a support surface or it is not accessible in a safe manner when it is in fluorinated GHG service.
Dual mechanical seal pump and dual mechanical seal agitator means a pump or agitator equipped with a dual mechanical seal system that includes a barrier fluid system where the barrier fluid is not in light liquid service; each barrier fluid system is equipped with a sensor that will detect failure of the seal system, the barrier fluid system, or both; and meets the following requirements:
(1) Each dual mechanical seal system is operated with the barrier fluid at a pressure that is at all times (except periods of startup, shutdown, or malfunction) greater than the pump or agitator stuffing box pressure; or
(2) Equipped with a barrier fluid degassing reservoir that is routed to a process or fuel gas system or connected by a closed-vent system to a control device; or
(3) Equipped with a closed-loop system that purges the barrier fluid into a process stream.
Equipment (for the purposes of § 98.123(d) and § 98.124(f) only) means each pump, compressor, agitator, pressure relief device, sampling connection system, open-ended valve or line, valve, connector, and instrumentation system in fluorinated GHG service for a process subject to this subpart; and any destruction devices or closed-vent systems to which processes subject to this subpart are vented.
Fluorinated gas means any fluorinated GHG, CFC, or HCFC.
Fluorinated gas product means the product of the process, including isolated intermediates.
Fully fluorinated GHGs means fluorinated GHGs that contain only single bonds and in which all available valence locations are filled by fluorine atoms. This includes but is not limited to saturated perfluorocarbons, SF
Generically-identified process means a process that is:
(1) Identified as a production process, a transformation process where no fluorinated GHG reactant is produced at another facility, or a transformation process where one or more fluorinated GHG reactants are produced at another facility;
(2) Further identified as a reaction, distillation, or packaging process, or a combination thereof; and
(3) Tagged with a discrete identifier, such as a letter or number, that remains constant from year to year.
In fluorinated GHG service means that a piece of equipment either contains or contacts a feedstock, by-product, or product that is a liquid or gas and contains at least 5 percent by weight fluorinated GHG.
In gas and vapor service means that a piece of equipment in regulated material service contains a gas or vapor at operating conditions.
In heavy liquid service means that a piece of equipment in regulated material service is not in gas and vapor service or in light liquid service.
In light liquid service means that a piece of equipment in regulated material service contains a liquid that meets the following conditions:
(1) The vapor pressure of one or more of the compounds is greater than 0.3 kilopascals at 20 °C.
(2) The total concentration of the pure compounds constituents having a vapor pressure greater than 0.3 kilopascals at 20 °C is equal to or greater than 20 percent by weight of the total process stream.
(3) The fluid is a liquid at operating conditions.
Vapor pressures may be determined by standard reference texts or ASTM D-2879, (incorporated by reference, see § 98.7).
In vacuum service means that equipment is operating at an internal pressure which is at least 5 kilopascals below ambient pressure.
Isolated intermediate means a product of a process that is stored before subsequent processing. An isolated intermediate is usually a product of chemical synthesis. Storage of an isolated intermediate marks the end of a process. Storage occurs at any time the intermediate is placed in equipment used solely for storage.
Major fluorinated GHG constituent means a fluorinated GHG constituent of a fluorinated gas product that occurs in concentrations greater than 1 percent by mass.
No external shaft pump and No external shaft agitator means any pump or agitator that is designed with no externally actuated shaft penetrating the pump or agitator housing.
Operating scenario means any specific operation of a process and includes the information specified in paragraphs (1) through (5) of this definition for each process. A change or series of changes to any of these elements, except for paragraph (4) of this definition, constitutes a different operating scenario.
(1) A description of the process, the specific process equipment used, and the range of operating conditions for the process.
(2) An identification of related process vents, their associated emissions episodes and durations, and calculations and engineering analyses to show the annual uncontrolled fluorinated GHG emissions from the process vent.
(3) The control or destruction devices used, as applicable, including a description of operating and/or testing conditions for any associated destruction device.
(4) The process vents (including those from other processes) that are simultaneously routed to the control or destruction device(s).
(5) The applicable monitoring requirements and any parametric level that assures destruction or removal for all emissions routed to the control or destruction device.
Process means all equipment that collectively functions to produce a fluorinated gas product, including an isolated intermediate (which is also a fluorinated gas product), or to transform a fluorinated gas product. A process may consist of one or more unit operations. For the purposes of this subpart, process includes any, all, or a combination of reaction, recovery, separation, purification, or other activity, operation, manufacture, or treatment which are used to produce a fluorinated gas product. For a continuous process, cleaning operations conducted may be considered part of the process, at the discretion of the facility. For a batch process, cleaning operations are part of the process. Ancillary activities are not considered a process or part of any process under this subpart. Ancillary activities include boilers and incinerators, chillers and refrigeration systems, and other equipment and activities that are not directly involved (i.e., they operate within a closed system and materials are not combined with process fluids) in the processing of raw materials or the manufacturing of a fluorinated gas product.
Process condenser means a condenser whose primary purpose is to recover material as an integral part of a process. All condensers recovering condensate from a process vent at or above the boiling point or all condensers in line prior to a vacuum source are considered process condensers. Typically, a primary condenser or condensers in series are considered to be integral to the process if they are capable of and normally used for the purpose of recovering chemicals for fuel value (i.e., net positive heating value), use, reuse or for sale for fuel value, use, or reuse.
Process vent (for the purposes of this subpart only) means a vent from a process vessel or vents from multiple process vessels within a process that are manifolded together into a common header, through which a fluorinated GHG-containing gas stream is, or has the potential to be, released to the atmosphere (or the point of entry into a control device, if any). Examples of process vents include, but are not limited to, vents on condensers used for product recovery, bottoms receivers, surge control vessels, reactors, filters, centrifuges, and process tanks. Process vents do not include vents on storage tanks, wastewater emission sources, or pieces of equipment.
Typical batch means a batch process operated within a range of operating conditions that are documented in an operating scenario. Emissions from a typical batch are based on the operating conditions that result in representative emissions. The typical batch defines the uncontrolled emissions for each emission episode defined under the operating scenario.
Uncontrolled fluorinated GHG emissions means a gas stream containing fluorinated GHG which has exited the process (or process condenser or control condenser, where applicable), but which has not yet been introduced into a destruction device to reduce the mass of fluorinated GHG in the stream. If the emissions from the process are not routed to a destruction device, uncontrolled emissions are those fluorinated GHG emissions released to the atmosphere.
Unsafe-to-monitor means that monitoring personnel would be exposed to an immediate danger as a consequence of monitoring the piece of equipment. Examples of unsafe-to-monitor equipment include, but are not limited to, equipment under extreme pressure or heat.
Table L-1 to Subpart L of Part 98 – Ranges of Effective Destruction Efficiency
Range of Reductions |
---|
≥99%. |
≥95% to |
≥75% to |
≥0% to |
Appendix A to Subpart L of Part 98 – Mass Balance Method for Fluorinated Gas Production
1. Mass Balance Method for § 98.123(b). [Note: Numbering convention here matches original rule text, 75 FR 74774, December 1, 2010.]
(b) Mass balance method. Before using the mass balance approach to estimate your fluorinated GHG emissions from a process, you must ensure that the process and the equipment and methods used to measure it meet either the error limits described in this paragraph and calculated under paragraph (b)(1) of this section or the requirements specified in paragraph § 98.124(b)(8). If you choose to calculate the error limits, you must estimate the absolute and relative errors associated with using the mass balance approach on that process using Equations L-1 through L-4 of this section in conjunction with Equations L-5 through L-10 of this section. You may use the mass-balance approach to estimate emissions from the process if this calculation results in an absolute error of less than or equal to 3,000 metric tons CO
(1) Error calculation. To perform the calculation, you must first calculate the absolute and relative errors associated with the quantities calculated using either Equations L-7 through L-10 of this section or Equation L-17 of this section. Alternatively, you may estimate these errors based on the variability of previous process measurements (e.g., the variability of measurements of stream concentrations), provided these measurements are representative of the current process and current measurement devices and techniques. Once errors have been calculated for the quantities in these equations, those errors must be used to calculate the errors in Equations L-6 and L-5 of this section. You may ignore the errors associated with Equations L-11, L-12, and L-13 of this section.
(i) Where the measured quantity is a mass, the error in the mass must be equated to the accuracy or precision (whichever is larger) of the flowmeter, scale, or combination of volumetric and density measurements at the flow rate or mass measured.
(ii) Where the measured quantity is a concentration of a stream component, the error of the concentration must be equated to the accuracy or precision (whichever is larger) with which you estimate the mean concentration of that stream component, accounting for the variability of the process, the frequency of the measurements, and the accuracy or precision (whichever is larger) of the analytical technique used to measure the concentration at the concentration measured. If the variability of process measurements is used to estimate the error, this variability shall be assumed to account both for the variability of the process and the precision of the analytical technique. Use standard statistical techniques such as the student’s t distribution to estimate the error of the mean of the concentration measurements as a function of process variability and frequency of measurement.
(iii) Equation L-1 of this section provides the general formula for calculating the absolute errors of sums and differences where the sum, S, is the summation of variables measured, a, b, c, etc. (e.g., S = a + b + c):
(iv) Equation L-2 of this section provides the general formula for calculating the relative errors of sums and differences:
(v) Equation L-3 of this section provides the general formula for calculating the absolute errors of products (e.g., flow rates of GHGs calculated as the product of the flow rate of the stream and the concentration of the GHG in the stream), where the product, P, is the result of multiplying the variables measured, a, b, c, etc. (e.g., P = a*b*c):
(vi) Equation L-4 of this section provides the general formula for calculating the relative errors of products:
(vii) Calculate the absolute error of the emissions estimate in terms of CO
(viii) To estimate the annual CO
(2) The total mass of each fluorinated GHG emitted annually from each fluorinated gas production and each fluorinated GHG transformation process must be estimated by using Equation L-5 of this section.
(3) The total mass of fluorine emitted from process i over the period p must be estimated at least monthly by calculating the difference between the total mass of fluorine in the reactant(s) (or inputs, for processes that do not involve a chemical reaction) and the total mass of fluorine in the product (or outputs, for processes that do not involve a chemical reaction), accounting for the total mass of fluorine in any destroyed or recaptured streams that contain reactants, products, or by-products (or inputs or outputs). This calculation must be performed using Equation L-6 of this section. An element other than fluorine may be used in the mass-balance equation, provided the element occurs in all of the fluorinated GHGs fed into or generated by the process. In this case, the mass fractions of the element in the reactants, products, and by-products must be calculated as appropriate for that element.
(4) The mass of total fluorine in destroyed or recaptured streams containing fluorine-containing reactants, products, and by-products must be estimated at least monthly using Equation L-7 of this section unless you use the alternative approach provided in paragraph (b)(15) of this section.
(5) The mass of each fluorinated GHG removed from process i in stream j and destroyed over the period p (i.e., P
(6) The mass of each fluorine-containing compound that is not a fluorinated GHG and that is removed from process i in stream j and destroyed over the period p (i.e., P
(7) The mass of fluorine-containing by-product k removed from process i in stream l and recaptured over the period p must be estimated using Equation L-10 of this section:
(8) To estimate the terms FER
(i) If the calculations under paragraph (b)(1)(viii) of this section, or any subsequent measurements and calculations under this subpart, indicate that the process emits 25,000 metric tons CO
(ii) For other vents, including vents from processes that emit less than 25,000 metric tons CO
(iii) For fluorine emissions that are not accounted for by vent estimates, you must characterize emissions as specified in § 98.124(b)(6).
(9) The total mass of fluorine-containing reactant d emitted must be estimated at least monthly based on the total fluorine emitted and the fraction that consists of fluorine-containing reactants using Equation L-11 of this section. If the fluorine-containing reactant d is a non-GHG, you may assume that FER
(10) The total mass of fluorine-containing product emitted must be estimated at least monthly based on the total fluorine emitted and the fraction that consists of fluorine-containing products using Equation L-12 of this section. If the fluorine-containing product is a non-GHG, you may assume that FEP is zero.
(11) The total mass of fluorine-containing by-product k emitted must be estimated at least monthly based on the total fluorine emitted and the fraction that consists of fluorine-containing by-products using Equation L-13 of this section. If fluorine-containing by-product k is a non-GHG, you may assume that FEB
(12) The mass fraction of fluorine in reactant d must be estimated using Equation L-14 of this section:
(13) The mass fraction of fluorine in the product must be estimated using Equation L-15 of this section:
(14) The mass fraction of fluorine in by-product k must be estimated using Equation L-16 of this section:
(15) Alternative for determining the mass of fluorine destroyed or recaptured. As an alternative to using Equation L-7 of this section as provided in paragraph (b)(4) of this section, you may estimate at least monthly the total mass of fluorine in destroyed or recaptured streams containing fluorine-containing compounds (including all fluorine-containing reactants, products, and byproducts) using Equation L-17 of this section.
(16) Weighted average destruction efficiency. For purposes of Equation L-17 of this section, calculate the weighted average destruction efficiency applicable to a destroyed stream using Equation L-18 of this section.
2. Mass Balance Method for § 98.124(b). [Note: Numbering convention here matches original rule text, 75 FR 74774, December 1, 2010.]
(b) Mass balance monitoring. If you determine fluorinated GHG emissions from any process using the mass balance method under § 98.123(b), you must estimate the total mass of each fluorinated GHG emitted from that process at least monthly. Only streams that contain greater than trace concentrations of fluorine-containing reactants, products, or by-products must be monitored under this paragraph. If you use an element other than fluorine in the mass-balance equation pursuant to § 98.123(b)(3), substitute that element for fluorine in the monitoring requirements of this paragraph.
(1) Mass measurements. Measure the following masses on a monthly or more frequent basis using flowmeters, weigh scales, or a combination of volumetric and density measurements with accuracies and precisions that allow the facility to meet the error criteria in § 98.123(b)(1):
(i) Total mass of each fluorine-containing product produced. Account for any used fluorine-containing product added into the production process upstream of the output measurement as directed at §§ 98.413(b) and 98.414(b). For each product, the mass produced used for the mass-balance calculation must be the same as the mass produced that is reported under subpart OO of this part, where applicable.
(ii) Total mass of each fluorine-containing reactant fed into the process.
(iii) The mass removed from the process in each stream fed into the destruction device.
(iv) The mass removed from the process in each recaptured stream.
(2) Concentration measurements for use with § 98.123(b)(4). If you use § 98.123(b)(4) to estimate the mass of fluorine in destroyed or recaptured streams, measure the following concentrations at least once each calendar month during which the process is operating, on a schedule to ensure that the measurements are representative of the full range of process conditions (e.g., catalyst age). Measure more frequently if this is necessary to meet the error criteria in § 98.123(b)(1). Use equipment and methods (e.g., gas chromatography) that comply with paragraph (e) of this section and that have an accuracy and precision that allow the facility to meet the error criteria in § 98.123(b)(1). Only fluorine-containing reactants, products, and by-products that occur in a stream in greater than trace concentrations must be monitored under this paragraph.
(i) The concentration (mass fraction) of the fluorine-containing product in each stream that is fed into the destruction device.
(ii) The concentration (mass fraction) of each fluorine-containing by-product in each stream that is fed into the destruction device.
(iii) The concentration (mass fraction) of each fluorine-containing reactant in each stream that is fed into the destruction device.
(iv) The concentration (mass fraction) of each fluorine-containing by-product in each stream that is recaptured (c
(3) Concentration measurements for use with § 98.123(b)(15). If you use § 98.123(b)(15) to estimate the mass of fluorine in destroyed or recaptured streams, measure the concentrations listed in paragraphs (b)(3)(i) and (ii) of this section at least once each calendar month during which the process is operating, on a schedule to ensure that the measurements are representative of the full range of process conditions (e.g., catalyst age). Measure more frequently if this is necessary to meet the error criteria in § 98.123(b)(1). Use equipment and methods (e.g., gas chromatography) that comply with paragraph (e) of this section and that have an accuracy and precision that allow the facility to meet the error criteria in § 98.123(b)(1). Only fluorine-containing reactants, products, and by-products that occur in a stream in greater than trace concentrations must be monitored under this paragraph.
(i) The concentration (mass fraction) of total fluorine in each stream that is fed into the destruction device.
(ii) The concentration (mass fraction) of total fluorine in each stream that is recaptured.
(4) Emissions characterization: process vents emitting 25,000 metric tons CO
(i) Uncontrolled emissions. If emissions from the process vent are not routed through a destruction device, sample and analyze emissions at the process vent or stack or sample and analyze emitted streams before the process vent. If the process has more than one operating scenario, you must either perform the emission characterization for each operating scenario or perform the emission characterization for the operating scenario that is expected to have the largest emissions and adjust the emission characterization for other scenarios using engineering calculations and assessments as specified in § 98.123(c)(4). To perform the characterization, take three samples under conditions that are representative for the operating scenario. Measure the concentration of each fluorine-containing compound in each sample. Use equipment and methods that comply with paragraph (e) of this section. Calculate the average concentration of each fluorine-containing compound across all three samples.
(ii) Controlled emissions using § 98.123(b)(15). If you use § 98.123(b)(15) to estimate the total mass of fluorine in destroyed or recaptured streams, and if the emissions from the process vent are routed through a destruction device, characterize emissions as specified in paragraph (b)(4)(i) of this section before the destruction device. Apply the destruction efficiency demonstrated for each fluorinated GHG in the destroyed stream to that fluorinated GHG. Exclude from the characterization fluorine-containing compounds that are not fluorinated GHGs.
(iii) Controlled emissions using § 98.123(b)(4). If you use § 98.123(b)(4) to estimate the mass of fluorine in destroyed or recaptured streams, and if the emissions from the process vent are routed through a destruction device, characterize the process vent’s emissions monthly (or more frequently) using the monthly (or more frequent) measurements under paragraphs (b)(1)(iii) and (b)(2)(i) through (iii) of this section. Apply the destruction efficiency demonstrated for each fluorinated GHG in the destroyed stream to that fluorinated GHG. Exclude from the characterization fluorine-containing compounds that are not fluorinated GHGs.
(iv) Emissions characterization frequency. You must repeat emission characterizations performed under paragraph (b)(4)(i) and (ii) of this section under paragraph (b)(4)(iv)(A) or (B) of this section, whichever occurs first:
(A) 10-year revision. Repeat the emission characterization every 10 years. In the calculations under § 98.123, apply the revised emission characterization to the process activity that occurs after the revision.
(B) Operating scenario change that affects the emission characterization. For planned operating scenario changes, you must estimate and compare the emission calculation factors for the changed operating scenario and for the original operating scenario whose process vent specific emission factor was measured. Use the engineering calculations and assessments specified in § 98.123(c)(4). If the share of total fluorine-containing compound emissions represented by any fluorinated GHG changes under the changed operating scenario by 15 percent or more of the total, relative to the previous operating scenario (this includes the cumulative change in the emission calculation factor since the last emissions test), you must repeat the emission characterization. Perform the emission characterization before February 28 of the year that immediately follows the change. In the calculations under § 98.123, apply the revised emission characterization to the process activity that occurs after the operating scenario change.
(v) Subsequent measurements. If a process vent with fluorinated GHG emissions less than 25,000 metric tons CO
(5) Emissions characterization: Process vents emitting less than 25,000 metric tons CO
(i) Uncontrolled emissions. If emissions from the process vent are not routed through a destruction device, emission measurements must consist of sampling and analysis of emissions at the process vent or stack, sampling and analysis of emitted streams before the process vent, previous test results, provided the tests are representative of current operating conditions of the process, or bench-scale or pilot-scale test data representative of the process operating conditions.
(ii) Controlled emissions using § 98.123(b)(15). If you use § 98.123(b)(15) to estimate the total mass of fluorine in destroyed or recaptured streams, and if the emissions from the process vent are routed through a destruction device, characterize emissions as specified in paragraph (b)(5)(i) of this section before the destruction device. Apply the destruction efficiency demonstrated for each fluorinated GHG in the destroyed stream to that fluorinated GHG. Exclude from the characterization fluorine-containing compounds that are not fluorinated GHGs.
(iii) Controlled emissions using § 98.123(b)(4). If you use § 98.123(b)(4) to estimate the mass of fluorine in destroyed or recaptured streams, and if the emissions from the process vent are routed through a destruction device, characterize the process vent’s emissions monthly (or more frequently) using the monthly (or more frequent) measurements under paragraphs (b)(1)(iii) and (b)(2)(i) through (iii) of this section. Apply the destruction efficiency demonstrated for each fluorinated GHG in the destroyed stream to that fluorinated GHG. Exclude from the characterization fluorine-containing compounds that are not fluorinated GHGs.
(6) Emissions characterization: Emissions not accounted for by process vent estimates. Calculate the weighted average emission characterization across the process vents before any destruction devices. Apply the weighted average emission characterization for all the process vents to any fluorine emissions that are not accounted for by process vent estimates.
(7) Impurities in reactants. If any fluorine-containing impurity is fed into a process along with a reactant (or other input) in greater than trace concentrations, this impurity shall be monitored under this section and included in the calculations under § 98.123 in the same manner as reactants fed into the process, fed into the destruction device, recaptured, or emitted, except the concentration of the impurity in the mass fed into the process shall be measured, and the mass of the impurity fed into the process shall be calculated as the product of the concentration of the impurity and the mass fed into the process. The mass of the reactant fed into the process may be reduced to account for the mass of the impurity.
(8) Alternative to error calculation. As an alternative to calculating the relative and absolute errors associated with the estimate of emissions under § 98.123(b), you may comply with the precision, accuracy, measurement and calculation frequency, and fluorinated GHG throughput requirements of paragraph (b)(8)(i) through (iv) of this section.
(i) Mass measurements. Measure the masses specified in paragraph (b)(1) of this section using flowmeters, weigh scales, or a combination of volumetric and density measurements with accuracies and precisions of ±0.2 percent of full scale or better.
(ii) Concentration measurements. Measure the concentrations specified in paragraph (b)(2) or (3) of this section, as applicable, using analytical methods with accuracies and precisions of ±10 percent or better.
(iii) Measurement and calculation frequency. Perform the mass measurements specified in paragraph (b)(1) of this section and the concentration measurements specified in paragraph (b)(2) or (3) of this section, as applicable, at least weekly, and calculate emissions at least weekly.
(iv) Fluorinated-GHG throughput limit. You may use the alternative to the error calculation specified in paragraph (b)(8) of this section only if the total annual CO
Subpart M [Reserved]
Subpart N – Glass Production
§ 98.140 Definition of the source category.
(a) A glass manufacturing facility manufactures flat glass, container glass, pressed and blown glass, or wool fiberglass by melting a mixture of raw materials to produce molten glass and form the molten glass into sheets, containers, fibers, or other shapes. A glass manufacturing facility uses one or more continuous glass melting furnaces to produce glass.
(b) A glass melting furnace that is an experimental furnace or a research and development process unit is not subject to this subpart.
§ 98.141 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a glass production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.142 GHGs to report.
You must report:
(a) CO
(b) CO
(c) CH
(d) CO
§ 98.143 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) For each continuous glass melting furnace that meets the conditions specified in § 98.33(b)(4)(ii) or (iii), you must calculate and report under this subpart the combined process and combustion CO
(b) For each continuous glass melting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO
(1) Calculate and report under this subpart the combined process and combustion CO
(2) Calculate and report the process and combustion CO
(i) For each carbonate-based raw material charged to the furnace, obtain from the supplier of the raw material the carbonate-based mineral mass fraction.
(ii) Determine the quantity of each carbonate-based raw material charged to the furnace.
(iii) Apply the appropriate emission factor for each carbonate-based raw material charged to the furnace, as shown in Table N-1 to this subpart.
(iv) Use Equation N-1 of this section to calculate process mass emissions of CO
(v) You must calculate the total process CO
(vi) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO
(c) As an alternative to data provided by the raw material supplier, a value of 1.0 can be used for the mass fraction (MF
§ 98.144 Monitoring and QA/QC requirements.
(a) You must measure annual amounts of carbonate-based raw materials charged to each continuous glass melting furnace from monthly measurements using plant instruments used for accounting purposes, such as calibrated scales or weigh hoppers. Total annual mass charged to glass melting furnaces at the facility shall be compared to records of raw material purchases for the year.
(b) Unless you use the default value of 1.0, you must measure carbonate-based mineral mass fractions at least annually to verify the mass fraction data provided by the supplier of the raw material; such measurements shall be based on sampling and chemical analysis using consensus standards that specify X-ray fluorescence. For measurements made in years prior to the emissions reporting year 2014, you may also use ASTM D3682-01 (Reapproved 2006) Standard Test Method for Major and Minor Elements in Combustion Residues from Coal Utilization Processes or ASTM D6349-09 Standard Test Method for Determination of Major and Minor Elements in Coal, Coke, and Solid Residues from Combustion of Coal and Coke by Inductively Coupled Plasma – Atomic Emission Spectrometry (both incorporated by reference, see § 98.7).
(c) Unless you use the default value of 1.0, you must determine the annual average mass fraction for the carbonate-based mineral in each carbonate-based raw material by calculating an arithmetic average of the monthly data obtained from raw material suppliers or sampling and chemical analysis.
(d) Unless you use the default value of 1.0, you must determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using an industry consensus standard. If performed, this chemical analysis must be conducted using an x-ray fluorescence test or other enhanced testing method published by an industry consensus standards organization (e.g., ASTM, ASME, API, etc.).
§ 98.145 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbonate raw materials consumed, etc.). If the monitoring and quality assurance procedures in § 98.144 cannot be followed and data is missing, you must use the most appropriate of the missing data procedures in paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such missing value estimates.
(a) For missing data on the monthly amounts of carbonate-based raw materials charged to any continuous glass melting furnace use the best available estimate(s) of the parameter(s), based on all available process data or data used for accounting purposes, such as purchase records.
(b) For missing data on the mass fractions of carbonate-based minerals in the carbonate-based raw materials assume that the mass fraction of each carbonate based mineral is 1.0.
§ 98.146 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) and (b) of this section, as applicable.
(a) If a CEMS is used to measure CO
(1) Annual quantity of each carbonate-based raw material charged to each continuous glass melting furnace and for all furnaces combined (tons).
(2) Annual quantity of glass produced by each glass melting furnace and by all furnaces combined (tons).
(b) If a CEMS is not used to determine CO
(1) Annual process emissions of CO
(2) Annual quantity of each carbonate-based raw material charged (tons) to all furnaces combined.
(3) Annual quantity of glass produced (tons) from each continuous glass melting furnace and from all furnaces combined.
(4) [Reserved]
(5) Results of all tests, if applicable, used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace, as specified in paragraphs (b)(5)(i) through (iii) of this section.
(i) Date of test.
(ii) Method(s) and any variations used in the analyses.
(iii) Mass fraction of each sample analyzed.
(6) [Reserved]
(7) Method used to determine decimal fraction of calcination, unless you used the default value of 1.0.
(8) Total number of continuous glass melting furnaces.
(9) The number of times in the reporting year that missing data procedures were followed to measure monthly quantities of carbonate-based raw materials or mass fraction of the carbonate-based minerals for any continuous glass melting furnace (months).
§ 98.147 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the records listed in paragraphs (a) through (d) of this section.
(a) If a CEMS is used to measure emissions, then you must retain the records required under § 98.37 for the Tier 4 Calculation Methodology and the following information specified in paragraphs (a)(1) and (a)(2) of this section:
(1) Monthly glass production rate for each continuous glass melting furnace (tons).
(2) Monthly amount of each carbonate-based raw material charged to each continuous glass melting furnace (tons).
(b) If process CO
(1) Monthly glass production rate for each continuous glass melting furnace (metric tons).
(2) Monthly amount of each carbonate-based raw material charged to each continuous glass melting furnace (metric tons).
(3) Data on carbonate-based mineral mass fractions provided by the raw material supplier for all raw materials consumed annually and included in calculating process emissions in Equation N-1 of this subpart, if applicable.
(4) Results of all tests, if applicable, used to verify the carbonate-based mineral mass fraction for each carbonate-based raw material charged to a continuous glass melting furnace, including the data specified in paragraphs (b)(4)(i) through (v) of this section.
(i) Date of test.
(ii) Method(s), and any variations of the methods, used in the analyses.
(iii) Mass fraction of each sample analyzed.
(iv) Relevant calibration data for the instrument(s) used in the analyses.
(v) Name and address of laboratory that conducted the tests.
(5) The decimal fraction of calcination achieved for each carbonate-based raw material, if a value other than 1.0 is used to calculate process mass emissions of CO
(c) All other documentation used to support the reported GHG emissions.
(d) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (d)(1) through (3) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (3) of this section.
(1) Annual average decimal mass fraction of carbonate-based mineral in each carbonate-based raw material for each continuous glass melting furnace (specify the default value, if used, or the value determined according to § 98.144) (percentage, expressed as a decimal) (Equation N-1 of § 98.143).
(2) Annual amount of each carbonate-based raw material charged to each continuous glass melting furnace (tons) (Equation N-1 of this subpart).
(3) Decimal fraction of calcination achieved for each carbonate-based raw material for each continuous glass melting furnace (specify the default value, if used, or the value determined according to § 98.144) (percentage, expressed as a decimal) (Equation N-1 of this subpart).
§ 98.148 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table N-1 to Subpart N of Part 98 – CO2 Emission Factors for Carbonate-Based Raw Materials
Carbonate-based raw material – mineral | CO a |
---|---|
Limestone – CaCO | 0.440 |
Dolomite – CaMg(CO | 0.477 |
Sodium carbonate/soda ash – Na | 0.415 |
Barium carbonate – BaCO | 0.223 |
Potassium carbonate – K | 0.318 |
Lithium carbonate (Li | 0.596 |
Strontium carbonate (SrCO | 0.298 |
a Emission factors in units of metric tons of CO
Subpart O – HCFC-22 Production and HFC-23 Destruction
§ 98.150 Definition of the source category.
The HCFC-22 production and HFC-23 destruction source category consists of HCFC-22 production processes and HFC-23 destruction processes.
(a) An HCFC-22 production process produces HCFC-22 (chlorodifluoromethane, or CHClF
(b) An HFC-23 destruction process is any process in which HFC-23 undergoes destruction. An HFC-23 destruction process may or may not be co-located with an HCFC-22 production process at the same facility.
§ 98.151 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an HCFC-22 production or HFC-23 destruction process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.152 GHGs to report.
(a) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(b) You must report HFC-23 emissions from HCFC-22 production processes and HFC-23 destruction processes.
§ 98.153 Calculating GHG emissions.
(a) The mass of HFC-23 generated from each HCFC-22 production process shall be estimated by using one of two methods, as applicable:
(1) Where the mass flow of the combined stream of HFC-23 and another reaction product (e.g., HCl) is measured, multiply the weekly (or more frequent) HFC-23 concentration measurement (which may be the average of more frequent concentration measurements) by the weekly (or more frequent) mass flow of the combined stream of HFC-23 and the other product. To estimate annual HFC-23 production, sum the weekly (or more frequent) estimates of the quantities of HFC-23 produced over the year. This calculation is summarized in Equation O-1 of this section:
(2) Where the mass of only a reaction product other than HFC-23 (either HCFC-22 or HCl) is measured, multiply the ratio of the weekly (or more frequent) measurement of the HFC-23 concentration and the weekly (or more frequent) measurement of the other product concentration by the weekly (or more frequent) mass produced of the other product. To estimate annual HFC-23 production, sum the weekly (or more frequent) estimates of the quantities of HFC-23 produced over the year. This calculation is summarized in Equation O-2 of this section, assuming that the other product is HCFC-22. If the other product is HCl, HCl may be substituted for HCFC-22 in Equations O-2 and O-3 of this section.
(b) The mass of HCFC-22 produced over the period p shall be estimated by using Equation O-3 of this section:
(c) For HCFC-22 production facilities that do not use a destruction device or that have a destruction device that is not directly connected to the HCFC-22 production equipment, HFC-23 emissions shall be estimated using Equation O-4 of this section:
(d) For HCFC-22 production facilities that use a destruction device connected to the HCFC-22 production equipment, HFC-23 emissions shall be estimated using Equation O-5 of this section:
(1) The mass of HFC-23 emitted annually from equipment leaks (for use in Equation O-5 of this section) shall be estimated by using Equation O-6 of this section:
(2) The mass of HFC-23 emitted annually from process vents (for use in Equation O-5 of this section) shall be estimated by using Equation O-7 of this section:
(3) The total mass of HFC-23 emitted from destruction devices shall be estimated by using Equation O-8 of this section:
(4) For facilities that destroy HFC-23, the total mass of HFC-23 destroyed shall be estimated by using Equation O-9 of this section:
§ 98.154 Monitoring and QA/QC requirements.
These requirements apply to measurements that are reported under this subpart or that are used to estimate reported quantities pursuant to § 98.153.
(a) The concentrations (fractions by weight) of HFC-23 and HCFC-22 in the product stream shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples.
(b) The mass flow of the product stream containing the HFC-23 shall be measured at least weekly using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.
(c) The mass of HCFC-22 or HCl coming out of the production process shall be measured at least weekly using weigh scales, flowmeters, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.
(d) The mass of any used HCFC-22 added back into the production process upstream of the output measurement in paragraph (c) of this section shall be measured (when being added) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the mass in paragraph (c) of this section is measured by weighing containers that include returned heels as well as newly produced fluorinated GHGs, the returned heels shall be considered used fluorinated HCFC-22 for purposes of this paragraph (d) of this section and § 98.153(b).
(e) The loss factor LF in Equation O-3 of this subpart for the mass of HCFC-22 produced shall have the value 1.015 or another value that can be demonstrated, to the satisfaction of the Administrator, to account for losses of HCFC-22 between the reactor and the point of measurement at the facility where production is being estimated.
(f) The mass of HFC-23 sent off site for sale shall be measured at least weekly (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.
(g) The mass of HFC-23 sent off site for destruction shall be measured at least weekly (when being packaged) using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than HFC-23, the concentration of the fluorinated GHG shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the HFC-23 sent to another facility for destruction.
(h) The masses of HFC-23 in storage at the beginning and end of the year shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better.
(i) The number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv shall be determined using EPA Method 21 at 40 CFR part 60, appendix A-7, and defining a leak as follows:
(1) A leak source that could emit HFC-23, and
(2) A leak source at whose surface a concentration of fluorocarbons equal to or greater than 10,000 ppm is measured.
(j) The number of sources of equipment type t with screening values less than 10,000 ppmv shall be the difference between the number of leak sources of equipment type t that could emit HFC-23 and the number of sources of equipment type t with screening values greater than or equal to 10,000 ppmv as determined under paragraph (i) of this section.
(k) The mass of HFC-23 emitted from process vents shall be estimated at least monthly by incorporating the results of the most recent emissions test into Equation O-7 of this subpart. HCFC-22 production facilities that use a destruction device connected to the HCFC-22 production equipment shall conduct emissions tests at process vents at least once every five years or after significant changes to the process. Emissions tests shall be conducted in accordance with EPA Method 18 at 40 CFR part 60, appendix A-6, under conditions that are typical for the production process at the facility. The sensitivity of the tests shall be sufficient to detect an emission rate that would result in annual emissions of 200 kg of HFC-23 if sustained over one year.
(l) For purposes of Equation O-9 of this subpart, the destruction efficiency must be equated to the destruction efficiency determined during a new or previous performance test of the destruction device. HFC-23 destruction facilities shall conduct annual measurements of HFC-23 concentrations at the outlet of the destruction device in accordance with EPA Method 18 at 40 CFR part 60, appendix A-6. Three samples shall be taken under conditions that are typical for the production process and destruction device at the facility, and the average concentration of HFC-23 shall be determined. The sensitivity of the concentration measurement shall be sufficient to detect an outlet concentration equal to or less than the outlet concentration determined in the destruction efficiency performance test. If the concentration measurement indicates that the HFC-23 concentration is less than or equal to that measured during the performance test that is the basis for the destruction efficiency, continue to use the previously determined destruction efficiency. If the concentration measurement indicates that the HFC-23 concentration is greater than that measured during the performance test that is the basis for the destruction efficiency, facilities shall either:
(1) Substitute the higher HFC-23 concentration for that measured during the destruction efficiency performance test and calculate a new destruction efficiency, or
(2) Estimate the mass emissions of HFC-23 from the destruction device based on the measured HFC-23 concentration and volumetric flow rate determined by measurement of volumetric flow rate using EPA Method 2, 2A, 2C,2D, or 2F at 40 CFR part 60, appendix A-1, or Method 26 at 40 CFR part 60, appendix A-2. Determine the mass rate of HFC-23 into the destruction device by measuring the HFC-23 concentration and volumetric flow rate at the inlet or by a metering device for HFC-23 sent to the device. Determine a new destruction efficiency based on the mass flow rate of HFC-23 into and out of the destruction device.
(m) HCFC-22 production facilities shall account for HFC-23 generation and emissions that occur as a result of startups, shutdowns, and malfunctions, either recording HFC-23 generation and emissions during these events, or documenting that these events do not result in significant HFC-23 generation and/or emissions.
(n) The mass of HFC-23 fed into the destruction device shall be measured at least weekly using flow meters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of 1.0 percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than HFC-23, the concentrations of the HFC-23 shall be measured at least weekly using equipment and methods (e.g., gas chromatography) with an accuracy and precision of 5 percent or better at the concentrations of the process samples. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the HFC-23 destroyed.
(o) In their estimates of the mass of HFC-23 destroyed, HFC-23 destruction facilities shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in State or local permitting requirements and/or destruction device manufacturer specifications.
(p) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures using NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ISO, or others). Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer.
(q) All gas chromatographs used to determine the concentration of HFC-23 in process streams shall be calibrated at least monthly through analysis of certified standards (or of calibration gases prepared from a high-concentration certified standard using a gas dilution system that meets the requirements specified in Method 205 at 40 CFR part 51, appendix M) with known HFC-23 concentrations that are in the same range (fractions by mass) as the process samples.
§ 98.155 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required process sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the following requirements:
(1) For each missing value of the HFC-23 or HCFC-22 concentration, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(2) For each missing value of the product stream mass flow or product mass, the substitute value of that parameter shall be a secondary product measurement where such a measurement is available. If that measurement is taken significantly downstream of the usual mass flow or mass measurement (e.g., at the shipping dock rather than near the reactor), the measurement shall be multiplied by 1.015 to compensate for losses. Where a secondary mass measurement is not available, the substitute value of the parameter shall be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the mass flow rate into the destruction device.
§ 98.156 Data reporting requirements.
(a) In addition to the information required by § 98.3(c), the HCFC-22 production facility shall report the following information for each HCFC-22 production process:
(1) Annual mass of HCFC-22 produced in metric tons.
(2) [Reserved]
(3) Annual mass of reactants fed into the process in metric tons of reactant.
(4) The mass (in metric tons) of materials other than HCFC-22 and HFC-23 (i.e., unreacted reactants, HCl and other by-products) that occur in more than trace concentrations and that are permanently removed from the process.
(5) The method for tracking startups, shutdowns, and malfunctions and HFC-23 generation/emissions during these events.
(6) The names and addresses of facilities to which any HFC-23 was sent for destruction, and the quantities of HFC-23 (metric tons) sent to each.
(7)-(10) [Reserved]
(11) Annual mass of HFC-23 emitted in metric tons.
(12) Annual mass of HFC-23 emitted from equipment leaks in metric tons.
(13) Annual mass of HFC-23 emitted from process vents in metric tons.
(b) In addition to the information required by § 98.3(c), facilities that destroy HFC-23 shall report the following for each HFC-23 destruction process:
(1)-(2) [Reserved]
(3) Annual mass of HFC-23 emitted from the destruction device.
(c) Each HFC-23 destruction facility shall report the concentration (mass fraction) of HFC-23 measured at the outlet of the destruction device during the facility’s annual HFC-23 concentration measurements at the outlet of the device. If the concentration of HFC-23 is below the detection limit of the measuring device, report the detection limit and that the concentration is below the detection limit.
(d) If the HFC-23 concentration measured pursuant to § 98.154(l) is greater than that measured during the performance test that is the basis for the destruction efficiency (DE), the facility shall report the method used to calculate the revised destruction efficiency, specifying whether § 98.154(l)(1) or (2) has been used for the calculation.
(e) By March 31, 2011 or within 60 days of commencing HFC-23 destruction, HFC-23 destruction facilities shall submit a one-time report including the following information for each destruction process:
(1) [Reserved]
(2) The methods used to determine destruction efficiency.
(3) The methods used to record the mass of HFC-23 destroyed.
(4) The name of other relevant federal or state regulations that may apply to the destruction process.
(5) If any changes are made that affect HFC-23 destruction efficiency or the methods used to record volume destroyed, then these changes must be reflected in a revision to this report. The revised report must be submitted to EPA within 60 days of the change.
§ 98.157 Records that must be retained.
(a) In addition to the data required by § 98.3(g), HCFC-22 production facilities shall retain the following records:
(1) The data used to estimate HFC-23 emissions.
(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements, and flowmeters used to measure the quantities reported under this rule, including the industry standards or manufacturer directions used for calibration pursuant to § 98.154(p) and (q).
(b) In addition to the data required by § 98.3(g), the HFC-23 destruction facilities shall retain the following records:
(1) Records documenting their one-time and annual reports in § 98.156(b) through (e).
(2) Records documenting the initial and periodic calibration of the gas chromatographs, weigh scales, volumetric and density measurements, and flowmeters used to measure the quantities reported under this subpart, including the industry standard practice or manufacturer directions used for calibration pursuant to § 98.154(p) and (q).
(c) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) through (16) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (16) of this section.
(1) Factor to account for the loss of HCFC-22 upstream of the measurement over the period, determined pursuant to § 98.154(e) (Equation O-3 of § 98.153).
(2) Mass of HCFC-22 that is measured coming out of the production process over the period. A period can be one year (kg) (Equation O-3).
(3) Mass of used HCFC-22 that is added to the production process upstream of the output measurement over the period. A period can be one year (kg) (Equation O-3).
(4) Mass of HFC-23 generated annually per HCFC-22 production process (metric tons) (Equation O-4 of § 98.153).
(5) Mass of HFC-23 sent off site for sale annually per HCFC-22 production process (metric tons) (Equation O-4).
(6) Mass of HFC-23 sent off site for destruction annually per HCFC-22 production process (metric tons) (Equation O-4).
(7) Mass of HFC-23 destroyed on site per HCFC-22 production process (metric tons) (Equation O-4).
(8) HFC-23 in storage at end of year per HCFC-22 production process (metric tons) (Equation O-4).
(9) HFC-23 in storage at beginning of year per HCFC-22 production process (metric tons) (Equation O-4).
(10) Mass of HFC-23 fed into each destruction device annually per HCFC-22 production process (metric tons) (Equation O-9 of § 98.153 and the calculation method in either § 98.154(l)(1) or (2)).
(11) Identify if each destruction efficiency for each HCFC-22 production process is entered directly, or is calculated using § 98.154(l)(1), or is calculated using § 98.154(l)(2) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
(12) Destruction efficiency of each destruction device for each HCFC-22 production process (decimal fraction) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
(13) Volumetric flow rate at the inlet of each destruction device for each HCFC-22 production process from previous test (kg/hr) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
(14) Volumetric flow rate at the inlet of destruction device during test for each HCFC-22 production process (kg/hr) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
(15) Concentration of HFC-23 at the inlet of destruction device for each HCFC-22 production process from previous test (weight fraction) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
(16) Concentration of HFC-23 at the inlet of destruction device for each HCFC-22 production process during test (weight fraction) (Equation O-9 and the calculation method in either § 98.154(l)(1) or (2)).
§ 98.158 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table O-1 to Subpart O of Part 98 – Emission Factors for Equipment Leaks
Equipment type | Service | Emission factor (kg/hr/source) | |
---|---|---|---|
≥10,000 ppmv | |||
Valves | Gas | 0.0782 | 0.000131 |
Valves | Light liquid | 0.0892 | 0.000165 |
Pump seals | Light liquid | 0.243 | 0.00187 |
Compressor seals | Gas | 1.608 | 0.0894 |
Pressure relief valves | Gas | 1.691 | 0.0447 |
Connectors | All | 0.113 | 0.0000810 |
Open-ended lines | All | 0.01195 | 0.00150 |
Subpart P – Hydrogen Production
§ 98.160 Definition of the source category.
(a) A hydrogen production source category consists of facilities that produce hydrogen gas sold as a product to other entities.
(b) This source category comprises process units that produce hydrogen by reforming, gasification, oxidation, reaction, or other transformations of feedstocks.
(c) This source category includes merchant hydrogen production facilities located within another facility if they are not owned by, or under the direct control of, the other facility’s owner and operator.
§ 98.161 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a hydrogen production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.162 GHGs to report.
You must report:
(a) CO
(b) [Reserved]
(c) CO
(d) For CO
§ 98.163 Calculating GHG emissions.
You must calculate and report the annual CO
(a) Continuous Emissions Monitoring Systems (CEMS). Calculate and report under this subpart the CO
(b) Fuel and feedstock material balance approach. Calculate and report CO
(1) Gaseous fuel and feedstock. You must calculate the annual CO
(2) Liquid fuel and feedstock. You must calculate the annual CO
(3) Solid fuel and feedstock. You must calculate the annual CO
(c) If GHG emissions from a hydrogen production process unit are vented through the same stack as any combustion unit or process equipment that reports CO
§ 98.164 Monitoring and QA/QC requirements.
The GHG emissions data for hydrogen production process units must be quality-assured as specified in paragraphs (a) or (b) of this section, as appropriate for each process unit:
(a) If a CEMS is used to measure GHG emissions, then the facility must comply with the monitoring and QA/QC procedures specified in § 98.34(c).
(b) If a CEMS is not used to measure GHG emissions, then you must:
(1) Calibrate all oil and gas flow meters that are used to measure liquid and gaseous fuel and feedstock volumes (except for gas billing meters) according to the monitoring and QA/QC requirements for the Tier 3 methodology in § 98.34(b)(1). Perform oil tank drop measurements (if used to quantify liquid fuel or feedstock consumption) according to § 98.34(b)(2). Calibrate all solids weighing equipment according to the procedures in § 98.3(i).
(2) Determine the carbon content and the molecular weight annually of standard gaseous hydrocarbon fuels and feedstocks having consistent composition (e.g., natural gas). For other gaseous fuels and feedstocks (e.g., biogas, refinery gas, or process gas), sample and analyze no less frequently than weekly to determine the carbon content and molecular weight of the fuel and feedstock.
(3) Determine the carbon content of fuel oil, naphtha, and other liquid fuels and feedstocks at least monthly, except annually for standard liquid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for liquid fuels and feedstocks delivered by bulk transport (e.g., by truck or rail).
(4) Determine the carbon content of coal, coke, and other solid fuels and feedstocks at least monthly, except annually for standard solid hydrocarbon fuels and feedstocks having consistent composition, or upon delivery for solid fuels and feedstocks delivered by bulk transport (e.g., by truck or rail).
(5) You must use the following applicable methods to determine the carbon content for all fuels and feedstocks, and molecular weight of gaseous fuels and feedstocks. Alternatively, you may use the results of chromatographic analysis of the fuel and feedstock, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions; and the methods used for operation, maintenance, and calibration of the chromatograph are documented in the written monitoring plan for the unit under § 98.3(g)(5).
(i) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(ii) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(iii) ASTM D2013-07 Standard Practice of Preparing Coal Samples for Analysis (incorporated by reference, see § 98.7).
(iv) ASTM D2234/D2234M-07 Standard Practice for Collection of a Gross Sample of Coal (incorporated by reference, see § 98.7).
(v) ASTM D2597-94 (Reapproved 2004) Standard Test Method for Analysis of Demethanized Hydrocarbon Liquid Mixtures Containing Nitrogen and Carbon Dioxide by Gas Chromatography (incorporated by reference, see § 98.7).
(vi) ASTM D3176-89 (Reapproved 2002), Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7).
(vii) ASTM D3238-95 (Reapproved 2005), Standard Test Method for Calculation of Carbon Distribution and Structural Group Analysis of Petroleum Oils by the n-d-M Method (incorporated by reference, see § 98.7).
(viii) ASTM D4057-06 Standard Practice for Manual Sampling of Petroleum and Petroleum Products (incorporated by reference, see § 98.7).
(ix) ASTM D4177-95 (Reapproved 2005) Standard Practice for Automatic Sampling of Petroleum and Petroleum Products (incorporated by reference, see § 98.7).
(x) ASTM D5291-02 (Reapproved 2007), Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7).
(xi) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).
(xii) ASTM D6609-08 Standard Guide for Part-Stream Sampling of Coal (incorporated by reference, see § 98.7).
(xiii) ASTM D6883-04 Standard Practice for Manual Sampling of Stationary Coal from Railroad Cars, Barges, Trucks, or Stockpiles (incorporated by reference, see § 98.7).
(xiv) ASTM D7430-08ae1 Standard Practice for Mechanical Sampling of Coal (incorporated by reference, see § 98.7).
(xv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(xvi) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see § 98.7).
(xvii) ISO 3170: Petroleum Liquids – Manual sampling – Third Edition (incorporated by reference, see § 98.7).
(xviii) ISO 3171: Petroleum Liquids – Automatic pipeline sampling – Second Edition (incorporated by reference, see § 98.7).
§ 98.165 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation), a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a), (b), and (c) of this section:
(a) For each missing value of the monthly fuel and feedstock consumption, the substitute data value must be the best available estimate of the fuel and feedstock consumption, based on all available process data (e.g., hydrogen production, electrical load, and operating hours). You must document and keep records of the procedures used for all such estimates.
(b) For each missing value of the carbon content or molecular weight of the fuel and feedstock, the substitute data value must be the arithmetic average of the quality-assured values of carbon contents or molecular weight of the fuel and feedstock immediately preceding and immediately following the missing data incident. If no quality-assured data on carbon contents or molecular weight of the fuel and feedstock are available prior to the missing data incident, the substitute data value must be the first quality-assured value for carbon contents or molecular weight of the fuel and feedstock obtained after the missing data period. You must document and keep records of the procedures used for all such estimates.
(c) For missing CEMS data, you must use the missing data procedures in § 98.35.
§ 98.166 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as appropriate, and paragraphs (c) through (e) of this section:
(a) If a CEMS is used to measure CO
(1) Unit identification number and annual CO
(2) Annual quantity of hydrogen produced (metric tons) for each process unit.
(3) Annual quantity of ammonia produced (metric tons), if applicable, for each process unit.
(b) If a CEMS is not used to measure CO
(1) Unit identification number and annual CO
(2) [Reserved]
(3) Annual quantity of hydrogen produced (metric tons).
(4) Annual quantity of ammonia intentionally produced as a desired product, if applicable (metric tons).
(5)-(6) [Reserved]
(7) Name and annual quantity (metric tons) of each carbon-containing fuel and feedstock.
(c) Quantity of CO
(d) Annual quantity of carbon other than CO
(e) Annual quantity of methanol intentionally produced as a desired product, if applicable, (metric tons) for each process unit.
§ 98.167 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section for each hydrogen production facility.
(a) If a CEMS is used to measure CO
(b) If a CEMS is not used to measure CO
(c) For units using the calculation methodologies described in § 98.163(b), the records required under § 98.3(g) must include both the company records and a detailed explanation of how company records are used to estimate the following:
(1) Fuel and feedstock consumption, when solid fuel and feedstock is combusted and a CEMS is not used to measure GHG emissions.
(2) Fossil fuel consumption, when, pursuant to § 98.33(e), the owner or operator of a unit that uses CEMS to quantify CO
(3) Sorbent usage, if the methodology in § 98.33(d) is used to calculate CO
(d) The owner or operator must document the procedures used to ensure the accuracy of the estimates of fuel and feedstock usage and sorbent usage (as applicable) in § 98.163(b), including, but not limited to, calibration of weighing equipment, fuel and feedstock flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(e) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (e)(1) through (12) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (e)(1) through (12) of this section.
(1) Indicate whether the monthly consumption of each gaseous fuel or feedstock is measured as mass or volume (Equation P-1 of § 98.163).
(2) Monthly volume of the gaseous fuel or feedstock (scf at standard conditions of 68 °F and atmospheric pressure) (Equation P-1).
(3) Monthly mass of the gaseous fuel or feedstock (kg of fuel or feedstock) (Equation P-1).
(4) Average monthly carbon content of the gaseous fuel or feedstock (kg C per kg of fuel or feedstock) (Equation P-1).
(5) Average monthly molecular weight of the gaseous fuel or feedstock (kg/kg-mole) (Equation P-1).
(6) Indicate whether the monthly consumption of each liquid fuel or feedstock is measured as mass or volume (Equation P-2 of § 98.163).
(7) Monthly volume of the liquid fuel or feedstock (gallons of fuel or feedstock) (Equation P-2).
(8) Monthly mass of the liquid fuel or feedstock (kg of fuel or feedstock) (Equation P-2).
(9) Average monthly carbon content of the liquid fuel or feedstock (kg C per gallon of fuel or feedstock) (Equation P-2).
(10) Average monthly carbon content of the liquid fuel or feedstock (kg C per kg of fuel or feedstock) (Equation P-2).
(11) Monthly mass of solid fuel or feedstock (kg of fuel and feedstock) (Equation P-3 of § 98.163).
(12) Average monthly carbon content of the solid fuel or feedstock (kg C per kg of fuel and feedstock) (Equation P-3).
§ 98.168 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart Q – Iron and Steel Production
§ 98.170 Definition of the source category.
The iron and steel production source category includes facilities with any of the following processes: taconite iron ore processing, integrated iron and steel manufacturing, cokemaking not collocated with an integrated iron and steel manufacturing process, direct reduction furnaces not collocated with an integrated iron and steel manufacturing process, and electric arc furnace (EAF) steelmaking not collocated with an integrated iron and steel manufacturing process. Integrated iron and steel manufacturing means the production of steel from iron ore or iron ore pellets. At a minimum, an integrated iron and steel manufacturing process has a basic oxygen furnace for refining molten iron into steel. Each cokemaking process and EAF process located at a facility with an integrated iron and steel manufacturing process is part of the integrated iron and steel manufacturing facility.
§ 98.171 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an iron and steel production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.172 GHGs to report.
(a) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(b) You must report CO
(c) You must report process CO
§ 98.173 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process CO
(b) Calculate and report under this subpart the process CO
(1) Carbon mass balance method. Calculate the annual mass emissions of CO
(i) For taconite indurating furnaces, estimate CO
(ii) For basic oxygen process furnaces, estimate CO
(iii) For non-recovery coke oven batteries, estimate CO
(iv) For sinter processes, estimate CO
(v) For EAFs, estimate CO
(vi) For decarburization vessels, estimate CO
(vii) For direct reduction furnaces, estimate CO
(2) Site-specific emission factor method. Conduct a performance test and measure CO
(i) You must measure the process production rate or process feed rate, as applicable, during the performance test according to the procedures in § 98.174(c)(5) and calculate the average rate for the test period in metric tons per hour.
(ii) You must calculate the hourly CO
(iii) You must calculate a site-specific emission factor for the process in metric tons of CO
(iv) You must calculate CO
(c) You must determine emissions of CO
(d) If GHG emissions from a taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, EAF, decarburization vessel, or direct reduction furnace are vented through a stack equipped with a CEMS that complies with the Tier 4 methodology in subpart C of this part, or through the same stack as any combustion unit or process equipment that reports CO
§ 98.174 Monitoring and QA/QC requirements.
(a) If you operate and maintain a CEMS that measures CO
(b) If you determine CO
(1) Except as provided in paragraph (b)(4) of this section, determine the mass of each process input and output other than fuels using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk density and volume measurements, etc.), record the totals for each process input and output for each calendar month, and sum the monthly mass to determine the annual mass for each process input and output. Determine the mass rate of fuels using the procedures for combustion units in § 98.34. No determination of the mass of steel output from decarburization vessels is required.
(2) Except as provided in paragraph (b)(4) of this section, determine the carbon content of each process input and output annually for use in the applicable equations in § 98.173(b)(1) based on analyses provided by the supplier or by the average carbon content determined by collecting and analyzing at least three samples each year using the standard methods specified in paragraphs (b)(2)(i) through (b)(2)(vi) of this section as applicable.
(i) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7) for limestone, dolomite, and slag.
(ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7) for coal, coke, and other carbonaceous materials.
(iii) ASTM E1915-07a, Standard Test Methods for Analysis of Metal Bearing Ores and Related Materials by Combustion Infrared-Absorption Spectrometry (incorporated by reference, see § 98.7) for iron ore, taconite pellets, and other iron-bearing materials.
(iv) ASTM E1019-08, Standard Test Methods for Determination of Carbon, Sulfur, Nitrogen, and Oxygen in Steel, Iron, Nickel, and Cobalt Alloys by Various Combustion and Fusion Techniques (incorporated by reference, see § 98.7) for iron and ferrous scrap.
(v) ASM CS-104 UNS No. G10460 – Alloy Digest April 1985 (Carbon Steel of Medium Carbon Content) (incorporated by reference, see § 98.7); ISO/CSAPR 15349-1:1998, Unalloyed steel – Determination of low carbon content, Part 1: Infrared absorption method after combustion in an electric resistance furnace (by peak separation) (1998-10-15) First Edition (incorporated by reference, see § 98.7); or ISO/CSAPR 15349-3:1998, Unalloyed steel-Determination of low carbon content Part 3: Infrared absorption method after combustion in an electric resistance furnace (with preheating) (1998-10-15) First Edition (incorporated by reference, see § 98.7) as applicable for steel.
(vi) For each process input that is a fuel, determine the carbon content and molecular weight (if applicable) using the applicable methods listed in § 98.34.
(3) For solid ferrous materials charged to basic oxygen process furnaces or EAFs that differ in carbon content, you may determine a weighted average carbon content based on the carbon content of each type of ferrous material and the average weight percent of each type that is used. Examples of these different ferrous materials include carbon steel, low carbon steel, stainless steel, high alloy steel, pig iron, iron scrap, and direct reduced iron.
(4) If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.
(5) Except as provided in paragraph (b)(4) of this section, you must determine the annual carbon content and monthly mass rate of any input or output that contains carbon that is not listed in the equations in § 98.173(b)(1) using the procedures in paragraphs (b)(1) and (b)(2) of this section.
(c) If you determine CO
(1) Conduct an annual performance test that is based on representative performance (i.e., performance based on normal operating conditions) of the affected process.
(2)(i) For the exhaust from basic oxygen furnaces, EAFs, decarburization vessels, and direct reduction furnaces, sample the furnace exhaust for at least three complete production cycles that start when the furnace is being charged and end after steel or iron and slag have been tapped. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel.
(ii) For the exhaust from continuously charged EAFs, sample the exhaust for a period spanning at least three hours. For EAFs that produce both carbon steel and stainless or specialty (low carbon) steel, develop an emission factor for the production of both types of steel.
(3) For taconite indurating furnaces, non-recovery coke batteries, and sinter processes, sample for at least 3 hours.
(4) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix A-2 to measure the CO
(5) Determine the mass rate of process feed or process production (as applicable) during the test using the same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, combination of bulk density and volume measurements, etc.)
(6) If your process operates under different conditions as part of normal operations in such a manner that CO
(7) If your EAF and decarburization vessel exhaust to a common emission control device and stack, you must sample each process in the ducts before the emissions are combined, sample each process when only one process is operating, or sample the combined emissions when both processes are operating and base the site-specific emission factor on the steel production rate of the EAF.
(8) The results of a performance test must include the analysis of samples, determination of emissions, and raw data. The performance test report must contain all information and data used to derive the emission factor.
(d) For a coke pushing process, determine the metric tons of coal charged to the coke ovens and record the totals for each pushing process for each calendar month. Coal charged to coke ovens can be measured using weigh belts or a combination of measuring volume and bulk density.
§ 98.175 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations in § 98.173 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must follow the missing data procedures in § 98.255(b) of subpart Y (Petroleum Refineries) of this part for flares burning coke oven gas or blast furnace gas. You must document and keep records of the procedures used for all such estimates.
(a) Except as provided in § 98.174(b)(4), 100 percent data availability is required for the carbon content of inputs and outputs for facilities that estimate emissions using the carbon mass balance procedure in § 98.173(b)(1) or facilities that estimate emissions using the site-specific emission factor procedure in § 98.173(b)(2).
(b) For missing records of the monthly mass or volume of carbon-containing inputs and outputs using the carbon mass balance procedure in § 98.173(b)(1), the substitute data value must be based on the best available estimate of the mass of the input or output material from all available process data or data used for accounting purposes.
§ 98.176 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information required in paragraphs (a) through (h) of this section for each coke pushing operation; taconite indurating furnace; basic oxygen furnace; non-recovery coke oven battery; sinter process; EAF; decarburization vessel; direct reduction furnace; and flare burning coke oven gas or blast furnace gas. For reporting year 2010, the information required in paragraphs (a) through (h) of this section is not required for decarburization vessels that are not argon-oxygen decarburization vessels. For reporting year 2011 and each subsequent reporting year, the information in paragraphs (a) through (h) of this section must be reported for all decarburization vessels.
(a) Unit identification number and annual CO
(b) If a CEMS is used to measure CO
(c) If a CEMS is used to measure CO
(d) If a CEMS is not used to measure CO
(e) If you use the carbon mass balance method in § 98.173(b)(1) to determine CO
(1) [Reserved]
(2) Whether the carbon content was determined from information from the supplier or by laboratory analysis, and if by laboratory analysis, the method used.
(3)-(4) [Reserved]
(5) If you used the missing data procedures in § 98.175(b), you must report how the monthly mass for each process input or output with missing data was determined and the number of months the missing data procedures were used.
(6) The information specified in paragraphs (e)(6)(i) through (vi) of this section aggregated for all process units for which CO
(i) The annual mass (metric tons) of all gaseous, liquid, and solid fuels (combined) used in process units for which CO
(ii) The annual mass (metric tons) of all non-fuel material inputs (combined) specified in Equations Q-1 through Q-7 of § 98.173, calculated as specified in Equation Q-10 of this section.
(iii) The annual mass (metric tons) of all solid and liquid products and byproducts (combined) specified in Equations Q-1 through Q-7 of § 98.173, calculated as specified in Equation Q-11 of this section.
(iv) The weighted average carbon content of all gaseous, liquid, and solid fuels (combined) included in Equation Q-9 of this section, calculated as specified in Equation Q-12 of this section.
(v) The weighted average carbon content of all non-fuel inputs to all process units (combined) included in Equation Q-10 of this section, calculated as specified in Equation Q-13 of this section.
(vi) The weighted average carbon content of all solid and liquid products and byproducts from all process units (combined) included in Equation Q-11 of this section, calculated as specified in Equation Q-14 of this section.
(f) If you used the site-specific emission factor method in § 98.173(b)(2) to determine CO
(1) The measured average hourly CO
(2)-(4) [Reserved]
(g) [Reserved]
(h) For flares burning coke oven gas or blast furnace gas, the information specified in § 98.256(e) of subpart Y (Petroleum Refineries) of this part.
§ 98.177 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (f) of this section, as applicable. Facilities that use CEMS to measure emissions must also retain records of the verification data required for the Tier 4 Calculating Methodology in § 98.36(e).
(a) Records of all analyses and calculations conducted, including all information reported as required under § 98.176.
(b) When the carbon mass balance method is used to estimate emissions for a process, the monthly mass of each process input and output that are used to determine the annual mass, except that no determination of the mass of steel output from decarburization vessels is required.
(c) Production capacity (in metric tons per year) for the production of taconite pellets, coke, sinter, iron, and raw steel.
(d) Annual operating hours for each taconite indurating furnace, basic oxygen furnace, non-recovery coke oven battery, sinter process, electric arc furnace, decarburization vessel, and direct reduction furnace.
(e) Facilities must keep records that include a detailed explanation of how company records or measurements are used to determine all sources of carbon input and output and the metric tons of coal charged to the coke ovens (e.g., weigh belts, a combination of measuring volume and bulk density). You also must document the procedures used to ensure the accuracy of the measurements of fuel usage including, but not limited to, calibration of weighing equipment, fuel flow meters, coal usage including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(f) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (f)(1) through (9) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (f)(1) through (9) of this section.
(1) The data in paragraphs (f)(1)(i) through (xxv) of this section for each applicable taconite indurating furnace for which the carbon mass balance method of reporting is used.
(i) Annual mass of each solid fuel (metric tons) (Equation Q-1 of § 98.173).
(ii) Carbon content of each solid fuel, from the fuel analysis (expressed as a decimal fraction) (Equation Q-1).
(iii) Annual volume of each gaseous fuel (scf) (Equation Q-1).
(iv) Average carbon content of each gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-1).
(v) Molecular weight of each gaseous fuel (kg/kg-mole) (Equation Q-1).
(vi) Annual volume of each liquid fuel (gallons) (Equation Q-1).
(vii) Carbon content of each liquid fuel, from the fuel analysis results (kg C per gallon of fuel) (Equation Q-1).
(viii) Annual mass of the greenball (taconite) pellets fed to the furnace (metric tons) (Equation Q-1).
(ix) Carbon content of the greenball (taconite) pellets, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-1).
(x) Annual mass of fired pellets produced by the furnace (metric tons) (Equation Q-1).
(xi) Carbon content of the fired pellets, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-1).
(xii) Annual mass of air pollution control residue collected (metric tons) (Equation Q-1).
(xiii) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-1).
(xiv) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-1).
(xv) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-1).
(xvi) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-1).
(xvii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-1).
(xviii) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-1).
(xix) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-1).
(xx) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-1).
(xxi) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-1).
(xxii) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-1).
(xxiii) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-1).
(xxiv) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-1).
(xxv) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-1).
(2) The data in paragraphs (f)(2)(i) through (xxvi) of this section for each applicable basic oxygen process furnace for which the carbon mass balance method of reporting is used.
(i) Annual mass of molten iron charged to the furnace (metric tons) (Equation Q-2 of § 98.173).
(ii) Carbon content of the molten iron charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(iii) Annual mass of ferrous scrap charged to the furnace (metric tons) (Equation Q-2).
(iv) Carbon content of the ferrous scrap charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(v) Annual mass of the flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons) (Equation Q-2).
(vi) Carbon content of the flux materials charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(vii) Annual mass of the carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons) (Equation Q-2).
(viii) Carbon content of the carbonaceous materials charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(ix) Annual mass of molten raw steel produced by the furnace (metric tons) (Equation Q-2).
(x) Carbon content of the steel produced by the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(xi) Annual mass of slag produced by the furnace (metric tons) (Equation Q-2).
(xii) Carbon content of the slag produced by the furnace, from the carbon analysis (expressed as a decimal fraction) (Equation Q-2).
(xiii) Annual mass of air pollution control residue collected for the furnace (metric tons) (Equation Q-2).
(xiv) Carbon content of the air pollution control residue collected for the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-2).
(xv) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-2).
(xvi) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-2).
(xvii) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-2).
(xviii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-2).
(xix) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-2).
(xx) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-2).
(xxi) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-2).
(xxii) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-2).
(xxiii) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-2).
(xxiv) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-2).
(xxv) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-2).
(xxvi) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-2).
(3) The data in paragraphs (f)(3)(i) through (xviii) of this section for each applicable non-recovery coke oven battery for which the carbon mass balance method of reporting is used.
(i) Annual mass of coal charged to the battery (metric tons) (Equation Q-3 of § 98.173).
(ii) Carbon content of the coal, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-3).
(iii) Annual mass of coke produced by the battery (metric tons) (Equation Q-3).
(iv) Carbon content of the coke, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-3).
(v) Annual mass of air pollution control residue collected (metric tons) (Equation Q-3).
(vi) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-3).
(vii) Annual mass of each other solid input containing carbon fed to each battery (metric tons) (Equation Q-3).
(viii) Carbon content of each other solid input containing carbon fed to each battery (expressed as a decimal fraction) (Equation Q-3).
(ix) Annual mass of each other solid output containing carbon produced by each battery (metric tons) (Equation Q-3).
(x) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-3).
(xi) Annual mass of each other gaseous input containing carbon fed to each battery (metric tons) (Equation Q-3).
(xii) Carbon content of each other gaseous input containing carbon fed to each battery (expressed as a decimal fraction) (Equation Q-3).
(xiii) Annual mass of each other gaseous output containing carbon produced by each battery (metric tons) (Equation Q-3).
(xiv) Carbon content of each other gaseous output containing carbon produced by each battery (expressed as a decimal fraction) (Equation Q-3).
(xv) Annual mass of each other liquid input containing carbon fed to each battery (metric tons) (Equation Q-3).
(xvi) Carbon content of each other liquid input containing carbon fed to each battery (expressed as a decimal fraction) (Equation Q-3).
(xvii) Annual mass of each other liquid output containing carbon produced by each battery (metric tons) (Equation Q-3).
(xviii) Carbon content of each other liquid output containing carbon produced by each battery (expressed as a decimal fraction) (Equation Q-3).
(4) The data in paragraphs (f)(4)(i) through (xxi) of this section for each applicable sinter process for which the carbon mass balance method of reporting is used.
(i) Annual volume of the gaseous fuel (scf) (Equation Q-4 of § 98.173).
(ii) Carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-4).
(iii) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-4).
(iv) Annual mass of sinter feed material (metric tons) (Equation Q-4).
(v) Carbon content of the mixed sinter feed materials that form the bed entering the sintering machine, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-4).
(vi) Annual mass of sinter produced (metric tons) (Equation Q-4).
(vii) Carbon content of the sinter pellets, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-4).
(viii) Annual mass of air pollution control residue collected (metric tons) (Equation Q-4).
(ix) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-4).
(x) Annual mass of each other solid input containing carbon fed to each sinter process (metric tons) (Equation Q-4).
(xi) Carbon content of each other solid input containing carbon fed to each sinter process (expressed as a decimal fraction) (Equation Q-4).
(xii) Annual mass of each other solid output containing carbon produced by each sinter process (metric tons) (Equation Q-4).
(xiii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-4).
(xiv) Annual mass of each other gaseous input containing carbon fed to each sinter process (metric tons) (Equation Q-4).
(xv) Carbon content of each other gaseous input containing carbon fed to each sinter process (expressed as a decimal fraction) (Equation Q-4).
(xvi) Annual mass of each other gaseous output containing carbon produced by each sinter process (metric tons) (Equation Q-4).
(xvii) Carbon content of each other gaseous output containing carbon produced by each sinter process (expressed as a decimal fraction) (Equation Q-4).
(xviii) Annual mass of each other liquid input containing carbon fed to each sinter process (metric tons) (Equation Q-4).
(xix) Carbon content of each other liquid input containing carbon fed to each sinter process (expressed as a decimal fraction) (Equation Q-4).
(xx) Annual mass of each other liquid output containing carbon produced by each sinter process (metric tons) (Equation Q-4).
(xxi) Carbon content of each other liquid output containing carbon produced by each sinter process (expressed as a decimal fraction) (Equation Q-4).
(5) The data in paragraphs (f)(5)(i) through (xxxi) of this section for each applicable electric arc furnace for which the carbon mass balance method of reporting is used.
(i) Annual mass of direct reduced iron (if any) charged to the furnace (metric tons) (Equation Q-5 of § 98.173).
(ii) Carbon content of the direct reduced iron, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5)
(iii) Annual mass of ferrous scrap charged to the furnace (metric tons) (Equation Q-5).
(iv) Carbon content of the ferrous scrap, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(v) Annual mass of flux materials (e.g., limestone, dolomite) charged to the furnace (metric tons) (EquationQ-5).
(vi) Carbon content of the flux materials, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(vii) Annual mass of carbon electrode consumed (metric tons) (Equation Q-5).
(viii) Carbon content of the carbon electrode, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(ix) Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons) (Equation Q-5).
(x) Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(xi) Annual mass of molten raw steel produced by the furnace (metric tons) (Equation Q-5).
(xii) Carbon content of the steel, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(xiii) Annual volume of the gaseous fuel (scf at 60F and 1 atm) (Equation Q-5).
(xiv) Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-5).
(xv) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-5).
(xvi) Annual mass of slag produced by the furnace (metric tons) (Equation Q-5).
(xvii) Carbon content of the slag, from the carbon analysis (expressed as a decimal fraction) (Equation Q-5).
(xviii) Annual mass of air pollution control residue collected (metric tons) (Equation Q-5).
(xix) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-5).
(xx) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-5).
(xxi) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-5).
(xxii) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-5).
(xxiii) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-5).
(xxiv) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-5).
(xxv) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-5).
(xxvi) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-5).
(xxvii) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-5).
(xxviii) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-5).
(xxix) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-5).
(xxx) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-5).
(xxxi) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-5).
(6) The data in paragraphs (f)(6)(i) through (xvii) of this section for each applicable decarburization vessel for which the carbon mass balance method of reporting is used.
(i) Annual mass of molten steel charged to the vessel (metric tons) (Equation Q-6 of § 98.173).
(ii) Carbon content of the molten steel before decarburization, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-6).
(iii) Carbon content of the molten steel after decarburization, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-6).
(iv) Annual mass of air pollution control residue collected (metric tons) (Equation Q-6).
(v) Carbon content of the air pollution control residue, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-6).
(vi) Annual mass of each other solid input containing carbon fed to each decarburization vessel (metric tons) (Equation Q-6).
(vii) Carbon content of each other solid input containing carbon fed to each decarburization vessel (expressed as a decimal fraction) (Equation Q-6).
(viii) Annual mass of each other solid output containing carbon produced by each decarburization vessel (metric tons) (Equation Q-6).
(ix) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-6).
(x) Annual mass of each other gaseous input containing carbon fed to each decarburization vessel (metric tons) (Equation Q-6).
(xi) Carbon content of each other gaseous input containing carbon fed to each decarburization vessel (expressed as a decimal fraction) (Equation Q-6).
(xii) Annual mass of each other gaseous output containing carbon produced by each decarburization vessel (metric tons) (Equation Q-6).
(xiii) Carbon content of each other gaseous output containing carbon produced by each decarburization vessel (expressed as a decimal fraction) (Equation Q-6).
(xiv) Annual mass of each other liquid input containing carbon fed to each decarburization vessel (metric tons) (Equation Q-6).
(xv) Carbon content of each other liquid input containing carbon fed to each decarburization vessel (expressed as a decimal fraction) (Equation Q-6).
(xvi) Annual mass of each other liquid output containing carbon produced by each decarburization vessel (metric tons) (Equation Q-6).
(xvii) Carbon content of each other liquid output containing carbon produced by each decarburization vessel (expressed as a decimal fraction) (Equation Q-6).
(7) The data in paragraphs (f)(7)(i) through (xxvii) of this section for each applicable direct reduction furnace for which the carbon mass balance method of reporting is used.
(i) Annual volume of the gaseous fuel (scf at 68F and 1 atm) (Equation Q-7 of § 98.173).
(ii) Average carbon content of the gaseous fuel, from the fuel analysis results (kg C per kg of fuel) (Equation Q-7).
(iii) Molecular weight of the gaseous fuel (kg/kg-mole) (Equation Q-7).
(iv) Annual mass of iron ore or iron pellets fed to the furnace (metric tons) (Equation Q-7).
(v) Carbon content of the iron ore or iron pellets, from the carbon analysis (expressed as a decimal fraction) (Equation Q-7).
(vi) Annual mass of carbonaceous materials (e.g., coal, coke) charged to the furnace (metric tons) (Equation Q-7).
(vii) Carbon content of the carbonaceous materials, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7).
(viii) Annual mass of each other material charged to the furnace (metric tons) (Equation Q-7).
(ix) Average carbon content of each other material charged to the furnace, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7).
(x) Annual mass of iron produced (metric tons) (Equation Q-7).
(xi) Carbon content of the iron produced, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7).
(xii) Annual mass of non-metallic materials produced by the furnace (metric tons) (Equation Q-7).
(xiii) Carbon content of the non-metallic materials produced, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7).
(xiv) Annual mass of air pollution control residue collected (metric tons) (Equation Q-7).
(xv) Carbon content of the air pollution control residue collected, from the carbon analysis results (expressed as a decimal fraction) (Equation Q-7).
(xvi) Annual mass of each other solid input containing carbon fed to each furnace (metric tons) (Equation Q-7).
(xvii) Carbon content of each other solid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-7).
(xviii) Annual mass of each other solid output containing carbon produced by each furnace (metric tons) (Equation Q-7).
(xix) Carbon content of each other solid output containing carbon (expressed as a decimal fraction) (Equation Q-7).
(xx) Annual mass of each other gaseous input containing carbon fed to each furnace (metric tons) (Equation Q-7).
(xxi) Carbon content of each other gaseous input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-7).
(xxii) Annual mass of each other gaseous output containing carbon produced by each furnace (metric tons) (Equation Q-7).
(xxiii) Carbon content of each other gaseous output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-7).
(xxiv) Annual mass of each other liquid input containing carbon fed to each furnace (metric tons) (Equation Q-7).
(xxv) Carbon content of each other liquid input containing carbon fed to each furnace (expressed as a decimal fraction) (Equation Q-7).
(xxvi) Annual mass of each other liquid output containing carbon produced by each furnace (metric tons) (Equation Q-7).
(xxvii) Carbon content of each other liquid output containing carbon produced by each furnace (expressed as a decimal fraction) (Equation Q-7).
(8) The data in paragraphs (f)(8)(i) and (ii) of this section for each process unit for which the site-specific emission factor method was used.
(i) Average hourly feed or production rate, as applicable, during the test (metric tons/hour) (as used in § 98.173(b)(2)(iii)).
(ii) Annual total feed or production, as applicable (metric tons) (as used in § 98.173(b)(2)(iv)).
(9) Total coal charged to the coke ovens for each process (metric tons/year)(as used in § 98.173(c)).
§ 98.178 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart R – Lead Production
§ 98.180 Definition of the source category.
The lead production source category consists of primary lead smelters and secondary lead smelters. A primary lead smelter is a facility engaged in the production of lead metal from lead sulfide ore concentrates through the use of pyrometallurgical techniques. A secondary lead smelter is a facility at which lead-bearing scrap materials (including but not limited to, lead-acid batteries) are recycled by smelting into elemental lead or lead alloys.
§ 98.181 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a lead production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.182 GHGs to report.
You must report:
(a) Process CO
(b) CO
(c) CH
(d) CO
§ 98.183 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) For each smelting furnace that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report combined process and combustion CO
(b) For each smelting furnace that is not subject to the requirements in paragraph (a) of this section, calculate and report the process and combustion CO
(1) Calculate and report under this subpart the combined process and combustion CO
(2) Calculate and report process and combustion CO
(i) For each smelting furnace, determine the annual mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into the smelting furnace and estimate annual process CO
(ii) Determine the combined annual process CO
(iii) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO
§ 98.184 Monitoring and QA/QC requirements.
If you determine process CO
(a) Determine the annual mass for each material used for the calculations of annual process CO
(b) For each material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed or used in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.
(1) Information provided by your material supplier.
(2) Collecting and analyzing at least three representative samples of the material each year. The carbon content of the material must be analyzed at least annually using the methods (and their QA/QC procedures) specified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable.
(i) ASTM E1941-04, Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see § 98.7) for analysis of metal ore and alloy product.
(ii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7), for analysis of carbonaceous reducing agents and carbon electrodes.
(iii) ASTM C25-06, Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7) for analysis of flux materials such as limestone or dolomite.
§ 98.185 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations in § 98.183 is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.
(a) For each missing data for the carbon content for the smelting furnaces at your facility that estimate annual process CO
(b) For missing records of the monthly mass of carbon-containing materials, the substitute data value must be based the best available estimate of the mass of the material from all available process data or data used for accounting purposes (such as purchase records).
§ 98.186 Data reporting procedures.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable.
(a) If a CEMS is used to measure CO
(1) Identification number of each smelting furnace.
(2) Annual lead product production capacity (tons).
(3) Annual production for each lead product (tons).
(4) Total number of smelting furnaces at facility used for lead production.
(b) If a CEMS is not used to measure CO
(1) Identification number of each smelting furnace. (2) Annual process CO
(3) Annual lead product production capacity for the facility and each smelting furnace(tons).
(4) Annual production for each lead product (tons).
(5) Total number of smelting furnaces at facility used for production of lead products reported in paragraph (b)(4) of this section.
(6)-(7) [Reserved]
(8) List the method used for the determination of carbon content for each material used for the calculation of annual process CO
(9) If you use the missing data procedures in § 98.185(b), you must report how the monthly mass of carbon-containing materials with missing data was determined and the number of months the missing data procedures were used.
§ 98.187 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records of the information specified in paragraphs (a) through (d) of this section, as applicable to the smelting furnaces at your facility.
(a) If a CEMS is used to measure combined process and combustion CO
(1) Monthly smelting furnace production quantity for each lead product (tons).
(2) Number of smelting furnace operating hours each month.
(3) Number of smelting furnace operating hours in calendar year.
(b) If the carbon mass balance procedure is used to determine process CO
(1) Monthly smelting furnace production quantity for each lead product (tons).
(2) Number of smelting furnace operating hours each month.
(3) Number of smelting furnace operating hours in calendar year.
(4) Monthly material quantity consumed, used, or produced for each material included for the calculations of annual process CO
(5) Average carbon content determined and records of the supplier provided information or analyses used for the determination for each material included for the calculations of annual process CO
(c) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each smelting furnace, including documentation of any materials excluded from Equation R-1 of this subpart that contribute less than 1 percent of the total carbon into or out of the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an smelting furnace including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(d) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (d)(1) through (10) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (10) of this section.
(1) Annual mass of lead ore charged to each smelting furnace (tons) (Equation R-1 of § 98.183).
(2) Carbon content of the lead ore per furnace, from the carbon analysis results (percent by weight, expressed as a decimal fraction) (Equation R-1).
(3) Annual mass of lead scrap charged to each smelting furnace (tons) (Equation R-1).
(4) Carbon content of the lead scrap per furnace, from the carbon analysis (percent by weight, expressed as a decimal fraction) (Equation R-1).
(5) Annual mass of flux materials (e.g., limestone, dolomite) charged to each smelting furnace (tons) (Equation R-1).
(6) Carbon content of the flux materials per furnace, from the carbon analysis (percent by weight, expressed as a decimal fraction) (Equation R-1).
(7) Annual mass of carbonaceous materials (e.g., coal, coke) charged to each smelting furnace (tons) (Equation R-1).
(8) Carbon content of the carbonaceous materials per furnace, from the carbon analysis (percent by weight, expressed as a decimal fraction) (Equation R-1).
(9) Annual mass of each other material containing carbon, other than fuel, fed, charged, or otherwise introduced into the smelting furnace (tons) (Equation R-1).
(10) Carbon content of each other material, from the carbon analysis results per furnace (percent by weight, expressed as a decimal fraction) (Equation R-1).
§ 98.188 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart S – Lime Manufacturing
§ 98.190 Definition of the source category.
(a) Lime manufacturing plants (LMPs) engage in the manufacture of a lime product by calcination of limestone, dolomite, shells or other calcareous substances as defined in 40 CFR 63.7081(a)(1).
(b) This source category includes all LMPs unless the LMP is located at a kraft pulp mill, soda pulp mill, sulfite pulp mill, or only processes sludge containing calcium carbonate from water softening processes. The lime manufacturing source category consists of marketed and non-marketed lime manufacturing facilities.
(c) Lime kilns at pulp and paper manufacturing facilities must report emissions under subpart AA of this part (Pulp and Paper Manufacturing).
§ 98.191 Reporting threshold.
You must report GHG emissions under this subpart if your facility is a lime manufacturing plant as defined in § 98.190 and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.192 GHGs to report.
You must report:
(a) CO
(b) CO
(c) N
(d) CO
(e) CO
§ 98.193 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) If all lime kilns meet the conditions specified in § 98.33(b)(4)(ii) or (iii), you must calculate and report under this subpart the combined process and combustion CO
(b) If CEMS are not required to be used to determine CO
(1) Calculate and report under this subpart the combined process and combustion CO
(2) Calculate and report process and combustion CO
(i) You must calculate a monthly emission factor for each type of lime produced using Equation S-1 of this section. Calcium oxide and magnesium oxide content must be analyzed monthly for each lime product type that is produced:
(ii) You must calculate a monthly emission factor for each type of calcined byproduct or waste sold (including lime kiln dust) using Equation S-2 of this section:
(iii) You must calculate the annual CO
(iv) You must calculate annual CO
(v) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO
(vi) You must calculate an annual average emission factor for each type of lime product produced using Equation S-5 of this section.
(vii) You must calculate an annual average emission factor for each type of calcined byproduct/waste by lime type that is sold using Equation S-6 of this section.
(viii) You must calculate an annual average result of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold using Equations S-7 through S-10 of this section.
§ 98.194 Monitoring and QA/QC requirements.
(a) You must determine the total quantity of each type of lime product that is produced and each calcined byproduct or waste (such as lime kiln dust) that is sold. The quantities of each should be directly measured monthly with the same plant instruments used for accounting purposes, including but not limited to, calibrated weigh feeders, rail or truck scales, and barge measurements. The direct measurements of each lime product shall be reconciled annually with the difference in the beginning of and end of year inventories for these products, when measurements represent lime sold.
(b) You must determine the annual quantity of each calcined byproduct or waste generated that is not sold by either direct measurement using the same instruments identified in paragraph (a) of this section or by using a calcined byproduct or waste generation rate.
(c) You must determine the chemical composition (percent total CaO and percent total MgO) of each type of lime product that is produced and each type of calcined byproduct or waste sold according to paragraph (c)(1) or (2) of this section. You must determine the chemical composition of each type of lime product that is produced and each type of calcined byproduct or waste sold on a monthly basis. You must determine the chemical composition for each type of calcined byproduct or waste that is not sold on an annual basis.
(1) ASTM C25-06 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference – see § 98.7).
(2) The National Lime Association’s CO
(d) You must use the analysis of calcium oxide and magnesium oxide content of each lime product that is produced and that is collected during the same month as the production data in monthly calculations.
(e) You must follow the quality assurance/quality control procedures (including documentation) in National Lime Association’s CO
§ 98.195 Procedures for estimating missing data.
For the procedure in § 98.193(b)(1), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., oxide content, quantity of lime products, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) or (b) of this section. You must document and keep records of the procedures used for all such estimates.
(a) For each missing value of the quantity of lime produced (by lime type), and quantity of calcined byproduct or waste produced and sold, the substitute data value shall be the best available estimate based on all available process data or data used for accounting purposes.
(b) For missing values related to the CaO and MgO content, you must conduct a new composition test according to the standard methods in § 98.194 (c)(1) or (c)(2).
§ 98.196 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable.
(a) If a CEMS is used to measure CO
(1) Method used to determine the quantity of lime that is produced and quantity of lime that is sold.
(2) Method used to determine the quantity of calcined lime byproduct or waste sold.
(3) Beginning and end of year inventories for each lime product that is produced, by type.
(4) Beginning and end of year inventories for calcined lime byproducts or wastes sold, by type.
(5) Annual amount of calcined lime byproduct or waste sold, by type (tons).
(6) Annual amount of lime product sold, by type (tons).
(7) Annual amount of calcined lime byproduct or waste that is not sold, by type (tons).
(8) Annual amount of lime product not sold, by type (tons).
(b) If a CEMS is not used to measure CO
(1) Annual CO
(2)-(3) [Reserved]
(4) Standard method used (ASTM or NLA testing method) to determine chemical compositions of each lime type produced and each calcined lime byproduct or waste type.
(5)-(6) [Reserved]
(7) Method used to determine the quantity of lime produced and/or lime sold.
(8) [Reserved]
(9) Method used to determine the quantity of calcined lime byproduct or waste sold.
(10)-(12) [Reserved]
(13) Beginning and end of year inventories for each lime product that is produced.
(14) Beginning and end of year inventories for calcined lime byproducts or wastes sold.
(15) Annual lime production capacity (tons) per facility.
(16) Number of times in the reporting year that missing data procedures were followed to measure lime production (months) or the chemical composition of lime products sold (months).
(17) Indicate whether CO
(i) The annual amount of CO
(ii) The method used to determine the amount of CO
(18) Annual quantity (tons) of lime product sold, by type.
(19) Annual average emission factors for each lime product type produced.
(20) Annual average emission factors for each calcined byproduct/waste by lime type that is sold.
(21) Annual average results of chemical composition analysis of each type of lime product produced and calcined byproduct/waste sold.
§ 98.197 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section.
(a) Annual operating hours in calendar year.
(b) Records of all analyses (e.g. chemical composition of lime products, by type) and calculations conducted.
(c) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) through (9) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (9) of this section.
(1) Monthly calcium oxide content for each lime type, determined according to § 98.194(c) (metric tons CaO/metric ton lime) (Equation S-1 of § 98.193).
(2) Monthly magnesium oxide content for each lime type, determined according to § 98.194(c) (metric tons MgO/metric ton lime) (Equation S-1).
(3) Monthly calcium oxide content for each calcined lime byproduct or waste type sold (metric tons CaO/metric ton lime) (Equation S-2 of § 98.193).
(4) Monthly magnesium oxide content for each calcined lime byproduct or waste type sold (metric tons MgO/metric ton lime) (Equation S-2).
(5) Calcium oxide content for each calcined lime byproduct or waste type that is not sold (metric tons CaO/metric ton lime) (Equation S-3 of § 98.193).
(6) Magnesium oxide content for each calcined lime byproduct or waste type that is not sold (metric tons MgO/metric ton lime) (Equation S-3).
(7) Annual weight or mass of calcined byproducts or wastes for lime type that is not sold (tons) (Equation S-3).
(8) Monthly weight or mass of each lime type produced (tons) (Equation S-4 of § 98.193).
(9) Monthly weight or mass of each calcined byproducts or wastes sold (tons) (Equation S-4).
§ 98.198 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table S-1 to Subpart S of Part 98 – Basic Parameters for the Calculation of Emission Factors for Lime Production
Variable | Stoichiometric ratio |
---|---|
SR | 0.7848 |
SR | 1.0918 |
Subpart T – Magnesium Production
§ 98.200 Definition of source category.
The magnesium production and processing source category consists of the following processes:
(a) Any process in which magnesium metal is produced through smelting (including electrolytic smelting), refining, or remelting operations.
(b) Any process in which molten magnesium is used in alloying, casting, drawing, extruding, forming, or rolling operations.
§ 98.201 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a magnesium production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.202 GHGs to report.
(a) You must report emissions of the following gases in metric tons per year resulting from their use as cover gases or carrier gases in magnesium production or processing:
(1) Sulfur hexafluoride (SF
(2) HFC-134a.
(3) The fluorinated ketone, FK 5-1-12.
(4) Carbon dioxide (CO
(5) Any other GHGs (as defined in § 98.6).
(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the CO
§ 98.203 Calculating GHG emissions.
(a) Calculate the mass of each GHG emitted from magnesium production or processing over the calendar year using either Equation T-1 or Equation T-2 of this section, as appropriate. Both of these equations equate emissions of cover gases or carrier gases to consumption of cover gases or carrier gases.
(1) To estimate emissions of cover gases or carrier gases by monitoring changes in container masses and inventories, emissions of each cover gas or carrier gas shall be estimated using Equation T-1 of this section:
(2) To estimate emissions of cover gases or carrier gases by monitoring changes in the masses of individual containers as their contents are used, emissions of each cover gas or carrier gas shall be estimated using Equation T-2 of this section:
(b) For purposes of Equation T-2 of this section, the mass of the cover gas used over the period p for an individual container shall be estimated by using Equation T-3 of this section:
(c) If a facility has mass flow controllers (MFC) and the capacity to track and record MFC measurements to estimate total gas usage, the mass of each cover or carrier gas monitored may be used as the mass of cover or carrier gas consumed (Q
§ 98.204 Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the request must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2011. The use of best available monitoring methods will not be approved beyond December 31, 2011.
(b) Emissions (consumption) of cover gases and carrier gases may be estimated by monitoring the changes in container weights and inventories using Equation T-1 of this subpart, by monitoring the changes in individual container weights as the contents of each container are used using Equations T-2 and T-3 of this subpart, or by monitoring the mass flow of the pure cover gas or carrier gas into the gas distribution system. Emissions must be estimated at least annually.
(c) When estimating emissions by monitoring the mass flow of the pure cover gas or carrier gas into the gas distribution system, you must use gas flow meters, or mass flow controllers, with an accuracy of 1 percent of full scale or better.
(d) When estimating emissions using Equation T-1 of this subpart, you must ensure that all the quantities required by Equation T-1 of this subpart have been measured using scales or load cells with an accuracy of 1 percent of full scale or better, accounting for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier e.g., for the contents of containers containing new gas or for the heels remaining in containers returned to the gas supplier) if the supplier provides documentation verifying that accuracy standards are met; however you remain responsible for the accuracy of these masses or weights under this subpart.
(e) When estimating emissions using Equations T-2 and T-3 of this subpart, you must monitor and record container identities and masses as follows:
(1) Track the identities and masses of containers leaving and entering storage with check-out and check-in sheets and procedures. The masses of cylinders returning to storage shall be measured immediately before the cylinders are put back into storage.
(2) Ensure that all the quantities required by Equations T-2 and T-3 of this subpart have been measured using scales or load cells with an accuracy of 1 percent of full scale or better, accounting for the tare weights of the containers. You may accept gas masses or weights provided by the gas supplier e.g., for the contents of cylinders containing new gas or for the heels remaining in cylinders returned to the gas supplier) if the supplier provides documentation verifying that accuracy standards are met; however, you remain responsible for the accuracy of these masses or weights under this subpart.
(f) All flowmeters, scales, and load cells used to measure quantities that are to be reported under this subpart shall be calibrated using calibration procedures specified by the flowmeter, scale, or load cell manufacturer. Calibration shall be performed prior to the first reporting year. After the initial calibration, recalibration shall be performed at the minimum frequency specified by the manufacturer.
§ 98.205 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emission calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter will be used in the calculations as specified in paragraph (b) of this section.
(b) Replace missing data on the emissions of cover or carrier gases by multiplying magnesium production during the missing data period by the average cover or carrier gas usage rate from the most recent period when operating conditions were similar to those for the period for which the data are missing. Calculate the usage rate for each cover or carrier gas using Equation T-4 of this section:
(c) If the precise before and after weights are not available, it should be assumed that the container was emptied in the process (i.e., quantity purchased should be used, less heel).
§ 98.206 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must include the following information at the facility level:
(a) Emissions of each cover or carrier gas in metric tons.
(b) Types of production processes at the facility (e.g., primary, secondary, die casting).
(c) Amount of magnesium produced or processed in metric tons for each process type. This includes the output of primary and secondary magnesium production processes and the input to magnesium casting processes.
(d) Cover and carrier gas flow rate (e.g., standard cubic feet per minute) for each production unit and composition in percent by volume.
(e) For any missing data, you must report the length of time the data were missing for each cover gas or carrier gas, the method used to estimate emissions in their absence, and the quantity of emissions thereby estimated.
(f) The annual cover gas usage rate for the facility for each cover gas, excluding the carrier gas (kg gas/metric ton Mg).
(g) If applicable, an explanation of any change greater than 30 percent in the facility’s cover gas usage rate (e.g., installation of new melt protection technology or leak discovered in the cover gas delivery system that resulted in increased emissions).
(h) A description of any new melt protection technologies adopted to account for reduced or increased GHG emissions in any given year.
§ 98.207 Records that must be retained.
In addition to the records specified in § 98.3(g), you must retain the following information at the facility level:
(a) Check-out and weigh-in sheets and procedures for gas cylinders.
(b) Accuracy certifications and calibration records for scales including the method or manufacturer’s specification used for calibration.
(c) Residual gas amounts (heel) in cylinders sent back to suppliers.
(d) Records, including invoices, for gas purchases, sales, and disbursements for all GHGs.
§ 98.208 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. Additionally, some sector-specific definitions are provided below:
Carrier gas means the gas with which cover gas is mixed to transport and dilute the cover gas thus maximizing its efficient use. Carrier gases typically include CO
Cover gas means SF
Subpart U – Miscellaneous Uses of Carbonate
§ 98.210 Definition of the source category.
(a) This source category includes any equipment that uses carbonates listed in Table U-1 in manufacturing processes that emit carbon dioxide. Table U-1 includes the following carbonates: limestone, dolomite, ankerite, magnesite, siderite, rhodochrosite, or sodium carbonate. Facilities are considered to emit CO
(b) This source category does not include equipment that uses carbonates or carbonate containing minerals that are consumed in the production of cement, glass, ferroalloys, iron and steel, lead, lime, phosphoric acid, pulp and paper, soda ash, sodium bicarbonate, sodium hydroxide, or zinc.
(c) This source category does not include carbonates used in sorbent technology used to control emissions from stationary fuel combustion equipment. Emissions from carbonates used in sorbent technology are reported under 40 CFR 98, subpart C (Stationary Fuel Combustion Sources).
§ 98.211 Reporting threshold.
You must report GHG emissions from miscellaneous uses of carbonate if your facility uses carbonates as defined in § 98.210 of this subpart and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.212 GHGs to report.
You must report CO
§ 98.213 Calculating GHG emissions.
You must determine CO
(a) Calculate the process emissions of CO
§ 98.214 Monitoring and QA/QC requirements.
(a) The annual mass of carbonate consumed (for Equation U-1 of this subpart) or carbonate inputs (for Equation U-2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or weigh belt feeders.
(b) The annual mass of carbonate outputs (for Equation U-2 of this subpart) must be determined annually from monthly measurements using the same plant instruments used for accounting purposes including purchase records or direct measurement, such as weigh hoppers or belt weigh feeders.
(c) If you follow the procedures of § 98.213(a), as an alternative to assuming a calcination fraction of 1.0, you can determine on an annual basis the calcination fraction for each carbonate consumed based on sampling and chemical analysis using a suitable method such as using an x-ray fluorescence standard method or other enhanced industry consensus standard method published by an industry consensus standard organization (e.g., ASTM, ASME, etc.).
§ 98.215 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraph (b) of this section. You must document and keep records of the procedures used for all such estimates.
(b) For each missing value of monthly carbonate consumed, monthly carbonate output, or monthly carbonate input, the substitute data value must be the best available estimate based on the all available process data or data used for accounting purposes.
§ 98.216 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (g) of this section at the facility level, as applicable.
(a) Annual CO
(b) [Reserved]
(c) Measurement method used to determine the mass of carbonate.
(d) Method used to calculate emissions.
(e) If you followed the calculation method of § 98.213(a), you must report the information in paragraphs (e)(1) through (3) of this section.
(1)-(2) [Reserved]
(3) If you determined the calcination fraction, indicate which standard method was used.
(f) [Reserved]
(g) Number of times in the reporting year that missing data procedures were followed to measure carbonate consumption, carbonate input or carbonate output (months).
§ 98.217 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (e) of this section:
(a) Monthly carbonate consumption (by carbonate type in tons).
(b) You must document the procedures used to ensure the accuracy of the monthly measurements of carbonate consumption, carbonate input or carbonate output including, but not limited to, calibration of weighing equipment and other measurement devices.
(c) Records of all analyses conducted to meet the requirements of this rule.
(d) Records of all calculations conducted.
(e) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (e)(1) through (4) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (e)(1) through (4) of this section.
(1) Fraction calcination achieved for each particular carbonate type. As an alternative to measuring the calcination fraction, a value of 1.0 can be used (decimal fraction) (Equation U-1 of § 98.213).
(2) Annual mass of each carbonate type consumed (tons) (Equation U-1).
(3) Annual mass of each input carbonate type (tons) (Equation U-2 of § 98.213).
(4) Annual mass of each output carbonate type (tons) (Equation U-2).
§ 98.218 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table U-1 to Subpart U of Part 98 – CO2 Emission Factors for Common Carbonates
Mineral name – carbonate | CO (tons CO |
---|---|
Limestone – CaCO | 0.43971 |
Magnesite – MgCO | 0.52197 |
Dolomite – CaMg(CO | 0.47732 |
Siderite – FeCO | 0.37987 |
Ankerite – Ca(Fe, Mg, Mn)(CO | 0.47572 |
Rhodochrosite – MnCO | 0.38286 |
Sodium Carbonate/Soda Ash – Na | 0.41492 |
Subpart V – Nitric Acid Production
§ 98.220 Definition of source category.
This source category includes a nitric acid production facility using one or more trains to produce weak nitric acid (30 to 70 percent in strength). Starting with reporting year 2018, this source category includes all nitric acid production facilities using one or more trains to produce nitric acid (any strength). A nitric acid train produces nitric acid through the catalytic oxidation of ammonia.
§ 98.221 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a nitric acid train and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.222 GHGs to report.
(a) You must report N
(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
§ 98.223 Calculating GHG emissions.
(a) You must determine annual N
(1) Use a site-specific emission factor and production data according to paragraphs (b) through (i) of this section.
(2) Request Administrator approval for an alternative method of determining N
(i) If you received Administrator approval for an alternative method of determining N
(ii) You must notify the EPA of your use of a previously approved alternative method in your annual report.
(iii) Otherwise, if you have not received Administrator approval for an alternative method of determining N
(iv) If the Administrator does not approve your requested alternative method within 150 days of the end of the reporting year, you must determine the N
(b) You must conduct an annual performance test for each nitric acid train according to paragraphs (b)(1) through (3) of this section.
(1) You must conduct the performance test at the absorber tail gas vent, referred to as the test point, for each nitric acid train according to § 98.224(b) through (f). If multiple nitric acid trains exhaust to a common abatement technology and/or emission point, you must sample each process in the ducts before the emissions are combined, sample each process when only one process is operating, or sample the combined emissions when multiple processes are operating and base the site-specific emission factor on the combined production rate of the multiple nitric acid trains.
(2) You must conduct the performance test under normal process operating conditions.
(3) You must measure the production rate during the performance test and calculate the production rate for the test period in tons (100 percent acid basis) per hour.
(c) Using the results of the performance test in paragraph (b) of this section, you must calculate an average site-specific emission factor for each nitric acid train “t” according to Equation V-1 of this section:
(d) If nitric acid train “t” exhausts to any N
(1) Use the manufacturer’s specified destruction efficiency.
(2) Estimate the destruction efficiency through process knowledge. Examples of information that could constitute process knowledge include calculations based on material balances, process stoichiometry, or previous test results provided the results are still relevant to the current vent stream conditions. You must document how process knowledge (if applicable) was used to determine the destruction efficiency.
(3) Calculate the destruction efficiency by conducting an additional performance test on the emissions stream following the N
(e) If nitric acid train “t” exhausts to any N
(f) [Reserved]
(g) You must calculate N
(1) If nitric acid train “t” exhausts to one N
(2) If multiple N
(3) If multiple N
(4) If nitric acid train “t” does not exhaust to any N
(h) You must determine the annual nitric acid production emissions combined from all nitric acid trains at your facility using Equation V-4 of this section:
(i) You must determine the total annual amount of nitric acid produced on each nitric acid train “t” (tons acid produced, 100 percent acid basis), according to § 98.224(f).
§ 98.224 Monitoring and QA/QC requirements.
(a) You must conduct a new performance test according to a test plan as specified in paragraphs (a)(1) through (3) of this section.
(1) Conduct the performance test annually. The test should be conducted at a point during the campaign which is representative of the average emissions rate from the nitric acid campaigns. Facilities must document the methods used to determine the representative point of the campaign when the performance test is conducted.
(2) Conduct the performance test when your nitric acid production process is changed, specifically when abatement equipment is installed.
(3) If you requested Administrator approval for an alternative method of determining N
(b) You must measure the N
(1) EPA Method 320 at 40 CFR part 63, appendix A, Measurement of Vapor Phase Organic and Inorganic Emissions by Extractive Fourier Transform Infrared (FTIR) Spectroscopy.
(2) ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference in § 98.7).
(3) An equivalent method, with Administrator approval.
(c) You must determine the production rate(s) (100 percent acid basis) from each nitric acid train during the performance test according to paragraphs (c)(1) or (2) of this section.
(1) Direct measurement of production and concentration (such as using flow meters, weigh scales, for production and concentration measurements).
(2) Existing plant procedures used for accounting purposes (i.e. dedicated tank-level and acid concentration measurements).
(d) You must determine the volumetric flow rate during the performance test in conjunction with the applicable EPA methods in 40 CFR part 60, appendices A-1 through A-4. Conduct three emissions test runs of 1 hour each. All QA/QC procedures specified in the reference test methods and any associated performance specifications apply. For each test, the facility must prepare an emission factor determination report that must include the items in paragraphs (d)(1) through (d)(3) of this section.
(1) Analysis of samples, determination of emissions, and raw data.
(2) All information and data used to derive the emissions factor(s).
(3) The production rate during each test and how it was determined.
(e) You must determine the total monthly amount of nitric acid produced. You must also determine the monthly amount of nitric acid produced while N
(f) You must determine the annual amount of nitric acid produced. You must also determine the annual amount of nitric acid produced while N
§ 98.225 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section.
(a) For each missing value of nitric acid production, the substitute data shall be the best available estimate based on all available process data or data used for accounting purposes (such as sales records).
(b) For missing values related to the performance test, including emission factors, production rate, and N
§ 98.226 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (q) of this section.
(a) Nitric Acid train identification number.
(b) Annual process N
(c)-(d) [Reserved]
(e) Annual nitric acid production from the nitric acid facility (tons, 100 percent acid basis).
(f) Number of nitric acid trains.
(g) Number of different N
(h) Abatement technologies used (if applicable) and date of installation of abatement technology.
(i)-(j) [Reserved]
(k) Type of nitric acid process used for each nitric acid train (low, medium, high, or dual pressure).
(l) Number of times in the reporting year that missing data procedures were followed to measure nitric acid production (months).
(m) If you conducted a performance test and calculated a site-specific emissions factor according to § 98.223(a)(1), each annual report must also contain the information specified in paragraphs (m)(1) through (7) of this section.
(1) [Reserved]
(2) Test method used for performance test.
(3)-(6) [Reserved]
(7) Number of times in the reporting year that a performance test had to be repeated (number).
(n) If you requested Administrator approval for an alternative method of determining N
(1) Name of alternative method.
(2) Description of alternative method.
(3) Request date.
(4) Approval date.
(o) [Reserved]
(p) [Reserved]
(q) Annual percent N
§ 98.227 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the records specified in paragraphs (a) through (h) of this section for each nitric acid production facility:
(a) Records of significant changes to process.
(b) Documentation of how process knowledge was used to estimate abatement technology destruction efficiency (if applicable).
(c) Performance test reports.
(d) Number of operating hours in the calendar year for each nitric acid train (hours).
(e) Annual nitric acid permitted production capacity (tons).
(f) Measurements, records, and calculations used to determine reported parameters.
(g) Documentation of the procedures used to ensure the accuracy of the measurements of all reported parameters, including but not limited to, calibration of weighing equipment, flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(h) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (h)(1) through (10) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (h)(1) through (10) of this section.
(1) Annual nitric acid produced from each nitric acid train (tons nitric acid produced, 100% acid basis).
(2) Indicate which equation was used to calculate emissions for each nitric acid train.
(3) N
(4) Volumetric flow rate of effluent gas per test run during the performance test (dscf/hr) (Equation V-1).
(5) Production rate per test run during the performance test (tons nitric acid produced per hour, 100 percent acid basis) (Equation V-1).
(6) Annual nitric acid production from each nitric acid train during which each N
(7) Destruction efficiency of N
(8) Destruction efficiency of each N
(9) Destruction efficiency of each N
(10) Fraction control factor of each N
§ 98.228 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart W – Petroleum and Natural Gas Systems
§ 98.230 Definition of the source category.
(a) This source category consists of the following industry segments:
(1) Offshore petroleum and natural gas production. Offshore petroleum and natural gas production is any platform structure, affixed temporarily or permanently to offshore submerged lands, that houses equipment to extract hydrocarbons from the ocean or lake floor and that processes and/or transfers such hydrocarbons to storage, transport vessels, or onshore. In addition, offshore production includes secondary platform structures connected to the platform structure via walkways, storage tanks associated with the platform structure and floating production and storage offloading equipment (FPSO). This source category does not include reporting of emissions from offshore drilling and exploration that is not conducted on production platforms.
(2) Onshore petroleum and natural gas production. Onshore petroleum and natural gas production means all equipment on a single well-pad or associated with a single well-pad (including but not limited to compressors, generators, dehydrators, storage vessels, engines, boilers, heaters, flares, separation and processing equipment, and portable non-self-propelled equipment, which includes well drilling and completion equipment, workover equipment, and leased, rented or contracted equipment) used in the production, extraction, recovery, lifting, stabilization, separation or treating of petroleum and/or natural gas (including condensate). This equipment also includes associated storage or measurement vessels, all petroleum and natural gas production equipment located on islands, artificial islands, or structures connected by a causeway to land, an island, or an artificial island. Onshore petroleum and natural gas production also means all equipment on or associated with a single enhanced oil recovery (EOR) well pad using CO
(3) Onshore natural gas processing. Natural gas processing means the separation of natural gas liquids (NGLs) or non-methane gases from produced natural gas, or the separation of NGLs into one or more component mixtures. Separation includes one or more of the following: forced extraction of natural gas liquids, sulfur and carbon dioxide removal, fractionation of NGLs, or the capture of CO
(4) Onshore natural gas transmission compression. Onshore natural gas transmission compression means any stationary combination of compressors that move natural gas from production fields, natural gas processing plants, or other transmission compressors through transmission pipelines to natural gas distribution pipelines, LNG storage facilities, or into underground storage. In addition, a transmission compressor station includes equipment for liquids separation, and tanks for the storage of water and hydrocarbon liquids. Residue (sales) gas compression that is part of onshore natural gas processing plants are included in the onshore natural gas processing segment and are excluded from this segment.
(5) Underground natural gas storage. Underground natural gas storage means subsurface storage, including depleted gas or oil reservoirs and salt dome caverns that store natural gas that has been transferred from its original location for the primary purpose of load balancing (the process of equalizing the receipt and delivery of natural gas); natural gas underground storage processes and operations (including compression, dehydration and flow measurement, and excluding transmission pipelines); and all the wellheads connected to the compression units located at the facility that inject and recover natural gas into and from the underground reservoirs.
(6) Liquefied natural gas (LNG) storage. LNG storage means onshore LNG storage vessels located above ground, equipment for liquefying natural gas, compressors to capture and re-liquefy boil-off-gas, re-condensers, and vaporization units for re-gasification of the liquefied natural gas.
(7) LNG import and export equipment. LNG import equipment means all onshore or offshore equipment that receives imported LNG via ocean transport, stores LNG, re-gasifies LNG, and delivers re-gasified natural gas to a natural gas transmission or distribution system. LNG export equipment means all onshore or offshore equipment that receives natural gas, liquefies natural gas, stores LNG, and transfers the LNG via ocean transportation to any location, including locations in the United States.
(8) Natural gas distribution. Natural gas distribution means the distribution pipelines and metering and regulating equipment at metering-regulating stations that are operated by a Local Distribution Company (LDC) within a single state that is regulated as a separate operating company by a public utility commission or that is operated as an independent municipally-owned distribution system. This segment also excludes customer meters and regulators, infrastructure, and pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and farm taps upstream of the local distribution company inlet.
(9) Onshore petroleum and natural gas gathering and boosting. Onshore petroleum and natural gas gathering and boosting means gathering pipelines and other equipment used to collect petroleum and/or natural gas from onshore production gas or oil wells and used to compress, dehydrate, sweeten, or transport the petroleum and/or natural gas to a natural gas processing facility, a natural gas transmission pipeline or to a natural gas distribution pipeline. Gathering and boosting equipment includes, but is not limited to gathering pipelines, separators, compressors, acid gas removal units, dehydrators, pneumatic devices/pumps, storage vessels, engines, boilers, heaters, and flares. Gathering and boosting equipment does not include equipment reported under any other industry segment defined in this section. Gathering pipelines operating on a vacuum and gathering pipelines with a GOR) less than 300 standard cubic feet per stock tank barrel (scf/STB) are not included in this industry segment (oil here refers to hydrocarbon liquids of all API gravities).
(10) Onshore natural gas transmission pipeline. Onshore natural gas transmission pipeline means all natural gas transmission pipelines as defined in § 98.238.
(b) [Reserved]
§ 98.231 Reporting threshold.
(a) You must report GHG emissions under this subpart if your facility contains petroleum and natural gas systems and the facility meets the requirements of § 98.2(a)(2), except for the industry segments in paragraphs (a)(1) through (4) of this section.
(1) Facilities must report emissions from the onshore petroleum and natural gas production industry segment only if emission sources specified in § 98.232(c) emit 25,000 metric tons of CO
(2) Facilities must report emissions from the natural gas distribution industry segment only if emission sources specified in § 98.232(i) emit 25,000 metric tons of CO
(3) Facilities must report emissions from the onshore petroleum and natural gas gathering and boosting industry segment only if emission sources specified in § 98.232(j) emit 25,000 metric tons of CO
(4) Facilities must report emissions from the onshore natural gas transmission pipeline industry segment only if emission sources specified in § 98.232(m) emit 25,000 metric tons of CO
(b) For applying the threshold defined in § 98.2(a)(2), natural gas processing facilities must also include owned or operated residue gas compression equipment.
§ 98.232 GHGs to report.
(a) You must report CO
(b) For offshore petroleum and natural gas production, report CO
(c) For an onshore petroleum and natural gas production facility, report CO
(1) Natural gas pneumatic device venting.
(2) [Reserved]
(3) Natural gas driven pneumatic pump venting.
(4) Well venting for liquids unloading.
(5) Gas well venting during well completions without hydraulic fracturing.
(6) Well venting during well completions with hydraulic fracturing that have a GOR of 300 scf/STB or greater (oil here refers to hydrocarbon liquids produced of all API gravities).
(7) Gas well venting during well workovers without hydraulic fracturing.
(8) Well venting during well workovers with hydraulic fracturing that have a GOR of 300 scf/STB or greater (oil here refers to hydrocarbon liquids produced of all API gravities).
(9) Flare stack emissions.
(10) Storage tanks vented emissions from produced hydrocarbons.
(11) Reciprocating compressor venting.
(12) Well testing venting and flaring.
(13) Associated gas venting and flaring from produced hydrocarbons.
(14) Dehydrator vents.
(15) [Reserved]
(16) EOR injection pump blowdown.
(17) Acid gas removal vents.
(18) EOR hydrocarbon liquids dissolved CO
(19) Centrifugal compressor venting.
(20) [Reserved]
(21) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components listed in paragraph (c)(11) or (19) of this section, and it does not include thief hatches or other openings on a storage vessel).
(22) You must use the methods in § 98.233(z) and report under this subpart the emissions of CO
(d) For onshore natural gas processing, report CO
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Blowdown vent stacks.
(4) Dehydrator vents.
(5) Acid gas removal vents.
(6) Flare stack emissions.
(7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters.
(e) For onshore natural gas transmission compression, report CO
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Transmission storage tanks.
(4) Blowdown vent stacks.
(5) Natural gas pneumatic device venting.
(6) Flare stack emissions.
(7) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters.
(8) Equipment leaks from all other components that are not listed in paragraph (e)(1), (2), or (7) of this section and are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a)(6) or (7). The other components subject to this paragraph (e)(8) also do not include thief hatches or other openings on a storage vessel. If these other components are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you may also elect to report emissions from these other components if you elect to survey them using a leak detection method described in § 98.234(a)(1) through (5).
(f) For underground natural gas storage, report CO
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Natural gas pneumatic device venting.
(4) Flare stack emissions.
(5) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, and meters associated with storage stations.
(6) Equipment leaks from all other components that are associated with storage stations, are not listed in paragraph (f)(1), (2), or (5) of this section, and are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a)(6) or (7). If these other components are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you may also elect to report emissions from these other components if you elect to survey them using a leak detection method described in § 98.234(a)(1) through (5).
(7) Equipment leaks from valves, connectors, open-ended lines, and pressure relief valves associated with storage wellheads.
(8) Equipment leaks from all other components that are associated with storage wellheads, are not listed in paragraph (f)(1), (2), or (7) of this section, and are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a, of this chapter or you elect to survey using a leak detection method described in § 98.234(a)(6) or (7). If these other components are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you may also elect to report emissions from these other components if you elect to survey them using a leak detection method described in § 98.234(a)(1) through (5).
(g) For LNG storage, report CO
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Flare stack emissions.
(4) Equipment leaks from valves, pump seals, connectors, and other equipment leak sources in LNG service.
(5) Equipment leaks from vapor recovery compressors, if you do not survey components associated with vapor recovery compressors in accordance with paragraph (g)(6) of this section.
(6) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and that are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a).
(7) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (g)(1) or (2) of this section, and are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a)(6) or (7). If these components are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you may also elect to report emissions from these components if you elect to survey them using a leak detection method described in § 98.234(a)(1) through (5).
(h) LNG import and export equipment, report CO
(1) Reciprocating compressor venting.
(2) Centrifugal compressor venting.
(3) Blowdown vent stacks.
(4) Flare stack emissions.
(5) Equipment leaks from valves, pump seals, connectors, and other equipment leak sources in LNG service.
(6) Equipment leaks from vapor recovery compressors, if you do not survey components associated with vapor recovery compressors in accordance with paragraph (h)(7) of this section.
(7) Equipment leaks from all components in gas service that are associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and that are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a).
(8) Equipment leaks from all components in gas service that are not associated with a vapor recovery compressor, are not listed in paragraph (h)(1) or (2) of this section, and that are either subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter or you elect to survey using a leak detection method described in § 98.234(a)(6) or (7). If these components are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you may also elect to report emissions from these components if you elect to survey them using a leak detection method described in § 98.234(a)(1) through (5).
(i) For natural gas distribution, report CO
(1) Equipment leaks from connectors, block valves, control valves, pressure relief valves, orifice meters, regulators, and open-ended lines at above grade transmission-distribution transfer stations.
(2) Equipment leaks at below grade transmission-distribution transfer stations.
(3) Equipment leaks at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations.
(4) Equipment leaks at below grade metering-regulating stations.
(5) Distribution main equipment leaks.
(6) Distribution services equipment leaks.
(7) Report under subpart W of this part the emissions of CO
(j) For an onshore petroleum and natural gas gathering and boosting facility, report CO
(1) Natural gas pneumatic device venting.
(2) Natural gas driven pneumatic pump venting.
(3) Acid gas removal vents.
(4) Dehydrator vents.
(5) Blowdown vent stacks.
(6) Storage tank vented emissions.
(7) Flare stack emissions.
(8) Centrifugal compressor venting.
(9) Reciprocating compressor venting.
(10) Equipment leaks from valves, connectors, open ended lines, pressure relief valves, pumps, flanges, and other components (such as instruments, loading arms, stuffing boxes, compressor seals, dump lever arms, and breather caps, but does not include components in paragraph (j)(8) or (9) of this section, and it does not include thief hatches or other openings on a storage vessel).
(11) Gathering pipeline equipment leaks.
(12) You must use the methods in § 98.233(z) and report under this subpart the emissions of CO
(k) Report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
(l) You must report under subpart PP of this part (Suppliers of Carbon Dioxide), CO
(m) For onshore natural gas transmission pipeline, report pipeline blowdown CO
§ 98.233 Calculating GHG emissions.
You must calculate and report the annual GHG emissions as prescribed in this section. For calculations that specify measurements in actual conditions, reporters may use a flow or volume measurement system that corrects to standard conditions and determine the flow or volume at standard conditions; otherwise, reporters must use average atmospheric conditions or typical operating conditions as applicable to the respective monitoring methods in this section.
(a) Natural gas pneumatic device venting. Calculate CH
(1) For all industry segments, determine “Count
(2) For the onshore petroleum and natural gas production industry segment, you have the option in the first two consecutive calendar years to determine “Count
(3) For all industry segments, determine the type of pneumatic device using engineering estimates based on best available information.
(4) Calculate both CH
(b) [Reserved]
(c) Natural gas driven pneumatic pump venting. (1) Calculate CH
(2) Calculate both CH
(d) Acid gas removal (AGR) vents. For AGR vents (including processes such as amine, membrane, molecular sieve or other absorbents and adsorbents), calculate emissions for CO
(1) Calculation Method 1. If you operate and maintain a continuous emissions monitoring system (CEMS) that has both a CO
(2) Calculation Method 2. If a CEMS is not available but a vent meter is installed, use the CO
(3) Calculation Method 3. If a CEMS or a vent meter is not installed, you may use the inlet or outlet gas flow rate of the acid gas removal unit to calculate emissions for CO
(4) Calculation Method 4. If CEMS or a vent meter is not installed, you may calculate emissions using any standard simulation software package, such as AspenTech HYSYS®, or API 4679 AMINECalc, that uses the Peng-Robinson equation of state and speciates CO
(i) Natural gas feed temperature, pressure, and flow rate.
(ii) Acid gas content of feed natural gas.
(iii) Acid gas content of outlet natural gas.
(iv) Unit operating hours, excluding downtime for maintenance or standby.
(v) Exit temperature of natural gas.
(vi) Solvent pressure, temperature, circulation rate, and weight.
(5) For Calculation Method 3, determine the gas flow rate of the inlet when using Equation W-4A of this section or the gas flow rate of the outlet when using Equation W-4B of this section for the natural gas stream of an AGR unit using a meter according to methods set forth in § 98.234(b). If you do not have a continuous flow meter, either install a continuous flow meter or use an engineering calculation to determine the flow rate.
(6) For Calculation Method 2, if a continuous gas analyzer is not available on the vent stack, either install a continuous gas analyzer or take quarterly gas samples from the vent gas stream for each quarter that the AGR unit is operating to determine Vol
(7) For Calculation Method 3, if a continuous gas analyzer is installed on the inlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, either install a continuous gas analyzer or take quarterly gas samples from the inlet gas stream for each quarter that the AGR unit is operating to determine Vol
(8) For Calculation Method 3, determine annual average volumetric fraction of CO
(i) If a continuous gas analyzer is installed on the outlet gas stream, then the continuous gas analyzer results must be used. If a continuous gas analyzer is not available, you may install a continuous gas analyzer.
(ii) If a continuous gas analyzer is not available or installed, quarterly gas samples may be taken from the outlet gas stream for each quarter that the AGR unit is operating to determine Vol
(iii) If a continuous gas analyzer is not available or installed, you may use the outlet pipeline quality specification for CO
(9) Calculate annual volumetric CO
(10) Calculate annual mass CO
(11) Determine if CO
(e) Dehydrator vents. For dehydrator vents, calculate annual CH
(1) Calculation Method 1. Calculate annual mass emissions from glycol dehydrators that have an annual average of daily natural gas throughput that is greater than or equal to 0.4 million standard cubic feet per day by using a software program, such as AspenTech HYSYS® or GRI-GLYCalc
(i) Feed natural gas flow rate.
(ii) Feed natural gas water content.
(iii) Outlet natural gas water content.
(iv) Absorbent circulation pump type (e.g., natural gas pneumatic/air pneumatic/electric).
(v) Absorbent circulation rate.
(vi) Absorbent type (e.g., triethylene glycol (TEG), diethylene glycol (DEG) or ethylene glycol (EG)).
(vii) Use of stripping gas.
(viii) Use of flash tank separator (and disposition of recovered gas).
(ix) Hours operated.
(x) Wet natural gas temperature and pressure.
(xi) Wet natural gas composition. Determine this parameter using one of the methods described in paragraphs (e)(1)(xi)(A) through (D) of this section.
(A) Use the GHG mole fraction as defined in paragraph (u)(2)(i) or (ii) of this section.
(B) If the GHG mole fraction cannot be determined using paragraph (u)(2)(i) or (ii) of this section, select a representative analysis.
(C) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice as specified in § 98.234(b) to sample and analyze wet natural gas composition.
(D) If only composition data for dry natural gas is available, assume the wet natural gas is saturated.
(2) Calculation Method 2. Calculate annual volumetric emissions from glycol dehydrators that have an annual average of daily natural gas throughput that is less than 0.4 million standard cubic feet per day using Equation W-5 of this section:
(3) Calculation Method 3. For dehydrators of any size that use desiccant, you must calculate emissions from the amount of gas vented from the vessel when it is depressurized for the desiccant refilling process using Equation W-6 of this section. Desiccant dehydrator emissions covered in this paragraph do not have to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
(4) For glycol dehydrators that use the calculation method in paragraph (e)(2) of this section, calculate both CH
(5) Determine if the dehydrator unit has vapor recovery. Adjust the emissions estimated in paragraphs (e)(1), (2), and (3) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data.
(6) Calculate annual emissions from dehydrator vents to flares or regenerator fire-box/fire tubes as follows:
(i) Use the dehydrator vent volume and gas composition as determined in paragraphs (e)(1) through (5) of this section, as applicable.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine dehydrator vent emissions from the flare or regenerator combustion gas vent.
(f) Well venting for liquids unloadings. Calculate annual volumetric natural gas emissions from well venting for liquids unloading using one of the calculation methods described in paragraphs (f)(1), (2), or (3) of this section. Calculate annual CH
(1) Calculation Method 1. Calculate emissions from wells with plunger lifts and wells without plunger lifts separately. For at least one well of each unique well tubing diameter group and pressure group combination in each sub-basin category (see § 98.238 for the definitions of tubing diameter group, pressure group, and sub-basin category), where gas wells are vented to the atmosphere to expel liquids accumulated in the tubing, install a recording flow meter on the vent line used to vent gas from the well (e.g., on the vent line off the wellhead separator or atmospheric storage tank) according to methods set forth in § 98.234(b). Calculate the total emissions from well venting to the atmosphere for liquids unloading using Equation W-7A of this section. For any tubing diameter group and pressure group combination in a sub-basin where liquids unloading occurs both with and without plunger lifts, Equation W-7A will be used twice, once for wells with plunger lifts and once for wells without plunger lifts.
(i) Determine the well vent average flow rate (“FR” in Equation W-7A of this section) as specified in paragraphs (f)(1)(i)(A) through (C) of this section for at least one well in a unique well tubing diameter group and pressure group combination in each sub-basin category. Calculate emissions from wells with plunger lifts and wells without plunger lifts separately.
(A) Calculate the average flow rate per hour of venting for each unique tubing diameter group and pressure group combination in each sub-basin category by dividing the recorded total annual flow by the recorded time (in hours) for all measured liquid unloading events with venting to the atmosphere.
(B) Apply the average hourly flow rate calculated under paragraph (f)(1)(i)(A) of this section to all wells in the same pressure group that have the same tubing diameter group, for the number of hours of venting these wells.
(C) Calculate a new average flow rate every other calendar year starting with the first calendar year of data collection. For a new producing sub-basin category, calculate an average flow rate beginning in the first year of production.
(ii) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(2) Calculation Method 2. Calculate the total emissions for each sub-basin from well venting to the atmosphere for liquids unloading without plunger lift assist using Equation W-8 of this section.
(3) Calculation Method 3. Calculate the total emissions for each sub-basin from well venting to the atmosphere for liquids unloading with plunger lift assist using Equation W-9 of this section.
(4) Calculate CH
(g) Well venting during completions and workovers with hydraulic fracturing. Calculate annual volumetric natural gas emissions from gas well and oil well venting during completions and workovers involving hydraulic fracturing using Equation W-10A or Equation W-10B of this section. Equation W-10A applies to well venting when the gas flowback rate is measured from a specified number of example completions or workovers and Equation W-10B applies when the gas flowback vent or flare volume is measured for each completion or workover. Completion and workover activities are separated into two periods, an initial period when flowback is routed to open pits or tanks and a subsequent period when gas content is sufficient to route the flowback to a separator or when the gas content is sufficient to allow measurement by the devices specified in paragraph (g)(1) of this section, regardless of whether a separator is actually utilized. If you elect to use Equation W-10A, you must follow the procedures specified in paragraph (g)(1). If you elect to use Equation W-10B, you must use a recording flow meter installed on the vent line, downstream of a separator and ahead of a flare or vent, to measure the gas flowback. For either equation, emissions must be calculated separately for completions and workovers, for each sub-basin, and for each well type combination identified in paragraph (g)(2) of this section. You must calculate CH
(1) If you elect to use Equation W-10A of this section on gas wells, you must use Calculation Method 1 as specified in paragraph (g)(1)(i) of this section, or Calculation Method 2 as specified in paragraph (g)(1)(ii) of this section, to determine the value of FRM
(i) Calculation Method 1. You must use Equation W-12A of this section as specified in paragraph (g)(1)(iii) of this section to determine the value of FRM
(ii) Calculation Method 2 (for gas wells). You must use Equation W-12A as specified in paragraph (g)(1)(iii) of this section to determine the value of FRM
(iii) For Equation W-10A of this section, calculate FRM
(iv) For Equation W-10A of this section, calculate FRM
(v) For Equation W-10A of this section, the ratio of gas flowback rate during well completions and workovers from hydraulic fracturing to 30-day gas production rate are applied to all well completions and well workovers, respectively, in the sub-basin and well type combination for the total number of hours of flowback and for the first 30 day average gas production rate for each of these wells.
(vi) For Equations W-12A and W-12B of this section, calculate new flowback rates for well completions and well workovers in each sub-basin and well type combination once every two years starting in the first calendar year of data collection.
(vii) For oil wells where the gas production rate is not metered and you elect to use Equation W-10A of this section, calculate the average gas production rate (PR
(A) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.
(B) You may use an industry standard practice as described in § 98.234(b).
(2) For paragraphs (g) introductory text and (g)(1) of this section, measurements and calculations are completed separately for workovers and completions per sub-basin and well type combination. A well type combination is a unique combination of the parameters listed in paragraphs (g)(2)(i) through (iv) of this section.
(i) Vertical or horizontal (directional drilling).
(ii) With flaring or without flaring.
(iii) Reduced emission completion/workover or not reduced emission completion/workover.
(iv) Oil well or gas well.
(3) Calculate both CH
(4) Calculate annual emissions from well venting during well completions and workovers from hydraulic fracturing where all or a portion of the gas is flared as specified in paragraphs (g)(4)(i) and (ii) of this section.
(i) Use the volumetric total natural gas emissions vented to the atmosphere during well completions and workovers as determined in paragraph (g) of this section to calculate volumetric and mass emissions using paragraphs (u) and (v) of this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to adjust emissions for the portion of gas flared during well completions and workovers using hydraulic fracturing. This adjustment to emissions from completions using flaring, versus completions without flaring, accounts for the conversion of CH
(h) Gas well venting during completions and workovers without hydraulic fracturing. Calculate annual volumetric natural gas emissions from each gas well venting during workovers without hydraulic fracturing using Equation W-13A of this section. Calculate annual volumetric natural gas emissions from each gas well venting during completions without hydraulic fracturing using Equation W-13B of this section. You must convert annual volumetric natural gas emissions to CH
(1) Calculate both CH
(2) Calculate annual emissions of CH
(i) Use the gas well venting volume and gas composition during well completions and workovers that are flared as determined using the methods specified in paragraphs (h) and (h)(1) of this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine emissions from the flare for gas well venting to a flare during completions and workovers without hydraulic fracturing.
(i) Blowdown vent stacks. Calculate CO
(1) Method for calculating unique physical volumes. You must calculate each unique physical volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, discharge bottles, and vessels) between isolation valves, in cubic feet, by using engineering estimates based on best available data.
(2) Method for determining emissions from blowdown vent stacks according to equipment or event type. If you elect to determine emissions according to each equipment or event type, using unique physical volumes as calculated in paragraph (i)(1) of this section, you must calculate emissions as specified in paragraph (i)(2)(i) of this section and either paragraph (i)(2)(ii) or, if applicable, paragraph (i)(2)(iii) of this section for each equipment or event type. For industry segments other than onshore natural gas transmission pipeline, equipment or event types must be grouped into the following seven categories: Facility piping (i.e., piping within the facility boundary other than physical volumes associated with distribution pipelines), pipeline venting (i.e., physical volumes associated with distribution pipelines vented within the facility boundary), compressors, scrubbers/strainers, pig launchers and receivers, emergency shutdowns (this category includes emergency shutdown blowdown emissions regardless of equipment type), and all other equipment with a physical volume greater than or equal to 50 cubic feet. If a blowdown event resulted in emissions from multiple equipment types and the emissions cannot be apportioned to the different equipment types, then categorize the blowdown event as the equipment type that represented the largest portion of the emissions for the blowdown event. For the onshore natural gas transmission pipeline segment, pipeline segments or event types must be grouped into the following eight categories: Pipeline integrity work (e.g., the preparation work of modifying facilities, ongoing assessments, maintenance or mitigation), traditional operations or pipeline maintenance, equipment replacement or repair (e.g., valves), pipe abandonment, new construction or modification of pipelines including commissioning and change of service, operational precaution during activities (e.g. excavation near pipelines), emergency shutdowns including pipeline incidents as defined in 49 CFR 191.3, and all other pipeline segments with a physical volume greater than or equal to 50 cubic feet. If a blowdown event resulted in emissions from multiple categories and the emissions cannot be apportioned to the different categories, then categorize the blowdown event in the category that represented the largest portion of the emissions for the blowdown event.
(i) Calculate the total annual natural gas emissions from each unique physical volume that is blown down using either Equation W-14A or W-14B of this section.
(ii) Except as allowed in paragraph (i)(2)(iii) of this section, calculate annual CH
(iii) For onshore natural gas transmission compression facilities and LNG import and export equipment, as an alternative to using the procedures in paragraph (i)(2)(ii) of this section, you may elect to sum the annual natural gas emissions as calculated using either Equation W-14A or Equation W-14B of paragraph (i)(2)(i) of this section for all unique physical volumes associated with the equipment type or event type. Calculate the total annual CH
(3) Method for determining emissions from blowdown vent stacks using a flow meter. In lieu of determining emissions from blowdown vent stacks as specified in paragraph (i)(2) of this section, you may use a flow meter and measure blowdown vent stack emissions for any unique physical volumes determined according to paragraph (i)(1) of this section to be greater than or equal to 50 cubic feet. If you choose to use this method, you must measure the natural gas emissions from the blowdown(s) through the monitored stack(s) using a flow meter according to methods in § 98.234(b), and calculate annual CH
(4) Method for converting from natural gas emissions to GHG volumetric and mass emissions. Calculate both CH
(j) Onshore production and onshore petroleum and natural gas gathering and boosting storage tanks. Calculate CH
(1) Calculation Method 1. Calculate annual CH
(i) Separator or non-separator equipment temperature.
(ii) Separator or non-separator equipment pressure.
(iii) Sales oil or stabilized oil API gravity.
(iv) Sales oil or stabilized oil production rate.
(v) Ambient air temperature.
(vi) Ambient air pressure.
(vii) Separator or non-separator equipment oil composition and Reid vapor pressure. If this data is not available, determine these parameters by using one of the methods described in paragraphs (j)(1)(vii)(A) through (C) of this section.
(A) If separator or non-separator equipment oil composition and Reid vapor pressure default data are provided with the software program, select the default values that most closely match your separator or non-separator equipment pressure first, and API gravity secondarily.
(B) If separator or non-separator equipment oil composition and Reid vapor pressure data are available through your previous analysis, select the latest available analysis that is representative of produced crude oil or condensate from the sub-basin category for onshore petroleum and natural gas production or from the county for onshore petroleum and natural gas gathering and boosting.
(C) Analyze a representative sample of separator or non-separator equipment oil in each sub-basin category for onshore petroleum and natural gas production or each county for onshore petroleum and natural gas gathering and boosting for oil composition and Reid vapor pressure using an appropriate standard method published by a consensus-based standards organization.
(2) Calculation Method 2. Calculate annual CH
(i) Flow to storage tank after passing through a separator. Assume that all of the CH
(ii) Flow to storage tank direct from wells. Calculate CH
(A) If well production oil and gas compositions are available through a previous analysis, select the latest available analysis that is representative of produced oil and gas from the sub-basin category and assume all of the CH
(B) If well production oil and gas compositions are not available, use default oil and gas compositions in software programs, such as API 4697 E&P Tank, that most closely match the well production gas/oil ratio and API gravity and assume all of the CH
(iii) Flow to storage tank direct from non-separator equipment. Calculate CH
(A) If other non-separator equipment liquid and gas compositions are available through a previous analysis, select the latest available analysis that is representative of liquid and gas from non-separator equipment in the same county and assume all of the CH
(B) If non-separator equipment liquid and gas compositions are not available, use default liquid and gas compositions in software programs, such as API 4697 E&P Tank, that most closely match the non-separator equipment gas/liquid ratio and API gravity and assume all of the CH
(3) Calculation Method 3. Calculate CH
(4) Determine if the storage tank receiving your separator oil has a vapor recovery system.
(i) Adjust the emissions estimated in paragraphs (j)(1) through (3) of this section downward by the magnitude of emissions recovered using a vapor recovery system as determined by engineering estimate based on best available data.
(ii) [Reserved]
(5) Determine if the storage tank receiving your separator oil is sent to flare(s).
(i) Use your separator flash gas volume and gas composition as determined in this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine storage tank emissions from the flare.
(6) If you use Calculation Method 1 or Calculation Method 2 in paragraph (j)(1) or (2) of this section, calculate emissions from occurrences of gas-liquid separator liquid dump valves not closing during the calendar year by using Equation W-16 of this section.
(7) Calculate both CH
(k) Transmission storage tanks. For vent stacks connected to one or more transmission condensate storage tanks, either water or hydrocarbon, without vapor recovery, in onshore natural gas transmission compression, calculate CH
(1) Except as specified in paragraph (k)(1)(iv) of this section, you must monitor the tank vapor vent stack annually for emissions using one of the methods specified in paragraphs (k)(1)(i) through (iii) of this section.
(i) Use an optical gas imaging instrument according to methods set forth in § 98.234(a)(1).
(ii) Measure the tank vent directly using a flow meter or high volume sampler according to methods in § 98.234(b) or (d) for a duration of 5 minutes.
(iii) Measure the tank vent using a calibrated bag according to methods in § 98.234(c) for a duration of 5 minutes or until the bag is full, whichever is shorter.
(iv) You may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak detection device according to methods set forth in § 98.234(a)(5).
(2) If the tank vapors from the vent stack are continuous for 5 minutes, or the optical gas imaging instrument or acoustic leak detection device detects a leak, then you must use one of the methods in either paragraph (k)(2)(i) or (ii) of this section.
(i) Use a flow meter, such as a turbine meter, calibrated bag, or high volume sampler to estimate tank vapor volumes from the vent stack according to methods set forth in § 98.234(b) through (d). If you do not have a continuous flow measurement device, you may install a flow measuring device on the tank vapor vent stack. If the vent is directly measured for five minutes under paragraph (k)(1)(ii) or (iii) of this section to detect continuous leakage, this serves as the measurement.
(ii) Use an acoustic leak detection device on each scrubber dump valve connected to the tank according to the method set forth in § 98.234(a)(5).
(3) If a leaking dump valve is identified, the leak must be counted as having occurred since the beginning of the calendar year, or from the previous test that did not detect leaking in the same calendar year. If the leaking dump valve is fixed following leak detection, the leak duration will end upon being repaired. If a leaking dump valve is identified and not repaired, the leak must be counted as having occurred through the rest of the calendar year.
(4) Use the requirements specified in paragraphs (k)(4)(i) and (ii) of this section to quantify annual emissions.
(i) Use the appropriate gas composition in paragraph (u)(2)(iii) of this section.
(ii) Calculate CH
(5) Calculate annual emissions from storage tanks to flares as specified in paragraphs (k)(5)(i) and (ii) of this section.
(i) Use the storage tank emissions volume and gas composition as determined in paragraphs (k)(1) through (4) of this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine storage tank emissions sent to a flare.
(l) Well testing venting and flaring. Calculate CH
(1) Determine the gas to oil ratio (GOR) of the hydrocarbon production from oil well(s) tested. Determine the production rate from gas well(s) tested.
(2) If GOR cannot be determined from your available data, then you must measure quantities reported in this section according to one of the procedures specified in paragraph (l)(2)(i) or (ii) of this section to determine GOR.
(i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.
(ii) You may use an industry standard practice as described in § 98.234(b).
(3) Estimate venting emissions using Equation W-17A (for oil wells) or Equation W-17B (for gas wells) of this section.
(4) Calculate natural gas volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(5) Calculate both CH
(6) Calculate emissions from well testing if emissions are routed to a flare as specified in paragraphs (l)(6)(i) and (ii) of this section.
(i) Use the well testing emissions volume and gas composition as determined in paragraphs (l)(1) through (4) of this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine well testing emissions from the flare.
(m) Associated gas venting and flaring. Calculate CH
(1) Determine the GOR of the hydrocarbon production from each well whose associated natural gas is vented or flared. If GOR from each well is not available, use the GOR from a cluster of wells in the same sub-basin category.
(2) If GOR cannot be determined from your available data, then you must use one of the procedures specified in paragraphs (m)(2)(i) or (ii) of this section to determine GOR.
(i) You may use an appropriate standard method published by a consensus-based standards organization if such a method exists.
(ii) You may use an industry standard practice as described in § 98.234(b).
(3) Estimate venting emissions using Equation W-18 of this section.
(4) Calculate both CH
(5) Calculate emissions from associated natural gas if emissions are routed to a flare as specified in paragraphs (m)(5)(i) and (ii) of this section.
(i) Use the associated natural gas volume and gas composition as determined in paragraph (m)(1) through (4) of this section.
(ii) Use the calculation method of flare stacks in paragraph (n) of this section to determine associated gas emissions from the flare.
(n) Flare stack emissions. Calculate CO
(1) If you have a continuous flow measurement device on the flare, you must use the measured flow volumes to calculate the flare gas emissions. If all of the flare gas is not measured by the existing flow measurement device, then the flow not measured can be estimated using engineering calculations based on best available data or company records. If you do not have a continuous flow measurement device on the flare, you can use engineering calculations based on process knowledge, company records, and best available data.
(2) If you have a continuous gas composition analyzer on gas to the flare, you must use these compositions in calculating emissions. If you do not have a continuous gas composition analyzer on gas to the flare, you must use the appropriate gas compositions for each stream of hydrocarbons going to the flare as specified in paragraphs (n)(2)(i) through (iii) of this section.
(i) For onshore natural gas production and onshore petroleum and natural gas gathering and boosting, determine the GHG mole fraction using paragraph (u)(2)(i) of this section.
(ii) For onshore natural gas processing, when the stream going to flare is natural gas, use the GHG mole fraction in feed natural gas for all streams upstream of the de-methanizer or dew point control, and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities. For onshore natural gas processing plants that solely fractionate a liquid stream, use the GHG mole fraction in feed natural gas liquid for all streams.
(iii) For any industry segment required to report to flare stack emissions under § 98.232, when the stream going to the flare is a hydrocarbon product stream, such as methane, ethane, propane, butane, pentane-plus and mixed light hydrocarbons, then you may use a representative composition from the source for the stream determined by engineering calculation based on process knowledge and best available data.
(3) Determine flare combustion efficiency from manufacturer. If not available, assume that flare combustion efficiency is 98 percent.
(4) Convert GHG volumetric emissions to standard conditions using calculations in paragraph (t) of this section.
(5) Calculate GHG volumetric emissions from flaring at standard conditions using Equations W-19 and W-20 of this section.
(6) Calculate both CH
(7) Calculate N
(8) If you operate and maintain a CEMS that has both a CO
(9) The flare emissions determined under this paragraph (n) must be corrected for flare emissions calculated and reported under other paragraphs of this section to avoid double counting of these emissions.
(o) Centrifugal compressor venting. If you are required to report emissions from centrifugal compressor venting as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2), you must conduct volumetric emission measurements specified in paragraph (o)(1) of this section using methods specified in paragraphs (o)(2) through (5) of this section; perform calculations specified in paragraphs (o)(6) through (9) of this section; and calculate CH
(1) General requirements for conducting volumetric emission measurements. You must conduct volumetric emission measurements on each centrifugal compressor as specified in this paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a measurement method specified in paragraph (o)(1)(i) or (ii) of this section. Manifolded compressor sources (as defined in § 98.238) must use a measurement method specified in paragraph (o)(1)(i), (ii), (iii), or (iv) of this section.
(i) Centrifugal compressor source as found measurements. Measure venting from each compressor according to either paragraph (o)(1)(i)(A) or (B) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraphs (o)(1)(i)(C) and (D) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable monitoring and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this section.
(A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (o)(2)(i)(A) or (B) of this section and, if the compressor has wet seal oil degassing vents, measure volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section.
(B) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in either paragraph (o)(2)(i)(A), (B), or (C) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode.
(C) You must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section at least once in any three consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If three consecutive calendar years occur without measuring the compressor in not-operating-depressurized-mode, you must measure the compressor as specified in paragraph (o)(1)(i)(B) of this section at the next scheduled depressurized shutdown. The requirement specified in this paragraph does not apply if the compressor has blind flanges in place throughout the reporting year. For purposes of this paragraph, a scheduled shutdown means a shutdown that requires a compressor to be taken off-line for planned or scheduled maintenance. A scheduled shutdown does not include instances when a compressor is taken offline due to a decrease in demand but must remain available.
(D) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for all existing compressors. For only the first year of operation of new compressors, calculate emissions according to paragraph (o)(6)(ii) of this section.
(ii) Centrifugal compressor source continuous monitoring. Instead of measuring the compressor source according to paragraph (o)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric emissions from a compressor source as specified in paragraph (o)(3) of this section.
(iii) Manifolded centrifugal compressor source as found measurements. For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (o)(1)(i), (ii), or (iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting measurements at the common vent stack as specified in paragraph (o)(4) of this section. The measurements must be conducted at the frequency specified in paragraphs (o)(1)(iii)(A) and (B) of this section.
(A) A minimum of one measurement must be taken for each manifolded group of compressor sources in a calendar year.
(B) The measurement may be performed while the compressors are in any compressor mode.
(iv) Manifolded centrifugal compressor source continuous monitoring. For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (o)(1)(i), (ii), or (iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded group of compressor sources as specified in paragraph (o)(5) of this section.
(2) Methods for performing as found measurements from individual centrifugal compressor sources. If conducting measurements for each compressor source, you must determine the volumetric emissions from blowdown valves and isolation valves as specified in paragraph (o)(2)(i) of this section, and the volumetric emissions from wet seal oil degassing vents as specified in paragraph (o)(2)(ii) of this section.
(i) For blowdown valves on compressors in operating-mode and for isolation valves on compressors in not-operating-depressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (o)(2)(i)(A) through (D) of this section.
(A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and § 98.234(d), respectively.
(B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer according to methods set forth in § 98.234(b).
(C) Use an acoustic leak detection device according to methods set forth in § 98.234(a)(5).
(D) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (o)(2)(i)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the methods.
(ii) For wet seal oil degassing vents in operating-mode, determine vapor volumes at standard conditions, using a temporary meter such as a vane anemometer or permanent flow meter according to methods set forth in § 98.234(b).
(3) Methods for continuous measurement from individual centrifugal compressor sources. If you elect to conduct continuous volumetric emission measurements for an individual compressor source as specified in paragraph (o)(1)(ii) of this section, you must measure volumetric emissions as specified in paragraphs (o)(3)(i) and (ii) of this section.
(i) Continuously measure the volumetric flow for the individual compressor source at standard conditions using a permanent meter according to methods set forth in § 98.234(b).
(ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
(4) Methods for performing as found measurements from manifolded groups of centrifugal compressor sources. If conducting measurements for a manifolded group of compressor sources, you must measure volumetric emissions as specified in paragraphs (o)(4)(i) and (ii) of this section.
(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.
(ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraphs (o)(4)(ii)(A) through (E) of this section.
(A) A temporary meter such as a vane anemometer according the methods set forth in § 98.234(b).
(B) Calibrated bagging according to methods set forth in § 98.234(c).
(C) A high volume sampler according to methods set forth § 98.234(d).
(D) An acoustic leak detection device according to methods set forth in § 98.234(a)(5).
(E) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (o)(4)(ii)(A) through (o)(4)(ii)(D) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method.
(5) Methods for continuous measurement from manifolded groups of centrifugal compressor sources. If you elect to conduct continuous volumetric emission measurements for a manifolded group of compressor sources as specified in paragraph (o)(1)(iv) of this section, you must measure volumetric emissions as specified in paragraphs (o)(5)(i) through (iii) of this section.
(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.
(ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b).
(iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (o)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
(6) Method for calculating volumetric GHG emissions from as found measurements for individual centrifugal compressor sources. For compressor sources measured according to paragraph (o)(1)(i) of this section, you must calculate annual GHG emissions from the compressor sources as specified in paragraphs (o)(6)(i) through (iv) of this section.
(i) Using Equation W-21 of this section, calculate the annual volumetric GHG emissions for each centrifugal compressor mode-source combination specified in paragraphs (o)(1)(i)(A) and (B) of this section that was measured during the reporting year.
(ii) Using Equation W-22 of this section, calculate the annual volumetric GHG emissions from each centrifugal compressor mode-source combination specified in paragraph (o)(1)(i)(A) and (B) of this section that was not measured during the reporting year.
(iii) Using Equation W-23 of this section, develop an emission factor for each compressor mode-source combination specified in paragraph (o)(1)(i)(A) and (B) of this section. These emission factors must be calculated annually and used in Equation W-22 of this section to determine volumetric emissions from a centrifugal compressor in the mode-source combinations that were not measured in the reporting year.
(iv) The reporter emission factor in Equation W-23 of this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator.
(7) Method for calculating volumetric GHG emissions from continuous monitoring of individual centrifugal compressor sources. For compressor sources measured according to paragraph (o)(1)(ii) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (o)(3) of this section and calculate annual volumetric GHG emissions associated with the compressor source using Equation W-24A of this section.
(8) Method for calculating volumetric GHG emissions from as found measurements of manifolded groups of centrifugal compressor sources. For manifolded groups of compressor sources measured according to paragraph (o)(1)(iii) of this section, you must calculate annual volumetric GHG emissions using Equation W-24B of this section. If the centrifugal compressors included in the manifolded group of compressor sources share the manifold with reciprocating compressors, you must follow the procedures in either this paragraph (o)(8) or paragraph (p)(8) of this section to calculate emissions from the manifolded group of compressor sources.
(9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of centrifugal compressor sources. For a manifolded group of compressor sources measured according to paragraph (o)(1)(iv) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (o)(5) of this section and calculate annual volumetric GHG emissions associated with each manifolded group of compressor sources using Equation W-24C of this section. If the centrifugal compressors included in the manifolded group of compressor sources share the manifold with reciprocating compressors, you must follow the procedures in either this paragraph (o)(9) or paragraph (p)(9) of this section to calculate emissions from the manifolded group of compressor sources.
(10) Method for calculating volumetric GHG emissions from wet seal oil degassing vents at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility. You must calculate emissions from centrifugal compressor wet seal oil degassing vents at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using Equation W-25 of this section.
(11) Method for converting from volumetric to mass emissions. You must calculate both CH
(12) General requirements for calculating volumetric GHG emissions from centrifugal compressors routed to flares. You must calculate and report emissions from all centrifugal compressor sources that are routed to a flare as specified in paragraphs (o)(12)(i) through (iii) of this section.
(i) Paragraphs (o)(1) through (11) of this section are not required for compressor sources that are routed to a flare.
(ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attributable to compressor sources from the flare.
(iii) Report all applicable activity data for compressors with compressor sources routed to flares as specified in § 98.236(o).
(p) Reciprocating compressor venting. If you are required to report emissions from reciprocating compressor venting as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1), you must conduct volumetric emission measurements specified in paragraph (p)(1) of this section using methods specified in paragraphs (p)(2) through (5) of this section; perform calculations specified in paragraphs (p)(6) through (9) of this section; and calculate CH
(1) General requirements for conducting volumetric emission measurements. You must conduct volumetric emission measurements on each reciprocating compressor as specified in this paragraph. Compressor sources (as defined in § 98.238) without manifolded vents must use a measurement method specified in paragraph (p)(1)(i) or (ii) of this section. Manifolded compressor sources (as defined in § 98.238) must use a measurement method specified in paragraph (p)(1)(i), (ii), (iii), or (iv) of this section.
(i) Reciprocating compressor source as found measurements. Measure venting from each compressor according to either paragraph (p)(1)(i)(A), (B), or (C) of this section at least once annually, based on the compressor mode (as defined in § 98.238) in which the compressor was found at the time of measurement, except as specified in paragraphs (p)(1)(i)(D) and (E) of this section. If additional measurements beyond the required annual testing are performed (including duplicate measurements or measurement of additional operating modes), then all measurements satisfying the applicable monitoring and QA/QC that is required by this paragraph (o) must be used in the calculations specified in this section.
(A) For a compressor measured in operating-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (B) of this section, and measure volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) of this section.
(B) For a compressor measured in standby-pressurized-mode, you must measure volumetric emissions from blowdown valve leakage through the blowdown vent as specified in either paragraph (p)(2)(i)(A) or (B) of this section.
(C) For a compressor measured in not-operating-depressurized-mode, you must measure volumetric emissions from isolation valve leakage as specified in either paragraph (p)(2)(i)(A), (B), or (C) of this section. If a compressor is not operated and has blind flanges in place throughout the reporting period, measurement is not required in this compressor mode.
(D) You must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at least once in any three consecutive calendar years, provided the measurement can be taken during a scheduled shutdown. If there is no scheduled shutdown within three consecutive calendar years, you must measure the compressor as specified in paragraph (p)(1)(i)(C) of this section at the next scheduled depressurized shutdown. For purposes of this paragraph, a scheduled shutdown means a shutdown that requires a compressor to be taken off-line for planned or scheduled maintenance. A scheduled shutdown does not include instances when a compressor is taken offline due to a decrease in demand but must remain available.
(E) An annual as found measurement is not required in the first year of operation for any new compressor that begins operation after as found measurements have been conducted for all existing compressors. For only the first year of operation of new compressors, calculate emissions according to paragraph (p)(6)(ii) of this section.
(ii) Reciprocating compressor source continuous monitoring. Instead of measuring the compressor source according to paragraph (p)(1)(i) of this section for a given compressor, you may elect to continuously measure volumetric emissions from a compressor source as specified in paragraph (p)(3) of this section.
(iii) Manifolded reciprocating compressor source as found measurements. For a compressor source that is part of a manifolded group of compressor sources (as defined in § 98.238), instead of measuring the compressor source according to paragraph (p)(1)(i), (ii), or (iv) of this section, you may elect to measure combined volumetric emissions from the manifolded group of compressor sources by conducting measurements at the common vent stack as specified in paragraph (p)(4) of this section. The measurements must be conducted at the frequency specified in paragraphs (p)(1)(iii)(A) and (B) of this section.
(A) A minimum of one measurement must be taken for each manifolded group of compressor sources in a calendar year.
(B) The measurement may be performed while the compressors are in any compressor mode.
(iv) Manifolded reciprocating compressor source continuous monitoring. For a compressor source that is part of a manifolded group of compressor sources, instead of measuring the compressor source according to paragraph (p)(1)(i), (ii), or (iii) of this section, you may elect to continuously measure combined volumetric emissions from the manifolded group of compressors sources as specified in paragraph (p)(5) of this section.
(2) Methods for performing as found measurements from individual reciprocating compressor sources. If conducting measurements for each compressor source, you must determine the volumetric emissions from blowdown valves and isolation valves as specified in paragraph (p)(2)(i) of this section. You must determine the volumetric emissions from reciprocating rod packing as specified in paragraph (p)(2)(ii) or (iii) of this section.
(i) For blowdown valves on compressors in operating-mode or standby-pressurized-mode, and for isolation valves on compressors in not-operating-depressurized-mode, determine the volumetric emissions using one of the methods specified in paragraphs (p)(2)(i)(A) through (D) of this section.
(A) Determine the volumetric flow at standard conditions from the blowdown vent using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and (d), respectively.
(B) Determine the volumetric flow at standard conditions from the blowdown vent using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b).
(C) Use an acoustic leak detection device according to methods set forth in § 98.234(a)(5).
(D) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraphs (p)(2)(i)(A) through (C) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method.
(ii) For reciprocating rod packing equipped with an open-ended vent line on compressors in operating-mode, determine the volumetric emissions using one of the methods specified in paragraphs (p)(2)(ii)(A) through (C) of this section.
(A) Determine the volumetric flow at standard conditions from the open-ended vent line using calibrated bagging or high volume sampler according to methods set forth in § 98.234(c) and (d), respectively.
(B) Determine the volumetric flow at standard conditions from the open-ended vent line using a temporary meter such as a vane anemometer, according to methods set forth in § 98.234(b).
(C) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (p)(2)(ii)(A) and (p)(4)(ii)(B) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method.
(iii) For reciprocating rod packing not equipped with an open-ended vent line on compressors in operating-mode, you must determine the volumetric emissions using the method specified in paragraphs (p)(2)(iii)(A) and (B) of this section.
(A) You must use the methods described in § 98.234(a) to conduct annual leak detection of equipment leaks from the packing case into an open distance piece, or for compressors with a closed distance piece, conduct annual detection of gas emissions from the rod packing vent, distance piece vent, compressor crank case breather cap, or other vent emitting gas from the rod packing.
(B) You must measure emissions found in paragraph (p)(2)(iii)(A) of this section using an appropriate meter, calibrated bag, or high volume sampler according to methods set forth in § 98.234(b), (c), and (d), respectively.
(3) Methods for continuous measurement from individual reciprocating compressor sources. If you elect to conduct continuous volumetric emission measurements for an individual compressor source as specified in paragraph (p)(1)(ii) of this section, you must measure volumetric emissions as specified in paragraphs (p)(3)(i) and (p)(3)(ii) of this section.
(i) Continuously measure the volumetric flow for the individual compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b).
(ii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(3)(i) of this section, the compressor blowdown emissions may be included with the reported emissions for the compressor source and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
(4) Methods for performing as found measurements from manifolded groups of reciprocating compressor sources. If conducting measurements for a manifolded group of compressor sources, you must measure volumetric emissions as specified in paragraphs (p)(4)(i) and (ii) of this section.
(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.
(ii) Determine the volumetric flow at standard conditions from the common stack using one of the methods specified in paragraph (p)(4)(ii)(A) through (E) of this section.
(A) A temporary meter such as a vane anemometer according the methods set forth in § 98.234(b).
(B) Calibrated bagging according to methods set forth in § 98.234(c).
(C) A high volume sampler according to methods set forth § 98.234(d).
(D) An acoustic leak detection device according to methods set forth in § 98.234(a)(5).
(E) You may choose to use any of the methods set forth in § 98.234(a) to screen for emissions. If emissions are detected using the methods set forth in § 98.234(a), then you must use one of the methods specified in paragraph (p)(4)(ii)(A) through (D) of this section. If emissions are not detected using the methods in § 98.234(a), then you may assume that the volumetric emissions are zero. For the purposes of this paragraph, when using any of the methods in § 98.234(a), emissions are detected whenever a leak is detected according to the method.
(5) Methods for continuous measurement from manifolded groups of reciprocating compressor sources. If you elect to conduct continuous volumetric emission measurements for a manifolded group of compressor sources as specified in paragraph (p)(1)(iv) of this section, you must measure volumetric emissions as specified in paragraphs (p)(5)(i) through (iii) of this section.
(i) Measure at a single point in the manifold downstream of all compressor inputs and, if practical, prior to comingling with other non-compressor emission sources.
(ii) Continuously measure the volumetric flow for the manifolded group of compressor sources at standard conditions using a permanent meter according to methods set forth in § 98.234(b).
(iii) If compressor blowdown emissions are included in the metered emissions specified in paragraph (p)(5)(ii) of this section, the compressor blowdown emissions may be included with the reported emissions for the manifolded group of compressor sources and do not need to be calculated separately using the method specified in paragraph (i) of this section for blowdown vent stacks.
(6) Method for calculating volumetric GHG emissions from as found measurements for individual reciprocating compressor sources. For compressor sources measured according to paragraph (p)(1)(i) of this section, you must calculate GHG emissions from the compressor sources as specified in paragraphs (p)(6)(i) through (iv) of this section.
(i) Using Equation W-26 of this section, calculate the annual volumetric GHG emissions for each reciprocating compressor mode-source combination specified in paragraphs (p)(1)(i)(A) through (C) of this section that was measured during the reporting year.
(ii) Using Equation W-27 of this section, calculate the annual volumetric GHG emissions from each reciprocating compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), and (C) of this section that was not measured during the reporting year.
(iii) Using Equation W-28 of this section, develop an emission factor for each compressor mode-source combination specified in paragraph (p)(1)(i)(A), (B), and (C) of this section. These emission factors must be calculated annually and used in Equation W-27 of this section to determine volumetric emissions from a reciprocating compressor in the mode-source combinations that were not measured in the reporting year.
(iv) The reporter emission factor in Equation W-28 of this section may be calculated by using all measurements from a single owner or operator instead of only using measurements from a single facility. If you elect to use this option, the reporter emission factor must be applied to all reporting facilities for the owner or operator.
(7) Method for calculating volumetric GHG emissions from continuous monitoring of individual reciprocating compressor sources. For compressor sources measured according to paragraph (p)(1)(ii) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (p)(3) of this section and calculate annual volumetric GHG emissions associated with the compressor source using Equation W-29A of this section.
(8) Method for calculating volumetric GHG emissions from as found measurements of manifolded groups of reciprocating compressor sources. For manifolded groups of compressor sources measured according to paragraph (p)(1)(iii) of this section, you must calculate annual GHG emissions using Equation W-29B of this section. If the reciprocating compressors included in the manifolded group of compressor sources share the manifold with centrifugal compressors, you must follow the procedures in either this paragraph (p)(8) or paragraph (o)(8) of this section to calculate emissions from the manifolded group of compressor sources.
(9) Method for calculating volumetric GHG emissions from continuous monitoring of manifolded group of reciprocating compressor sources. For a manifolded group of compressor sources measured according to paragraph (p)(1)(iv) of this section, you must use the continuous volumetric emission measurements taken as specified in paragraph (p)(5) of this section and calculate annual volumetric GHG emissions associated with each manifolded group of compressor sources using Equation W-29C of this section. If the reciprocating compressors included in the manifolded group of compressor sources share the manifold with centrifugal compressors, you must follow the procedures in either this paragraph (p)(9) or paragraph (o)(9) of this section to calculate emissions from the manifolded group of compressor sources.
(10) Method for calculating volumetric GHG emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility. You must calculate emissions from reciprocating compressor venting at an onshore petroleum and natural gas production facility or an onshore petroleum and natural gas gathering and boosting facility using Equation W-29D of this section.
(11) Method for converting from volumetric to mass emissions. You must calculate both CH
(12) General requirements for calculating volumetric GHG emissions from reciprocating compressors routed to flares. You must calculate and report emissions from all reciprocating compressor sources that are routed to a flare as specified in paragraphs (p)(12)(i) through (iii) of this section.
(i) Paragraphs (p)(1) through (11) of this section are not required for compressor sources that are routed to a flare.
(ii) If any compressor sources are routed to a flare, calculate the emissions for the flare stack as specified in paragraph (n) of this section and report emissions from the flare as specified in § 98.236(n), without subtracting emissions attributable to compressor sources from the flare.
(iii) Report all applicable activity data for compressors with compressor sources routed to flares as specified in § 98.236(p).
(q) Equipment leak surveys. For the components identified in paragraphs (q)(1)(i) through (iii) of this section, you must conduct equipment leak surveys using the leak detection methods specified in paragraphs (q)(1)(i) through (iii) of this section. For the components identified in paragraph (q)(1)(iv) of this section, you may elect to conduct equipment leak surveys, and if you elect to conduct surveys, you must use a leak detection method specified in paragraph (q)(1)(iv) of this section. This paragraph (q) applies to components in streams with gas content greater than 10 percent CH
(1) Survey requirements. (i) For the components listed in § 98.232(e)(7), (f)(5), (g)(4), and (h)(5), that are not subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you must conduct surveys using any of the leak detection methods listed in § 98.234(a) and calculate equipment leak emissions using the procedures specified in paragraph (q)(2) of this section.
(ii) For the components listed in § 98.232(d)(7) and (i)(1), you must conduct surveys using any of the leak detection methods listed in § 98.234(a)(1) through (5) and calculate equipment leak emissions using the procedures specified in paragraph (q)(2) of this section.
(iii) For the components listed in § 98.232(c)(21), (e)(7), (e)(8), (f)(5), (f)(6), (f)(7), (f)(8), (g)(4), (g)(6), (g)(7), (h)(5), (h)(7), (h)(8), and (j)(10) that are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter, you must conduct surveys using any of the leak detection methods in § 98.234(a)(6) or (7) and calculate equipment leak emissions using the procedures specified in paragraph (q)(2) of this section.
(iv) For the components listed in § 98.232(c)(21), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), or (j)(10), that are not subject to fugitive emissions standards in § 60.5397a of this chapter, you may elect to conduct surveys according to this paragraph (q), and, if you elect to do so, then you must use one of the leak detection methods in § 98.234(a).
(A) If you elect to use a leak detection method in § 98.234(a)(1) through (5) for the surveyed component types in § 98.232(c)(21), (f)(7), (g)(6), (h)(7), or (j)(10) in lieu of the population count methodology specified in paragraph (r) of this section, then you must calculate emissions for the surveyed component types in § 98.232(c)(21), (f)(7), (g)(6), (h)(7), or (j)(10) using the procedures in paragraph (q)(2) of this section.
(B) If you elect to use a leak detection method in § 98.234(a)(1) through (5) for the surveyed component types in § 98.232(e)(8), (f)(6), (f)(8), (g)(7), and (h)(8), then you must use the procedures in paragraph (q)(2) of this section to calculate those emissions.
(C) If you elect to use a leak detection method in § 98.234(a)(6) or (7) for any elective survey under this subparagraph (q)(1)(iv), then you must survey the component types in § 98.232(c)(21), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), and (j)(10) that are not subject to fugitive emissions standards in § 60.5397a of this chapter, and you must calculate emissions from the surveyed component types in § 98.232(c)(21), (e)(8), (f)(6), (f)(7), (f)(8), (g)(6), (g)(7), (h)(7), (h)(8), and (j)(10) using the emission calculation requirements in paragraph (q)(2) of this section.
(2) Emission calculation methodology. For industry segments listed in § 98.230(a)(2) through (9), if equipment leaks are detected during surveys required or elected for components listed in paragraphs (q)(1)(i) through (iv) of this section, then you must calculate equipment leak emissions per component type per reporting facility using Equation W-30 of this section and the requirements specified in paragraphs (q)(2)(i) through (xi) of this section. For the industry segment listed in § 98.230(a)(8), the results from Equation W-30 are used to calculate population emission factors on a meter/regulator run basis using Equation W-31 of this section. If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, “n,” according to paragraph (q)(2)(x)(A) of this section, then you must calculate the emissions from all above grade transmission-distribution transfer stations as specified in paragraph (q)(2)(xi) of this section.
(i) You must conduct at least one leak detection survey in a calendar year. The leak detection surveys selected must be conducted during the calendar year. If you conduct multiple complete leak detection surveys in a calendar year, you must use the results from each complete leak detection survey when calculating emissions using Equation W-30. For components subject to the well site and compressor station fugitive emissions standards in § 60.5397a of this chapter, each survey conducted in accordance with § 60.5397a of this chapter will be considered a complete leak detection survey for purposes of this section.
(ii) Calculate both CO
(iii) Onshore petroleum and natural gas production facilities must use the appropriate default whole gas leaker emission factors for components in gas service, light crude service, and heavy crude service listed in Table W-1E to this subpart.
(iv) Onshore petroleum and natural gas gathering and boosting facilities must use the appropriate default whole gas leaker factors for components in gas service listed in Table W-1E to this subpart.
(v) Onshore natural gas processing facilities must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non-compressor components in gas service listed in Table W-2 to this subpart.
(vi) Onshore natural gas transmission compression facilities must use the appropriate default total hydrocarbon leaker emission factors for compressor components in gas service and non-compressor components in gas service listed in Table W-3A to this subpart.
(vii) Underground natural gas storage facilities must use the appropriate default total hydrocarbon leaker emission factors for storage stations or storage wellheads in gas service listed in Table W-4A to this subpart.
(viii) LNG storage facilities must use the appropriate default methane leaker emission factors for LNG storage components in LNG service or gas service listed in Table W-5A to this subpart.
(ix) LNG import and export facilities must use the appropriate default methane leaker emission factors for LNG terminals components in LNG service or gas service listed in Table W-6A to this subpart.
(x) Natural gas distribution facilities must use Equation W-30 of this section and the default methane leaker emission factors for transmission-distribution transfer station components in gas service listed in Table W-7 to this subpart to calculate component emissions from annual equipment leak surveys conducted at above grade transmission-distribution transfer stations. Natural gas distribution facilities are required to perform equipment leak surveys only at above grade stations that qualify as transmission-distribution transfer stations. Below grade transmission-distribution transfer stations and all metering-regulating stations that do not meet the definition of transmission-distribution transfer stations are not required to perform equipment leak surveys under this section.
(A) Natural gas distribution facilities may choose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years “n,” not exceeding a five year period to cover all above grade transmission-distribution transfer stations. If the facility chooses to use the multiple year option, then the number of transmission-distribution transfer stations that are monitored in each year should be approximately equal across all years in the cycle.
(B) Use Equation W-31 of this section to determine the meter/regulator run population emission factors for each GHG
(C) The emission factor “EFs,
(xi) If you chose to conduct equipment leak surveys at all above grade transmission-distribution transfer stations over multiple years, “n,” according to paragraph (q)(2)(x)(A) of this section, you must use the meter/regulator run population emission factors calculated using Equation W-31 of this section and the total count of all meter/regulator runs at above grade transmission-distribution transfer stations to calculate emissions from all above grade transmission-distribution transfer stations using Equation W-32B in paragraph (r) of this section.
(r) Equipment leaks by population count. This paragraph (r) applies to emissions sources listed in § 98.232(c)(21), (f)(7), (g)(5), (h)(6), and (j)(10) if you are not required to comply with paragraph (q) of this section and if you do not elect to comply with paragraph (q) of this section for these components in lieu of this paragraph (r). This paragraph (r) also applies to emission sources listed in § 98.232(i)(2), (i)(3), (i)(4), (i)(5), (i)(6), and (j)(11). To be subject to the requirements of this paragraph (r), the listed emissions sources also must contact streams with gas content greater than 10 percent CH
Tubing systems equal to or less than one half inch diameter are exempt from the requirements of paragraph (r) of this section and do not need to be reported. You must calculate emissions from all emission sources listed in this paragraph using Equation W-32A of this section, except for natural gas distribution facility emission sources listed in § 98.232(i)(3). Natural gas distribution facility emission sources listed in § 98.232(i)(3) must calculate emissions using Equation W-32B of this section and according to paragraph (r)(6)(ii) of this section.
(1) Calculate both CH
(2) Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must use the appropriate default whole gas population emission factors listed in Table W-1A of this subpart. Major equipment and components associated with gas wells and onshore petroleum and natural gas gathering and boosting systems are considered gas service components in reference to Table W-1A of this subpart and major natural gas equipment in reference to Table W-1B of this subpart. Major equipment and components associated with crude oil wells are considered crude service components in reference to Table W-1A of this subpart and major crude oil equipment in reference to Table W-1C of this subpart. Where facilities conduct EOR operations the emissions factor listed in Table W-1A of this subpart shall be used to estimate all streams of gases, including recycle CO
(i) Component Count Method 1. For all onshore petroleum and natural gas production operations and onshore petroleum and natural gas gathering and boosting operations in the facility perform the following activities:
(A) Count all major equipment listed in Table W-1B and Table W-1C of this subpart. For meters/piping, use one meters/piping per well-pad for onshore petroleum and natural gas production operations and the number of meters in the facility for onshore petroleum and natural gas gathering and boosting operations.
(B) Multiply major equipment counts by the average component counts listed in Table W-1B of this subpart for onshore natural gas production and onshore petroleum and natural gas gathering and boosting; and Table W-1C of this subpart for onshore oil production. Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart.
(ii) Component Count Method 2. Count each component individually for the facility. Use the appropriate factor in Table W-1A of this subpart for operations in Eastern and Western U.S. according to the mapping in Table W-1D of this subpart.
(3) Underground natural gas storage facilities must use the appropriate default total hydrocarbon population emission factors for storage wellheads in gas service listed in Table W-4B to this subpart.
(4) LNG storage facilities must use the appropriate default methane population emission factor for LNG storage compressors in gas service listed in Table W-5B to this subpart.
(5) LNG import and export facilities must use the appropriate default methane population emission factor for LNG terminal compressors in gas service listed in Table W-6B to this subpart.
(6) Natural gas distribution facilities must use the appropriate methane emission factors as described in paragraphs (r)(6)(i) and (ii) of this section.
(i) Below grade metering-regulating stations, distribution mains, and distribution services must use the appropriate default methane population emission factors listed in Table W-7 of this subpart. Below grade transmission-distribution transfer stations must use the emission factor for below grade metering-regulating stations.
(ii) Above grade metering-regulating stations that are not above grade transmission-distribution transfer stations must use the meter/regulator run population emission factor calculated in Equation W-31. Natural gas distribution facilities that do not have above grade transmission-distribution transfer stations are not required to calculate emissions for above grade metering-regulating stations and are not required to report GHG emissions in § 98.236(r)(2)(v).
(s) Offshore petroleum and natural gas production facilities. Report CO
(1) Offshore production facilities under BOEMRE jurisdiction shall report the same annual emissions as calculated and reported by BOEMRE in data collection and emissions estimation study published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS).
(i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication year, report the most recent BOEMRE reported emissions data published by BOEMRE referenced in 30 CFR 250.302 through 304 (GOADS). Adjust emissions based on the operating time for the facility relative to the operating time in the most recent BOEMRE published study.
(ii) [Reserved]
(2) Offshore production facilities that are not under BOEMRE jurisdiction must use the most recent monitoring methods and calculation methods published by BOEMRE referenced in 30 CFR 250.302 through 250.304 to calculate and report annual emissions (GOADS).
(i) For any calendar year that does not overlap with the most recent BOEMRE emissions study publication, you may report the most recently reported emissions data submitted to demonstrate compliance with this subpart of part 98, with emissions adjusted based on the operating time for the facility relative to operating time in the previous reporting period.
(ii) [Reserved]
(3) If BOEMRE discontinues or delays their data collection effort by more than 4 years, then offshore reporters shall once in every 4 years use the most recent BOEMRE data collection and emissions estimation methods to estimate emissions. These emission estimates would be used to report emissions from the facility sources as required in paragraph (s)(1)(i) of this section.
(4) For either first or subsequent year reporting, offshore facilities either within or outside of BOEMRE jurisdiction that were not covered in the previous BOEMRE data collection cycle must use the most recent BOEMRE data collection and emissions estimation methods published by BOEMRE referenced in 30 CFR 250.302 through 250.304 to calculate and report emissions.
(t) GHG volumetric emissions using actual conditions. If equation parameters in § 98.233 are already determined at standard conditions as provided in the introductory text in § 98.233, which results in volumetric emissions at standard conditions, then this paragraph does not apply. Calculate volumetric emissions at standard conditions as specified in paragraphs (t)(1) or (2) of this section, with actual pressure and temperature determined by engineering estimates based on best available data unless otherwise specified.
(1) Calculate natural gas volumetric emissions at standard conditions using actual natural gas emission temperature and pressure, and Equation W-33 of this section for conversions of E
(2) Calculate GHG volumetric emissions at standard conditions using actual GHG emissions temperature and pressure, and Equation W-34 of this section.
You may use either a default compressibility factor of 1, or a site-specific compressibility factor based on actual temperature and pressure conditions.
(3) Reporters using 68 °F for standard temperature may use the ratio 519.67/527.67 to convert volumetric emissions from 68 °F to 60 °F.
(u) GHG volumetric emissions at standard conditions. Calculate GHG volumetric emissions at standard conditions as specified in paragraphs (u)(1) and (2) of this section.
(1) Estimate CH
(2) For Equation W-35 of this section, the mole fraction, M
(i) GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities. If you have a continuous gas composition analyzer for produced natural gas, you must use an annual average of these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then you must use an annual average gas composition based on your most recent available analysis of the sub-basin category or facility, as applicable to the emission source.
(ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the de-methanizer or dew point control and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas processing facilities. For onshore natural gas processing plants that solely fractionate a liquid stream, use the GHG mole percent in feed natural gas liquid for all streams. If you have a continuous gas composition analyzer on feed natural gas, you must use these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, then annual samples must be taken according to methods set forth in § 98.234(b).
(iii) GHG mole fraction in transmission pipeline natural gas that passes through the facility for the onshore natural gas transmission compression industry segment and the onshore natural gas transmission pipeline industry segment. You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data.
(iv) GHG mole fraction in natural gas stored in the underground natural gas storage industry segment. You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data.
(v) GHG mole fraction in natural gas stored in the LNG storage industry segment. You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data.
(vi) GHG mole fraction in natural gas stored in the LNG import and export industry segment. For export facilities that receive gas from transmission pipelines, you may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data.
(vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural gas distribution facilities. You may use either a default 95 percent methane and 1 percent carbon dioxide fraction for GHG mole fraction in natural gas or site specific engineering estimates based on best available data.
(v) GHG mass emissions. Calculate GHG mass emissions in metric tons by converting the GHG volumetric emissions at standard conditions into mass emissions using Equation W-36 of this section.
ρ
(w) EOR injection pump blowdown. Calculate CO
(1) Calculate the total injection pump system volume in cubic feet (including pipelines, manifolds and vessels) between isolation valves.
(2) Retain logs of the number of blowdowns per calendar year.
(3) Calculate the total annual CO
(x) EOR hydrocarbon liquids dissolved CO
(1) Determine the amount of CO
(2) Estimate emissions using Equation W-38 of this section.
S
(y) [Reserved]
(z) Onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, and natural gas distribution combustion emissions. Calculate CO
(1) If a fuel combusted in the stationary or portable equipment is listed in Table C-1 of subpart C of this part, or is a blend containing one or more fuels listed in Table C-1, calculate emissions according to paragraph (z)(1)(i) of this section. If the fuel combusted is natural gas and is of pipeline quality specification and has a minimum high heat value of 950 Btu per standard cubic foot, use the calculation method described in paragraph (z)(1)(i) of this section and you may use the emission factor provided for natural gas as listed in Table C-1. If the fuel is natural gas, and is not pipeline quality or has a high heat value of less than 950 Btu per standard cubic feet, calculate emissions according to paragraph (z)(2) of this section. If the fuel is field gas, process vent gas, or a blend containing field gas or process vent gas, calculate emissions according to paragraph (z)(2) of this section.
(i) For fuels listed in Table C-1 or a blend containing one or more fuels listed in Table C-1, calculate CO
(ii) Emissions from fuel combusted in stationary or portable equipment at onshore petroleum and natural gas production facilities, at onshore petroleum and natural gas gathering and boosting facilities, and at natural gas distribution facilities will be reported according to the requirements specified in § 98.236(z) and not according to the reporting requirements specified in subpart C of this part.
(2) For fuel combustion units that combust field gas, process vent gas, a blend containing field gas or process vent gas, or natural gas that is not of pipeline quality or that has a high heat value of less than 950 Btu per standard cubic feet, calculate combustion emissions as follows:
(i) You may use company records to determine the volume of fuel combusted in the unit during the reporting year.
(ii) If you have a continuous gas composition analyzer on fuel to the combustion unit, you must use these compositions for determining the concentration of gas hydrocarbon constituent in the flow of gas to the unit. If you do not have a continuous gas composition analyzer on gas to the combustion unit, you must use the appropriate gas compositions for each stream of hydrocarbons going to the combustion unit as specified in the applicable paragraph in (u)(2) of this section.
(iii) Calculate GHG volumetric emissions at actual conditions using Equations W-39A and W-39B of this section:
(iv) Calculate GHG volumetric emissions at standard conditions using calculations in paragraph (t) of this section.
(v) Calculate both combustion-related CH
(vi) Calculate N
(3) External fuel combustion sources with a rated heat capacity equal to or less than 5 mmBtu/hr do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the type and number of each external fuel combustion unit.
(4) Internal fuel combustion sources, not compressor-drivers, with a rated heat capacity equal to or less than 1 mmBtu/hr (or the equivalent of 130 horsepower), do not need to report combustion emissions or include these emissions for threshold determination in § 98.231(a). You must report the type and number of each internal fuel combustion unit.
§ 98.234 Monitoring and QA/QC requirements.
The GHG emissions data for petroleum and natural gas emissions sources must be quality assured as applicable as specified in this section. Offshore petroleum and natural gas production facilities shall adhere to the monitoring and QA/QC requirements as set forth in 30 CFR 250.
(a) You must use any of the methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) of through-valve leakage from all source types listed in § 98.233(k), (o), and (p) that occur during a calendar year. You must use any of the methods described in paragraphs (a)(1) through (7) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(i) that occur during a calendar year. You must use any of the methods described in paragraphs (a)(1) through (5) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(ii) that occur during a calendar year. You must use one of the methods described in paragraph (a)(6) or (7) of this section to conduct leak detection(s) of equipment leaks from components as specified in § 98.233(q)(1)(iii). If electing to comply with § 98.233(q) as specified in § 98.233(q)(1)(iv), you must use any of the methods described in paragraphs (a)(1) through (7) of this section to conduct leak detection(s) of equipment leaks from component types as specified in § 98.233(q)(1)(iv) that occur during a calendar year.
(1) Optical gas imaging instrument as specified in § 60.18 of this chapter.
Use an optical gas imaging instrument for equipment leak detection in accordance with 40 CFR part 60, subpart A, § 60.18 of the Alternative work practice for monitoring equipment leaks, § 60.18(i)(1)(i); § 60.18(i)(2)(i) except that the monitoring frequency shall be annual using the detection sensitivity level of 60 grams per hour as stated in 40 CFR Part 60, subpart A, Table 1: Detection Sensitivity Levels; § 60.18(i)(2)(ii) and (iii) except the gas chosen shall be methane, and § 60.18(i)(2)(iv) and (v); § 60.18(i)(3); § 60.18(i)(4)(i) and (v); including the requirements for daily instrument checks and distances, and excluding requirements for video records. Any emissions detected by the optical gas imaging instrument is a leak unless screened with Method 21 (40 CFR part 60, appendix A-7) monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, you must operate the optical gas imaging instrument to image the source types required by this subpart in accordance with the instrument manufacturer’s operating parameters. Unless using methods in paragraph (a)(2) of this section, an optical gas imaging instrument must be used for all source types that are inaccessible and cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface.
(2) Method 21. Use the equipment leak detection methods in 40 CFR part 60, appendix A-7, Method 21. If using Method 21 monitoring, if an instrument reading of 10,000 ppm or greater is measured, a leak is detected. Inaccessible emissions sources, as defined in 40 CFR part 60, are not exempt from this subpart. If the equipment leak detection methods in this paragraph cannot be used, you must use alternative leak detection devices as described in paragraph (a)(1) of this section to monitor inaccessible equipment leaks or vented emissions.
(3) Infrared laser beam illuminated instrument. Use an infrared laser beam illuminated instrument for equipment leak detection. Any emissions detected by the infrared laser beam illuminated instrument is a leak unless screened with Method 21 monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, you must operate the infrared laser beam illuminated instrument to detect the source types required by this subpart in accordance with the instrument manufacturer’s operating parameters.
(4) [Reserved]
(5) Acoustic leak detection device. Use the acoustic leak detection device to detect through-valve leakage. When using the acoustic leak detection device to quantify the through-valve leakage, you must use the instrument manufacturer’s calculation methods to quantify the through-valve leak. When using the acoustic leak detection device, if a leak of 3.1 scf per hour or greater is calculated, a leak is detected. In addition, you must operate the acoustic leak detection device to monitor the source valves required by this subpart in accordance with the instrument manufacturer’s operating parameters. Acoustic stethoscope type devices designed to detect through valve leakage when put in contact with the valve body and that provide an audible leak signal but do not calculate a leak rate can be used to identify non-leakers with subsequent measurement required to calculate the rate if through-valve leakage is identified. Leaks are reported if a leak rate of 3.1 scf per hour or greater is measured.
(6) Optical gas imaging instrument as specified in § 60.5397a of this chapter. Use an optical gas imaging instrument for equipment leak detection in accordance with § 60.5397a(b), (c)(3), (c)(7), and (e) of this chapter and paragraphs (a)(6)(i) through (iii) of this section. Unless using methods in paragraph (a)(7) of this section, an optical gas imaging instrument must be used for all source types that are inaccessible and cannot be monitored without elevating the monitoring personnel more than 2 meters above a support surface.
(i) For the purposes of this subpart, any visible emissions from a component listed in § 98.232 observed by the optical gas imaging instrument is a leak.
(ii) For the purposes of this subpart, the term “fugitive emissions component” in § 60.5397a of this chapter means “component.”
(iii) For the purpose of complying with § 98.233(q)(1)(iv), the phrase “the collection of fugitive emissions components at well sites and compressor stations” in § 60.5397a(b) of this chapter means “the collection of components for which you elect to comply with § 98.233(q)(1)(iv).”
(7) Method 21 as specified in § 60.5397a of this chapter. Use the equipment leak detection methods in appendix A-7 to part 60 of this chapter, Method 21, in accordance with § 60.5397a(b), (c)(8), and (e) of this chapter and paragraphs (a)(7)(i) through (iii) of this section. Inaccessible emissions sources, as defined in part 60 of this chapter, are not exempt from this subpart. If the equipment leak detection methods in this paragraph cannot be used, you must use alternative leak detection devices as described in paragraph (a)(6) of this section to monitor inaccessible equipment leaks.
(i) For the purposes of this subpart, any instrument reading from a component listed in § 98.232 of this chapter of 500 ppm or greater using Method 21 is a leak.
(ii) For the purposes of this subpart, the term “fugitive emissions component” in § 60.5397a of this chapter means “component.”
(iii) For the purpose of complying with § 98.233(q)(1)(iv), the phrase “the collection of fugitive emissions components at well sites and compressor stations” in § 60.5397a(b) of this chapter means “the collection of components for which you elect to comply with § 98.233(q)(1)(iv).”
(b) You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure quantities reported in § 98.233 according to the procedures in § 98.3(i) and the procedures in paragraph (b) of this section. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or you may use an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(c) Use calibrated bags (also known as vent bags) only where the emissions are at near-atmospheric pressures and below the maximum temperature specified by the vent bag manufacturer such that the bag is safe to handle. The bag opening must be of sufficient size that the entire emission can be tightly encompassed for measurement till the bag is completely filled.
(1) Hold the bag in place enclosing the emissions source to capture the entire emissions and record the time required for completely filling the bag. If the bag inflates in less than one second, assume one second inflation time.
(2) Perform three measurements of the time required to fill the bag, report the emissions as the average of the three readings.
(3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t).
(4) Estimate CH
(d) Use a high volume sampler to measure emissions within the capacity of the instrument.
(1) A technician following manufacturer instructions shall conduct measurements, including equipment manufacturer operating procedures and measurement methods relevant to using a high volume sampler, including positioning the instrument for complete capture of the equipment leak without creating backpressure on the source.
(2) If the high volume sampler, along with all attachments available from the manufacturer, is not able to capture all the emissions from the source then use anti-static wraps or other aids to capture all emissions without violating operating requirements as provided in the instrument manufacturer’s manual.
(3) Estimate natural gas volumetric emissions at standard conditions using calculations in § 98.233(t). Estimate CH
(4) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH
(e) Peng Robinson Equation of State means the equation of state defined by Equation W-41 of this section:
(f) Special reporting provisions for best available monitoring methods in reporting year 2015 – (1) Best available monitoring methods. From January 1, 2015 to March 31, 2015, for a facility subject to this subpart, you must use the calculation methodologies and equations in § 98.233 “Calculating GHG Emissions”, but you may use the best available monitoring method for any parameter for which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2015 as specified in paragraphs (f)(2) and (3) of this section. Starting no later than April 1, 2015, you must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part, except as provided in paragraph (f)(4) of this section. Best available monitoring methods means any of the following methods:
(i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(2) Best available monitoring methods for well-related measurement data. You may use best available monitoring methods for well-related measurement data identified in paragraphs (f)(2)(i) and (ii) of this section that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart.
(i) If Calculation Method 1 for liquids unloading in § 98.233(f)(1) was used in calendar year 2014 and will be used again in calendar year 2015, the vented natural gas flow rate for any well in a unique tubing diameter group and pressure group combination that has not been previously measured.
(ii) If using Equation W-10A of this subpart to determine natural gas emissions from completions and workovers for representative wells, the initial and average flowback rates (when using Calculation Method 1 in § 98.233(g)(1)(i)) or pressures upstream and downstream of the choke (when using Calculation Method 2 in § 98.233(g)(1)(ii)) for any well in a well type combination that has not been previously measured.
(3) Best available monitoring methods for emissions measurement. You may use best available monitoring methods for sources listed in paragraphs (f)(3)(i) and (ii) of this section if the required measurement data cannot reasonably be obtained according to the monitoring and QA/QC requirements of this part.
(i) Centrifugal compressor as found measurements of manifolded emissions from groups of centrifugal compressor sources according to § 98.233(o)(4) and (5), in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in § 98.232(d)(2), (e)(2), (f)(2), (g)(2), and (h)(2).
(ii) Reciprocating compressor as found measurements of manifolded emissions from groups of reciprocating compressor sources according to § 98.233(p)(4) and (5), in onshore natural gas processing, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment as specified in § 98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1).
(4) Requests for extension of the use of best available monitoring methods beyond March 31, 2015. You may submit a request to the Administrator to use one or more best available monitoring methods for sources listed in paragraphs (f)(2) and (3) of this section beyond March 31, 2015.
(i) Timing of request. The extension request must be submitted to EPA no later than January 31, 2015.
(ii) Content of request. Requests must contain the following information:
(A) A list of specific source types and parameters for which you are seeking use of best available monitoring methods.
(B) For each specific source type for which you are requesting use of best available monitoring methods, a description of the reasons that the needed equipment could not be obtained and installed before April 1, 2015.
(C) A description of the specific actions you will take to obtain and install the equipment as soon as reasonably feasible and the expected date by which the equipment will be installed and operating.
(iii) Approval criteria. To obtain approval to use best available monitoring methods after March 31, 2015, you must submit a request demonstrating to the Administrator’s satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by April 1, 2015. The use of best available methods under paragraph (f) of this section will not be approved beyond December 31, 2015.
(g) Special reporting provisions for best available monitoring methods in reporting year 2016 – (1) Best available monitoring methods. From January 1, 2016, to December 31, 2016, you must use the calculation methodologies and equations in § 98.233 but you may use the best available monitoring method as described in paragraph (g)(2) of this section for any parameter specified in paragraphs (g)(3) through (6) of this section for which it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2016. Starting no later than January 1, 2017, you must discontinue using best available methods and begin following all applicable monitoring and QA/QC requirements of this part. For onshore petroleum and natural gas production, this paragraph (g)(1) only applies if emissions from well completions and workovers of oil wells with hydraulic fracturing cause your facility to exceed the reporting threshold in § 98.231(a)(1).
(2) Best available monitoring methods means any of the following methods:
(i) Monitoring methods currently used by the facility that do not meet the specifications of this subpart.
(ii) Supplier data.
(iii) Engineering calculations.
(iv) Other company records.
(3) Best available monitoring methods for well-related measurement data for oil wells with hydraulic fracturing. You may use best available monitoring methods for any well-related measurement data that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart for venting during well completions and workovers of oil wells with hydraulic fracturing.
(4) Best available monitoring methods for measurement data for onshore petroleum and natural gas gathering and boosting facilities. You may use best available monitoring methods for any leak detection and/or measurement data that cannot reasonably be measured according to the monitoring and QA/QC requirements of this subpart for acid gas removal vents as specified in § 98.233(d).
(5) Best available monitoring methods for measurement data for natural gas transmission pipelines. You may use best available monitoring methods for any measurement data for natural gas transmission pipelines that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart for blowdown vent stacks.
(6) Best available monitoring methods for specified activity data. You may use best available monitoring methods for activity data as listed in paragraphs (g)(6)(i) through (iii) of this section that cannot reasonably be obtained according to the monitoring and QA/QC requirements of this subpart for well completions and workovers of oil wells with hydraulic fracturing, onshore petroleum and natural gas gathering and boosting facilities, or natural gas transmission pipelines.
(i) Cumulative hours of venting, days, or times of operation in § 98.233(e), (g), (o), (p), and (r).
(ii) Number of blowdowns, completions, workovers, or other events in § 98.233(g) and (i).
(iii) Cumulative volume produced, volume input or output, or volume of fuel used in paragraphs § 98.233(d), (e), (j), (n), and (z).
(h) For well venting for liquids unloading, if a monitoring period other than the full calendar year is used to determine the cumulative amount of time in hours of venting for each well (the term “T
§ 98.235 Procedures for estimating missing data.
Except as specified in § 98.233, whenever a value of a parameter is unavailable for a GHG emission calculation required by this subpart (including, but not limited to, if a measuring device malfunctions during unit operation or activity data are not collected), you must follow the procedures specified in paragraphs (a) through (i) of this section, as applicable.
(a) For stationary and portable combustion sources that use the calculation methods of subpart C of this part, you must use the missing data procedures in subpart C of this part.
(b) For each missing value of a parameter that should have been measured quarterly or more frequently using equipment including, but not limited to, a continuous flow meter, composition analyzer, thermocouple, or pressure gauge, you must substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, you must use the first quality-assured value obtained after the missing data period as the substitute data value. A value is quality-assured according to the procedures specified in § 98.234.
(c) For each missing value of a parameter that should have been measured annually, you must repeat the estimation or measurement activity for those sources as soon as possible, including in the subsequent calendar year if missing data are not discovered until after December 31 of the year in which data are collected, until valid data for reporting are obtained. Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used for that subsequent year’s emissions estimation. Where missing data procedures are used for the previous year, at least 30 days must separate emissions estimation or measurements for the previous year and emissions estimation or measurements for the current year of data collection.
(d) For each missing value of a parameter that should have been measured biannually (every two years), you must conduct the estimation or measurement activity for those sources as soon as possible in the subsequent calendar year if the estimation or measurement was not made in the appropriate year (first year of data collection and every two years thereafter), until valid data for reporting are obtained. Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used to alternate or postpone subsequent biannual emissions estimations or measurements.
(e) For the first 6 months of required data collection, facilities that become newly subject to this subpart W may use best engineering estimates for any data that cannot reasonably be measured or obtained according to the requirements of this subpart.
(f) For the first 6 months of required data collection, facilities that are currently subject to this subpart W and that acquire new sources from another facility that were not previously subject to this subpart W may use best engineering estimates for any data related to those newly acquired sources that cannot reasonably be measured or obtained according to the requirements of this subpart.
(g) Unless addressed in another paragraph of this section, for each missing value of any activity data, you must substitute data value(s) using the best available estimate(s) of the parameter(s), based on all applicable and available process or other data (including, but not limited to, processing rates, operating hours).
(h) You must report information for all measured and substitute values of a parameter, and the procedures used to substitute an unavailable value of a parameter per the requirements in § 98.236(bb).
(i) You must follow recordkeeping requirements listed in § 98.237(f).
§ 98.236 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain reported emissions and related information as specified in this section. Reporters that use a flow or volume measurement system that corrects to standard conditions as provided in the introductory text in § 98.233 for data elements that are otherwise required to be determined at actual conditions, report gas volumes at standard conditions rather the gas volumes at actual conditions and report the standard temperature and pressure used by the measurement system rather than the actual temperature and pressure.
(a) The annual report must include the information specified in paragraphs (a)(1) through (10) of this section for each applicable industry segment. The annual report must also include annual emissions totals, in metric tons of each GHG, for each applicable industry segment listed in paragraphs (a)(1) through (10), and each applicable emission source listed in paragraphs (b) through (z) of this section.
(1) Onshore petroleum and natural gas production. For the equipment/activities specified in paragraphs (a)(1)(i) through (xvii) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
(ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph (c) of this section.
(iii) Acid gas removal units. Report the information specified in paragraph (d) of this section.
(iv) Dehydrators. Report the information specified in paragraph (e) of this section.
(v) Liquids unloading. Report the information specified in paragraph (f) of this section.
(vi) Completions and workovers with hydraulic fracturing. Report the information specified in paragraph (g) of this section.
(vii) Completions and workovers without hydraulic fracturing. Report the information specified in paragraph (h) of this section.
(viii) Onshore production storage tanks. Report the information specified in paragraph (j) of this section.
(ix) Well testing. Report the information specified in paragraph (l) of this section.
(x) Associated natural gas. Report the information specified in paragraph (m) of this section.
(xi) Flare stacks. Report the information specified in paragraph (n) of this section.
(xii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(xiii) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(xiv) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(xv) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(xvi) EOR injection pumps. Report the information specified in paragraph (w) of this section.
(xvii) EOR hydrocarbon liquids. Report the information specified in paragraph (x) of this section.
(xviii) Combustion equipment. Report the information specified in paragraph (z) of this section.
(2) Offshore petroleum and natural gas production. Report the information specified in paragraph (s) of this section.
(3) Onshore natural gas processing. For the equipment/activities specified in paragraphs (a)(3)(i) through (vii) of this section, report the information specified in the applicable paragraphs of this section.
(i) Acid gas removal units. Report the information specified in paragraph (d) of this section.
(ii) Dehydrators. Report the information specified in paragraph (e) of this section.
(iii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(iv) Flare stacks. Report the information specified in paragraph (n) of this section.
(v) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(vi) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(vii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(4) Onshore natural gas transmission compression. For the equipment/activities specified in paragraphs (a)(4)(i) through (vii) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
(ii) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(iii) Transmission storage tanks. Report the information specified in paragraph (k) of this section.
(iv) Flare stacks. Report the information specified in paragraph (n) of this section.
(v) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(vi) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(vii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(5) Underground natural gas storage. For the equipment/activities specified in paragraphs (a)(5)(i) through (vi) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
(ii) Flare stacks. Report the information specified in paragraph (n) of this section.
(iii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(iv) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(v) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(vi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(6) LNG storage. For the equipment/activities specified in paragraphs (a)(6)(i) through (v) of this section, report the information specified in the applicable paragraphs of this section.
(i) Flare stacks. Report the information specified in paragraph (n) of this section.
(ii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(iii) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(iv) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(v) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(7) LNG import and export equipment. For the equipment/activities specified in paragraphs (a)(7)(i) through (vi) of this section, report the information specified in the applicable paragraphs of this section.
(i) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(ii) Flare stacks. Report the information specified in paragraph (n) of this section.
(iii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(iv) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(v) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(vi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(8) Natural gas distribution. For the equipment/activities specified in paragraphs (a)(8)(i) through (iii) of this section, report the information specified in the applicable paragraphs of this section.
(i) Combustion equipment. Report the information specified in paragraph (z) of this section.
(ii) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(iii) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(9) Onshore petroleum and natural gas gathering and boosting. For the equipment/activities specified in paragraphs (a)(9)(i) through (xi) of this section, report the information specified in the applicable paragraphs of this section.
(i) Natural gas pneumatic devices. Report the information specified in paragraph (b) of this section.
(ii) Natural gas driven pneumatic pumps. Report the information specified in paragraph (c) of this section.
(iii) Acid gas removal units. Report the information specified in paragraph (d) of this section.
(iv) Dehydrators. Report the information specified in paragraph (e) of this section.
(v) Blowdown vent stacks. Report the information specified in paragraph (i) of this section.
(vi) Storage tanks. Report the information specified in paragraph (j) of this section.
(vii) Flare stacks. Report the information specified in paragraph (n) of this section.
(viii) Centrifugal compressors. Report the information specified in paragraph (o) of this section.
(ix) Reciprocating compressors. Report the information specified in paragraph (p) of this section.
(x) Equipment leak surveys. Report the information specified in paragraph (q) of this section.
(xi) Equipment leaks by population count. Report the information specified in paragraph (r) of this section.
(xii) Combustion equipment. Report the information specified in paragraph (z) of this section.
(10) Onshore natural gas transmission pipeline. For blowdown vent stacks, report the information specified in paragraph (i) of this section.
(b) Natural gas pneumatic devices. You must indicate whether the facility contains the following types of equipment: Continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, and intermittent bleed natural gas pneumatic devices. If the facility contains any continuous high bleed natural gas pneumatic devices, continuous low bleed natural gas pneumatic devices, or intermittent bleed natural gas pneumatic devices, then you must report the information specified in paragraphs (b)(1) through (b)(4) of this section.
(1) The number of natural gas pneumatic devices as specified in paragraphs (b)(1)(i) and (ii) of this section.
(i) The total number of devices of each type, determined according to § 98.233(a)(1) and (2).
(ii) If the reported value in paragraph (b)(1)(i) of this section is an estimated value determined according to § 98.233(a)(2), then you must report the information specified in paragraphs (b)(1)(ii)(A) through (C) of this section.
(A) The number of devices of each type reported in paragraph (b)(1)(i) of this section that are counted.
(B) The number of devices of each type reported in paragraph (b)(1)(i) of this section that are estimated (not counted).
(C) Whether the calendar year is the first calendar year of reporting or the second calendar year of reporting.
(2) For each type of pneumatic device, the estimated average number of hours in the calendar year that the natural gas pneumatic devices reported in paragraph (b)(1)(i) of this section were operating in the calendar year (“T
(3) Annual CO
(4) Annual CH
(c) Natural gas driven pneumatic pumps. You must indicate whether the facility has any natural gas driven pneumatic pumps. If the facility contains any natural gas driven pneumatic pumps, then you must report the information specified in paragraphs (c)(1) through (4) of this section.
(1) Count of natural gas driven pneumatic pumps.
(2) Average estimated number of hours in the calendar year the pumps were operational (“T” in Equation W-2 of this subpart).
(3) Annual CO
(4) Annual CH
(d) Acid gas removal units. You must indicate whether your facility has any acid gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant. If your facility contains any acid gas removal units that vent directly to the atmosphere, to a flare or engine, or to a sulfur recovery plant, then you must report the information specified in paragraphs (d)(1) and (2) of this section.
(1) You must report the information specified in paragraphs (d)(1)(i) through (vi) of this section for each acid gas removal unit.
(i) A unique name or ID number for the acid gas removal unit. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single acid gas removal unit for each location it operates at in a given year.
(ii) Total feed rate entering the acid gas removal unit, using a meter or engineering estimate based on process knowledge or best available data, in million cubic feet per year.
(iii) The calculation method used to calculate CO
(iv) Whether any CO
(v) Annual CO
(vi) Sub-basin ID that best represents the wells supplying gas to the unit (for the onshore petroleum and natural gas production industry segment only) or name of the county that best represents the equipment supplying gas to the unit (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(2) You must report information specified in paragraphs (d)(2)(i) through (iii) of this section, applicable to the calculation method reported in paragraph (d)(1)(iii) of this section, for each acid gas removal unit.
(i) If you used Calculation Method 1 or Calculation Method 2 as specified in § 98.233(d) to calculate CO
(A) Annual average volumetric fraction of CO
(B) Annual volume of gas vented from the acid gas removal unit, in cubic feet.
(ii) If you used Calculation Method 3 as specified in § 98.233(d) to calculate CO
(A) Indicate which equation was used (Equation W-4A or W-4B).
(B) Annual average volumetric fraction of CO
(C) Annual average volumetric fraction of CO
(D) The natural gas flow rate used, as specified in Equation W-4A of this subpart, reported as either total annual volume of natural gas flow into the acid gas removal unit in cubic feet at actual conditions; or total annual volume of natural gas flow out of the acid gas removal unit, as specified in Equation W-4B of this subpart, in cubic feet at actual conditions.
(iii) If you used Calculation Method 4 as specified in § 98.233(d) to calculate CO
(A) The name of the simulation software package used.
(B) Natural gas feed temperature, in degrees Fahrenheit.
(C) Natural gas feed pressure, in pounds per square inch.
(D) Natural gas flow rate, in standard cubic feet per minute.
(E) Acid gas content of the feed natural gas, in mole percent.
(F) Acid gas content of the outlet natural gas, in mole percent.
(G) Unit operating hours, excluding downtime for maintenance or standby, in hours per year.
(H) Exit temperature of the natural gas, in degrees Fahrenheit.
(I) Solvent pressure, in pounds per square inch.
(J) Solvent temperature, in degrees Fahrenheit.
(K) Solvent circulation rate, in gallons per minute.
(L) Solvent weight, in pounds per gallon.
(e) Dehydrators. You must indicate whether your facility contains any of the following equipment: Glycol dehydrators with an annual average daily natural gas throughput greater than or equal to 0.4 million standard cubic feet per day, glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day, and dehydrators that use desiccant. If your facility contains any of the equipment listed in this paragraph (e), then you must report the applicable information in paragraphs (e)(1) through (3).
(1) For each glycol dehydrator that has an annual average daily natural gas throughput greater than or equal to 0.4 million standard cubic feet per day (as specified in § 98.233(e)(1)), you must report the information specified in paragraphs (e)(1)(i) through (xviii) of this section for the dehydrator.
(i) A unique name or ID number for the dehydrator. For the onshore petroleum and natural gas production and the onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single dehydrator for each location it operates at in a given year.
(ii) Dehydrator feed natural gas flow rate, in million standard cubic feet per day, determined by engineering estimate based on best available data.
(iii) Dehydrator feed natural gas water content, in pounds per million standard cubic feet.
(iv) Dehydrator outlet natural gas water content, in pounds per million standard cubic feet.
(v) Dehydrator absorbent circulation pump type (e.g., natural gas pneumatic, air pneumatic, or electric).
(vi) Dehydrator absorbent circulation rate, in gallons per minute.
(vii) Type of absorbent (e.g., triethylene glycol (TEG), diethylene glycol (DEG), or ethylene glycol (EG)).
(viii) Whether stripper gas is used in dehydrator.
(ix) Whether a flash tank separator is used in dehydrator.
(x) Total time the dehydrator is operating, in hours.
(xi) Temperature of the wet natural gas, in degrees Fahrenheit.
(xii) Pressure of the wet natural gas, in pounds per square inch gauge.
(xiii) Mole fraction of CH
(xiv) Mole fraction of CO
(xv) Whether any dehydrator emissions are vented to a vapor recovery device.
(xvi) Whether any dehydrator emissions are vented to a flare or regenerator firebox/fire tubes. If any emissions are vented to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(1)(xvi)(A) through (C) of this section for these emissions from the dehydrator.
(A) Annual CO
(B) Annual CH
(C) Annual N
(xvii) Whether any dehydrator emissions are vented to the atmosphere without being routed to a flare or regenerator firebox/fire tubes. If any emissions are not routed to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(1)(xvii)(A) and (B) of this section for those emissions from the dehydrator.
(A) Annual CO
(B) Annual CH
(xviii) Sub-basin ID that best represents the wells supplying gas to the dehydrator (for the onshore petroleum and natural gas production industry segment only) or name of the county that best represents the equipment supplying gas to the dehydrator (for the onshore petroleum and natural gas gathering and boosting industry segment only).
(2) For glycol dehydrators with an annual average daily natural gas throughput less than 0.4 million standard cubic feet per day (as specified in § 98.233(e)(2)), you must report the information specified in paragraphs (e)(2)(i) through (v) of this section for the entire facility.
(i) The total number of dehydrators at the facility.
(ii) Whether any dehydrator emissions were vented to a vapor recovery device. If any dehydrator emissions were vented to a vapor recovery device, then you must report the total number of dehydrators at the facility that vented to a vapor recovery device.
(iii) Whether any dehydrator emissions were vented to a control device other than a vapor recovery device or a flare or regenerator firebox/fire tubes. If any dehydrator emissions were vented to a control device(s) other than a vapor recovery device or a flare or regenerator firebox/fire tubes, then you must specify the type of control device(s) and the total number of dehydrators at the facility that were vented to each type of control device.
(iv) Whether any dehydrator emissions were vented to a flare or regenerator firebox/fire tubes. If any dehydrator emissions were vented to a flare or regenerator firebox/fire tubes, then you must report the information specified in paragraphs (e)(2)(iv)(A) through (D) of this section.
(A) The total number of dehydrators venting to a flare or regenerator firebox/fire tubes.
(B) Annual CO
(C) Annual CH
(D) Annual N
(v) For dehydrator emissions that were not vented to a flare or regenerator firebox/fire tubes, report the information specified in paragraphs (e)(2)(v)(A) and (B) of this section.
(A) Annual CO
(B) Annual CH
(3) For dehydrators that use desiccant (as specified in § 98.233(e)(3)), you must report the information specified in paragraphs (e)(3)(i) through (iii) of this section for the entire facility.
(i) The same information specified in paragraphs (e)(2)(i) through (iv) of this section for glycol dehydrators, and report the information under this paragraph for dehydrators that use desiccant.
(ii) Annual CO
(iii) Annual CH
(f) Liquids unloading. You must indicate whether well venting for liquids unloading occurs at your facility, and if so, which methods (as specified in § 98.233(f)) were used to calculate emissions. If your facility performs well venting for liquids unloading and uses Calculation Method 1, then you must report the information specified in paragraph (f)(1) of this section. If the facility performs liquids unloading and uses Calculation Method 2 or 3, then you must report the information specified in paragraph (f)(2) of this section.
(1) For each sub-basin and well tubing diameter and pressure group for which you used Calculation Method 1 to calculate natural gas emissions from well venting for liquids unloading, report the information specified in paragraphs (f)(1)(i) through (xii) of this section. Report information separately for wells with plunger lifts and wells without plunger lifts.
(i) Sub-basin ID.
(ii) Well tubing diameter and pressure group ID and a list of the well ID numbers associated with each sub-basin and well tubing diameter and pressure group ID.
(iii) Plunger lift indicator.
(iv) Count of wells vented to the atmosphere for the sub-basin/well tubing diameter and pressure group.
(v) Percentage of wells for which the monitoring period used to determine the cumulative amount of time venting was not the full calendar year.
(vi) Cumulative amount of time wells were vented (sum of “T
(vii) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all wells in the sub-basin/well tubing diameter and pressure group.
(viii) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(1).
(ix) Annual CO
(x) Annual CH
(xi) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xi)(A) through (E) of this section for each individual well not using a plunger lift that was tested during the year.
(A) Well ID number of tested well.
(B) Casing pressure, in pounds per square inch absolute.
(C) Internal casing diameter, in inches.
(D) Measured depth of the well, in feet.
(E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour.
(xii) For each well tubing diameter group and pressure group combination, you must report the information specified in paragraphs (f)(1)(xii)(A) through (E) of this section for each individual well using a plunger lift that was tested during the year.
(A) Well ID number.
(B) The tubing pressure, in pounds per square inch absolute.
(C) The internal tubing diameter, in inches.
(D) Measured depth of the well, in feet.
(E) Average flow rate of the well venting over the duration of the liquids unloading, in standard cubic feet per hour.
(2) For each sub-basin for which you used Calculation Method 2 or 3 (as specified in § 93.233(f)) to calculate natural gas emissions from well venting for liquids unloading, you must report the information in (f)(2)(i) through (x) of this section. Report information separately for each calculation method.
(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin.
(ii) Calculation method.
(iii) Plunger lift indicator.
(iv) Number of wells vented to the atmosphere.
(v) Cumulative number of unloadings vented to the atmosphere for each well, aggregated across all wells.
(vi) Annual natural gas emissions, in standard cubic feet, from well venting for liquids unloading, calculated according to § 98.233(f)(2) or (3), as applicable.
(vii) Annual CO
(viii) Annual CH
(ix) For wells without plunger lifts, the average internal casing diameter, in inches.
(x) For wells with plunger lifts, the average internal tubing diameter, in inches.
(g) Completions and workovers with hydraulic fracturing. You must indicate whether your facility had any well completions or workovers with hydraulic fracturing during the calendar year. If your facility had well completions or workovers with hydraulic fracturing during the calendar year, then you must report information specified in paragraphs (g)(1) through (10) of this section, for each sub-basin and well type combination. Report information separately for completions and workovers.
(1) Sub-basin ID and a list of the well ID numbers associated with each sub-basin that had completions or workovers with hydraulic fracturing during the calendar year.
(2) Well type combination (horizontal or vertical, gas well or oil well).
(3) Number of completions or workovers in the sub-basin and well type combination category.
(4) Calculation method used.
(5) If you used Equation W-10A of § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(5)(i) through (iii) of this section.
(i) Cumulative gas flowback time, in hours, from when gas is first detected until sufficient quantities are present to enable separation, and the cumulative flowback time, in hours, after sufficient quantities of gas are present to enable separation (sum of “T
(ii) For the measured well(s), the flowback rate, in standard cubic feet per hour (average of “FR
(iii) If you used Equation W-12C of § 98.233 to calculate the average gas production rate for an oil well, then you must report the information specified in paragraphs (g)(5)(iii)(A) and (B) of this section.
(A) Gas to oil ratio for the well in standard cubic feet of gas per barrel of oil (“GOR
(B) Volume of oil produced during the first 30 days of production after completions of each newly drilled well or well workover using hydraulic fracturing, in barrels (“V
(6) If you used Equation W-10B of § 98.233 to calculate annual volumetric total gas emissions, then you must report the information specified in paragraphs (g)(6)(i) through (iii) of this section.
(i) Vented natural gas volume, in standard cubic feet, for each well in the sub-basin (“FV
(ii) Flow rate at the beginning of the period of time when sufficient quantities of gas are present to enable separation, in standard cubic feet per hour, for each well in the sub-basin (“FR
(iii) The well ID number for which vented natural gas volume was measured.
(7) Annual gas emissions, in standard cubic feet (“E
(8) Annual CO
(9) Annual CH
(10) If the well emissions were vented to a flare, then you must report the total N
(h) Completions and workovers without hydraulic fracturing. You must indicate whether the facility had any gas well completions without hydraulic fracturing or any gas well workovers without hydraulic fracturing, and if the activities occurred with or without flaring. If the facility had gas well completions or workovers without hydraulic fracturing, then you must report the information specified in paragraphs (h)(1) through (4) of this section, as applicable.
(1) For each sub-basin with gas well completions without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(1)(i) through (vi) of this section.
(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin for gas well completions without hydraulic fracturing and without flaring.
(ii) Number of well completions that vented gas directly to the atmosphere without flaring.
(iii) Total number of hours that gas vented directly to the atmosphere during venting for all completions in the sub-basin category (the sum of all “T
(iv) Average daily gas production rate for all completions without hydraulic fracturing in the sub-basin without flaring, in standard cubic feet per hour (average of all “V
(v) Annual CO
(vi) Annual CH
(2) For each sub-basin with gas well completions without hydraulic fracturing and with flaring, report the information specified in paragraphs (h)(2)(i) through (vii) of this section.
(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin for gas well completions without hydraulic fracturing and with flaring.
(ii) Number of well completions that flared gas.
(iii) Total number of hours that gas vented to a flare during venting for all completions in the sub-basin category (the sum of all “T
(iv) Average daily gas production rate for all completions without hydraulic fracturing in the sub-basin with flaring, in standard cubic feet per hour (the average of all “V
(v) Annual CO
(vi) Annual CH
(vii) Annual N
(3) For each sub-basin with gas well workovers without hydraulic fracturing and without flaring, report the information specified in paragraphs (h)(3)(i) through (iv) of this section.
(i) Sub-basin ID and a list of the well ID numbers associated with each sub-basin for gas well workovers without hydraulic fracturing and without flaring.
(ii) Number of workovers that vented gas to the atmosphere without flaring.
(iii) Annual CO
(iv) Annual CH
(4) For each sub-basin with gas well workovers without hydraulic fracturing and with flaring, report the information specified in paragraphs (h)(4)(i) through (v) of this section.
(i) Sub-basin ID and a list of well ID numbers associated with each sub-basin for gas well workovers without hydraulic fracturing and with flaring.
(ii) Number of workovers that flared gas.
(iii) Annual CO
(iv) Annual CH
(v) Annual N
(i) Blowdown vent stacks. You must indicate whether your facility has blowdown vent stacks. If your facility has blowdown vent stacks, then you must report whether emissions were calculated by equipment or event type or by using flow meters or a combination of both. If you calculated emissions by equipment or event type for any blowdown vent stacks, then you must report the information specified in paragraph (i)(1) of this section considering, in aggregate, all blowdown vent stacks for which emissions were calculated by equipment or event type. If you calculated emissions using flow meters for any blowdown vent stacks, then you must report the information specified in paragraph (i)(2) of this section considering, in aggregate, all blowdown vent stacks for which emissions were calculated using flow meters. For the onshore natural gas transmission pipeline segment, you must also report the information in paragraph (i)(3) of this section.
(1) Report by equipment or event type. If you calculated emissions from blowdown vent stacks by the seven categories listed in § 98.233(i)(2) for industry segments other than the onshore natural gas transmission pipeline segment, then you must report the equipment or event types and the information specified in paragraphs (i)(1)(i) through (iii) of this section for each equipment or event type. If a blowdown event resulted in emissions from multiple equipment types, and the emissions cannot be apportioned to the different equipment types, then you may report the information in paragraphs (i)(1)(i) through (iii) of this section for the equipment type that represented the largest portion of the emissions for the blowdown event. If you calculated emissions from blowdown vent stacks by the eight categories listed in § 98.233(i)(2) for the onshore natural gas transmission pipeline segment, then you must report the pipeline segments or event types and the information specified in paragraphs (i)(1)(i) through (iii) of this section for each “equipment or event type” (i.e., category). If a blowdown event resulted in emissions from multiple categories, and the emissions cannot be apportioned to the different categories, then you may report the information in paragraphs (i)(1)(i) through (iii) of this section for the “equipment or event type” (i.e., category) that represented the largest portion of the emissions for the blowdown event.
(i) Total number of blowdowns in the calendar year for the equipment or event type (the sum of equation variable “N” from Equation W-14A or Equation W-14B of this subpart, for all unique physical volumes for the equipment or event type).
(ii) Annual CO
(iii) Annual CH
(2) Report by flow meter. If you elect to calculate emissions from blowdown vent stacks by using a flow meter according to § 98.233(i)(3), then you must report the information specified in paragraphs (i)(2)(i) and (ii) of this section for the facility.
(i) Annual CO
(ii) Annual CH
(3) Onshore natural gas transmission pipeline segment. Report the information in paragraphs (i)(3)(i) through (iii) of this section for each state.
(i) Annual CO
(ii) Annual CH
(iii) Annual number of blowdown events.
(j) Onshore production and onshore petroleum and natural gas gathering and boosting storage tanks. You must indicate whether your facility sends produced oil to atmospheric tanks. If your facility sends produced oil to atmospheric tanks, then you must indicate which Calculation Method(s) you used to calculate GHG emissions, and you must report the information specified in paragraphs (j)(1) and (2) of this section as applicable. If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j), and any atmospheric tanks were observed to have malfunctioning dump valves during the calendar year, then you must indicate that dump valves were malfunctioning and you must report the information specified in paragraph (j)(3) of this section.
(1) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j) to calculate GHG emissions, then you must report the information specified in paragraphs (j)(1)(i) through (xvi) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) and by calculation method. Onshore petroleum and natural gas gathering and boosting facilities do not report the information specified in paragraphs (j)(1)(ix) and (xi) of this section.
(i) Sub-basin ID (for onshore production) or county name (for onshore petroleum and natural gas gathering and boosting).
(ii) Calculation method used, and name of the software package used if using Calculation Method 1.
(iii) The total annual oil volume from gas-liquid separators and direct from wells or non-separator equipment that is sent to applicable onshore production and onshore petroleum and natural gas gathering and boosting storage tanks, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and delineation wells are the only wells in the sub-basin with oil production greater than or equal to 10 barrels per day and flowing to gas-liquid separators or direct to storage tanks. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the total volume of oil from all wells and the well ID number(s) for the well(s) included in this volume.
(iv) The average gas-liquid separator or non-separator equipment temperature, in degrees Fahrenheit.
(v) The average gas-liquid separator or non-separator equipment pressure, in pounds per square inch gauge.
(vi) The average sales oil or stabilized oil API gravity, in degrees.
(vii) The minimum and maximum concentration (mole fraction) of CO
(viii) The minimum and maximum concentration (mole fraction) of CH
(ix) The number of wells sending oil to gas-liquid separators or directly to atmospheric tanks.
(x) The number of atmospheric tanks.
(xi) An estimate of the number of atmospheric tanks, not on well-pads, receiving your oil.
(xii) If any emissions from the atmospheric tanks at your facility were controlled with vapor recovery systems, then you must report the information specified in paragraphs (j)(1)(xii)(A) through (E) of this section.
(A) The number of atmospheric tanks that control emissions with vapor recovery systems.
(B) Total CO
(C) Total CH
(D) Annual CO
(E) Annual CH
(xiii) If any atmospheric tanks at your facility vented gas directly to the atmosphere without using a vapor recovery system or without flaring, then you must report the information specified in paragraphs (j)(1)(xiii)(A) through (C) of this section.
(A) The number of atmospheric tanks that vented gas directly to the atmosphere without using a vapor recovery system or without flaring.
(B) Annual CO
(C) Annual CH
(xiv) If you controlled emissions from any atmospheric tanks at your facility with one or more flares, then you must report the information specified in paragraphs (j)(1)(xiv)(A) through (D) of this section.
(A) The number of atmospheric tanks that controlled emissions with flares.
(B) Annual CO
(C) Annual CH
(D) Annual N
(2) If you used Calculation Method 3 to calculate GHG emissions, then you must report the information specified in paragraphs (j)(2)(i) through (iii) of this section.
(i) Report the information specified in paragraphs (j)(2)(i)(A) through (F) of this section, at the basin level, for atmospheric tanks where emissions were calculated using Calculation Method 3 of § 98.233(j). Onshore gathering and boosting facilities do not report the information specified in paragraphs (j)(2)(i)(E) and (F) of this section.
(A) The total annual oil/condensate throughput that is sent to all atmospheric tanks in the basin, in barrels. You may delay reporting of this data element for onshore production if you indicate in the annual report that wildcat wells and delineation wells are the only wells in the sub-basin with oil/condensate production less than 10 barrels per day and that send oil/condensate to atmospheric tanks. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the total annual oil/condensate throughput from all wells and the well ID number(s) for the well(s) included in this volume.
(B) An estimate of the fraction of oil/condensate throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the basin that controlled emissions with flares.
(C) An estimate of the fraction of oil/condensate throughput reported in paragraph (j)(2)(i)(A) of this section sent to atmospheric tanks in the basin that controlled emissions with vapor recovery systems.
(D) The number of atmospheric tanks in the basin.
(E) The number of wells with gas-liquid separators (“Count” from Equation W-15 of this subpart) in the basin.
(F) The number of wells without gas-liquid separators (“Count” from Equation W-15 of this subpart) in the basin.
(ii) Report the information specified in paragraphs (j)(2)(ii)(A) through (D) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) with atmospheric tanks whose emissions were calculated using Calculation Method 3 of § 98.233(j) and that did not control emissions with flares.
(A) Sub-basin ID (for onshore production) or county name (for onshore petroleum and natural gas gathering and boosting).
(B) The number of atmospheric tanks in the sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) that did not control emissions with flares.
(C) Annual CO
(D) Annual CH
(iii) Report the information specified in paragraphs (j)(2)(iii)(A) through (E) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) with atmospheric tanks whose emissions were calculated using Calculation Method 3 of § 98.233(j) and that controlled emissions with flares.
(A) Sub-basin ID (for onshore production) or county name (for onshore petroleum and natural gas gathering and boosting).
(B) The number of atmospheric tanks in the sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting) that controlled emissions with flares.
(C) Annual CO
(D) Annual CH
(E) Annual N
(3) If you used Calculation Method 1 or Calculation Method 2 of § 98.233(j), and any gas-liquid separator liquid dump values did not close properly during the calendar year, then you must report the information specified in paragraphs (j)(3)(i) through (iv) of this section for each sub-basin (for onshore production) or county (for onshore petroleum and natural gas gathering and boosting).
(i) The total number of gas-liquid separators whose liquid dump valves did not close properly during the calendar year.
(ii) The total time the dump valves on gas-liquid separators did not close properly in the calendar year, in hours (sum of the “T
(iii) Annual CO
(iv) Annual CH
(k) Transmission storage tanks. You must indicate whether your facility contains any transmission storage tanks. If your facility contains at least one transmission storage tank, then you must report the information specified in paragraphs (k)(1) through (3) of this section for each transmission storage tank vent stack.
(1) For each transmission storage tank vent stack, report the information specified in (k)(1)(i) through (iv) of this section.
(i) The unique name or ID number for the transmission storage tank vent stack.
(ii) Method used to determine if dump valve leakage occurred.
(iii) Indicate whether scrubber dump valve leakage occurred for the transmission storage tank vent according to § 98.233(k)(2).
(iv) Indicate if there is a flare attached to the transmission storage tank vent stack.
(2) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii) of this section, and the vent stack vented directly to the atmosphere during the calendar year, then you must report the information specified in paragraphs (k)(2)(i) through (v) of this section for each transmission storage vent stack where scrubber dump valve leakage occurred.
(i) Method used to measure the leak rate.
(ii) Measured leak rate (average leak rate from a continuous flow measurement device), in standard cubic feet per hour.
(iii) Duration of time that the leak is counted as having occurred, in hours, as determined in § 98.233(k)(3) (may use best available data if a continuous flow measurement device was used).
(iv) Annual CO
(v) Annual CH
(3) If scrubber dump valve leakage occurred for a transmission storage tank vent stack, as reported in paragraph (k)(1)(iii), and the vent stack vented to a flare during the calendar year, then you must report the information specified in paragraphs (k)(3)(i) through (vi) of this section.
(i) Method used to measure the leak rate.
(ii) Measured leakage rate (average leak rate from a continuous flow measurement device) in standard cubic feet per hour.
(iii) Duration of time that flaring occurred in hours, as defined in § 98.233(k)(3) (may use best available data if a continuous flow measurement device was used).
(iv) Annual CO
(v) Annual CH
(vi) Annual N
(l) Well testing. You must indicate whether you performed gas well or oil well testing, and if the testing of gas wells or oil wells resulted in vented or flared emissions during the calendar year. If you performed well testing that resulted in vented or flared emissions during the calendar year, then you must report the information specified in paragraphs (l)(1) through (4) of this section, as applicable.
(1) If you used Equation W-17A of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are not vented to a flare, then you must report the information specified in paragraphs (l)(1)(i) through (vii) of this section.
(i) Number of wells tested in the calendar year.
(ii) Well ID numbers for the wells tested in the calendar year.
(iii) Average number of well testing days per well for well(s) tested in the calendar year.
(iv) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.
(v) Average flow rate for well(s) tested, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average flow rate for well(s) tested and the well ID number(s) for the well(s) included in the measurement.
(vi) Annual CO
(vii) Annual CH
(2) If you used Equation W-17A of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from oil wells and the emissions are vented to a flare, then you must report the information specified in paragraphs (l)(2)(i) through (viii) of this section.
(i) Number of wells tested in the calendar year.
(ii) Well ID numbers for the wells tested in the calendar year.
(iii) Average number of well testing days per well for well(s) tested in the calendar year.
(iv) Average gas to oil ratio for well(s) tested, in cubic feet of gas per barrel of oil.
(v) Average flow rate for well(s) tested, in barrels of oil per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average flow rate for well(s) tested and the well ID number(s) for the well(s) included in the measurement.
(vi) Annual CO
(vii) Annual CH
(viii) Annual N
(3) If you used Equation W-17B of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were not vented to a flare, then you must report the information specified in paragraphs (l)(3)(i) through (vi) of this section.
(i) Number of wells tested in the calendar year.
(ii) Well ID numbers for the wells tested in the calendar year.
(iii) Average number of well testing days per well for well(s) tested in the calendar year.
(iv) Average annual production rate for well(s) tested, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average annual production rate for well(s) tested and the well ID number(s) for the well(s) included in the measurement.
(v) Annual CO
(vi) Annual CH
(4) If you used Equation W-17B of § 98.233 to calculate annual volumetric natural gas emissions at actual conditions from gas wells and the emissions were vented to a flare, then you must report the information specified in paragraphs (l)(4)(i) through (vii) of this section.
(i) Number of wells tested in calendar year.
(ii) Well ID numbers for the wells tested in the calendar year.
(iii) Average number of well testing days per well for well(s) tested in the calendar year.
(iv) Average annual production rate for well(s) tested, in actual cubic feet per day. You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells are the only wells that are tested. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured average annual production rate for well(s) tested and the well ID number(s) for the well(s) included in the measurement.
(v) Annual CO
(vi) Annual CH
(vii) Annual N
(m) Associated natural gas. You must indicate whether any associated gas was vented or flared during the calendar year. If associated gas was vented or flared during the calendar year, then you must report the information specified in paragraphs (m)(1) through (8) of this section for each sub-basin.
(1) Sub-basin ID and a list of well ID numbers for wells for which associated gas was vented or flared.
(2) Indicate whether any associated gas was vented directly to the atmosphere without flaring.
(3) Indicate whether any associated gas was flared.
(4) Average gas to oil ratio, in standard cubic feet of gas per barrel of oil (average of the “GOR” values used in Equation W-18 of this subpart).
(5) Volume of oil produced, in barrels, in the calendar year during the time periods in which associated gas was vented or flared (the sum of “V
(6) Total volume of associated gas sent to sales, in standard cubic feet, in the calendar year during time periods in which associated gas was vented or flared (the sum of “SG” values used in Equation W-18 of § 98.233(m)). You may delay reporting of this data element if you indicate in the annual report that wildcat wells and/or delineation wells from which associated gas was vented or flared. If you elect to delay reporting of this data element, you must report by the date specified in § 98.236(cc) the measured total volume of associated gas sent to sales for well(s) with associated gas venting and flaring and the well ID number(s) for the well(s) included in the measurement.
(7) If you had associated gas emissions vented directly to the atmosphere without flaring, then you must report the information specified in paragraphs (m)(7)(i) through (iii) of this section for each sub-basin.
(i) Total number of wells for which associated gas was vented directly to the atmosphere without flaring and a list of their well ID numbers.
(ii) Annual CO
(iii) Annual CH
(8) If you had associated gas emissions that were flared, then you must report the information specified in paragraphs (m)(8)(i) through (iv) of this section for each sub-basin.
(i) Total number of wells for which associated gas was flared and a list of their well ID numbers.
(ii) Annual CO
(iii) Annual CH
(iv) Annual N
(n) Flare stacks. You must indicate if your facility contains any flare stacks. You must report the information specified in paragraphs (n)(1) through (12) of this section for each flare stack at your facility, and for each industry segment applicable to your facility.
(1) Unique name or ID for the flare stack. For the onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting industry segments, a different name or ID may be used for a single flare stack for each location where it operates at in a given calendar year.
(2) Indicate whether the flare stack has a continuous flow measurement device.
(3) Indicate whether the flare stack has a continuous gas composition analyzer on feed gas to the flare.
(4) Volume of gas sent to the flare, in standard cubic feet (“V
(5) Fraction of the feed gas sent to an un-lit flare (“Z
(6) Flare combustion efficiency, expressed as the fraction of gas combusted by a burning flare.
(7) Mole fraction of CH
(8) Mole fraction of CO
(9) Annual CO
(10) Annual CH
(11) Annual N
(12) Indicate whether a CEMS was used to measure emissions from the flare. If a CEMS was used to measure emissions from the flare, then you are not required to report N
(o) Centrifugal compressors. You must indicate whether your facility has centrifugal compressors. You must report the information specified in paragraphs (o)(1) and (2) of this section for all centrifugal compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(o)(2) or (4), you must report the information specified in paragraph (o)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(o)(3) or (5), you must report the information specified in paragraph (o)(4) of this section. Centrifugal compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting are not required to report information in paragraphs (o)(1) through (4) of this section and instead must report the information specified in paragraph (o)(5) of this section.
(1) Compressor activity data. Report the information specified in paragraphs (o)(1)(i) through (xiv) of this section for each centrifugal compressor located at your facility.
(i) Unique name or ID for the centrifugal compressor.
(ii) Hours in operating-mode.
(iii) Hours in not-operating-depressurized-mode.
(iv) Indicate whether the compressor was measured in operating-mode.
(v) Indicate whether the compressor was measured in not-operating-depressurized-mode.
(vi) Indicate which, if any, compressor sources are part of a manifolded group of compressor sources.
(vii) Indicate which, if any, compressor sources are routed to a flare.
(viii) Indicate which, if any, compressor sources have vapor recovery.
(ix) Indicate which, if any, compressor source emissions are captured for fuel use or are routed to a thermal oxidizer.
(x) Indicate whether the compressor has blind flanges installed and associated dates.
(xi) Indicate whether the compressor has wet or dry seals.
(xii) If the compressor has wet seals, the number of wet seals.
(xiii) Power output of the compressor driver (hp).
(xiv) Indicate whether the compressor had a scheduled depressurized shutdown during the reporting year.
(2) Compressor source. (i) For each compressor source at each compressor, report the information specified in paragraphs (o)(2)(i)(A) through (C) of this section.
(A) Centrifugal compressor name or ID. Use the same ID as in paragraph (o)(1)(i) of this section.
(B) Centrifugal compressor source (wet seal, isolation valve, or blowdown valve).
(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source.
(ii) For each leak or vent, report the information specified in paragraphs (o)(2)(ii)(A) through (E) of this section.
(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
(B) Indicate whether an as found measurement(s) as identified in § 98.233(o)(2) or (4) was conducted on the leak or vent.
(C) Indicate whether continuous measurements as identified in § 98.233(o)(3) or (5) were conducted on the leak or vent.
(D) Report emissions as specified in paragraphs (o)(2)(ii)(D)(1) and (2) of this section for the leak or vent. If the leak or vent is routed to a flare, combustion, or vapor recovery, you are not required to report emissions under this paragraph.
(1) Annual CO
(2) Annual CH
(E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device.
(3) As found measurement sample data. If the measurement methods specified in § 98.233(o)(2) or (4) are conducted, report the information specified in paragraph (o)(3)(i) of this section. If the calculation specified in § 98.233(o)(6)(ii) is performed, report the information specified in paragraph (o)(3)(ii) of this section.
(i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (o)(3)(i)(A) through (F) of this section.
(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.
(B) Measurement date.
(C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.
(D) Measured flow rate, in standard cubic feet per hour.
(E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken.
(F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(ii) For each compressor mode-source combination where a reporter emission factor as calculated in Equation W-23 was used to calculate emissions in Equation W-22, report the information specified in paragraphs (o)(3)(ii)(A) through (D) of this section.
(A) The compressor mode-source combination.
(B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF
(C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count
(D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter’s applicable facilities.
(4) Continuous measurement data. If the measurement methods specified in § 98.233(o)(3) or (5) are conducted, report the information specified in paragraphs (o)(4)(i) through (iv) of this section for each continuous measurement conducted on each leak or vent associated with each compressor source or manifolded group of compressor sources.
(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (o)(2)(i)(C) of this section.
(ii) Measured volume of flow during the reporting year, in million standard cubic feet.
(iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 98.233(o)(3)(ii) and (o)(5)(iii).
(iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(5) Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting. Centrifugal compressors with wet seal degassing vents in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting must report the information specified in paragraphs (o)(5)(i) through (iii) of this section.
(i) Number of centrifugal compressors that have wet seal oil degassing vents.
(ii) Annual CO
(iii) Annual CH
(p) Reciprocating compressors. You must indicate whether your facility has reciprocating compressors. You must report the information specified in paragraphs (p)(1) and (2) of this section for all reciprocating compressors at your facility. For each compressor source or manifolded group of compressor sources that you conduct as found leak measurements as specified in § 98.233(p)(2) or (4), you must report the information specified in paragraph (p)(3) of this section. For each compressor source or manifolded group of compressor sources that you conduct continuous monitoring as specified in § 98.233(p)(3) or (5), you must report the information specified in paragraph (p)(4) of this section. Reciprocating compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting are not required to report information in paragraphs (p)(1) through (4) of this section and instead must report the information specified in paragraph (p)(5) of this section.
(1) Compressor activity data. Report the information specified in paragraphs (p)(1)(i) through (xiv) of this section for each reciprocating compressor located at your facility.
(i) Unique name or ID for the reciprocating compressor.
(ii) Hours in operating-mode.
(iii) Hours in standby-pressurized-mode.
(iv) Hours in not-operating-depressurized-mode.
(v) Indicate whether the compressor was measured in operating-mode.
(vi) Indicate whether the compressor was measured in standby-pressurized-mode.
(vii) Indicate whether the compressor was measured in not-operating-depressurized-mode.
(viii) Indicate which, if any, compressor sources are part of a manifolded group of compressor sources.
(ix) Indicate which, if any, compressor sources are routed to a flare.
(x) Indicate which, if any, compressor sources have vapor recovery.
(xi) Indicate which, if any, compressor source emissions are captured for fuel use or are routed to a thermal oxidizer.
(xii) Indicate whether the compressor has blind flanges installed and associated dates.
(xiii) Power output of the compressor driver (hp).
(xiv) Indicate whether the compressor had a scheduled depressurized shutdown during the reporting year.
(2) Compressor source. (i) For each compressor source at each compressor, report the information specified in paragraphs (p)(2)(i)(A) through (C) of this section.
(A) Reciprocating compressor name or ID. Use the same ID as in paragraph (p)(1)(i) of this section.
(B) Reciprocating compressor source (isolation valve, blowdown valve, or rod packing).
(C) Unique name or ID for the leak or vent. If the leak or vent is connected to a manifolded group of compressor sources, use the same leak or vent ID for each compressor source in the manifolded group. If multiple compressor sources are released through a single vent for which continuous measurements are used, use the same leak or vent ID for each compressor source released via the measured vent. For a single compressor using as found measurements, you must provide a different leak or vent ID for each compressor source.
(ii) For each leak or vent, report the information specified in paragraphs (p)(2)(ii)(A) through (E) of this section.
(A) Indicate whether the leak or vent is for a single compressor source or manifolded group of compressor sources and whether the emissions from the leak or vent are released to the atmosphere, routed to a flare, combustion (fuel or thermal oxidizer), or vapor recovery.
(B) Indicate whether an as found measurement(s) as identified in § 98.233(p)(2) or (4) was conducted on the leak or vent.
(C) Indicate whether continuous measurements as identified in § 98.233(p)(3) or (5) were conducted on the leak or vent.
(D) Report emissions as specified in paragraphs (p)(2)(ii)(D)(1) and (2) of this section for the leak or vent. If the leak or vent is routed to flare, combustion, or vapor recovery, you are not required to report emissions under this paragraph.
(1) Annual CO
(2) Annual CH
(E) If the leak or vent is routed to flare, combustion, or vapor recovery, report the percentage of time that the respective device was operational when the compressor source emissions were routed to the device.
(3) As found measurement sample data. If the measurement methods specified in § 98.233(p)(2) or (4) are conducted, report the information specified in paragraph (p)(3)(i) of this section. If the calculation specified in § 98.233(p)(6)(ii) is performed, report the information specified in paragraph (p)(3)(ii) of this section.
(i) For each as found measurement performed on a leak or vent, report the information specified in paragraphs (p)(3)(i)(A) through (F) of this section.
(A) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.
(B) Measurement date.
(C) Measurement method. If emissions were not detected when using a screening method, report the screening method. If emissions were detected using a screening method, report only the method subsequently used to measure the volumetric emissions.
(D) Measured flow rate, in standard cubic feet per hour.
(E) For each compressor attached to the leak or vent, report the compressor mode during which the measurement was taken.
(F) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(ii) For each compressor mode-source combination where a reporter emission factor as calculated in Equation W-28 was used to calculate emissions in Equation W-27, report the information specified in paragraphs (p)(3)(ii)(A) through (D) of this section
(A) The compressor mode-source combination.
(B) The compressor mode-source combination reporter emission factor, in standard cubic feet per hour (EF
(C) The total number of compressors measured in the compressor mode-source combination in the current reporting year and the preceding two reporting years (Count
(D) Indicate whether the compressor mode-source combination reporter emission factor is facility-specific or based on all of the reporter’s applicable facilities.
(4) Continuous measurement data. If the measurement methods specified in § 98.233(p)(3) or (5) are conducted, report the information specified in paragraphs (p)(4)(i) through (iv) of this section for each continuous measurement conducted on each leak or vent associated with each compressor source or manifolded group of compressor sources.
(i) Name or ID of leak or vent. Use same leak or vent ID as in paragraph (p)(2)(i)(C) of this section.
(ii) Measured volume of flow during the reporting year, in million standard cubic feet.
(iii) Indicate whether the measured volume of flow during the reporting year includes compressor blowdown emissions as allowed for in § 98.233(p)(3)(ii) and (p)(5)(iii).
(iv) If the measurement is for a manifolded group of compressor sources, indicate whether the measurement location is prior to or after comingling with non-compressor emission sources.
(5) Onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting. Reciprocating compressors in onshore petroleum and natural gas production and onshore petroleum and natural gas gathering and boosting must report the information specified in paragraphs (p)(5)(i) through (iii) of this section.
(i) Number of reciprocating compressors.
(ii) Annual CO
(iii) Annual CH
(q) Equipment leak surveys. For any components subject to or complying with the requirements of § 98.233(q), you must report the information specified in paragraphs (q)(1) and (2) of this section. Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must also report the information specified in paragraph (q)(3) of this section.
(1) You must report the information specified in paragraphs (q)(1)(i) through (v) of this section.
(i) Except as specified in paragraph (q)(1)(ii) of this section, the number of complete equipment leak surveys performed during the calendar year.
(ii) Natural gas distribution facilities performing equipment leak surveys across a multiple year leak survey cycle must report the number of years in the leak survey cycle.
(iii) Except for onshore natural gas processing facilities and natural gas distribution facilities, indicate whether any equipment components at your facility are subject to the well site or compressor station fugitive emissions standards in § 60.5397a of this chapter. Report the indication per facility, not per component type.
(iv) For facilities in onshore petroleum and natural gas production, onshore petroleum and natural gas gathering and boosting, onshore natural gas transmission compression, underground natural gas storage, LNG storage, and LNG import and export equipment, indicate whether you elected to comply with § 98.233(q) according to § 98.233(q)(1)(iv) for any equipment components at your facility.
(v) Report each type of method described in § 98.234(a) that was used to conduct leak surveys.
(2) You must indicate whether your facility contains any of the component types subject to or complying with § 98.233(q) that are listed in § 98.232(c)(21), (d)(7), (e)(7), (e)(8), (f)(5), (f)(6), (f)(7), (f)(8), (g)(4), (g)(6), (g)(7), (h)(5), (h)(7), (h)(8), (i)(1), or (j)(10) for your facility’s industry segment. For each component type that is located at your facility, you must report the information specified in paragraphs (q)(2)(i) through (v) of this section. If a component type is located at your facility and no leaks were identified from that component, then you must report the information in paragraphs (q)(2)(i) through (v) of this section but report a zero (“0”) for the information required according to paragraphs (q)(2)(ii) through (v) of this section.
(i) Component type.
(ii) Total number of the surveyed component type that were identified as leaking in the calendar year (“x
(iii) Average time the surveyed components are assumed to be leaking and operational, in hours (average of “T
(iv) Annual CO
(v) Annual CH
(3) Natural gas distribution facilities with emission sources listed in § 98.232(i)(1) must also report the information specified in paragraphs (q)(3)(i) through (viii) and, if applicable, (q)(3)(ix) of this section.
(i) Number of above grade transmission-distribution transfer stations surveyed in the calendar year.
(ii) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in the calendar year (“Count
(iii) Average time that meter/regulator runs surveyed in the calendar year were operational, in hours (average of “T
(iv) Number of above grade transmission-distribution transfer stations surveyed in the current leak survey cycle.
(v) Number of meter/regulator runs at above grade transmission-distribution transfer stations surveyed in current leak survey cycle (sum of “Count
(vi) Average time that meter/regulator runs surveyed in the current leak survey cycle were operational, in hours (average of “T
(vii) Meter/regulator run CO
(viii) Meter/regulator run CH
(ix) If your natural gas distribution facility performs equipment leak surveys across a multiple year leak survey cycle, you must also report:
(A) The total number of meter/regulator runs at above grade transmission-distribution transfer stations at your facility (“Count
(B) Average estimated time that each meter/regulator run at above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T
(C) Annual CO
(D) Annual CH
(r) Equipment leaks by population count. If your facility is subject to the requirements of § 98.233(r), then you must report the information specified in paragraphs (r)(1) through (3) of this section, as applicable.
(1) You must indicate whether your facility contains any of the emission source types required to use Equation W-32A of § 98.233. You must report the information specified in paragraphs (r)(1)(i) through (v) of this section separately for each emission source type required to use Equation W-32A that is located at your facility. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the information specified in paragraphs (r)(1)(i) through (v) separately by component type, service type, and geographic location (i.e., Eastern U.S. or Western U.S.).
(i) Emission source type. Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the component type, service type and geographic location.
(ii) Total number of the emission source type at the facility (“Count
(iii) Average estimated time that the emission source type was operational in the calendar year, in hours (“T
(iv) Annual CO
(v) Annual CH
(2) Natural gas distribution facilities must also report the information specified in paragraphs (r)(2)(i) through (v) of this section.
(i) Number of above grade transmission-distribution transfer stations at the facility.
(ii) Number of above grade metering-regulating stations that are not transmission-distribution transfer stations at the facility.
(iii) Total number of meter/regulator runs at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations (“Count
(iv) Average estimated time that each meter/regulator run at above grade metering-regulating stations that are not above grade transmission-distribution transfer stations was operational in the calendar year, in hours per meter/regulator run (“T
(v) If your facility has above grade metering-regulating stations that are not above grade transmission-distribution transfer stations and your facility also has above grade transmission-distribution transfer stations, you must also report:
(A) Annual CO
(B) Annual CH
(3) Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must also report the information specified in paragraphs (r)(3)(i) and (ii) of this section.
(i) Calculation method used.
(ii) Onshore petroleum and natural gas production facilities and onshore petroleum and natural gas gathering and boosting facilities must report the information specified in paragraphs (r)(3)(ii)(A) and (B) of this section, for each major equipment type, production type (i.e., natural gas or crude oil), and geographic location combination in Tables W-1B and W-1C to this subpart for which equipment leak emissions are calculated using the methodology in § 98.233(r).
(A) An indication of whether the facility contains the major equipment type.
(B) If the facility does contain the equipment type, the count of the major equipment type.
(s) Offshore petroleum and natural gas production. You must report the information specified in paragraphs (s)(1) through (3) of this section for each emission source type listed in the most recent BOEMRE study.
(1) Annual CO
(2) Annual CH
(3) Annual N
(t) [Reserved]
(u) [Reserved]
(v) [Reserved]
(w) EOR injection pumps. You must indicate whether CO
(1) Sub-basin ID.
(2) EOR injection pump system identifier.
(3) Pump capacity, in barrels per day.
(4) Total volume of EOR injection pump system equipment chambers, in cubic feet (“V
(5) Number of blowdowns for the EOR injection pump system in the calendar year.
(6) Density of critical phase EOR injection gas, in kilograms per cubic foot (“R
(7) Mass fraction of CO
(8) Annual CO
(x) EOR hydrocarbon liquids. You must indicate whether hydrocarbon liquids were produced through EOR operations. If hydrocarbon liquids were produced through EOR operations, you must report the information specified in paragraphs (x)(1) through (4) of this section for each sub-basin category with EOR operations.
(1) Sub-basin ID.
(2) Total volume of hydrocarbon liquids produced through EOR operations in the calendar year, in barrels (“V
(3) Average CO
(4) Annual CO
(y) [Reserved]
(z) Combustion equipment at onshore petroleum and natural gas production facilities, onshore petroleum and natural gas gathering and boosting facilities, and natural gas distribution facilities. If your facility is required by § 98.232(c)(22), (i)(7), or (j)(12) to report emissions from combustion equipment, then you must indicate whether your facility has any combustion units subject to reporting according to paragraph (a)(1)(xvii), (a)(8)(i), or (a)(9)(xi) of this section. If your facility contains any combustion units subject to reporting according to paragraph (a)(1)(xviii), (a)(8)(i), or (a)(9)(xii) of this section, then you must report the information specified in paragraphs (z)(1) and (2) of this section, as applicable.
(1) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour; or, internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 mmBtu/hr (or the equivalent of 130 horsepower). If the facility contains external fuel combustion units with a rated heat capacity less than or equal to 5 million Btu per hour or internal fuel combustion units that are not compressor-drivers, with a rated heat capacity less than or equal to 1 million Btu per hour (or the equivalent of 130 horsepower), then you must report the information specified in paragraphs (z)(1)(i) and (ii) of this section for each unit type.
(i) The type of combustion unit.
(ii) The total number of combustion units.
(2) Indicate whether the combustion units include: External fuel combustion units with a rated heat capacity greater than 5 million Btu per hour; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or, internal fuel combustion units of any heat capacity that are compressor-drivers. If your facility contains: External fuel combustion units with a rated heat capacity greater than 5 mmBtu/hr; internal fuel combustion units that are not compressor-drivers, with a rated heat capacity greater than 1 million Btu per hour (or the equivalent of 130 horsepower); or internal fuel combustion units of any heat capacity that are compressor-drivers, then you must report the information specified in paragraphs (z)(2)(i) through (vi) of this section for each combustion unit type and fuel type combination.
(i) The type of combustion unit.
(ii) The type of fuel combusted.
(iii) The quantity of fuel combusted in the calendar year, in thousand standard cubic feet, gallons, or tons.
(iv) Annual CO
(v) Annual CH
(vi) Annual N
(aa) Each facility must report the information specified in paragraphs (aa)(1) through (11) of this section, for each applicable industry segment, by using best available data. If a quantity required to be reported is zero, you must report zero as the value.
(1) For onshore petroleum and natural gas production, report the data specified in paragraphs (aa)(1)(i) and (ii) of this section.
(i) Report the information specified in paragraphs (aa)(1)(i)(A) through (C) of this section for the basin as a whole.
(A) The quantity of gas produced in the calendar year from wells, in thousand standard cubic feet. This includes gas that is routed to a pipeline, vented or flared, or used in field operations. This does not include gas injected back into reservoirs or shrinkage resulting from lease condensate production.
(B) The quantity of gas produced in the calendar year for sales, in thousand standard cubic feet.
(C) The quantity of crude oil and condensate produced in the calendar year for sales, in barrels.
(ii) Report the information specified in paragraphs (aa)(1)(ii)(A) through (M) of this section for each unique sub-basin category.
(A) State.
(B) County.
(C) Formation type.
(D) The number of producing wells at the end of the calendar year and a list of the well ID numbers (exclude only those wells permanently taken out of production, i.e., plugged and abandoned).
(E) The number of producing wells acquired during the calendar year and a list of the well ID numbers.
(F) The number of producing wells divested during the calendar year and a list of the well ID numbers.
(G) The number of wells completed during the calendar year and a list of the well ID numbers.
(H) The number of wells permanently taken out of production (i.e., plugged and abandoned) during the calendar year and a list of the well ID numbers.
(I) Average mole fraction of CH
(J) Average mole fraction of CO
(K) If an oil sub-basin, report the average GOR of all wells, in thousand standard cubic feet per barrel.
(L) If an oil sub-basin, report the average API gravity of all wells.
(M) If an oil sub-basin, report average low pressure separator pressure, in pounds per square inch gauge.
(2) For offshore production, report the quantities specified in paragraphs (aa)(2)(i) and (ii) of this section.
(i) The total quantity of gas handled at the offshore platform in the calendar year, in thousand standard cubic feet, including production volumes and volumes transferred via pipeline from another location.
(ii) The total quantity of oil and condensate handled at the offshore platform in the calendar year, in barrels, including production volumes and volumes transferred via pipeline from another location.
(3) For natural gas processing, report the information specified in paragraphs (aa)(3)(i) through (vii) of this section.
(i) The quantity of natural gas received at the gas processing plant in the calendar year, in thousand standard cubic feet.
(ii) The quantity of processed (residue) gas leaving the gas processing plant in the calendar year, in thousand standard cubic feet.
(iii) The cumulative quantity of all NGLs (bulk and fractionated) received at the gas processing plant in the calendar year, in barrels.
(iv) The cumulative quantity of all NGLs (bulk and fractionated) leaving the gas processing plant in the calendar year, in barrels.
(v) Average mole fraction of CH
(vi) Average mole fraction of CO
(vii) Indicate whether the facility fractionates NGLs.
(4) For natural gas transmission compression, report the quantity specified in paragraphs (aa)(4)(i) through (v) of this section.
(i) The quantity of gas transported through the compressor station in the calendar year, in thousand standard cubic feet.
(ii) Number of compressors.
(iii) Total compressor power rating of all compressors combined, in horsepower.
(iv) Average upstream pipeline pressure, in pounds per square inch gauge.
(v) Average downstream pipeline pressure, in pounds per square inch gauge.
(5) For underground natural gas storage, report the quantities specified in paragraphs (aa)(5)(i) through (iii) of this section.
(i) The quantity of gas injected into storage in the calendar year, in thousand standard cubic feet.
(ii) The quantity of gas withdrawn from storage in the calendar year, in thousand standard cubic feet.
(iii) Total storage capacity, in thousand standard cubic feet.
(6) For LNG import equipment, report the quantity of LNG imported in the calendar year, in thousand standard cubic feet.
(7) For LNG export equipment, report the quantity of LNG exported in the calendar year, in thousand standard cubic feet.
(8) For LNG storage, report the quantities specified in paragraphs (aa)(8)(i) through (iii) of this section.
(i) The quantity of LNG added into storage in the calendar year, in thousand standard cubic feet.
(ii) The quantity of LNG withdrawn from storage in the calendar year, in thousand standard cubic feet.
(iii) Total storage capacity, in thousand standard cubic feet.
(9) For natural gas distribution, report the quantities specified in paragraphs (aa)(9)(i) through (vii) of this section.
(i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report.
(ii) The quantity of natural gas withdrawn from in-system storage in the calendar year, in thousand standard cubic feet.
(iii) The quantity of natural gas added to in-system storage in the calendar year, in thousand standard cubic feet.
(iv) The quantity of natural gas delivered to end users, in thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for.
(v) The quantity of natural gas transferred to third parties such as other LDCs or pipelines, in thousand standard cubic feet. This value does not include stolen gas, or gas that is otherwise unaccounted for.
(vi) The quantity of natural gas consumed by the LDC for operational purposes, in thousand standard cubic feet.
(vii) The estimated quantity of gas stolen in the calendar year, in thousand standard cubic feet.
(10) For onshore petroleum and natural gas gathering and boosting facilities, report the quantities specified in paragraphs (aa)(10)(i) through (iv) of this section.
(i) The quantity of gas received by the gathering and boosting facility in the calendar year, in thousand standard cubic feet.
(ii) The quantity of gas transported to a natural gas processing facility, a natural gas transmission pipeline, a natural gas distribution pipeline, or another gathering and boosting facility in the calendar year, in thousand standard cubic feet.
(iii) The quantity of all hydrocarbon liquids received by the gathering and boosting facility in the calendar year, in barrels.
(iv) The quantity of all hydrocarbon liquids transported to a natural gas processing facility, a natural gas transmission pipeline, a natural gas distribution pipeline, or another gathering and boosting facility in the calendar year, in barrels.
(11) For onshore natural gas transmission pipeline facilities, report the quantities specified in paragraphs (aa)(11)(i) through (vi) of this section.
(i) The quantity of natural gas received at all custody transfer stations in the calendar year, in thousand standard cubic feet. This value may include meter corrections, but only for the calendar year covered by the annual report.
(ii) The quantity of natural gas withdrawn from in-system storage in the calendar year, in thousand standard cubic feet.
(iii) The quantity of natural gas added to in-system storage in the calendar year, in thousand standard cubic feet.
(iv) The quantity of natural gas transferred to third parties such as LDCs or other transmission pipelines, in thousand standard cubic feet.
(v) The quantity of natural gas consumed by the transmission pipeline facility for operational purposes, in thousand standard cubic feet.
(vi) The miles of transmission pipeline for each state in the facility.
(bb) For any missing data procedures used, report the information in § 98.3(c)(8) except as provided in paragraphs (bb)(1) and (2) of this section.
(1) For quarterly measurements, report the total number of quarters that a missing data procedure was used for each data element rather than the total number of hours.
(2) For annual or biannual (once every two years) measurements, you do not need to report the number of hours that a missing data procedure was used for each data element.
(cc) If you elect to delay reporting the information in paragraph (g)(5)(i), (g)(5)(ii), (g)(5)(iii)(A), (g)(5)(iii)(B), (h)(1)(iv), (h)(2)(iv), (j)(1)(iii), (j)(2)(i)(A), (l)(1)(iv), (l)(2)(iv), (l)(3)(iii), (l)(4)(iii), (m)(5), or (m)(6) of this section, you must report the information required in that paragraph no later than the date 2 years following the date specified in § 98.3(b) introductory text.
§ 98.237 Records that must be retained.
Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011. In addition to the information required by § 98.3(g), you must retain the following records:
(a) Dates on which measurements were conducted.
(b) Results of all emissions detected and measurements.
(c) Calibration reports for detection and measurement instruments used.
(d) Inputs and outputs of calculations or emissions computer model runs used for engineering estimation of emissions.
(e) The records required under § 98.3(g)(2)(i) shall include an explanation of how company records, engineering estimation, or best available information are used to calculate each applicable parameter under this subpart.
(f) For each time a missing data procedure was used, keep a record listing the emission source type, a description of the circumstance that resulted in the need to use missing data procedures, the missing data provisions in § 98.235 that apply, the calculation or analysis used to develop the substitute value, and the substitute value.
§ 98.238 Definitions.
Except as provided in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Acid gas means hydrogen sulfide (H
Acid gas removal unit (AGR) means a process unit that separates hydrogen sulfide and/or carbon dioxide from sour natural gas using liquid or solid absorbents or membrane separators.
Acid gas removal vent emissions mean the acid gas separated from the acid gas absorbing medium (e.g., an amine solution) and released with methane and other light hydrocarbons to the atmosphere or a flare.
Associated gas venting or flaring means the venting or flaring of natural gas which originates at wellheads that also produce hydrocarbon liquids and occurs either in a discrete gaseous phase at the wellhead or is released from the liquid hydrocarbon phase by separation. This does not include venting or flaring resulting from activities that are reported elsewhere, including tank venting, well completions, and well workovers.
Associated with a single well-pad means associated with the hydrocarbon stream as produced from one or more wells located on that single well-pad. The association ends where the stream from a single well-pad is combined with streams from one or more additional single well-pads, where the point of combination is located off that single well-pad. Onshore production storage tanks on or associated with a single well-pad are considered a part of the onshore production facility.
Basin means geologic provinces as defined by the American Association of Petroleum Geologists (AAPG) Geologic Note: AAPG-CSD Geologic Provinces Code Map: AAPG Bulletin, Prepared by Richard F. Meyer, Laure G. Wallace, and Fred J. Wagner, Jr., Volume 75, Number 10 (October 1991) (incorporated by reference, see § 98.7) and the Alaska Geological Province Boundary Map, Compiled by the American Association of Petroleum Geologists Committee on Statistics of Drilling in Cooperation with the USGS, 1978 (incorporated by reference, see § 98.7).
Compressor means any machine for raising the pressure of a natural gas or CO
Compressor mode means the operational and pressurized status of a compressor. For a centrifugal compressor, “mode” refers to either operating-mode or not-operating-depressurized-mode. For a reciprocating compressor, “mode” refers to either: Operating-mode, standby-pressurized-mode, or not-operating-depressurized-mode.
Compressor source means the source of certain venting or leaking emissions from a centrifugal or reciprocating compressor. For centrifugal compressors, “source” refers to blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind flanges, and wet seal oil degassing vents. For reciprocating compressors, “source” refers to blowdown valve leakage through the blowdown vent, unit isolation valve leakage through an open blowdown vent without blind flanges, and rod packing emissions.
Condensate means hydrocarbon and other liquid, including both water and hydrocarbon liquids, separated from natural gas that condenses due to changes in the temperature, pressure, or both, and remains liquid at storage conditions.
Delineation well means a well drilled in order to determine the boundary of a field or producing reservoir.
Distribution pipeline means a pipeline that is designated as such by the Pipeline and Hazardous Material Safety Administration (PHMSA) 49 CFR 192.3.
Engineering estimation, for purposes of subpart W, means an estimate of emissions based on engineering principles applied to measured and/or approximated physical parameters such as dimensions of containment, actual pressures, actual temperatures, and compositions.
Enhanced oil recovery (EOR) means the use of certain methods such as water flooding or gas injection into existing wells to increase the recovery of crude oil from a reservoir. In the context of this subpart, EOR applies to injection of critical phase or immiscible carbon dioxide into a crude oil reservoir to enhance the recovery of oil.
External combustion means fired combustion in which the flame and products of combustion are separated from contact with the process fluid to which the energy is delivered. Process fluids may be air, hot water, or hydrocarbons. External combustion equipment may include fired heaters, industrial boilers, and commercial and domestic combustion units.
Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements means the collection of all distribution pipelines and metering-regulating stations that are operated by a Local Distribution Company (LDC) within a single state that is regulated as a separate operating company by a public utility commission or that are operated as an independent municipally-owned distribution system.
Facility with respect to natural gas distribution for purposes of reporting under this subpart and for the corresponding subpart A requirements means the collection of all distribution pipelines and metering-regulating stations that are operated by a Local Distribution Company (LDC) within a single state that is regulated as a separate operating company by a public utility commission or that are operated as an independent municipally-owned distribution system.
Facility with respect to onshore petroleum and natural gas gathering and boosting for purposes of reporting under this subpart and for the corresponding subpart A requirements means all gathering pipelines and other equipment located along those pipelines that are under common ownership or common control by a gathering and boosting system owner or operator and that are located in a single hydrocarbon basin as defined in this section. Where a person owns or operates more than one gathering and boosting system in a basin (for example, separate gathering lines that are not connected), then all gathering and boosting equipment that the person owns or operates in the basin would be considered one facility. Any gathering and boosting equipment that is associated with a single gathering and boosting system, including leased, rented, or contracted activities, is considered to be under common control of the owner or operator of the gathering and boosting system that contains the pipeline. The facility does not include equipment and pipelines that are part of any other industry segment defined in this subpart.
Facility with respect to onshore petroleum and natural gas production for purposes of reporting under this subpart and for the corresponding subpart A requirements means all petroleum or natural gas equipment on a single well-pad or associated with a single well-pad and CO
Facility with respect to the onshore natural gas transmission pipeline segment means the total U.S. mileage of natural gas transmission pipelines, as defined in this section, owned and operated by an onshore natural gas transmission pipeline owner or operator as defined in this section. The facility does not include pipelines that are part of any other industry segment defined in this subpart.
Farm Taps are pressure regulation stations that deliver gas directly from transmission pipelines to generally rural customers. In some cases a nearby LDC may handle the billing of the gas to the customer(s).
Field means oil and gas fields identified in the United States as defined by the Energy Information Administration Oil and Gas Field Code Master List 2008, DOE/EIA 0370(08) (incorporated by reference, see § 98.7).
Flare, for the purposes of subpart W, means a combustion device, whether at ground level or elevated, that uses an open or closed flame to combust waste gases without energy recovery.
Flare combustion efficiency means the fraction of hydrocarbon gas, on a volume or mole basis, that is combusted at the flare burner tip.
Flare stack emissions means CO
Forced extraction of natural gas liquids means removal of ethane or higher carbon number hydrocarbons existing in the vapor phase in natural gas, by removing ethane or heavier hydrocarbons derived from natural gas into natural gas liquids by means of a forced extraction process. Forced extraction processes include but are not limited to refrigeration, absorption (lean oil), cryogenic expander, and combinations of these processes. Forced extraction does not include in and of itself; natural gas dehydration, or the collection or gravity separation of water or hydrocarbon liquids from natural gas at ambient temperature or heated above ambient temperatures, or the condensation of water or hydrocarbon liquids through passive reduction in pressure or temperature, or portable dewpoint suppression skids.
Gathering and boosting system means a single network of pipelines, compressors and process equipment, including equipment to perform natural gas compression, dehydration, and acid gas removal, that has one or more connection points to gas and oil production and a downstream endpoint, typically a gas processing plant, transmission pipeline, LDC pipeline, or other gathering and boosting system.
Gathering and boosting system owner or operator means any person that holds a contract in which they agree to transport petroleum or natural gas from one or more onshore petroleum and natural gas production wells to a natural gas processing facility, another gathering and boosting system, a natural gas transmission pipeline, or a distribution pipeline, or any person responsible for custody of the petroleum or natural gas transported.
Horizontal well means a well bore that has a planned deviation from primarily vertical to a primarily horizontal inclination or declination tracking in parallel with and through the target formation.
Internal combustion means the combustion of a fuel that occurs with an oxidizer (usually air) in a combustion chamber. In an internal combustion engine the expansion of the high-temperature and -pressure gases produced by combustion applies direct force to a component of the engine, such as pistons, turbine blades, or a nozzle. This force moves the component over a distance, generating useful mechanical energy. Internal combustion equipment may include gasoline and diesel industrial engines, natural gas-fired reciprocating engines, and gas turbines.
Liquefied natural gas (LNG) means natural gas (primarily methane) that has been liquefied by reducing its temperature to −260 degrees Fahrenheit at atmospheric pressure.
LNG boil-off gas means natural gas in the gaseous phase that vents from LNG storage tanks due to ambient heat leakage through the tank insulation and heat energy dissipated in the LNG by internal pumps.
Manifolded compressor source means a compressor source (as defined in this section) that is manifolded to a common vent that routes gas from multiple compressors.
Manifolded group of compressor sources means a collection of any combination of manifolded compressor sources (as defined in this section) that are manifolded to a common vent.
Meter/regulator run means a series of components used in regulating pressure or metering natural gas flow, or both, in the natural gas distribution industry segment. At least one meter, at least one regulator, or any combination of both on a single run of piping is considered one meter/regulator run.
Metering-regulating station means a station that meters the flowrate, regulates the pressure, or both, of natural gas in a natural gas distribution facility. This does not include customer meters, customer regulators, or farm taps.
Natural gas means a naturally occurring mixture or process derivative of hydrocarbon and non-hydrocarbon gases found in geologic formations beneath the earth’s surface, of which its constituents include, but are not limited to, methane, heavier hydrocarbons and carbon dioxide. Natural gas may be field quality, pipeline quality, or process gas.
Offshore means seaward of the terrestrial borders of the United States, including waters subject to the ebb and flow of the tide, as well as adjacent bays, lakes or other normally standing waters, and extending to the outer boundaries of the jurisdiction and control of the United States under the Outer Continental Shelf Lands Act.
Onshore natural gas transmission pipeline owner or operator means, for interstate pipelines, the person identified as the transmission pipeline owner or operator on the Certificate of Public Convenience and Necessity issued under 15 U.S.C. 717f, or, for intrastate pipelines, the person identified as the owner or operator on the transmission pipeline’s Statement of Operating Conditions under section 311 of the Natural Gas Policy Act, or for pipelines that fall under the “Hinshaw Exemption” as referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 (w)(1994), the person identified as the owner or operator on blanket certificates issued under 18 CFR 284.224. If an intrastate pipeline is not subject to section 311 of the Natural Gas Policy Act (NGPA), the onshore natural gas transmission pipeline owner or operator is the person identified as the owner or operator on reports to the state regulatory body regulating rates and charges for the sale of natural gas to consumers.
Onshore petroleum and natural gas production owner or operator means the person or entity who holds the permit to operate petroleum and natural gas wells on the drilling permit or an operating permit where no drilling permit is issued, which operates an onshore petroleum and/or natural gas production facility (as described in § 98.230(a)(2). Where petroleum and natural gas wells operate without a drilling or operating permit, the person or entity that pays the State or Federal business income taxes is considered the owner or operator.
Operating pressure means the containment pressure that characterizes the normal state of gas or liquid inside a particular process, pipeline, vessel or tank.
Pressure groups as applicable to each sub-basin are defined as follows: Less than or equal to 25 psig; greater than 25 psig and less than or equal to 60 psig; greater than 60 psig and less than or equal to 110 psig; greater than 110 psig and less than or equal to 200 psig; and greater than 200 psig. The pressure in the context of pressure groups is either the well shut-in pressure; well casing pressure; or you may use the casing-to-tubing pressure of one well from the same sub-basin multiplied by the tubing pressure for each well in the sub-basin.
Pump means a device used to raise pressure, drive, or increase flow of liquid streams in closed or open conduits.
Pump seals means any seal on a pump drive shaft used to keep methane and/or carbon dioxide containing light liquids from escaping the inside of a pump case to the atmosphere.
Pump seal emissions means hydrocarbon gas released from the seal face between the pump internal chamber and the atmosphere.
Reduced emissions completion means a well completion following hydraulic fracturing where gas flowback emissions from the gas outlet of the separator that are otherwise vented are captured, cleaned, and routed to the flow line or collection system, re-injected into the well or another well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with de minimis direct venting to the atmosphere. Short periods of flaring during a reduced emissions completion may occur.
Reduced emissions workover means a well workover with hydraulic fracturing (i.e., refracturing) where gas flowback emissions from the gas outlet of the separator that are otherwise vented are captured, cleaned, and routed to the flow line or collection system, re-injected into the well or another well, used as an on-site fuel source, or used for other useful purpose that a purchased fuel or raw material would serve, with de minimis direct venting to the atmosphere. Short periods of flaring during a reduced emissions workover may occur.
Reservoir means a porous and permeable underground natural formation containing significant quantities of hydrocarbon liquids and/or gases.
Residue Gas and Residue Gas Compression mean, respectively, production lease natural gas from which gas liquid products and, in some cases, non-hydrocarbon components have been extracted such that it meets the specifications set by a pipeline transmission company, and/or a distribution company; and the compressors operated by the processing facility, whether inside the processing facility boundary fence or outside the fence-line, that deliver the residue gas from the processing facility to a transmission pipeline.
Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase.
Sub-basin category, for onshore natural gas production, means a subdivision of a basin into the unique combination of wells with the surface coordinates within the boundaries of an individual county and subsurface completion in one or more of each of the following five formation types: Oil, high permeability gas, shale gas, coal seam, or other tight gas reservoir rock. The distinction between high permeability gas and tight gas reservoirs shall be designated as follows: High permeability gas reservoirs with >0.1 millidarcy permeability, and tight gas reservoirs with ≤0.1 millidarcy permeability. Permeability for a reservoir type shall be determined by engineering estimate. Wells that produce only from high permeability gas, shale gas, coal seam, or other tight gas reservoir rock are considered gas wells; gas wells producing from more than one of these formation types shall be classified into only one type based on the formation with the most contribution to production as determined by engineering knowledge. All wells that produce hydrocarbon liquids (with or without gas) and do not meet the definition of a gas well in this sub-basin category definition are considered to be in the oil formation. All emission sources that handle condensate from gas wells in high permeability gas, shale gas, or tight gas reservoir rock formations are considered to be in the formation that the gas well belongs to and not in the oil formation.
Transmission-distribution (T-D) transfer station means a metering-regulating station where a local distribution company takes part or all of the natural gas from a transmission pipeline and puts it into a distribution pipeline.
Transmission pipeline means a Federal Energy Regulatory Commission rate-regulated Interstate pipeline, a state rate-regulated Intrastate pipeline, or a pipeline that falls under the “Hinshaw Exemption” as referenced in section 1(c) of the Natural Gas Act, 15 U.S.C. 717-717 (w)(1994).
Tubing diameter groups are defined as follows: Outer diameter less than or equal to 1 inch; outer diameter greater than 1 inch and less than 2.375 inch; and outer diameter greater than or equal to 2.375 inch.
Tubing systems means piping equal to or less than one half inch diameter as per nominal pipe size.
Turbine meter means a flow meter in which a gas or liquid flow rate through the calibrated tube spins a turbine from which the spin rate is detected and calibrated to measure the fluid flow rate.
Vented emissions means intentional or designed releases of CH
Vertical well means a well bore that is primarily vertical but has some unintentional deviation or one or more intentional deviations to enter one or more subsurface targets that are off-set horizontally from the surface location, intercepting the targets either vertically or at an angle.
Well identification (ID) number means the unique and permanent identification number assigned to a petroleum or natural gas well. If the well has been assigned a US Well Number, the well ID number required in this subpart is the US Well Number. If a US Well Number has not been assigned to the well, the well ID number is the identifier established by the well’s permitting authority.
Well testing venting and flaring means venting and/or flaring of natural gas at the time the production rate of a well is determined for regulatory, commercial, or technical purposes. If well testing is conducted immediately after well completion or workover, then it is considered part of well completion or workover.
Wildcat well means a well outside known fields or the first well drilled in an oil or gas field where no other oil and gas production exists.
Table W-1A to Subpart W of Part 98 – Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production Facilities and Onshore Petroleum and Natural Gas Gathering and Boosting Facilities
Table W-1A to Subpart W of Part 98 – Default Whole Gas Emission Factors for Onshore Petroleum and Natural Gas Production Facilities and Onshore Petroleum and Natural Gas Gathering and Boosting Facilities
Onshore petroleum and natural gas production and Onshore petroleum and natural gas gathering and boosting | Emission factor (scf/hour/component) |
---|---|
Population Emission Factors – All Components, Gas Service 1 | |
Valve | 0.027 |
Connector | 0.003 |
Open-ended Line | 0.061 |
Pressure Relief Valve | 0.040 |
Low Continuous Bleed Pneumatic Device Vents 2 | 1.39 |
High Continuous Bleed Pneumatic Device Vents 2 | 37.3 |
Intermittent Bleed Pneumatic Device Vents 2 | 13.5 |
Pneumatic Pumps 3 | 13.3 |
Population Emission Factors – All Components, Light Crude Service 4 | |
Valve | 0.05 |
Flange | 0.003 |
Connector | 0.007 |
Open-ended Line | 0.05 |
Pump | 0.01 |
Other 5 | 0.30 |
Population Emission Factors – All Components, Heavy Crude Service 6 | |
Valve | 0.0005 |
Flange | 0.0009 |
Connector (other) | 0.0003 |
Open-ended Line | 0.006 |
Other 5 | 0.003 |
Population Emission Factors – Gathering Pipelines, by Material Type 7 | |
Protected Steel | 0.47 |
Unprotected Steel | 16.59 |
Plastic/Composite | 2.50 |
Cast Iron | 27.60 |
Population Emission Factors – All Components, Gas Service 1 | |
Valve | 0.121 |
Connector | 0.017 |
Open-ended Line | 0.031 |
Pressure Relief Valve | 0.193 |
Low Continuous Bleed Pneumatic Device Vents 2 | 1.39 |
High Continuous Bleed Pneumatic Device Vents 2 | 37.3 |
Intermittent Bleed Pneumatic Device Vents 2 | 13.5 |
Pneumatic Pumps 3 | 13.3 |
Population Emission Factors – All Components, Light Crude Service 4 | |
Valve | 0.05 |
Flange | 0.003 |
Connector (other) | 0.007 |
Open-ended Line | 0.05 |
Pump | 0.01 |
Other 5 | 0.30 |
Population Emission Factors – All Components, Heavy Crude Service 6 | |
Valve | 0.0005 |
Flange | 0.0009 |
Connector (other) | 0.0003 |
Open-ended Line | 0.006 |
Other 5 | 0.003 |
Population Emission Factors – Gathering Pipelines by Material Type 7 | |
Protected Steel | 0.47 |
Unprotected Steel | 16.59 |
Plastic/Composite | 2.50 |
Cast Iron | 27.60 |
1 For multi-phase flow that includes gas, use the gas service emissions factors.
2 Emission Factor is in units of “scf/hour/device.”
3 Emission Factor is in units of “scf/hour/pump.”
4 Hydrocarbon liquids greater than or equal to 20°API are considered “light crude.”
5 “Others” category includes instruments, loading arms, pressure relief valves, stuffing boxes, compressor seals, dump lever arms, and vents.
6 Hydrocarbon liquids less than 20°API are considered “heavy crude.”
7 Emission factors are in units of “scf/hour/mile of pipeline.”
Table W-1B to Subpart W of Part 98 – Default Average Component Counts for Major Onshore Natural Gas Production Equipment and Onshore Petroleum and Natural Gas Gathering and Boosting Equipment
Major equipment | Valves | Connectors | Open-ended lines | Pressure relief valves |
---|---|---|---|---|
Wellheads | 8 | 38 | 0.5 | 0 |
Separators | 1 | 6 | 0 | 0 |
Meters/piping | 12 | 45 | 0 | 0 |
Compressors | 12 | 57 | 0 | 0 |
In-line heaters | 14 | 65 | 2 | 1 |
Dehydrators | 24 | 90 | 2 | 2 |
Wellheads | 11 | 36 | 1 | 0 |
Separators | 34 | 106 | 6 | 2 |
Meters/piping | 14 | 51 | 1 | 1 |
Compressors | 73 | 179 | 3 | 4 |
In-line heaters | 14 | 65 | 2 | 1 |
Dehydrators | 24 | 90 | 2 | 2 |
Table W-1C to Subpart W of Part 98 – Default Average Component Counts For Major Crude Oil Production Equipment
Major equipment | Valves | Flanges | Connectors | Open-ended lines | Other components |
---|---|---|---|---|---|
Wellhead | 5 | 10 | 4 | 0 | 1 |
Separator | 6 | 12 | 10 | 0 | 0 |
Heater-treater | 8 | 12 | 20 | 0 | 0 |
Header | 5 | 10 | 4 | 0 | 0 |
Wellhead | 5 | 10 | 4 | 0 | 1 |
Separator | 6 | 12 | 10 | 0 | 0 |
Heater-treater | 8 | 12 | 20 | 0 | 0 |
Header | 5 | 10 | 4 | 0 | 0 |
Table W-1D to Subpart W of Part 98 – Designation Of Eastern And Western U.S.
Eastern U.S. | Western U.S. |
---|---|
Connecticut | Alabama |
Delaware | Alaska |
Florida | Arizona |
Georgia | Arkansas |
Illinois | California |
Indiana | Colorado |
Kentucky | Hawaii |
Maine | Idaho |
Maryland | Iowa |
Massachusetts | Kansas |
Michigan | Louisiana |
New Hampshire | Minnesota |
New Jersey | Mississippi |
New York | Missouri |
North Carolina | Montana |
Ohio | Nebraska |
Pennsylvania | Nevada |
Rhode Island | New Mexico |
South Carolina | North Dakota |
Tennessee | Oklahoma |
Vermont | Oregon |
Virginia | South Dakota |
West Virginia | Texas |
Wisconsin | Utah |
Washington | |
Wyoming |
Table W-1E to Subpart W of Part 98 – Default Whole Gas Leaker Emission Factors for Onshore Petroleum and Natural Gas Production and Onshore Petroleum and Natural Gas Gathering and Boosting
Equipment components | Emission factor (scf/hour/component) | |
---|---|---|
If you survey using any of the methods in § 98.234(a)(1) through (6) | If you survey using Method 21 as specified in § 98.234(a)(7) | |
Leaker Emission Factors – All Components, Gas Service 1 | ||
Valve | 4.9 | 3.5 |
Flange | 4.1 | 2.2 |
Connector (other) | 1.3 | 0.8 |
Open-Ended Line 2 | 2.8 | 1.9 |
Pressure Relief Valve | 4.5 | 2.8 |
Pump Seal | 3.7 | 1.4 |
Other 3 | 4.5 | 2.8 |
Leaker Emission Factors – All Components, Light Crude Service 1 | ||
Valve | 3.2 | 2.2 |
Flange | 2.7 | 1.4 |
Connector (other) | 1.0 | 0.6 |
Open-Ended Line | 1.6 | 1.1 |
Pump | 3.7 | 2.6 |
Agitator Seal | 3.7 | 2.6 |
Other 3 | 3.1 | 2.0 |
Leaker Emission Factors – All Components, Heavy Crude Service 1 | ||
Valve | 3.2 | 2.2 |
Flange | 2.7 | 1.4 |
Connector (other) | 1.0 | 0.6 |
Open-Ended Line | 1.6 | 1.1 |
Pump | 3.7 | 2.6 |
Agitator Seal | 3.7 | 2.6 |
Other 3 | 3.1 | 2.0 |
1 For multi-phase flow that includes gas, use the gas service emission factors.
2 The open-ended lines component type includes blowdown valve and isolation valve leaks emitted through the blowdown vent stack for centrifugal and reciprocating compressors.
3 “Others” category includes any equipment leak emission point not specifically listed in this table, as specified in § 98.232(c)(21) and (j)(10).
4 Hydrocarbon liquids greater than or equal to 20°API are considered “light crude.”
5 Hydrocarbon liquids less than 20°API are considered “heavy crude.”
Table W-2 to Subpart W of Part 98 – Default Total Hydrocarbon Emission Factors for Onshore Natural Gas Processing
Onshore natural gas processing plants | Emission factor (scf/hour/ component) |
---|---|
Valve 1 | 14.84 |
Connector | 5.59 |
Open-Ended Line | 17.27 |
Pressure Relief Valve | 39.66 |
Meter | 19.33 |
Valve 1 | 6.42 |
Connector | 5.71 |
Open-Ended Line | 11.27 |
Pressure Relief Valve | 2.01 |
Meter | 2.93 |
1 Valves include control valves, block valves and regulator valves.
Table W-3A to Subpart W of Part 98 – Default Total Hydrocarbon Leaker Emission Factors for Onshore Natural Gas Transmission Compression
Onshore natural gas transmission compression | Emission factor (scf/hour/component) | |
---|---|---|
If you survey using any of the methods in § 98.234(a)(1) through (6) | If you survey using Method 21 as specified in § 98.234(a)(7) | |
Valve 1 | 14.84 | 9.51 |
Connector | 5.59 | 3.58 |
Open-Ended Line | 17.27 | 11.07 |
Pressure Relief Valve | 39.66 | 25.42 |
Meter or Instrument | 19.33 | 12.39 |
Other 2 | 4.1 | 2.63 |
Valve 1 | 6.42 | 4.12 |
Connector | 5.71 | 3.66 |
Open-Ended Line | 11.27 | 7.22 |
Pressure Relief Valve | 2.01 | 1.29 |
Meter or Instrument | 2.93 | 1.88 |
Other 2 | 4.1 | 2.63 |
1 Valves include control valves, block valves and regulator valves.
2 Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table, as specified in § 98.232(e)(8).
Table W-3B to Subpart W of Part 98 – Default Total Hydrocarbon Population Emission Factors for Onshore Natural Gas Transmission Compression
Table W-3B to Subpart W of Part 98 – Default Total Hydrocarbon Population Emission Factors for Onshore Natural Gas Transmission Compression
Population emission factors – gas service onshore natural gas transmission compression | Emission factor (scf/hour/component) |
---|---|
Low Continuous Bleed Pneumatic Device Vents 1 | 1.37 |
High Continuous Bleed Pneumatic Device Vents 1 | 18.20 |
Intermittent Bleed Pneumatic Device Vents 1 | 2.35 |
1 Emission Factor is in units of “scf/hour/device.”
Table W-4A to Subpart W of Part 98 – Default Total Hydrocarbon Leaker Emission Factors for Underground Natural Gas Storage
Underground natural gas storage | Emission factor (scf/hour/component) | |
---|---|---|
If you survey using any of the methods in § 98.234(a)(1) through (6) | If you survey using Method 21 as specified in § 98.234(a)(7) | |
Valve 1 | 14.84 | 9.51 |
Connector (other) | 5.59 | 3.58 |
Open-Ended Line | 17.27 | 11.07 |
Pressure Relief Valve | 39.66 | 25.42 |
Meter and Instrument | 19.33 | 12.39 |
Other 2 | 4.1 | 2.63 |
Valve 1 | 4.5 | 3.2 |
Connector (other than flanges) | 1.2 | 0.7 |
Flange | 3.8 | 2.0 |
Open-Ended Line | 2.5 | 1.7 |
Pressure Relief Valve | 4.1 | 2.5 |
Other 2 | 4.1 | 2.5 |
1 Valves include control valves, block valves and regulator valves.
2 Other includes any potential equipment leak emission point in gas service that is not specifically listed in this table, as specified in § 98.232(f)(6) and (8).
Table W-4B to Subpart W of Part 98 – Default Total Hydrocarbon Population Emission Factors for Underground Natural Gas Storage
Table W-4B to Subpart W of Part 98 – Default Total Hydrocarbon Population Emission Factors for Underground Natural Gas Storage
Underground natural gas storage | Emission factor (scf/hour/component) |
---|---|
Connector | 0.01 |
Valve | 0.1 |
Pressure Relief Valve | 0.17 |
Open-Ended Line | 0.03 |
Low Continuous Bleed Pneumatic Device Vents 1 | 1.37 |
High Continuous Bleed Pneumatic Device Vents 1 | 18.20 |
Intermittent Bleed Pneumatic Device Vents 1 | 2.35 |
1 Emission Factor is in units of “scf/hour/device.”
Table W-5A to Subpart W of Part 98 – Default Methane Leaker Emission Factors for Liquefied Natural Gas (LNG) Storage
LNG storage | Emission factor (scf/hour/component) | |
---|---|---|
If you survey using any of the methods in § 98.234(a)(1) through (6) | If you survey using Method 21 as specified in § 98.234(a)(7) | |
Valve | 1.19 | 0.23 |
Pump Seal | 4.00 | 0.73 |
Connector | 0.34 | 0.11 |
Other 1 | 1.77 | 0.99 |
Valve 2 | 14.84 | 9.51 |
Connector | 5.59 | 3.58 |
Open-Ended Line | 17.27 | 11.07 |
Pressure Relief Valve | 39.66 | 25.42 |
Meter and Instrument | 19.33 | 12.39 |
Other 3 | 4.1 | 2.63 |
1 “Other” equipment type for components in LNG service should be applied for any equipment type other than connectors, pumps, or valves.
2 Valves include control valves, block valves and regulator valves.
3 “Other” equipment type for components in gas service should be applied for any equipment type other than valves, connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, as specified in § 98.232(g)(6) and (7).
Table W-5B to Subpart W of Part 98 – Default Methane Population Emission Factors for Liquefied Natural Gas (LNG) Storage
LNG storage | Emission factor (scf/hour/component) |
---|---|
Vapor Recovery Compressor 1 | 4.17 |
1 Emission Factor is in units of “scf/hour/device.”
Table W-6A to Subpart W of Part 98 – Default Methane Leaker Emission Factors for LNG Import and Export Equipment
LNG import and export equipment | Emission factor (scf/hour/component) | |
---|---|---|
If you survey using any of the methods in § 98.234(a)(1) through (6) | If you survey using Method 21 as specified in § 98.234(a)(7) | |
Valve | 1.19 | 0.23 |
Pump Seal | 4.00 | 0.73 |
Connector | 0.34 | 0.11 |
Other 1 | 1.77 | 0.99 |
Valve 2 | 14.84 | 9.51 |
Connector | 5.59 | 3.58 |
Open-Ended Line | 17.27 | 11.07 |
Pressure Relief Valve | 39.66 | 25.42 |
Meter and Instrument | 19.33 | 12.39 |
Other 3 | 4.1 | 2.63 |
1 “Other” equipment type for components in LNG service should be applied for any equipment type other than connectors, pumps, or valves.
2 Valves include control valves, block valves and regulator valves.
3 “Other” equipment type for components in gas service should be applied for any equipment type other than valves, connectors, flanges, open-ended lines, pressure relief valves, and meters and instruments, as specified in § 98.232(h)(7) and (8).
Table W-6B to Subpart W of Part 98 – Default Methane Population Emission Factors for LNG Import and Export Equipment
Table W-6B to Subpart W of Part 98 – Default Methane Population Emission Factors for LNG Import and Export Equipment
LNG import and export equipment | Emission factor (scf/hour/component) |
---|---|
Vapor Recovery Compressor 1 | 4.17 |
1 Emission Factor is in units of “scf/hour/compressor.”
Table W-7 to Subpart W of Part 98 – Default Methane Emission Factors for Natural Gas Distribution
Natural gas distribution | Emission factor (scf/hour/ component) |
---|---|
1 | |
Connector | 1.69 |
Block Valve | 0.557 |
Control Valve | 9.34 |
Pressure Relief Valve | 0.27 |
Orifice Meter | 0.212 |
Regulator | 0.772 |
Open-ended Line | 26.131 |
1 2 | |
Below Grade M&R Station, Inlet Pressure >300 psig | 1.30 |
Below Grade M&R Station, Inlet Pressure 100 to 300 psig | 0.20 |
Below Grade M&R Station, Inlet Pressure | 0.10 |
3 | |
Unprotected Steel | 12.58 |
Protected Steel | 0.35 |
Plastic | 1.13 |
Cast Iron | 27.25 |
4 | |
Unprotected Steel | 0.19 |
Protected Steel | 0.02 |
Plastic | 0.001 |
Copper | 0.03 |
1 Excluding customer meters.
2 Emission Factor is in units of “scf/hour/station.”
3 Emission Factor is in units of “scf/hour/mile.”
4 Emission Factor is in units of “scf/hour/number of services.”
Subpart X – Petrochemical Production
§ 98.240 Definition of the source category.
(a) The petrochemical production source category consists of processes as described in paragraphs (a)(1) and (2) of this section.
(1) The petrochemical production source category consists of all processes that produce acrylonitrile, carbon black, ethylene, ethylene dichloride, ethylene oxide, or methanol, as either an intermediate in the on-site production of other chemicals or as an end product for sale or shipment off site, except as specified in paragraphs (b) through (g) of this section.
(2) When ethylene dichloride and vinyl chloride monomer are produced in an integrated process, you may consider the entire integrated process to be the petrochemical process for the purpose of complying with the mass balance option in § 98.243(c). If you elect to consider the integrated process to be the petrochemical process, then the mass balance must be performed over the entire integrated process.
(b) A process that produces a petrochemical as a byproduct is not part of the petrochemical production source category.
(c) A facility that makes methanol, hydrogen, and/or ammonia from synthesis gas is part of the petrochemical source category if the annual mass of methanol produced exceeds the individual annual mass production levels of both hydrogen recovered as product and ammonia. The facility is part of subpart P of this part (Hydrogen Production) if the annual mass of hydrogen recovered as product exceeds the individual annual mass production levels of both methanol and ammonia. The facility is part of subpart G of this part (Ammonia Manufacturing) if the annual mass of ammonia produced exceeds the individual annual mass production levels of both hydrogen recovered as product and methanol.
(d) A direct chlorination process that is operated independently of an oxychlorination process to produce ethylene dichloride is not part of the petrochemical production source category.
(e) A process that produces bone black is not part of the petrochemical source category.
(f) A process that produces a petrochemical from bio-based feedstock is not part of the petrochemical production source category.
(g) A process that solely distills or recycles waste solvent that contains a petrochemical is not part of the petrochemical production source category.
§ 98.241 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a petrochemical process as specified in § 98.240, and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.242 GHGs to report.
You must report the information in paragraphs (a) through (c) of this section:
(a) CO
(1) If you comply with § 98.243(b) or (d), report under this subpart the calculated CO
(2) If you comply with § 98.243(c), report under this subpart the calculated CO
(b) CO
(1) If you comply with § 98.243(b) or (d), report these emissions from stationary combustion units that are associated with petrochemical process units and burn only supplemental fuel under subpart C of this part (General Stationary Fuel Combustion Sources) by following the requirements of subpart C.
(2) If you comply with § 98.243(c), report CO
(c) CO
§ 98.243 Calculating GHG emissions.
(a) If you route all process vent emissions and emissions from combustion of process off-gas to one or more stacks and use CEMS on each stack to measure CO
(b) Continuous emission monitoring system (CEMS). Route all process vent emissions and emissions from stationary combustion units that burn any amount of process off-gas to one or more stacks and determine GHG emissions as specified in paragraphs (b)(1) through (3) of this section.
(1) Determine CO
(2) For each stack (except flare stacks) that includes emissions from combustion of petrochemical process off-gas, calculate CH
(3) For each flare, calculate CO
(c) Mass balance for each petrochemical process unit. Calculate the emissions of CO
(1) For each gaseous and liquid feedstock and product, measure the volume or mass used or produced each calendar month with a flow meter by following the procedures specified in § 98.244(b)(2). Alternatively, for liquids, you may calculate the volume used or collected in each month based on measurements of the liquid level in a storage tank at least once per month (and just prior to each change in direction of the level of the liquid) following the procedures specified in § 98.244(b)(3). Fuels used for combustion purposes are not considered to be feedstocks.
(2) For each solid feedstock and product, measure the mass used or produced each calendar month by following the procedures specified in § 98.244(b)(1).
(3) Collect a sample of each feedstock and product at least once per month and determine the molecular weight (for gaseous materials when the quantity is measured in scf) and carbon content of each sample according to the procedures of § 98.244(b)(4). If multiple valid molecular weight or carbon content measurements are made during the monthly measurement period, average them arithmetically. However, if a particular liquid or solid feedstock is delivered in lots, and if multiple deliveries of the same feedstock are received from the same supply source in a given calendar month, only one representative sample is required. Alternatively, you may use the results of analyses conducted by a feedstock supplier, or product customer, provided the sampling and analysis is conducted at least once per month using any of the procedures specified in § 98.244(b)(4).
(4) If you determine that the monthly average concentration of a specific compound in a feedstock or product is greater than 99.5 percent by volume or mass, then as an alternative to the sampling and analysis specified in paragraph (c)(3) of this section, you may determine molecular weight and carbon content in accordance with paragraphs (c)(4)(i) through (iii) of this section.
(i) Calculate the molecular weight and carbon content assuming 100 percent of that feedstock or product is the specific compound.
(ii) Maintain records of any determination made in accordance with this paragraph (c)(4) along with all supporting data, calculations, and other information.
(iii) Reevaluate determinations made under this paragraph (c)(4) after any process change that affects the feedstock or product composition. Keep records of the process change and the corresponding composition determinations. If the feedstock or product composition changes so that the average monthly concentration falls below 99.5 percent, you are no longer permitted to use this alternative method.
(5) Calculate the CO
(i) Gaseous feedstocks and products. Use Equation X-1 of this section to calculate the net annual carbon input or output from gaseous feedstocks and products. Note that the result will be a negative value if there are no gaseous feedstocks in the process but there are gaseous products.
(ii) Liquid feedstocks and products. Use Equation X-2 of this section to calculate the net carbon input or output from liquid feedstocks and products. Note that the result will be a negative value if there are no liquid feedstocks in the process but there are liquid products.
(iii) Solid feedstocks and products. Use Equation X-3 of this section to calculate the net annual carbon input or output from solid feedstocks and products. Note that the result will be a negative value if there are no solid feedstocks in the process but there are solid products.
(iv) Annual emissions. Use the results from Equations X-1 through X-3 of this section, as applicable, in Equation X-4 of this section to calculate annual CO
(d) Optional combustion methodology for ethylene production processes. For each ethylene production process, calculate GHG emissions from combustion units that burn fuel that contains any off-gas from the ethylene process as specified in paragraphs (d)(1) through (d)(5) of this section.
(1) Except as specified in paragraphs (d)(2) and (d)(5) of this section, calculate CO
(2) You may use either Equation C-1 or Equation C-2a in subpart C of this part to calculate CO
(i) The annual average flow rate of fuel gas (that contains ethylene process off-gas) in the fuel gas line to the combustion unit, prior to any split to individual burners or ports, does not exceed 345 standard cubic feet per minute at 60 °F and 14.7 pounds per square inch absolute, and a flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe. Calculate the annual average flow rate using company records assuming total flow is evenly distributed over 525,600 minutes per year.
(ii) The combustion unit has a maximum rated heat input capacity of less than 30 mmBtu/hr, and a flow meter is not installed at any point in the line supplying fuel gas (that contains ethylene process off-gas) or an upstream common pipe.
(3) Except as specified in paragraph (d)(5) of this section, calculate CH
(i) For all gaseous fuels that contain ethylene process off-gas, use the emission factors for “Fuel Gas” in Table C-2 of subpart C of this part (General Stationary Fuel Combustion Sources).
(ii) For Tier 3, use either the default high heat value for fuel gas in Table C-1 of subpart C of this part or a calculated HHV, as allowed in Equation C-8 of subpart C of this part.
(4) You are not required to use the same Tier for each stationary combustion unit that burns ethylene process off-gas.
(5) For each flare, calculate CO
§ 98.244 Monitoring and QA/QC requirements.
(a) If you use CEMS to determine emissions from process vents, you must comply with the procedures specified in § 98.34(c).
(b) If you use the mass balance methodology in § 98.243(c), use the procedures specified in paragraphs (b)(1) through (b)(4) of this section to determine feedstock and product flows and carbon contents.
(1) Operate, maintain, and calibrate belt scales or other weighing devices as described in Specifications, Tolerances, and Other Technical Requirements for Weighing and Measuring Devices NIST Handbook 44 (2009) (incorporated by reference, see § 98.7), or follow procedures specified by the measurement device manufacturer. You must recalibrate each weighing device according to one of the following frequencies. You may recalibrate either at the minimum frequency specified by the manufacturer or biennially (i.e., once every two years).
(2) Operate and maintain all flow meters used for gas and liquid feedstocks and products according to the manufacturer’s recommended procedures. You must calibrate each of these flow meters as specified in paragraphs (b)(2)(i) and (b)(2)(ii) of this section:
(i) You may use either the calibration methods specified by the flow meter manufacturer or an industry consensus standard method. Each flow meter must meet the applicable accuracy specification in § 98.3(i), except as otherwise specified in §§ 98.3(i)(4) through (i)(6).
(ii) You must recalibrate each flow meter according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, biennially (every two years), or at the interval specified by the industry consensus standard practice used.
(3) You must perform tank level measurements (if used to determine feedstock or product flows) according to one of the following methods. You may use any standard method published by a consensus-based standards organization or you may use an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th Floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org,) and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
(4) Beginning January 1, 2010, use any applicable methods specified in paragraphs (b)(4)(i) through (xv) of this section to determine the carbon content or composition of feedstocks and products and the average molecular weight of gaseous feedstocks and products. Calibrate instruments in accordance with paragraphs (b)(4)(i) through (xv) of this section, as applicable. For coal used as a feedstock, the samples for carbon content determinations shall be taken at a location that is representative of the coal feedstock used during the corresponding monthly period. For carbon black products, samples shall be taken of each grade or type of product produced during the monthly period. Samples of coal feedstock or carbon black product for carbon content determinations may be either grab samples collected and analyzed monthly or a composite of samples collected more frequently and analyzed monthly. Analyses conducted in accordance with methods specified in paragraphs (b)(4)(i) through (xv) of this section may be performed by the owner or operator, by an independent laboratory, by the supplier of a feedstock, or by a product customer.
(i) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(ii) ASTM D6060-96 (Reapproved 2001) Standard Practice for Sampling of Process Vents With a Portable Gas Chromatograph (incorporated by reference, see § 98.7).
(iii) ASTM D2505-88(Reapproved 2004)e1 Standard Test Method for Ethylene, Other Hydrocarbons, and Carbon Dioxide in High-Purity Ethylene by Gas Chromatography (incorporated by reference, see § 98.7).
(iv) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(v) ASTM D3176-89 (Reapproved 2002) Standard Practice Method for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7).
(vi) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7).
(vii) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).
(viii) Method 8015C, Method 8021B, Method 8031, or Method 9060A (all incorporated by reference, see § 98.7).
(ix) Method 18 at 40 CFR part 60, appendix A-6.
(x) Performance Specification 9 in 40 CFR part 60, appendix B for continuous online gas analyzers. The 7-day calibration error test period must be completed prior to the effective date of the rule.
(xi) ASTM D2593-93 (Reapproved 2009) Standard Test Method for Butadiene Purity and Hydrocarbon Impurities by Gas Chromatography (incorporated by reference, see § 98.7).
(xii) ASTM D7633-10 Standard Test Method for Carbon Black – Carbon Content (incorporated by reference, see § 98.7).
(xiii) The results of chromatographic analysis of a feedstock or product, provided that the chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions.
(xiv) The results of mass spectrometer analysis of a feedstock or product, provided that the mass spectrometer is operated, maintained, and calibrated according to the manufacturer’s instructions.
(xv) Beginning on January 1, 2010, the methods specified in paragraphs (b)(4)(xv)(A) and (B) of this section may be used as alternatives for the methods specified in paragraphs (b)(4)(i) through (b)(4)(xiv) of this section.
(A) An industry standard practice or a method published by a consensus-based standards organization if such a method exists for carbon black feedstock oils and carbon black products. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.naesb.org). The method(s) used shall be documented in the monitoring plan required under § 98.3(g)(5).
(B) Modifications of existing analytical methods or other methods that are applicable to your process provided that the methods listed in paragraphs (b)(4)(i) through (b)(4)(xiv) of this section are not appropriate because the relevant compounds cannot be detected, the quality control requirements are not technically feasible, or use of the method would be unsafe.
(c) If you comply with § 98.243(b) or (d), conduct monitoring and QA/QC for flares in accordance with § 98.254(b) through (e) for each flare gas flow meter, gas composition meter, and/or heating value monitor that you use to comply with § 98.253(b)(1) through (b)(3). You must implement all applicable QA/QC requirements specified in this paragraph (c) beginning no later than January 1, 2015.
§ 98.245 Procedures for estimating missing data.
For missing feedstock and product flow rates, use the same procedures as for missing fuel usage as specified in § 98.35(b)(2). For missing feedstock and product carbon contents and missing molecular weights for gaseous feedstocks and products, use the same procedures as for missing carbon contents and missing molecular weights for fuels as specified in § 98.35(b)(1).
For missing flare data, follow the procedures in § 98.255(b) and (c).
§ 98.246 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a), (b), or (c) of this section, as appropriate for each process unit.
(a) If you use the mass balance methodology in § 98.243(c), you must report the information specified in paragraphs (a)(1) through (13) of this section for each type of petrochemical produced, reported by process unit.
(1) The petrochemical process unit ID number or other appropriate descriptor.
(2) The type of petrochemical produced, names of products, and names of carbon-containing feedstocks.
(3) Annual CO
(4) The temperature (in °F) at which the gaseous feedstock and product volumes used in Equation X-1 of § 98.243 were determined.
(5) Annual quantity of each type of petrochemical produced from each process unit (metric tons). If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, report the amount of intermediate EDC produced (metric tons). The reported amount of intermediate EDC produced may be a measured quantity or an estimate that is based on process knowledge and best available data.
(6) For each feedstock and product, provide the information specified in paragraphs (a)(6)(i) through (a)(6)(iii) of this section.
(i) Name of each method used to determine carbon content or molecular weight in accordance with § 98.244(b)(4);
(ii) Description of each type of measurement device (e.g., flow meter, weighing device) used to determine volume or mass in accordance with § 98.244(b)(1) through (3).
(iii) Identification of each method (i.e., method number, title, or other description) used to determine volume or mass in accordance with § 98.244(b)(1) through (3).
(7) [Reserved]
(8) Identification of each combustion unit that burned both process off-gas and supplemental fuel, including combustion units that are not part of the petrochemical process unit.
(9) The number of days during which off-specification product was produced if the alternative to sampling and analysis specified in § 98.243(c)(4) is used for a product, and, if applicable, the date of any process change that reduced the monthly average composition to less than 99.5 percent for each product or feedstock for which you comply with the alternative to sampling and analysis specified in § 98.243(c)(4).
(10) You may elect to report the flow and carbon content of wastewater, and you may elect to report the annual mass of carbon released in fugitive emissions and in process vents that are not controlled with a combustion device. These values may be estimated based on engineering analyses. These values are not to be used in the mass balance calculation.
(11) If you determine carbon content or composition of a feedstock or product using a method under § 98.244(b)(4)(xv)(B), report the information listed in paragraphs (a)(11)(i) through (a)(11)(iii) of this section. Include the information in paragraph (a)(11)(i) of this section in each annual report. Include the information in paragraphs (a)(11)(ii) and (a)(11)(iii) of this section only in the first applicable annual report, and provide any changes to this information in subsequent annual reports.
(i) Name or title of the analytical method.
(ii) A copy of the method. If the method is a modification of a method listed in §§ 98.244(b)(4)(i) through (xiv), you may provide a copy of only the sections that differ from the listed method.
(iii) An explanation of why an alternative to the methods listed in §§ 98.244(b)(4)(i) through (xiv) is needed.
(12) Name and annual quantity (in metric tons) of each carbon-containing feedstock included in Equations X-1, X-2, and X-3 of § 98.243.
(13) Name and annual quantity (in metric tons) of each product included in Equations X-1, X-2, and X-3.
(14) Annual average of the measurements or determinations of the carbon content of each feedstock and product, conducted according to § 98.243(c)(3) or (4).
(i) For feedstocks and products that are gaseous or solid, report this quantity in kg C per kg of feedstock or product.
(ii) For liquid feedstocks and products, report this quantity either in units of kg C per kg of feedstock or product, or kg C per gallon of feedstock or product.
(15) For each gaseous feedstock and product, the annual average of the measurements or determinations of the molecular weight in units of kg per kg mole, conducted according to § 98.243(c)(3) or (4).
(b) If you measure emissions in accordance with § 98.243(b), then you must report the information listed in paragraphs (b)(1) through (10) of this section.
(1) The petrochemical process unit ID or other appropriate descriptor, and the type of petrochemical produced.
(2) For CEMS used on stacks that include emissions from stationary combustion units that burn any amount of off-gas from the petrochemical process, report the relevant information required under § 98.36(c)(2) and (e)(2)(vi) for the Tier 4 calculation methodology. Section 98.36(c)(2)(ii), (ix) and (x) do not apply for the purposes of this subpart.
(3) For CEMS used on stacks that do not include emissions from stationary combustion units, report the information required under § 98.36(b)(6) and (7), (b)(9)(i) and (ii) and (e)(2)(vi).
(4) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) or (3) of this section, provide an estimate based on engineering judgment of the fraction of the total CO
(5) For each CEMS monitoring location that meets the conditions in paragraph (b)(2) of this section, report the CH
(6) [Reserved]
(7) Information listed in § 98.256(e) of subpart Y of this part for each flare that burns process off-gas.
(8) Annual quantity of each type of petrochemical produced from each process unit (metric tons). If you are electing to consider the petrochemical process unit to be the entire integrated ethylene dichloride/vinyl chloride monomer process, report the amount of intermediate EDC produced (metric tons). The reported amount of intermediate EDC produced may be a measured quantity or an estimate that is based on process knowledge and best available data.
(9) Name and annual quantity (in metric tons) of each carbon-containing feedstock.
(10) Name and annual quantity (in metric tons) of each product.
(c) If you comply with the combustion methodology specified in § 98.243(d), you must report under this subpart the information listed in paragraphs (c)(1) through (c)(5) of this section.
(1) The ethylene process unit ID or other appropriate descriptor.
(2) For each stationary combustion unit that burns ethylene process off-gas (or group of stationary sources with a common pipe), except flares, the relevant information listed in § 98.36 for the applicable Tier methodology. For each stationary combustion unit or group of units (as applicable) that burns ethylene process off-gas, provide an estimate based on engineering judgment of the fraction of the total emissions that is attributable to combustion of off-gas from the ethylene process unit.
(3) Information listed in § 98.256(e) of subpart Y of this part for each flare that burns ethylene process off-gas.
(4) Name and annual quantity of each feedstock (metric tons).
(5) Annual quantity of ethylene produced from each process unit (metric tons).
§ 98.247 Records that must be retained.
In addition to the recordkeeping requirements in § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section, as applicable.
(a) If you comply with the CEMS measurement methodology in § 98.243(b), then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37, records of the procedures used to develop estimates of the fraction of total emissions attributable to petrochemical processing and combustion of petrochemical process off-gas as required in § 98.246(b), and records of any annual average HHV calculations.
(b) If you comply with the mass balance methodology in § 98.243(c), then you must retain records of the information listed in paragraphs (b)(1) through (4) of this section.
(1) Results of feedstock or product composition determinations conducted in accordance with § 98.243(c)(4).
(2) Start and end times for time periods when off-specification product is produced, if you comply with the alternative methodology in § 98.243(c)(4) for determining carbon content of product.
(3) As part of the monitoring plan required under § 98.3(g)(5), record the estimated accuracy of measurement devices and the technical basis for these estimates.
(4) The dates and results (e.g., percent calibration error) of the calibrations of each measurement device.
(c) If you comply with the combustion methodology in § 98.243(d), then you must retain under this subpart the records required for the applicable Tier Calculation Methodologies in § 98.37. If you comply with § 98.243(d)(2), you must also keep records of the annual average flow calculations.
(d) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (d)(1) through (30) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (30) of this section.
(1) Indicate whether the feedstock is measured as mass or volume (Equation X-1 of § 98.243).
(2) Indicate whether you used the alternative to sampling and analysis specified in § 98.243(c)(4) (Equation X-1).
(3) Volume of gaseous feedstock introduced per month (scf) (Equation X-1).
(4) Mass of gaseous feedstock introduced per month (kg) (Equation X-1).
(5) Average carbon content of the gaseous feedstock per month (kg C per kg of feedstock) (Equation X-1).
(6) Molecular weight of gaseous feedstock per month (kg per kg-mole) (Equation X-1).
(7) Indicate whether the gaseous product is measured as mass or volume (Equation X-1).
(8) Volume of gaseous product produced per month (scf) (Equation X-1).
(9) Mass of gaseous product produced per month (kg) (Equation X-1).
(10) Average carbon content of gaseous product (including streams containing CO
(11) Molecular weight of gaseous product per month (kg per kg-mole) (Equation X-1).
(12) Molar volume conversion factor of product (scf per kg-mole) (Equation X-1).
(13) Indicate whether feedstock is measured as mass or volume (Equation X-2 of § 98.243).
(14) Indicate whether you used the alternative to sampling and analysis specified in § 98.243(c)(4) (Equation X-2).
(15) Volume of liquid feedstock introduced per month (gallons) (Equation X-2).
(16) Mass of liquid feedstock introduced per month (kg) (Equation X-2).
(17) Average carbon content of liquid feedstock per month (kg C per gallon) (Equation X-2).
(18) Average carbon content of liquid feedstock per month (kg C per kg of feedstock) (Equation X-2).
(19) Indicate whether product is measured as mass or volume per month (Equation X-2).
(20) Volume of liquid product produced per month (gallons) (Equation X-2).
(21) Mass of liquid product produced per month (kg) (Equation X-2).
(22) Average carbon content of liquid product per month, including organic liquid wastes (kg C per gallon) (Equation X-2).
(23) Average carbon content of liquid product, including organic liquid wastes (kg C per kg of product) (Equation X-2).
(24) Indicate whether you used the alternative to sampling and analysis specified in § 98.243(c)(4) (Equation X-3 of § 98.243).
(25) Mass of solid feedstock introduced per month (kg) (Equation X-3).
(26) Average carbon content of solid feedstock per month (kg C per kg of feedstock) (Equation X-3).
(27) Mass of solid product produced per month (kg) (Equation X-3).
(28) Average carbon content of solid product per month (kg C per kg of product) (Equation X-3).
(29) Records required in § 98.257(b)(1) through (8) of this section for each flare that burns ethylene process off-gas.
(30) Records required in § 98.37 for each stationary fuel combustion unit (or group of stationary sources with a common pipe) that burns ethylene process off-gas, except flares.
§ 98.248 Definitions.
Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Product means each of the following carbon-containing outputs from a process: The petrochemical, recovered byproducts, and liquid organic wastes that are not combusted onsite. Product does not include process vent emissions, fugitive emissions, or wastewater.
Subpart Y – Petroleum Refineries
§ 98.250 Definition of source category.
(a) A petroleum refinery is any facility engaged in producing gasoline, gasoline blending stocks, naphtha, kerosene, distillate fuel oils, residual fuel oils, lubricants, or asphalt (bitumen) through distillation of petroleum or through redistillation, cracking, or reforming of unfinished petroleum derivatives, except as provided in paragraph (b) of this section.
(b) For the purposes of this subpart, facilities that distill only pipeline transmix (off-spec material created when different specification products mix during pipeline transportation) are not petroleum refineries, regardless of the products produced.
(c) This source category consists of the following sources at petroleum refineries: Catalytic cracking units; fluid coking units; delayed coking units; catalytic reforming units; coke calcining units; asphalt blowing operations; blowdown systems; storage tanks; process equipment components (compressors, pumps, valves, pressure relief devices, flanges, and connectors) in gas service; marine vessel, barge, tanker truck, and similar loading operations; flares; sulfur recovery plants; and non-merchant hydrogen plants (i.e., hydrogen plants that are owned or under the direct control of the refinery owner and operator).
§ 98.251 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a petroleum refineries process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.252 GHGs to report.
You must report:
(a) CO
(1) The annual average fuel gas flow rate in the fuel gas line to the combustion unit, prior to any split to individual burners or ports, does not exceed 345 standard cubic feet per minute at 60 °F and 14.7 pounds per square inch absolute and either of the conditions in paragraph (a)(1)(i) or (ii) of this section exist. Calculate the annual average flow rate using company records assuming total flow is evenly distributed over 525,600 minutes per year.
(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe.
(ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator.
(2) The combustion unit has a maximum rated heat input capacity of less than 30 mmBtu/hr and either of the following conditions exist:
(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream common pipe; or
(ii) The fuel gas line contains only vapors from loading or unloading, waste or wastewater handling, and remediation activities that are combusted in a thermal oxidizer or thermal incinerator.
(b) CO
(c) CO
(d) CO
(e) CO
(f) CO
(g) CH
(h) CO
(i) CO
§ 98.253 Calculating GHG emissions.
(a) Calculate GHG emissions required to be reported in § 98.252(b) through (i) using the applicable methods in paragraphs (b) through (n) of this section.
(b) For flares, calculate GHG emissions according to the requirements in paragraphs (b)(1) through (3) of this section. All gas discharged through the flare stack must be included in the flare GHG emissions calculations with the exception of gas used for the flare pilots, which may be excluded.
(1) Calculate the CO
(i) Flow measurement. If you have a continuous flow monitor on the flare, you must use the measured flow rates when the monitor is operational and the flow rate is within the calibrated range of the measurement device to calculate the flare gas flow. If you do not have a continuous flow monitor on the flare and for periods when the monitor is not operational or the flow rate is outside the calibrated range of the measurement device, you must use engineering calculations, company records, or similar estimates of volumetric flare gas flow.
(ii) Heat value or carbon content measurement. If you have a continuous higher heating value monitor or gas composition monitor on the flare or if you monitor these parameters at least weekly, you must use the measured heat value or carbon content value in calculating the CO
(A) If you monitor gas composition, calculate the CO
(B) If you monitor heat content but do not monitor gas composition, calculate the CO
(iii) Alternative to heat value or carbon content measurements. If you do not measure the higher heating value or carbon content of the flare gas at least weekly, determine the quantity of gas discharged to the flare separately for periods of routine flare operation and for periods of start-up, shutdown, or malfunction, and calculate the CO
(A) For periods of start-up, shutdown, or malfunction, use engineering calculations and process knowledge to estimate the carbon content of the flared gas for each start-up, shutdown, or malfunction event exceeding 500,000 scf/day.
(B) For periods of normal operation, use the average higher heating value measured for the fuel gas used as flare sweep or purge gas for the higher heating value of the flare gas. If higher heating value of the fuel gas is not measured, the higher heating value of the flare gas under normal operations may be estimated from historic data or engineering calculations.
(C) Calculate the CO
(2) Calculate CH
(3) Calculate N
(c) For catalytic cracking units and traditional fluid coking units, calculate the GHG emissions using the applicable methods described in paragraphs (c)(1) through (c)(5) of this section.
(1) If you operate and maintain a CEMS that measures CO
(i) Calculate CO
(ii) For catalytic cracking units whose process emissions are discharged through a combined stack with other CO
(2) For catalytic cracking units and fluid coking units with rated capacities greater than 10,000 barrels per stream day (bbls/sd) that do not use a continuous CO
(i) Calculate the CO
(ii) Either continuously monitor the volumetric flow rate of exhaust gas from the fluid catalytic cracking unit regenerator or fluid coking unit burner prior to the combustion of other fossil fuels or calculate the volumetric flow rate of this exhaust gas stream using either Equation Y-7a or Equation Y-7b of this section.
(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO
(3) For catalytic cracking units and fluid coking units with rated capacities of 10,000 barrels per stream day (bbls/sd) or less that do not use a continuous CO
(i) If you continuously or no less frequently than daily monitor the O
(ii) If you do not monitor at least daily the O
(iii) If you have a CO boiler that uses auxiliary fuels or combusts materials other than catalytic cracking unit or fluid coking unit exhaust gas, you must determine the CO
(4) Calculate CH
(5) Calculate N
(d) For fluid coking units that use the flexicoking design, the GHG emissions from the resulting use of the low value fuel gas must be accounted for only once. Typically, these emissions will be accounted for using the methods described in subpart C of this part (General Stationary Fuel Combustion Sources). Alternatively, you may use the methods in paragraph (c) of this section provided that you do not otherwise account for the subsequent combustion of this low value fuel gas.
(e) For catalytic reforming units, calculate the CO
(1) If you operate and maintain a CEMS that measures CO
(2) If you continuously or no less frequently than daily monitor the O
(3) Calculate CO
(f) For on-site sulfur recovery plants and for sour gas sent off site for sulfur recovery, calculate and report CO
(1) If you operate and maintain a CEMS that measures CO
(2) Flow measurement. If you have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use the measured flow rates when the monitor is operational to calculate the sour gas flow rate. If you do not have a continuous flow monitor on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site sulfur recovery, you must use engineering calculations, company records, or similar estimates of volumetric sour gas flow.
(3) Carbon content. If you have a continuous gas composition monitor capable of measuring carbon content on the sour gas feed to the sulfur recovery plant or the sour gas feed sent for off-site for sulfur recovery, or if you monitor gas composition for carbon content on a routine basis, you must use the measured carbon content value. Alternatively, you may develop a site-specific carbon content factor using limited measurement data or engineering estimates or use the default factor of 0.20.
(4) Calculate the CO
(5) If tail gas is recycled to the front of the sulfur recovery plant and the recycled flow rate and carbon content is included in the measured data under paragraphs (f)(2) and (f)(3) of this section, respectively, then the annual CO
(g) For coke calcining units, calculate GHG emissions according to the applicable provisions in paragraphs (g)(1) through (g)(3) of this section.
(1) If you operate and maintain a CEMS that measures CO
(2) Calculate the CO
(3) For all coke calcining units, use the CO
(h) For asphalt blowing operations, calculate CO
(1) For uncontrolled asphalt blowing operations or asphalt blowing operations controlled either by vapor scrubbing or by another non-combustion control device, calculate CO
(2) For asphalt blowing operations controlled by either a thermal oxidizer, a flare, or other vapor combustion control device, calculate CO
(i) For each delayed coking unit, calculate the CH
(1) Determine the typical dry mass of coke produced per cycle from company records of the mass of coke produced by the delayed coking unit. Alternatively, you may estimate the typical dry mass of coke produced per cycle based on the delayed coking unit vessel (coke drum) dimensions and typical coke drum outage at the end of the coking cycle using Equation Y-18a of this section.
(2) Determine the typical mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to venting to the atmosphere using Equation Y-18b of this section.
(3) Determine the average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere using either Equation Y-18c or Y-18d of this section, as appropriate, based on the measurement system available.
(4) Determine the typical mass of steam generated and released per decoking cycle using Equation Y-18e of this section.
(5) Calculate the CH
(j) For each process vent not covered in paragraphs (a) through (i) of this section that can reasonably be expected to contain greater than 2 percent by volume CO
(k) For uncontrolled blowdown systems, you must calculate CH
(l) For equipment leaks, calculate CH
(1) Use process-specific methane composition data (from measurement data or process knowledge) and any of the emission estimation procedures provided in the Protocol for Equipment Leak Emissions Estimates (EPA-453/R-95-017, NTIS PB96-175401).
(2) Use Equation Y-21 of this section.
(m) For storage tanks, except as provided in paragraph (m)(3) of this section, calculate CH
(1) For storage tanks other than those processing unstabilized crude oil, you must either calculate CH
(2) For storage tanks that process unstabilized crude oil, calculate CH
(3) You do not need to calculate CH
(i) Units permanently attached to conveyances such as trucks, trailers, rail cars, barges, or ships;
(ii) Pressure vessels designed to operate in excess of 204.9 kilopascals and without emissions to the atmosphere;
(iii) Bottoms receivers or sumps;
(iv) Vessels storing wastewater; or
(v) Reactor vessels associated with a manufacturing process unit.
(n) For crude oil, intermediate, or product loading operations for which the vapor-phase concentration of methane is 0.5 volume percent or more, calculate CH
§ 98.254 Monitoring and QA/QC requirements.
(a) Fuel flow meters, gas composition monitors, and heating value monitors that are associated with sources that use a CEMS to measure CO
(b) All gas flow meters, gas composition monitors, and heating value monitors that are used to provide data for the GHG emissions calculations in this subpart for sources other than those subject to the requirements in paragraph (a) of this section shall be calibrated according to the procedures specified by the manufacturer, or according to the procedures in the applicable methods specified in paragraphs (c) through (g) of this section. In the case of gas flow meters, all gas flow meters must meet the calibration accuracy requirements in § 98.3(i). All gas flow meters, gas composition monitors, and heating value monitors must be recalibrated at the applicable frequency specified in paragraph (b)(1) or (b)(2) of this section.
(1) You must recalibrate each gas flow meter according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, biennially (every two years), or at the interval specified by the industry consensus standard practice used.
(2) You must recalibrate each gas composition monitor and heating value monitor according to one of the following frequencies. You may recalibrate at the minimum frequency specified by the manufacturer, annually, or at the interval specified by the industry standard practice used.
(c) For flare or sour gas flow meters and gas flow meters used to comply with the requirements in § 98.253(j), operate, calibrate, and maintain the flow meter according to one of the following. You may use the procedures specified by the flow meter manufacturer, or a method published by a consensus-based standards organization. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
(d) Except as provided in paragraph (g) of this section, determine gas composition and, if required, average molecular weight of the gas using any of the following methods. Alternatively, the results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph are documented in the written Monitoring Plan for the unit under § 98.3(g)(5).
(1) Method 18 at 40 CFR part 60, appendix A-6.
(2) ASTM D1945-03 Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(3) ASTM D1946-90 (Reapproved 2006) Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(4) GPA 2261-00 Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see § 98.7).
(5) UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(6) ASTM D2503-92 (Reapproved 2007) Standard Test Method for Relative Molecular Mass (Molecular Weight) of Hydrocarbons by Thermoelectric Measurement of Vapor Pressure (incorporated by reference, see § 98.7).
(e) Determine flare gas higher heating value using any of the following methods. Alternatively, the results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph is operated, maintained, and calibrated according to the manufacturer’s instructions; and the methods used for operation, maintenance, and calibration of the gas chromatograph are documented in the written Monitoring Plan for the unit under § 98.3(g)(5).
(1) ASTM D4809-06 Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference, see § 98.7).
(2) ASTM D240-02 (Reapproved 2007) Standard Test Method for Heat of Combustion of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference, see § 98.7).
(3) ASTM D1826-94 (Reapproved 2003) Standard Test Method for Calorific (Heating) Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated by reference, see § 98.7).
(4) ASTM D3588-98 (Reapproved 2003) Standard Practice for Calculating Heat Value, Compressibility Factor, and Relative Density of Gaseous Fuels (incorporated by reference, see § 98.7).
(5) ASTM D4891-89 (Reapproved 2006) Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion (incorporated by reference, see § 98.7).
(f) For gas flow meters used to comply with the requirements in § 98.253(c)(2)(ii), install, operate, calibrate, and maintain each gas flow meter according to the requirements in 40 CFR 63.1572(c) and the following requirements.
(1) Locate the flow monitor at a site that provides representative flow rates. Avoid locations where there is swirling flow or abnormal velocity distributions due to upstream and downstream disturbances.
(2) [Reserved]
(3) Use a continuous monitoring system capable of correcting for the temperature, pressure, and moisture content to output flow in dry standard cubic feet (standard conditions as defined in § 98.6).
(g) For exhaust gas CO
(h) Determine the mass of petroleum coke as required by Equation Y-13 of this subpart using mass measurement equipment meeting the requirements for commercial weighing equipment as described in Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices, NIST Handbook 44 (2009) (incorporated by reference, see § 98.7). Calibrate the measurement device according to the procedures specified by NIST handbook 44 (incorporated by reference, see § 98.7) or the procedures specified by the manufacturer. Recalibrate either biennially or at the minimum frequency specified by the manufacturer.
(i) Determine the carbon content of petroleum coke as required by Equation Y-13 of this subpart using any one of the following methods. Calibrate the measurement device according to procedures specified by the method or procedures specified by the measurement device manufacturer.
(1) ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7).
(2) ASTM D5291-02 (Reapproved 2007) Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Petroleum Products and Lubricants (incorporated by reference, see § 98.7).
(3) ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).
(j) Determine the quantity of petroleum process streams using company records. These quantities include the quantity of coke produced per cycle, asphalt blown, quantity of crude oil plus the quantity of intermediate products received from off site, and the quantity of unstabilized crude oil received at the facility.
(k) Determine temperature or pressure of delayed coking unit vessel using process instrumentation operated, maintained, and calibrated according to the manufacturer’s instructions.
(l) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of fuel usage, gas composition, and heating value including but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
§ 98.255 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required (e.g., concentrations, flow rates, fuel heating values, carbon content values). Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a CEMS malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations.
(a) For stationary combustion sources, use the missing data procedures in subpart C of this part.
(b) For each missing value of the heat content, carbon content, or molecular weight of the fuel, substitute the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(c) For missing CO
(d) For hydrogen plants, use the missing data procedures in subpart P of this part.
§ 98.256 Data reporting requirements.
In addition to the reporting requirements of § 98.3(c), you must report the information specified in paragraphs (a) through (q) of this section.
(a) For combustion sources, follow the data reporting requirements under subpart C of this part (General Stationary Fuel Combustion Sources).
(b) For hydrogen plants, follow the data reporting requirements under subpart P of this part (Hydrogen Production).
(c)-(d) [Reserved]
(e) For flares, owners and operators shall report:
(1) The flare ID number (if applicable).
(2) A description of the type of flare (steam assisted, air-assisted).
(3) A description of the flare service (general facility flare, unit flare, emergency only or back-up flare) and an indication of whether or not the flare is serviced by a flare gas recovery system.
(4) The calculated CO
(5) A description of the method used to calculate the CO
(6) If you use Equation Y-1a in § 98.253, an indication of whether daily or weekly measurement periods are used, annual average carbon content of the flare gas (in kg carbon per kg flare gas), and, either the annual volume of flare gas combusted (in scf/year) and the annual average molecular weight (in kg/kg-mole), or the annual mass of flare gas combusted (in kg/yr).
(7) If you use Equation Y-1b of § 98.253, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in scf/year), the annual average CO
(i) The annual average concentration of the compound (volume or mole percent).
(ii) [Reserved]
(8) If you use Equation Y-2 of this subpart, an indication of whether daily or weekly measurement periods are used, the annual volume of flare gas combusted (in million (MM) scf/year), the annual average higher heating value of the flare gas (in mmBtu/mmscf), and an indication of whether the annual volume of flare gas combusted and the annual average higher heating value of the flare gas were determined using standard conditions of 68 °F and 14.7 psia or 60 °F and 14.7 psia.
(9) If you use Equation Y-3 of § 98.253, the number of SSM events exceeding 500,000 scf/day.
(10) The basis for the value of the fraction of carbon in the flare gas contributed by methane used in Equation Y-4 of § 98.253.
(f) For catalytic cracking units, traditional fluid coking units, and catalytic reforming units, owners and operators shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit (fluid catalytic cracking unit, thermal catalytic cracking unit, traditional fluid coking unit, or catalytic reforming unit).
(3) Maximum rated throughput of the unit, in bbl/stream day.
(4) The calculated CO
(5) A description of the method used to calculate the CO
(6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO
(7) If you use Equation Y-6 of § 98.253, the annual average exhaust gas flow rate, %CO
(8) If you use Equation Y-7a of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %O
(9) If you use Equation Y-7b of this subpart, the annual average flow rate of inlet air and oxygen-enriched air, %N
(10) If you use Equation Y-8 of § 98.253, the basis for the value of the average carbon content of coke.
(11) Indicate whether you use a measured value, a unit-specific emission factor, or a default for CH
(12) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for N
(13) If you use Equation Y-11 of § 98.253, the number of regeneration cycles or measurement periods during the reporting year and the average coke burn-off quantity per cycle or measurement period.
(g) For fluid coking unit of the flexicoking type, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) A description of the type of unit.
(3) Maximum rated throughput of the unit, in bbl/stream day.
(4) Indicate whether the GHG emissions from the low heat value gas are accounted for in subpart C of this part or § 98.253(c).
(5) If the GHG emissions for the low heat value gas are calculated at the flexicoking unit, also report the calculated annual CO
(h) For on-site sulfur recovery plants and for emissions from sour gas sent off-site for sulfur recovery, the owner and operator shall report:
(1) The plant ID number (if applicable).
(2) For each on-site sulfur recovery plant, the maximum rated throughput (metric tons sulfur produced/stream day), a description of the type of sulfur recovery plant, and an indication of the method used to calculate CO
(3) The calculated CO
(4) [Reserved]
(5) If you recycle tail gas to the front of the sulfur recovery plant, indicate whether the recycled flow rate and carbon content are included in the measured data under § 98.253(f)(2) and (3). Indicate whether a correction for CO
(i) Indicate whether you used the default (95 percent) or a unit specific correction, and if a unit-specific correction was used, report the value of the correction and the approach used.
(ii) If the following data are not used to calculate the recycling correction factor, report the information specified in paragraphs (h)(5)(ii)(A) through (B) of this section.
(A) The annual volume of recycled tail gas (in scf/year).
(B) The annual average mole fraction of carbon in the tail gas (in kg-mole C/kg-mole gas).
(6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO
(7) If you use the process vent method in § 98.253(j) for a non-Claus sulfur recovery plant, the relevant information required under paragraph (l)(5) of this section.
(i) For coke calcining units, the owner and operator shall report:
(1) The unit ID number (if applicable).
(2) Maximum rated throughput of the unit, in metric tons coke calcined/stream day.
(3) The calculated CO
(4) A description of the method used to calculate the CO
(5) If you use Equation Y-13 of § 98.253, an indication of whether coke dust is recycled to the unit (e.g., all dust is recycled, a portion of the dust is recycled, or none of the dust is recycled).
(6) If you use a CEMS, the relevant information required under § 98.36 for the Tier 4 Calculation Methodology, the CO
(7) Indicate whether you use a measured value, a unit-specific emission factor or a default emission factor for CH
(8) Indicate whether you use a measured value, a unit-specific emission factor, or a default emission factor for N
(j) For asphalt blowing operations, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) [Reserved]
(3) The type of control device used to reduce methane (and other organic) emissions from the unit.
(4) The calculated annual CO
(5) If you use Equation Y-14 of § 98.253, the basis for the CO
(6) If you use Equation Y-15 of § 98.253, the basis for the CH
(7) If you use Equation Y-16a of § 98.253, the basis for the carbon emission factor used.
(8) If you use Equation Y-16b of § 98.253, the basis for the CO
(9) If you use Equation Y-17 of § 98.253, the basis for the CH
(10) If you use Equation Y-19 of this subpart, the relevant information required under paragraph (l)(5) of this section.
(k) For each delayed coking unit, the owner or operator shall report:
(1) The unit ID number (if applicable).
(2) Maximum rated throughput of the unit, in bbl/stream day.
(3) Annual quantity of coke produced in the unit during the reporting year, in metric tons.
(4) The calculated annual CH
(5) The total number of delayed coking vessels (or coke drums) associated with the delayed coking unit.
(6) The basis for the typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (mass measurements from company records or calculated using Equation Y-18a of this subpart).
(7) An indication of the method used to estimate the average temperature of the coke bed, T
(8) An indication of whether a unit-specific methane emissions factor or the default methane emission factor was used for the delayed coking unit.
(l) For each process vent subject to § 98.253(j), the owner or operator shall report:
(1) The vent ID number (if applicable).
(2) The unit or operation associated with the emissions.
(3) The type of control device used to reduce methane (and other organic) emissions from the unit, if applicable.
(4) The calculated annual CO
(5) The annual volumetric flow discharged to the atmosphere (in scf), and an indication of the measurement or estimation method, annual average mole fraction of each GHG above the concentration threshold or otherwise required to be reported and an indication of the measurement or estimation method, and for intermittent vents, the number of venting events and the cumulative venting time.
(m) For uncontrolled blowdown systems, the owner or operator shall report:
(1) An indication of whether the uncontrolled blowdown emission are reported under § 98.253(k) or § 98.253(j) or a statement that the facility does not have any uncontrolled blowdown systems.
(2) The cumulative annual CH
(3) For uncontrolled blowdown systems reporting under § 98.253(k), the basis for the value of the methane emission factor used for uncontrolled blowdown systems.
(4) For uncontrolled blowdown systems reporting under § 98.253(j), the relevant information required under paragraph (l)(5) of this section.
(n) For equipment leaks, the owner or operator shall report:
(1) The cumulative CH
(2) The method used to calculate the reported equipment leak emissions.
(3) The number of each type of emission source listed in Equation Y-21 of this subpart at the facility.
(o) For storage tanks, the owner or operator shall report:
(1) The cumulative annual CH
(2) For storage tanks other than those processing unstabilized crude oil:
(i) The method used to calculate the reported storage tank emissions for storage tanks other than those processing unstabilized crude (i.e., either AP 42, Section 7.1 (incorporated by reference, see § 98.7), or Equation Y-22 of this section).
(ii) [Reserved]
(3) The cumulative CH
(4) For storage tanks that process unstabilized crude oil:
(i) The method used to calculate the reported unstabilized crude oil storage tank emissions.
(ii)-(iv) [Reserved]
(v) The basis for the mole fraction of CH
(vi) If you did not use Equation Y-23, the tank-specific methane composition data and the annual gas generation volume (scf/yr) used to estimate the cumulative CH
(5)-(7) [Reserved]
(p) For loading operations, the owner or operator shall report:
(1) The cumulative annual CH
(2) The types of materials loaded that have an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, and the type of vessel (barge, tanker, marine vessel, etc.) in which each type of material is loaded.
(3) The type of control system used to reduce emissions from the loading of material with an equilibrium vapor-phase concentration of methane of 0.5 volume percent or greater, if any (submerged loading, vapor balancing, etc.).
(q) Name of each method listed in § 98.254 or a description of manufacturer’s recommended method used to determine a measured parameter.
§ 98.257 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) and (b) of this section.
(a) The records of all parameters monitored under § 98.255. If you comply with the combustion methodology in § 98.252(a), then you must retain under this subpart the records required for the Tier 3 and/or Tier 4 Calculation Methodologies in § 98.37 and you must keep records of the annual average flow calculations.
(b) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (b)(1) through (73) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) through (73) of this section.
(1) Volume of flare gas combusted during measurement period (scf) (Equation Y-1b of § 98.253).
(2) Mole percent CO
(3) Mole percent concentration of compound “x” in the flare gas stream during the measurement period (mole percent) (Equation Y-1b).
(4) Carbon mole number of compound “x” in the flare gas stream during the measurement period (mole carbon atoms per mole compound) (Equation Y-1b).
(5) Molar volume conversion factor (scf per kg-mole) (Equation Y-1b).
(6) Annual volume of flare gas combusted for each flare during normal operations from company records (million (MM) standard cubic feet per year, MMscf/year) (Equation Y-3 of § 98.253).
(7) Higher heating value for fuel gas or flare gas for each flare from company records (British thermal units per scf, Btu/scf = MMBtu/MMscf) (Equation Y-3).
(8) Volume of flare gas combusted during indexed start-up, shutdown, or malfunction event from engineering calculations (scf) (Equation Y-3).
(9) Average molecular weight of the flare gas, from the analysis results or engineering calculations for the event (kg/kg-mole) (Equation Y-3).
(10) Molar volume conversion factor (scf per kg-mole) (Equation Y-3).
(11) Average carbon content of the flare gas, from analysis results or engineering calculations for the event (kg C per kg flare gas) (Equation Y-3).
(12) Weight fraction of carbon in the flare gas prior to combustion in each flare that is contributed by methane from measurement values or engineering calculations (kg C in methane in flare gas/kg C in flare gas) (Equation Y-4 of § 98.253).
(13) Annual throughput of unit from company records for each catalytic cracking unit or fluid coking unit (barrels/year) (Equation Y-8 of § 98.253).
(14) Coke burn-off factor from engineering calculations (default for catalytic cracking units = 7.3; default for fluid coking units = 11) (kg coke per barrel of feed) (Equation Y-8).
(15) Carbon content of coke based on measurement or engineering estimate (kg C per kg coke) (Equation Y-8).
(16) Value of unit-specific CH
(17) Annual activity data (e.g., input or product rate), including the units of measure, in units of measure consistent with the emission factor, for each catalytic cracking unit, traditional fluid coking unit, catalytic reforming unit, and coke calcining unit (calculation method in § 98.253(c)(4)).
(18) Value of unit-specific N
(19) Annual activity data (e.g., input or product rate), including the units of measure, in units of measure consistent with the emission factor, for each catalytic cracking unit, traditional fluid coking unit, catalytic reforming unit, and coke calcining unit (calculation method in § 98.253(c)(5)).
(20) Carbon content of coke based on measurement or engineering estimate (default = 0.94) (kg C per kg coke) (Equation Y-11 of § 98.253).
(21) Volumetric flow rate of sour gas (including sour water stripper gas) feed sent off site for sulfur recovery in the year (scf/year) (Equation Y-12 of § 98.253).
(22) Mole fraction of carbon in the sour gas feed sent off site for sulfur recovery (kg-mole C/kg-mole gas) (Equation Y-12).
(23) Molar volume conversion factor for sour gas sent off site (scf per kg-mole) (Equation Y-12).
(24) Volumetric flow rate of sour gas (including sour water stripper gas) fed to the onsite sulfur recovery plant (scf/year) (Equation Y-12).
(25) Mole fraction of carbon in the sour gas fed to the onsite sulfur recovery plant (kg-mole C/kg-mole gas) (Equation Y-12).
(26) Molar volume conversion factor for onsite sulfur recovery plant (scf per kg-mole) (Equation Y-12).
(27) Annual mass of green coke fed to the coke calcining unit from facility records (metric tons/year) (Equation Y-13 of § 98.253).
(28) Annual mass of marketable petroleum coke produced by the coke calcining unit from facility records (metric tons/year) (Equation Y-13).
(29) Annual mass of petroleum coke dust removed from the process through the dust collection system of the coke calcining unit from facility records. For coke calcining units that recycle the collected dust, the mass of coke dust removed from the process is the mass of coke dust collected less the mass of coke dust recycled to the process (metric tons/year) (Equation Y-13).
(30) Average mass fraction carbon content of green coke from facility measurement data (metric tons C per metric ton green coke) (Equation Y-13).
(31) Average mass fraction carbon content of marketable petroleum coke produced by the coke calcining unit from facility measurement data (metric tons C per metric ton petroleum coke (Equation Y-13).
(32) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year (MMbbl/year)) (Equation Y-14 of § 98.253).
(33) Emission factor for CO
(34) Emission factor for CH
(35) Quantity of asphalt blown (million barrels/year (MMbbl/year)) (Equation Y-16a of § 98.253).
(36) Carbon emission factor from asphalt blowing from facility-specific test data (metric tons C/MMbbl asphalt blown) (Equation Y-16a).
(37) Quantity of asphalt blown for each asphalt blowing unit (million barrels per year (MMbbl/year)) (Equation Y-16b of § 98.253).
(38) Emission factor for CO
(39) Carbon emission factor from asphalt blowing from facility-specific test data for each asphalt blowing unit (metric tons C/MMbbl asphalt blown) (Equation Y-16b).
(40) Emission factor for CH
(41) Typical dry mass of coke in the delayed coking unit vessel at the end of the coking cycle (metric tons/cycle) from company records or calculated using Equation Y-18a of this subpart (Equations Y-18a, Y-18b and Y-18e in § 98.253) for each delayed coking unit.
(42) Internal height of delayed coking unit vessel (feet) (Equation Y-18a in § 98.253) for each delayed coking unit.
(43) Typical distance from the top of the delayed coking unit vessel to the top of the coke bed (i.e., coke drum outage) at the end of the coking cycle (feet) from company records or engineering estimates (Equation Y-18a in § 98.253) for each delayed coking unit.
(44) Diameter of delayed coking unit vessel (feet) (Equations Y-18a and Y-18b in § 98.253) for each delayed coking unit.
(45) Mass of water in the delayed coking unit vessel at the end of the cooling cycle prior to atmospheric venting (metric ton/cycle) (Equations Y-18b and Y-18e in § 98.253) for each delayed coking unit.
(46) Typical distance from the bottom of the coking unit vessel to the top of the water level at the end of the cooling cycle just prior to atmospheric venting (feet) from company records or engineering estimates (Equation Y-18b in § 98.253) for each delayed coking unit.
(47) Mass of steam generated and released per decoking cycle (metric tons/cycle) (Equations Y-18e and Y-18f in § 98.253) for each delayed coking unit.
(48) Average temperature of the delayed coking unit vessel when the drum is first vented to the atmosphere ( °F) (Equations Y-18c, Y-18d, and Y-18e in § 98.253) for each delayed coking unit.
(49) Temperature of the delayed coking unit vessel overhead line measured as near the coking unit vessel as practical just prior to venting the atmosphere (Equation Y-18c in § 98.253) for each delayed coking unit.
(50) Pressure of the delayed coking unit vessel just prior to opening the atmospheric vent (psig) (Equation Y-18d in § 98.253) for each delayed coking unit.
(51) Methane emission factor for delayed coking unit (kilograms CH
(52) Cumulative number of decoking cycles (or coke-cutting cycles) for all delayed coking unit vessels associated with the delayed coking unit during the year (Equation Y-18f in § 98.253) for each delayed coking unit.
(53) Average volumetric flow rate of process gas during the event from measurement data, process knowledge, or engineering estimates for each set of coke drums or vessels of the same size (scf per hour) (Equation Y-19 of § 98.253).
(54) Mole fraction of methane in process vent during the event from measurement data, process knowledge, or engineering estimates for each set of coke drums or vessels of the same size (kg-mole CH
(55) Venting time for the event for each set of coke drums or vessels of the same size (hours) (Equation Y-19).
(56) Molar volume conversion factor for each set of coke drums or vessels of the same size (scf per kg-mole) (Equation Y-19).
(57) Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year) (Equation Y-20 of § 98.253).
(58) Molar volume conversion factor (scf per kg-mole) (Equation Y-20).
(59) Methane emission factor for uncontrolled blown systems (scf CH
(60) Quantity of crude oil plus the quantity of intermediate products received from off site that are processed at the facility (MMbbl/year) (Equation Y-22 of § 98.253).
(61) Quantity of unstabilized crude oil received at the facility (MMbbl/year) (Equation Y-23 of § 98.253).
(62) Pressure differential from the previous storage pressure to atmospheric pressure (psi) (Equation Y-23).
(63) Average mole fraction of CH
(64) Molar volume conversion factor (scf per kg-mole) (Equation Y-23).
(65) Specify whether the calculated or default loading factor L specified in § 98.253(n) is entered, for each liquid loaded to each vessel (methods specified in § 98.253(n)).
(66) Saturation factor specified in § 98.253(n), for each liquid loaded to each vessel (methods specified in § 98.253(n)).
(67) True vapor pressure of liquid loaded, for each liquid loaded to each vessel (psia) (methods specified in § 98.253(n)).
(68) Molecular weight of vapors (lb per lb-mole), for each liquid loaded to each vessel (methods specified in § 98.253(n)).
(69) Temperature of bulk liquid loaded, for each liquid loaded to each vessel (°R, degrees Rankine) (methods specified in § 98.253(n)).
(70) Total loading loss (without efficiency correction), for each liquid loaded to each vessel (pounds per 1000 gallons loaded) (methods specified in § 98.253(n)).
(71) Overall emission control system reduction efficiency, including the vapor collection system efficiency and the vapor recovery or destruction efficiency (enter zero if no emission controls), for each liquid loaded to each vessel (percent) (methods specified § 98.253(n)).
(72) Vapor phase concentration of methane in liquid loaded, for each liquid loaded to each vessel (percent by volume) (methods specified in § 98.253(n)).
(73) Quantity of material loaded, for each liquid loaded to each vessel (thousand gallon per year) (methods specified in § 98.253(n)).
§ 98.258 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart Z – Phosphoric Acid Production
§ 98.260 Definition of the source category.
The phosphoric acid production source category consists of facilities with a wet-process phosphoric acid process line used to produce phosphoric acid. A wet-process phosphoric acid process line is the production unit or units identified by an individual identification number in an operating permit and/or any process unit or group of process units at a facility reacting phosphate rock from a common supply source with acid.
§ 98.261 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a phosphoric acid production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.262 GHGs to report.
(a) You must report CO
(b) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
§ 98.263 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process CO
(b) Calculate and report under this subpart the process CO
(1) Calculate the annual CO
(i) If your process measurement provides the inorganic carbon content of phosphate rock as an output, calculate and report the process CO
(ii) If your process measurement provides the CO
(2) You must determine the total emissions from the facility using Equation Z-2 of this section:
(c) If GHG emissions from a wet-process phosphoric acid process line are vented through the same stack as any combustion unit or process equipment that reports CO
§ 98.264 Monitoring and QA/QC requirements.
(a) You must obtain a monthly grab sample of phosphate rock directly from the rock being fed to the process line before it enters the mill using one of the following methods. You may conduct the representative bulk sampling using a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by the Association of Fertilizer and Phosphate Chemists (AFPC). If phosphate rock is obtained from more than one origin in a month, you must obtain a sample from each origin of rock or obtain a composite representative sample.
(b) You must determine the carbon dioxide or inorganic carbon content of each monthly grab sample of phosphate rock (consumed in the production of phosphoric acid). You may use a method published by a consensus standards organization, or you may use industry consensus standard practice methods, including but not limited to the Phosphate Mining States Methods Used and Adopted by AFPC.
(c) You must determine the mass of phosphate rock consumed each month (by origin) in each wet-process phosphoric acid process line. You can use existing plant procedures that are used for accounting purposes (such as sales records) or you can use data from existing monitoring equipment that is used to measure total mass flow of phosphorous-bearing feed under 40 CFR part 60 or part 63.
§ 98.265 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter must be used in the calculations as specified in paragraphs (a) and (b) of this section.
(a) For each missing value of the inorganic carbon content or CO
(b) For each missing value of monthly mass consumption of phosphate rock (by origin), you must use the best available estimate based on all available process data or data used for accounting purposes.
§ 98.266 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) through (f) of this section.
(a) Annual phosphoric acid production, by origin of the phosphate rock (tons).
(b) Annual phosphoric acid production capacity (tons).
(c) Annual arithmetic average percent inorganic carbon or carbon dioxide in phosphate rock from monthly records (percent by weight, expressed as a decimal fraction).
(d) Annual phosphate rock consumption from monthly measurement records by origin (tons).
(e) If you use a CEMS to measure CO
(1) The identification number of each wet-process phosphoric acid process line.
(2) The annual CO
(f) If you do not use a CEMS to measure emissions, then you must report the information in paragraphs (f)(1) through (9) of this section.
(1) Identification number of each wet-process phosphoric acid process line.
(2) Annual CO
(3) Annual phosphoric acid production capacity (tons) for each wet-process phosphoric acid process line.
(4) Method used to estimate any missing values of inorganic carbon content or carbon dioxide content of phosphate rock for each wet-process phosphoric acid process line.
(5) [Reserved]
(6) [Reserved]
(7) Number of wet-process phosphoric acid process lines.
(8) Number of times missing data procedures were used to estimate phosphate rock consumption (months), inorganic carbon contents of the phosphate rock (months), and CO
(9) Annual process CO
§ 98.267 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (d) of this section for each wet-process phosphoric acid production facility.
(a) Monthly mass of phosphate rock consumed by origin (tons).
(b) Records of all phosphate rock purchases and/or deliveries (if vertically integrated with a mine).
(c) Documentation of the procedures used to ensure the accuracy of monthly phosphate rock consumption by origin.
(d) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (d)(1) through (4) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (d)(1) through (4) of this section.
(1) Inorganic carbon content of a grab sample batch of phosphate rock by origin obtained during month by wet-process phosphoric acid process line, from the carbon analysis results (percent by weight, expressed as a decimal fraction) (Equation Z-1a of § 98.263).
(2) Mass of phosphate rock by origin consumed in month by wet-process phosphoric acid process line (tons) (Equation Z-1a).
(3) Carbon dioxide content of a grab sample batch of phosphate rock by origin obtained during month by wet-process phosphoric acid process line (percent by weight, expressed as a decimal fraction) (Equation Z-1b of § 98.263).
(4) Mass of phosphate rock by origin consumed in month by wet-process phosphoric acid process line (tons) (Equation Z-1b).
§ 98.268 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table Z-1 to Subpart Z of Part 98 – Default Chemical Composition of Phosphate Rock by Origin
Origin | Total carbon (percent by weight) |
---|---|
Central Florida | 1.6 |
North Florida | 1.76 |
North Carolina (Calcined) | 0.76 |
Idaho (Calcined) | 0.60 |
Morocco | 1.56 |
Subpart AA – Pulp and Paper Manufacturing
§ 98.270 Definition of source category.
(a) The pulp and paper manufacturing source category consists of facilities that produce market pulp (i.e., stand-alone pulp facilities), manufacture pulp and paper (i.e., integrated facilities), produce paper products from purchased pulp, produce secondary fiber from recycled paper, convert paper into paperboard products (e.g., containers), or operate coating and laminating processes.
(b) The emission units for which GHG emissions must be reported are listed in paragraphs (b)(1) through (b)(5) of this section:
(1) Chemical recovery furnaces at kraft and soda mills (including recovery furnaces that burn spent pulping liquor produced by both the kraft and semichemical process).
(2) Chemical recovery combustion units at sulfite facilities.
(3) Chemical recovery combustion units at stand-alone semichemical facilities.
(4) Pulp mill lime kilns at kraft and soda facilities.
(5) Systems for adding makeup chemicals (CaCO
§ 98.271 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a pulp and paper manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.272 GHGs to report.
You must report the emissions listed in paragraphs (a) through (f) of this section:
(a) CO
(b) CO
(c) CO
(d) CO
(e) CO
(f) CO
§ 98.273 Calculating GHG emissions.
(a) For each chemical recovery furnace located at a kraft or soda facility, you must determine CO
(1) Calculate fossil fuel-based CO
(2) Calculate fossil fuel-based CH
(3) Calculate biogenic CO
(b) For each chemical recovery combustion unit located at a sulfite or stand-alone semichemical facility, you must determine CO
(1) Calculate fossil CO
(2) Calculate CH
(3) Calculate biogenic CO
(4) Calculate CH
(c) For each pulp mill lime kiln located at a kraft or soda facility, you must determine CO
(1) Calculate CO
(2) Calculate CH
(3) Biogenic CO
(d) For makeup chemical use, you must calculate CO
§ 98.274 Monitoring and QA/QC requirements.
(a) Each facility subject to this subpart must quality assure the GHG emissions data according to the applicable requirements in § 98.34. All QA/QC data must be available for inspection upon request.
(b) Fuel properties needed to perform the calculations in Equations AA-1 and AA-2 of this subpart must be determined according to paragraphs (b)(1) through (b)(3) of this section.
(1) High heat values of black liquor must be determined no less than annually using T684 om-06 Gross Heating Value of Black Liquor, TAPPI (incorporated by reference, see § 98.7). If measurements are performed more frequently than annually, then the high heat value used in Equation AA-1 of this subpart must be based on the average of the representative measurements made during the year.
(2) The annual mass of spent liquor solids must be determined using either of the methods specified in paragraph (b)(2)(i) or (b)(2)(ii) of this section.
(i) Measure the mass of spent liquor solids annually (or more frequently) using T-650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference in § 98.7). If measurements are performed more frequently than annually, then the mass of spent liquor solids used in Equation AA-1 of this subpart must be based on the average of the representative measurements made during the year.
(ii) Determine the annual mass of spent liquor solids based on records of measurements made with an online measurement system that determines the mass of spent liquor solids fired in a chemical recovery furnace or chemical recovery combustion unit.
(3) Carbon analyses for spent pulping liquor must be determined no less than annually using ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7). If measurements using ASTM D5373-08 are performed more frequently than annually, then the spent pulping liquor carbon content used in Equation AA-2 of this subpart must be based on the average of the representative measurements made during the year.
(c) Each facility must keep records that include a detailed explanation of how company records of measurements are used to estimate GHG emissions. The owner or operator must also document the procedures used to ensure the accuracy of the measurements of fuel, spent liquor solids, and makeup chemical usage, including, but not limited to calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices must be recorded and the technical basis for these estimates must be provided. The procedures used to convert spent pulping liquor flow rates to units of mass (i.e., spent liquor solids firing rates) also must be documented.
(d) Records must be made available upon request for verification of the calculations and measurements.
§ 98.275 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements of paragraphs (a) through (c) of this section:
(a) There are no missing data procedures for measurements of heat content and carbon content of spent pulping liquor. A re-test must be performed if the data from any annual measurements are determined to be invalid.
(b) For missing measurements of the mass of spent liquor solids or spent pulping liquor flow rates, use the lesser value of either the maximum mass or fuel flow rate for the combustion unit, or the maximum mass or flow rate that the fuel meter can measure. Alternatively, records of the daily spent liquor solids firing rate obtained to comply with § 63.866(c)(1) of this chapter may be used, adjusting for the duration of the missing measurements, as appropriate.
(c) For the use of makeup chemicals (carbonates), the substitute data value shall be the best available estimate of makeup chemical consumption, based on available data (e.g., past accounting records, production rates). The owner or operator shall document and keep records of the procedures used for all such estimates.
§ 98.276 Data reporting requirements.
In addition to the information required by § 98.3(c) and the applicable information required by § 98.36, each annual report must contain the information in paragraphs (a) through (l) of this section as applicable:
(a) Annual emissions of CO
(b) [Reserved]
(c) Basis for determining the annual mass of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see § 98.7) or an online measurement system).
(d) [Reserved]
(e) The default emission factor for CO
(f)-(i) [Reserved]
(j) Annual steam purchases (pounds of steam per year).
(k) Total annual production of unbleached virgin chemical pulp produced onsite during the reporting year in air-dried metric tons per year. This total annual production value is the sum of all kraft, semichemical, soda, and sulfite pulp produced onsite, prior to bleaching, through all virgin pulping lines. Do not include mechanical pulp or secondary fiber repulped for paper production in the virgin pulp production total.
(l) For each pulp mill lime kiln, report the information specified in paragraphs (l)(1) and (2) of this section.
(1) The quantity of calcium oxide (CaO) produced (metric tons).
(2) The percent of annual heat input, individually for each fossil fuel type.
§ 98.277 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the records in paragraphs (a) through (g) of this section.
(a) GHG emission estimates (including separate estimates of biogenic CO
(b) Annual analyses of spent pulping liquor HHV for each chemical recovery furnace at kraft and soda facilities.
(c) Annual analyses of spent pulping liquor carbon content for each chemical recovery combustion unit at a sulfite or semichemical pulp facility.
(d) Annual quantity of spent liquor solids combusted in each chemical recovery furnace and chemical recovery combustion unit, and the basis for detemining the annual quantity of the spent liquor solids combusted (whether based on T650 om-05 Solids Content of Black Liquor, TAPPI (incorporated by reference, see § 98.7) or an online measurement system). If an online measurement system is used, you must retain records of the calculations used to determine the annual quantity of spent liquor solids combusted from the continuous measurements.
(e) Annual steam purchases.
(f) Annual quantities of makeup chemicals used.
(g) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (g)(1) through (27) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (g)(1) through (27) of this section.
(1) Mass of the solid fuel combusted (tons/year) (Equation C-1 of § 98.33).
(2) Volume of the liquid fuel combusted (gallons/year) (Equation C-1).
(3) Volume of the gaseous fuel combusted (scf/year) (Equation C-1).
(4) Annual natural gas usage (therms/year) (Equation C-1a of § 98.33).
(5) Annual natural gas usage (mmBtu/year) (Equation C-1b of § 98.33).
(6) Mass of the solid fuel combusted (tons/year) (Equation C-2a of § 98.33).
(7) Volume of the liquid fuel combusted (gallons/year) (Equation C-2a).
(8) Volume of the gaseous fuel combusted (scf/year) (Equation C-2a).
(9) Annual mass of the solid fuel combusted (short tons/year) (Equation C-3 of § 98.33).
(10) Annual average carbon content of the solid fuel (percent by weight, expressed as a decimal fraction) (Equation C-3).
(11) Annual volume of the liquid fuel combusted (gallons/year) (Equation C-4 of § 98.33).
(12) Annual average carbon content of the liquid fuel (kg C per gallon of fuel) (Equation C-4).
(13) Annual volume of the gaseous fuel combusted (scf/year) (Equation C-5 of § 98.33).
(14) Annual average carbon content of the gaseous fuel (kg C per kg of fuel) (Equation C-5).
(15) Annual average molecular weight of the gaseous fuel (kg/kg-mole) (Equation C-5).
(16) Molar volume conversion factor at standard conditions, as defined in § 98.6 (scf per kg-mole) (Equation C-5).
(17) Identify if you will use the default high heat value from Table C-1 of subpart C of this part, or actual HHV data (Equation C-8 of § 98.33).
(18) High heat value of the fuel (mmBTU/tons) (Equation C-8).
(19) High heat value of the fuel (mmBTU/gallons) (Equation C-8).
(20) High heat value of the fuel (mmBTU/scf) (Equation C-8).
(21) Mass of spent liquor solids combusted from each chemical recovery furnace located at a kraft or soda facility, in short tons in year, determined according to § 98.274(b) (tons/year) (Equation AA-1 of § 98.273).
(22) Annual high heat value of the spent liquor solids from each chemical recovery furnace located at a kraft or soda facility determined according to § 98.274(b) (mmBtu per kilogram) (Equation AA-1).
(23) Annual high heat value of the spent liquor solids from each chemical recovery combustion unit located at a sulfite or stand-alone semichemical facility, determined according to § 98.274(b) (mmBtu per kilogram) (Equation AA-1).
(24) Mass of the spent liquor solids combusted in short tons per year determined according to § 98.274(b) (tons/year) (Equation AA-2 of § 98.273).
(25) Annual carbon content of the spent liquor solids, determined according to § 98.274(b) (percent by weight, expressed as a decimal fraction (e.g., 95% = 0.95)) (Equation AA-2).
(26) Make-up quantity of CaCO
(27) Make-up quantity of Na
§ 98.278 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table AA-1 to Subpart AA of Part 98 – Kraft Pulping Liquor Emissions Factors for Biomass-Based CO2 , CH4 , and N2 O
Wood furnish | Biomass-based emissions factors (kg/mmBtu HHV) | ||
---|---|---|---|
a CO | CH | N | |
North American Softwood | 94.4 | 0.0019 | 0.00042 |
North American Hardwood | 93.7 | 0.0019 | 0.00042 |
Bagasse | 95.5 | 0.0019 | 0.00042 |
Bamboo | 93.7 | 0.0019 | 0.00042 |
Straw | 95.1 | 0.0019 | 0.00042 |
a Includes emissions from both the recovery furnace and pulp mill lime kiln.
Table AA-2 to Subpart AA of Part 98 – Kraft Lime Kiln and Calciner Emissions Factors for CH4 and N2 O
Fuel | Fossil fuel-based emissions factors (kg/mmBtu HHV) | |||
---|---|---|---|---|
Kraft rotary lime kilns | Kraft calciners a | |||
CH | N | CH | N | |
Residual Oil (any type) | 0.0027 | 0 | 0.0027 | 0.0003 |
Distillate Oil (any type) | 0.0027 | 0 | 0.0027 | 0.0004 |
Natural Gas | 0.0027 | 0 | 0.0027 | 0.0001 |
Biogas | 0.0027 | 0 | 0.0027 | 0.0001 |
Petroleum coke | 0.0027 | 0 | b NA | b NA |
Other Fuels | See Table C-2 | 0 | See Table C-2 | See Table C-2 |
a Includes, for example, fluidized bed calciners at kraft mills.
b Emission factors for kraft calciners are not available.
Subpart BB – Silicon Carbide Production
§ 98.280 Definition of the source category.
Silicon carbide production includes any process that produces silicon carbide for abrasive purposes.
§ 98.281 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a silicon carbide production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.282 GHGs to report.
You must report:
(a) CO
(b) CO
§ 98.283 Calculating GHG emissions.
You must calculate and report the combined annual process CO
(a) Calculate and report under this subpart the combined annual process CO
(b) Calculate and report under this subpart the combined annual process CO
(1) Use Equation BB-1 of this section to calculate the facility-specific emissions factor for determining CO
(2) Calculate annual CO
(c) If GHG emissions from a silicon carbide production furnace or process unit are vented through the same stack as any combustion unit or process equipment that reports CO
§ 98.284 Monitoring and QA/QC requirements.
(a) You must measure your consumption of petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records.
(b) You must document the procedures used to ensure the accuracy of monthly petroleum coke consumption measurements.
(c) For CO
(d) For quality assurance and quality control of the supplier data, you must conduct an annual measurement of the carbon content of the petroleum coke using ASTM D3176-89 and ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).
§ 98.285 Procedures for estimating missing data.
For the petroleum coke input procedure in § 98.283(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.
(a) For each missing value of the monthly carbon content of petroleum coke, the substitute data value shall be the arithmetic average of the quality-assured values of carbon contents immediately preceding and immediately following the missing data incident. If no quality-assured data on carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period.
(b) For each missing value of the monthly petroleum coke consumption, the substitute data value shall be the best available estimate of the petroleum coke consumption based on all available process data or information used for accounting purposes (such as purchase records).
§ 98.286 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable for each silicon carbide production facility.
(a) If a CEMS is used to measure process CO
(1) Annual consumption of petroleum coke (tons).
(2) Annual production of silicon carbide (tons).
(3) Annual production capacity of silicon carbide (tons).
(b) If a CEMS is not used to measure process CO
(1) [Reserved]
(2) Annual production of silicon carbide (tons).
(3) Annual production capacity of silicon carbide (tons).
(4) [Reserved]
(5) Whether carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard method.
(6) [Reserved]
(7) Sampling analysis results for carbon content of consumed petroleum coke as determined for QA/QC of supplier data under § 98.284(d) (percent by weight expressed as a decimal fraction).
(8) Number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months) and petroleum coke consumption (number of months).
§ 98.287 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each silicon carbide production facility.
(a) If a CEMS is used to measure CO
(1) Records of all petroleum coke purchases.
(2) Annual operating hours.
(b) If a CEMS is not used to measure emissions, you must retain records for the information listed in this paragraph (b):
(1) Records of all analyses and calculations conducted for reported data listed in § 98.286(b).
(2) Records of all petroleum coke purchases.
(3) Annual operating hours.
(c) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) and (2) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) and (2) of this section.
(1) Carbon content factor for petroleum coke consumed in month from the supplier or as measured by the applicable method (percent by weight expressed as a decimal fraction) (Equation BB-1 of § 98.283).
(2) Petroleum coke consumption in month (tons) (Equation BB-2 of § 98.283).
§ 98.288 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart CC – Soda Ash Manufacturing
§ 98.290 Definition of the source category.
(a) A soda ash manufacturing facility is any facility with a manufacturing line that produces soda ash by one of the methods in paragraphs (a)(1) through (3) of this section:
(1) Calcining trona.
(2) Calcining sodium sesquicarbonate.
(3) Using a liquid alkaline feedstock process that directly produces CO
(b) In the context of the soda ash manufacturing sector, “calcining” means the thermal/chemical conversion of the bicarbonate fraction of the feedstock to sodium carbonate.
§ 98.291 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a soda ash manufacturing process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.292 GHGs to report.
You must report:
(a) CO
(b) CO
(c) CH
(d) CO
§ 98.293 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) For each soda ash manufacturing line that meets the conditions specified in § 98.33(b)(4)(ii) or (b)(4)(iii), you must calculate and report under this subpart the combined process and combustion CO
(b) For each soda ash manufacturing line that is not subject to the requirements in paragraph (a) of this section, calculate and report the process CO
(1) Calculate and report under this subpart the combined process and combustion CO
(2) Use either Equation CC-1 or Equation CC-2 of this section to calculate annual CO
(3) Site-specific emission factor method. Use Equations CC-3, CC-4, and CC-5 of this section to determine annual CO
(i) During the performance test, you must measure the process vent flow from each process vent during the test and calculate the average rate for the test period in metric tons per hour.
(ii) Using the test data, you must calculate the hourly CO
(iii) Using the test data, you must calculate a CO
(iv) You must calculate annual CO
(4) Calculate and report under subpart C of this part (General Stationary Fuel Combustion Sources) the combustion CO
§ 98.294 Monitoring and QA/QC requirements.
Section 98.293 provides three different procedures for emission calculations. The appropriate paragraphs (a) through (c) of this section should be used for the procedure chosen.
(a) If you determine your emissions using § 98.293(b)(2) (Equation CC-1 of this subpart) you must:
(1) Determine the monthly inorganic carbon content of the trona from a weekly composite analysis for each soda ash manufacturing line, using a modified version of ASTM E359-00 (Reapproved 2005)e1, Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see § 98.7). ASTM E359-00(Reapproved 2005) e1 is designed to measure the total alkalinity in soda ash not in trona. The modified method referred to above adjusts the regular ASTM method to express the results in terms of trona. Although ASTM E359-00 (Reapproved 2005) e1 uses manual titration, suitable autotitrators may also be used for this determination.
(2) Measure the mass of trona input to each soda ash manufacturing line on a monthly basis using belt scales or methods used for accounting purposes.
(3) Document the procedures used to ensure the accuracy of the monthly measurements of trona consumed.
(b) If you calculate CO
(1) Determine the inorganic carbon content of the soda ash (i.e., soda ash purity) using ASTM E359-00 (Reapproved 2005) e1 Standard Test Methods for Analysis of Soda Ash (Sodium Carbonate) (incorporated by reference, see § 98.7). Although ASTM E359-00 (Reapproved 2005) e1 uses manual titration, suitable autotitrators may also be used for this determination.
(2) Measure the mass of soda ash produced by each soda ash manufacturing line on a monthly basis using belt scales, by weighing the soda ash at the truck or rail loadout points of your facility, or methods used for accounting purposes.
(3) Document the procedures used to ensure the accuracy of the monthly measurements of soda ash produced.
(c) If you calculate CO
(1) Conduct an annual performance test that is based on representative performance (i.e., performance based on normal operating conditions) of the affected process.
(2) Sample the stack gas and conduct three emissions test runs of 1 hour each.
(3) Conduct the stack test using EPA Method 3A at 40 CFR part 60, appendix A-2 to measure the CO
(i) Analysis of samples, determination of emissions, and raw data.
(ii) All information and data used to derive the emissions factor(s).
(iii) You must determine the average process vent flow rate from the mine water stripper/evaporater during each test and document how it was determined.
(4) You must also determine the annual vent flow rate from the mine water stripper/evaporater from monthly information using the same plant instruments or procedures used for accounting purposes (i.e., volumetric flow meter).
§ 98.295 Procedures for estimating missing data.
For the emission calculation methodologies in § 98.293(b)(2) and (b)(3), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., inorganic carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) through (d) of this section. You must document and keep records of the procedures used for all such missing value estimates.
(a) For each missing value of the weekly composite of inorganic carbon content of either soda ash or trona, the substitute data value shall be the arithmetic average of the quality-assured values of inorganic carbon contents from the week immediately preceding and the week immediately following the missing data incident. If no quality-assured data on inorganic carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period.
(b) For each missing value of either the monthly soda ash production or the trona consumption, the substitute data value shall be the best available estimate(s) of the parameter(s), based on all available process data or data used for accounting purposes.
(c) For each missing value collected during the performance test (hourly CO
(d) For each missing value of the monthly process vent flow rate from mine water stripper/evaporator, the subsititute data value shall be the best available estimate(s) of the parameter(s), based on all available process data or the lesser of the maximum capacity of the system or the maximum rate the meter can measure.
§ 98.296 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as appropriate for each soda ash manufacturing facility.
(a) If a CEMS is used to measure CO
(1) Annual consumption of trona or liquid alkaline feedstock for each manufacturing line (tons).
(2) Annual production of soda ash for each manufacturing line (tons).
(3) Annual production capacity of soda ash for each manufacturing line (tons).
(4) Identification number of each manufacturing line.
(b) If a CEMS is not used to measure CO
(1) Identification number of each manufacturing line.
(2) Annual process CO
(3) Annual production of soda ash for each manufacturing line (tons).
(4) Annual production capacity of soda ash for each manufacturing line (tons).
(5)-(7) [Reserved]
(8) Whether CO
(9) Number of manufacturing lines located used to produce soda ash.
(10) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method (§ 98.293(b)(3)) to estimate emissions then you must report the following relevant information for each manufacturing line or stack:
(i) Stack gas volumetric flow rate during performance test (dscfm).
(ii) Hourly CO
(iii) CO
(iv) CO
(v) Average process vent flow from mine water stripper/evaporator during performance test (pounds/hour).
(vi) Annual process vent flow rate from mine water stripper/evaporator (thousand pounds/hour).
(11) Number of times missing data procedures were used and for which parameter as specified in this paragraph (b)(11):
(i) Trona or soda ash (number of months).
(ii) Inorganic carbon contents of trona or soda ash (weeks).
(iii) Process vent flow rate from mine water stripper/evaporator (number of months).
§ 98.297 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each soda ash manufacturing line.
(a) If a CEMS is used to measure CO
(1) Monthly production of soda ash (tons)
(2) Monthly consumption of trona or liquid alkaline feedstock (tons)
(3) Annual operating hours (hours).
(b) If a CEMS is not used to measure emissions, then you must retain records for the information listed in this paragraph (b):
(1) Records of all analyses and calculations conducted for determining all reported data as listed in § 98.296(b).
(2) If using Equation CC-1 or CC-2 of this subpart, weekly inorganic carbon content factor of trona or soda ash, depending on method chosen, as measured by the applicable method in § 98.294(b) (percent by weight expressed as a decimal fraction).
(3) Annual operating hours for each manufacturing line used to produce soda ash (hours).
(4) You must document the procedures used to ensure the accuracy of the monthly trona consumption or soda ash production measurements including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(5) If you produce soda ash using the liquid alkaline feedstock process and use the site-specific emission factor method to estimate emissions (§ 98.293(b)(3)) then you must also retain the following relevant information:
(i) Records of performance test results.
(ii) You must document the procedures used to ensure the accuracy of the annual average vent flow measurements including, but not limited to, calibration of flow rate meters and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(c) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) through (4) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (4) of this section
(1) Inorganic carbon content in trona input, from the carbon analysis results for month (percent by weight, expressed as a decimal fraction) (Equation CC-1 of § 98.293).
(2) Mass of trona input in month (tons) (Equation CC-1).
(3) Inorganic carbon content in soda ash output, from the carbon analysis results for month (percent by weight, expressed as a decimal fraction) (Equation CC-2 of § 98.293).
(4) Mass of soda ash output in month (tons) (Equation CC-2).
§ 98.298 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart DD – Electrical Transmission and Distribution Equipment Use
§ 98.300 Definition of the source category.
(a) The electrical transmission and distribution equipment use source category consists of all electric transmission and distribution equipment and servicing inventory insulated with or containing sulfur hexafluoride (SF
(1) Gas-insulated substations.
(2) Circuit breakers.
(3) Switchgear, including closed-pressure and hermetically sealed-pressure switchgear and gas-insulated lines containing SF
(4) Gas containers such as pressurized cylinders.
(5) Gas carts.
(6) Electric power transformers.
(7) Other containers of SF
§ 98.301 Reporting threshold.
(a) You must report GHG emissions from an electric power system if the total nameplate capacity of SF
(b) A facility other than an electric power system that is subject to this part because of emissions from any other source category listed in Table A-3 or A-4 in subpart A of this part is not required to report emissions under subpart DD of this part unless the total nameplate capacity of SF
§ 98.302 GHGs to report.
You must report total SF
§ 98.303 Calculating GHG emissions.
(a) Calculate the annual SF
(b) Use Equation DD-1 of this section to estimate emissions of PFCs from power transformers, substituting the relevant PFC(s) for SF
§ 98.304 Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, you may follow the provisions of § 98.3(d)(1) through (d)(2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference in § 98.3(d)(1) through (d)(2) to 2010 means 2011, to March 31 means June 30, and to April 1 means July 1. Any reference to the effective date in § 98.3(d)(1) through (d)(2) means February 28, 2011.
(b) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting:
(1) Review inputs to Equation DD-1 of this section to ensure inputs and outputs to the company’s system are included.
(2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the Decrease in SF
(3) Ensure that beginning-of-year inventory matches end-of-year inventory from the previous year.
(4) Ensure that in addition to SF
(c) Ensure the following QA/QC methods are employed throughout the year:
(1) Ensure that cylinders returned to the gas supplier are consistently weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer’s specifications. Either measure residual gas (the amount of gas remaining in returned cylinders) or have the gas supplier measure it. If the gas supplier weighs the residual gas, obtain from the gas supplier a detailed monthly accounting, within ±2 pounds, of residual gas amounts in the cylinders returned to the gas supplier.
(2) Ensure that cylinders weighed for the beginning and end of year inventory measurements are weighed on a scale that is certified to be accurate and precise to within 2 pounds of true weight and is periodically recalibrated per the manufacturer’s specifications. All scales used to measure quantities that are to be reported under § 98.306 must be calibrated using calibration procedures specified by the scale manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer.
(3) Ensure all substations have provided information to the manager compiling the emissions report (if it is not already handled through an electronic inventory system).
(d) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
§ 98.305 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from equipment with a similar nameplate capacity for SF
§ 98.306 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each electric power system, by chemical:
(a) Nameplate capacity of equipment (pounds) containing SF
(1) Existing at the beginning of the year (excluding hermetically sealed-pressure switchgear).
(2) New hermetically sealed-pressure switchgear during the year.
(3) New equipment other than hermetically sealed-pressure switchgear during the year.
(4) Retired hermetically sealed-pressure switchgear during the year.
(5) Retired equipment other than hermetically sealed-pressure switchgear during the year.
(b) Transmission miles (length of lines carrying voltages above 35 kilovolts).
(c) Distribution miles (length of lines carrying voltages at or below 35 kilovolts).
(d) Pounds of SF
(e) Pounds of SF6 and PFC stored in containers, but not in energized equipment, at the end of the year.
(f) Pounds of SF
(g) Pounds of SF
(h) Pounds of SF
(i) Pounds of SF
(j) Pounds of SF
(k) Pounds of SF
(l) Pounds of SF
(m) State(s) or territory in which the facility lies.
(n) The number of SF
(1) New hermetically sealed-pressure switchgear during the year.
(2) New equipment other than hermetically sealed-pressure switchgear during the year.
(3) Retired hermetically sealed-pressure switchgear during the year.
(4) Retired equipment other than hermetically sealed-pressure switchgear during the year.
§ 98.307 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain records of the information reported and listed in § 98.306.
§ 98.308 Definitions.
Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Facility, with respect to an electric power system, means the electric power system as defined in this paragraph. An electric power system is comprised of all electric transmission and distribution equipment insulated with or containing SF
Electric power transmission or distribution entity means any entity that transmits, distributes, or supplies electricity to a consumer or other user, including any company, electric cooperative, public electric supply corporation, a similar Federal department (including the Bureau of Reclamation or the Corps of Engineers), a municipally owned electric department offering service to the public, an electric public utility district, or a jointly owned electric supply project.
Operator, for the purposes of this subpart, means any person who operates or supervises a facility, excluding a person whose sole responsibility is to ensure reliability, balance load or otherwise address electricity flow.
Subpart EE – Titanium Dioxide Production
§ 98.310 Definition of the source category.
The titanium dioxide production source category consists of facilities that use the chloride process to produce titanium dioxide.
§ 98.311 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a titanium dioxide production process and the facility meets the requirements of either § 98.2(a)(1) or (a)(2).
§ 98.312 GHGs to report.
(a) You must report CO
(b) You must report CO
§ 98.313 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process CO
(b) Calculate and report under this subpart the annual process CO
(1) You must calculate the annual CO
(2) You must calculate the annual CO
(3) If facility generates carbon-containing waste, you must calculate the total annual quantity of carbon-containing waste produced from all process lines using Equation EE-3 of this section and its carbon contents according to § 98.314(e) and (f):
(c) If GHG emissions from a chloride process line are vented through the same stack as any combustion unit or process equipment that reports CO
§ 98.314 Monitoring and QA/QC requirements.
(a) You must measure your consumption of calcined petroleum coke using plant instruments used for accounting purposes including direct measurement weighing the petroleum coke fed into your process (by belt scales or a similar device) or through the use of purchase records.
(b) You must document the procedures used to ensure the accuracy of monthly calcined petroleum coke consumption measurements.
(c) You must determine the carbon content of the calcined petroleum coke each month based on reports from the supplier. Alternatively, facilities can measure monthly carbon contents of the petroleum coke using ASTM D3176-89 (Reapproved 2002) Standard Practice for Ultimate Analysis of Coal and Coke (incorporated by reference, see § 98.7) and ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7).
(d) For quality assurance and quality control of the supplier data, you must conduct an annual measurement of the carbon content from a representative sample of the petroleum coke consumed using ASTM D3176-89 and ASTM D5373-08.
(e) You must determine the quantity of carbon-containing waste generated from each titanium dioxide production line on a monthly basis using plant instruments used for accounting purposes including direct measurement weighing the carbon-containing waste not used during the process (by belt scales or a similar device) or through the use of sales records.
(f) You must determine the carbon contents of the carbon-containing waste from each titanium production line on an annual basis by collecting and analyzing a representative sample of the material using ASTM D3176-89 and ASTM D5373-08.
§ 98.315 Procedures for estimating missing data.
For the petroleum coke input procedure in § 98.313(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., carbon content values, etc.). Therefore, whenever the monitoring and quality assurance procedures in § 98.315 cannot be followed, a substitute data value for the missing parameter shall be used in the calculations as specified in the paragraphs (a) through (c) of this section. You must document and keep records of the procedures used for all such estimates.
(a) For each missing value of the monthly carbon content of calcined petroleum coke the substitute data value shall be the arithmetic average of the quality-assured values of carbon contents for the month immediately preceding and the month immediately following the missing data incident. If no quality-assured data on carbon contents are available prior to the missing data incident, the substitute data value shall be the first quality-assured value for carbon contents obtained after the missing data period.
(b) For each missing value of the monthly calcined petroleum coke consumption and/or carbon-containing waste, the substitute data value shall be the best available estimate of the monthly petroleum coke consumption based on all available process data or information used for accounting purposes (such as purchase records).
(c) For each missing value of the carbon content of carbon-containing waste, you must conduct a new analysis following the procedures in § 98.314(f).
§ 98.316 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable for each titanium dioxide production line.
(a) If a CEMS is used to measure CO
(1) Identification number of each process line.
(2) Annual consumption of calcined petroleum coke (tons).
(3) Annual production of titanium dioxide (tons).
(4) Annual production capacity of titanium dioxide (tons).
(5) Annual production of carbon-containing waste (tons), if applicable.
(b) If a CEMS is not used to measure CO
(1) Identification number of each process line.
(2) Annual CO
(3) Annual consumption of calcined petroleum coke for each process line (tons).
(4) Annual production of titanium dioxide for each process line (tons).
(5) Annual production capacity of titanium dioxide for each process line (tons).
(6) [Reserved]
(7) Annual production of carbon-containing waste for each process line (tons), if applicable.
(8) Monthly production of titanium dioxide for each process line (tons).
(9) [Reserved]
(10) Whether monthly carbon content of the petroleum coke is based on reports from the supplier or through self measurement using applicable ASTM standard methods.
(11) Carbon content for carbon-containing waste for each process line (percent by weight expressed as a decimal fraction).
(12) If carbon content of petroleum coke is based on self measurement, the ASTM standard methods used.
(13) Sampling analysis results of carbon content of petroleum coke as determined for QA/QC of supplier data under § 98.314(d) (percent by weight expressed as a decimal fraction).
(14) Number of separate chloride process lines located at the facility.
(15) The number of times in the reporting year that missing data procedures were followed to measure the carbon contents of petroleum coke (number of months); petroleum coke consumption (number of months); carbon-containing waste generated (number of months); and carbon contents of the carbon-containing waste (number of times during year).
§ 98.317 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each titanium dioxide production facility.
(a) If a CEMS is used to measure CO
(1) Records of all calcined petroleum coke purchases.
(2) Annual operating hours for each titanium dioxide process line.
(b) If a CEMS is not used to measure CO
(1) Records of all calcined petroleum coke purchases (tons).
(2) Records of all analyses and calculations conducted for all reported data as listed in § 98.316(b).
(3) Sampling analysis results for carbon content of consumed calcined petroleum coke (percent by weight expressed as a decimal fraction).
(4) Sampling analysis results for the carbon content of carbon containing waste (percent by weight expressed as a decimal fraction), if applicable.
(5) Monthly production of carbon-containing waste (tons).
(6) You must document the procedures used to ensure the accuracy of the monthly petroleum coke consumption and quantity of carbon-containing waste measurement including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(7) Annual operating hours for each titanium dioxide process line (hours).
(c) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) and (2) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) and (2) of this section.
(1) Carbon content factor for petroleum coke consumed in month from the supplier or as measured by the applicable method incorporated by reference in § 98.7 according to § 98.314(c) (percent by weight, expressed as a decimal fraction) (Equation EE-2 of § 98.313).
(2) Calcined petroleum coke consumption for process line in month (tons) (Equation EE-2).
§ 98.318 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart FF – Underground Coal Mines
§ 98.320 Definition of the source category.
(a) This source category consists of active underground coal mines, and any underground mines under development that have operational pre-mining degasification systems. An underground coal mine is a mine at which coal is produced by tunneling into the earth to the coalbed, which is then mined with underground mining equipment such as cutting machines and continuous, longwall, and shortwall mining machines, and transported to the surface. Underground coal mines are categorized as active if any one of the following five conditions apply:
(1) Mine development is underway.
(2) Coal has been produced within the last 90 days.
(3) Mine personnel are present in the mine workings.
(4) Mine ventilation fans are operative.
(5) The mine is designated as an ”intermittent” mine by the Mine Safety and Health Administration (MSHA).
(b) This source category includes the following:
(1) Each ventilation system shaft or vent hole, including both those points where mine ventilation air is emitted and those where it is sold, used onsite, or otherwise destroyed (including by ventilation air methane (VAM) oxidizers).
(2) Each degasification system well or gob gas vent hole, including degasification systems deployed before, during, or after mining operations are conducted in a mine area. This includes both those wells and vent holes where coal bed gas is emitted, and those where the gas is sold, used onsite, or otherwise destroyed (including by flaring).
(c) This source category does not include abandoned or closed mines, surface coal mines, or post-coal mining activities (e.g., storage or transportation of coal).
§ 98.321 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an active underground coal mine and the facility meets the requirements of § 98.2(a)(1).
§ 98.322 GHGs to report.
(a) You must report CH
(b) You must report CH
(c) You must report net CH
(d) You must report under this subpart the CO
(e) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the CO
(f) An underground coal mine that is subject to this part because emissions from source categories described in Tables A-3, A-4 or A-5 of subpart A of this part, or from stationary combustion (subpart C of this part), is not required to report emissions under this subpart unless the coal mine liberates 36,500,000 actual cubic feet (acf) or more of methane per year from its ventilation system.
§ 98.323 Calculating GHG emissions.
(a) For each ventilation shaft, vent hole, or centralized point into which CH
(1) The quarterly periods are:
(i) January 1-March 31.
(ii) April 1-June 30.
(iii) July 1-September 30.
(iv) October 1-December 31.
(2) Values of V, C, T, P, and, if applicable, (f
(3) If a facility has more than one monitoring point, the facility must calculate total CH
(b) For each monitoring point in the degasification system (this could be at each degasification well and/or vent hole, or at more centralized points into which CH
(1) Values for V, C, T, P, and, if applicable, (f
(2) Quarterly total CH
(c) If gas from a degasification system or ventilation system is sold, used onsite, or otherwise destroyed (including by flaring or VAM oxidation), you must calculate the quarterly CH
(1) Calculate total CH
(2) [Reserved]
(d) You must calculate the quarterly measured net CH
(e) For the methane collected from degasification and/or ventilation systems that is destroyed on site and is not a fuel input for energy generation or use (those emissions are monitored and reported under Subpart C of this part), you must estimate the CO
§ 98.324 Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the request must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2011. The use of best available monitoring methods will not be approved beyond December 31, 2011.
(b) For CH
(1) Collect quarterly or more frequent grab samples (with no fewer than 6 weeks between measurements) for methane concentration and make quarterly measurements of flow rate, temperature, pressure, and, if applicable, moisture content. The sampling and measurements must be made at the same locations as Mine Safety and Health Administration (MSHA) inspection samples are taken, and should be taken when the mine is operating under normal conditions. You must follow MSHA sampling procedures as set forth in the MSHA Handbook entitled, Coal Mine Safety and Health General Inspection Procedures Handbook, Handbook Number: PH16-V-1 (incorporated by reference, see § 98.7). You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.
(2) Obtain results of the quarterly (or more frequent) testing performed by MSHA for the methane flowrate. At the same location and within seven days of the MSHA sampling, make measurements of temperature and pressure using the same procedures specified in paragraph (b)(1) of this section. The annual average barometric pressure from the nearest National Oceanic and Atmospheric Administration (NOAA) weather service station may be used as a default for pressure. If the MSHA data for methane flow is provided in the units of actual cubic feet of methane per day, the methane flow data is inserted into Equation FF-1 of this section in place of the value for V and the variables MCF, C/100%, and 1440 are removed from the equation.
(3) Monitor emissions through the use of one or more continuous emission monitoring systems (CEMS). If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems.
(c) For CH
(1) Monitor emissions through the use of one or more continuous emissions monitoring systems (CEMS). If operators use CEMS as the basis for emissions reporting, they must provide documentation on the process for using data obtained from their CEMS to estimate emissions from their mine ventilation systems.
(2) Collect weekly (once each calendar week, with at least three days between measurements) or more frequent samples, for all degasification wells and gob gas vent holes. Determine weekly or more frequent flow rates, methane concentration, temperature, and pressure from these degasification wells and gob gas vent holes. Methane composition should be determined either by submitting samples to a lab for analysis, or from the use of methanometers at the degasification monitoring site. Follow the sampling protocols for sampling of methane emissions from ventilation shafts, as described in § 98.324(b)(1). You must record the date of sampling, flow, temperature, pressure, and moisture measurements, the methane concentration (percent), the bottle number of samples collected, and the location of the measurement or collection.
(3) If the CH
(i) The gas flow meter at least once each calendar week; if measuring with CEMS. If only one measurement is made each calendar week, there must be at least three days between measurements; and
(ii) The grab sample, if using grab samples, at the time of the sample.
(d) Monitoring must adhere to one of the methods specified in paragraphs (d)(1) through (d)(2) of this section.
(1) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography; ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography; ASTM D4891-89 (Reapproved 2006), Standard Test Method for Heating Value of Gases in Natural Gas Range by Stoichiometric Combustion; or ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(2) As an alternative to the gas chromatography methods provided in paragraph (d)(1) of this section, you may use gaseous organic concentration analyzers and a correction factor to calculate the CH
(i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine gaseous organic concentration as required in § 98.323 and in paragraphs (b) and (c) of this section. You must calibrate the instrument with CH
(ii) Determine a correction factor that will be used with the gaseous organic concentrations measured in paragraph (i) of this section. The correction factor must be determined at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (d)(2)(ii)(A) through (d)(2)(ii)(C) of this section.
(A) Take a minimum of three grab samples of the gas with a minimum of 20 minutes between samples and determine the methane composition of the gas using one of the methods specified in paragraph (d)(1) of this section.
(B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the gaseous organic concentration of the gas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (d)(2)(i) of this section.
(C) Determine the arithmetic average methane concentration and the arithmetic average gaseous organic concentration of the samples analyzed according to paragraphs (d)(2)(ii)(A) and (d)(2)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the correction factor.
(iii) Calculate the CH
(e) All flow meters and gas composition monitors that are used to provide data for the GHG emissions calculations shall be calibrated prior to the first reporting year, using the applicable methods specified in paragraphs (d), and (e)(1) through (e)(7) of this section. Alternatively, calibration procedures specified by the flow meter manufacturer may be used. Flow meters and gas composition monitors shall be recalibrated either at the minimum frequency specified by the manufacturer or annually. The operator shall operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH
(1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).
(3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).
(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).
(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7).
(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).
(7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see § 98.7).
(f) For CH
(g) All temperature, pressure, and moisture content monitors must be operated and calibrated using the procedures and frequencies specified by the manufacturer.
(h) The owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of flow meters, and other measurement devices. The estimated accuracy of measurements and the technical basis for the estimated accuracy shall be recorded.
§ 98.325 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, in accordance with paragraph (b) of this section.
(b) For each missing value of CH
§ 98.326 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each mine:
(a) Quarterly CH
(b) Weekly CH
(c) Quarterly CH
(d) Quarterly CH
(e) Quarterly CO
(f) Quarterly volumetric flow rate for each ventilation monitoring point and units of measure (scfm or acfm), date and location of each measurement, and method of measurement (quarterly sampling or continuous monitoring), used in Equation FF-1 of this subpart. Specify whether the volumetric flow rate measurement at each ventilation monitoring point is on dry basis or wet basis; and, if a flow meter is used, indicate whether or not the flow meter automatically corrects for moisture content.
(g) Quarterly CH
(h) Weekly volumetric flow rate used to calculate CH
(i) Quarterly CH
(j) Weekly volumetric flow rate used to calculate CH
(k) Weekly CH
(l) Dates in quarterly reporting period where active ventilation of mining operations is taking place.
(m) Dates in quarterly reporting period where degasification of mining operations is taking place.
(n) Dates in quarterly reporting period when continuous monitoring equipment is not properly functioning, if applicable.
(o) Temperature (°R), pressure (atm), moisture content (if applicable), and the moisture correction factor (if applicable) used in Equations FF-1 and FF-3 of this subpart; and the gaseous organic concentration correction factor, if Equation FF-9 of this subpart was required. Moisture content is required to be reported only if CH
(p) For each destruction device, a description of the device, including an indication of whether destruction occurs at the coal mine or off-site. If destruction occurs at the mine, also report an indication of whether a back-up destruction device is present at the mine, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), and the destruction efficiencies assumed (percent).
(q) A description of the gas collection system (manufacturer, capacity, and number of wells) the surface area of the gas collection system (square meters), and the annual operating hours of the gas collection system.
(r) Identification information and description for each well, shaft, and vent hole, including paragraphs (r)(1) through (r)(3) of this section:
(1) Indication of whether the well, shaft, or vent hole is monitored individually, or as part of a centralized monitoring point. Note which method (sampling or continuous monitoring) was used.
(2) Start date and close date of each well, shaft, and vent hole. If the well, shaft, or vent hole is operating through the end of the reporting year, December 31st of the reporting year shall be the close date for purposes of reporting.
(3) Number of days the well, shaft, or vent hole was in operation during the reporting year. To obtain the number of days in the reporting year, divide the total number of hours that the system was in operation by 24 hours per day.
(s) For each centralized monitoring point, identification of the wells and shafts included in the point. Note which method (sampling or continuous monitoring) was used.
(t) Mine Safety and Health Administration (MSHA) identification for this coal mine.
§ 98.327 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the following records:
(a) Calibration records for all monitoring equipment, including the method or manufacturer’s specification used for calibration.
(b) Records of gas sales.
(c) Logbooks of parameter measurements.
(d) Laboratory analyses of samples.
§ 98.328 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart GG – Zinc Production
§ 98.330 Definition of the source category.
The zinc production source category consists of zinc smelters and secondary zinc recycling facilities.
§ 98.331 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a zinc production process and the facility meets the requirements of either § 98.2(a)(1) or (2).
§ 98.332 GHGs to report.
You must report:
(a) CO
(b) CO
(c) CO
§ 98.333 Calculating GHG emissions.
You must calculate and report the annual process CO
(a) Calculate and report under this subpart the process or combined process and combustion CO
(b) Calculate and report under this subpart the process CO
(1) For each Waelz kiln or electrothermic furnace at your facility used for zinc production, you must determine the mass of carbon in each carbon-containing material, other than fuel, that is fed, charged, or otherwise introduced into each Waelz kiln and electrothermic furnace at your facility for each year and calculate annual CO
(2) You must determine the CO
(c) If GHG emissions from a Waelz kiln or electrothermic furnace are vented through the same stack as any combustion unit or process equipment that reports CO
§ 98.334 Monitoring and QA/QC requirements.
If you determine CO
(a) Determine the mass of each solid carbon-containing input material consumed using facility instruments, procedures, or records used for accounting purposes including direct measurement weighing or through the use of purchase records same plant instruments or procedures that are used for accounting purposes (such as weigh hoppers, belt weigh feeders, weighed purchased quantities in shipments or containers, combination of bulk density and volume measurements, etc.). Record the total mass for the materials consumed each calendar month and sum the monthly mass to determine the annual mass for each input material.
(b) For each input material identified in paragraph (a) of this section, you must determine the average carbon content of the material consumed or used in the calendar year using the methods specified in either paragraph (b)(1) or (b)(2) of this section.
(1) Information provided by your material supplier.
(2) Collecting and analyzing at least three representative samples of the material using the appropriate testing method. For each carbon-containing input material identified for which the carbon content is not provided by your material supplier, the carbon content of the material must be analyzed at least annually using the appropriate standard methods (and their QA/QC procedures), which are identified in paragraphs (b)(2)(i) through (b)(2)(iii) of this section, as applicable. If you document that a specific process input or output contributes less than one percent of the total mass of carbon into or out of the process, you do not have to determine the monthly mass or annual carbon content of that input or output.
(i) Using ASTM E1941-04 Standard Test Method for Determination of Carbon in Refractory and Reactive Metals and Their Alloys (incorporated by reference, see § 98.7), analyze zinc bearing materials.
(ii) Using ASTM D5373-08 Standard Test Methods for Instrumental Determination of Carbon, Hydrogen, and Nitrogen in Laboratory Samples of Coal (incorporated by reference, see § 98.7), analyze carbonaceous reducing agents and carbon electrodes.
(iii) Using ASTM C25-06 Standard Test Methods for Chemical Analysis of Limestone, Quicklime, and Hydrated Lime (incorporated by reference, see § 98.7), analyze flux materials such as limestone or dolomite.
§ 98.335 Procedures for estimating missing data.
For the carbon input procedure in § 98.333(b), a complete record of all measured parameters used in the GHG emissions calculations is required (e.g., raw materials carbon content values, etc.). Therefore, whenever a quality-assured value of a required parameter is unavailable, a substitute data value for the missing parameter shall be used in the calculations as specified in paragraphs (a) and (b) of this section. You must document and keep records of the procedures used for all such estimates.
(a) For missing records of the carbon content of inputs for facilities that estimate emissions using the carbon input procedure in § 98.333(b); 100 percent data availability is required. You must repeat the test for average carbon contents of inputs according to the procedures in § 98.335(b) if data are missing.
(b) For missing records of the annual mass of carbon-containing inputs using the carbon input procedure in § 98.333(b), the substitute data value must be based on the best available estimate of the mass of the input material from all available process data or information used for accounting purposes, such as purchase records.
§ 98.336 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the information specified in paragraphs (a) or (b) of this section, as applicable, for each Waelz kiln or electrothermic furnace.
(a) If a CEMS is used to measure CO
(1) Annual zinc product production capacity (tons).
(2) Annual production quantity for each zinc product (tons).
(3) Annual facility production quantity for each zinc product (tons).
(4) Number of Waelz kilns at each facility used for zinc production.
(5) Number of electrothermic furnaces at each facility used for zinc production.
(b) If a CEMS is not used to measure CO
(1) Identification number and annual process CO
(2) Annual zinc product production capacity (tons).
(3) Annual production quantity for each zinc product (tons).
(4) Number of Waelz kilns at each facility used for zinc production.
(5) Number of electrothermic furnaces at each facility used for zinc production.
(6) [Reserved]
(7) [Reserved]
(8) Whether carbon content of each carbon-containing input material charged to each kiln or furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method.
(9) If carbon content of each carbon-containing input material charged to each kiln or furnace is based on self measurement, the ASTM Standard Test Method used.
(10) [Reserved]
(11) Whether carbon content of the carbon electrode used in each furnace is based on reports from the supplier or through self measurement using applicable ASTM standard method.
(12) If carbon content of carbon electrode used in each furnace is based on self measurement, the ASTM standard method used.
(13) If you use the missing data procedures in § 98.335(b), you must report how the monthly mass of carbon-containing materials with missing data was determined and the number of months the missing data procedures were used.
§ 98.337 Records that must be retained.
In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a) through (c) of this section for each zinc production facility.
(a) If a CEMS is used to measure emissions, then you must retain under this subpart the records required for the Tier 4 Calculation Methodology in § 98.37 and the information listed in this paragraph (a):
(1) Monthly facility production quantity for each zinc product (tons).
(2) Annual operating hours for all Waelz kilns and electrothermic furnaces used in zinc production.
(b) If a CEMS is not used to measure emissions, you must also retain the records specified in paragraphs (b)(1) through (b)(7) of this section.
(1) Records of all analyses and calculations conducted for data reported as listed in § 98.336(b).
(2) Annual operating hours for Waelz kilns and electrothermic furnaces used in zinc production.
(3) Monthly production quantity for each zinc product (tons).
(4) Monthly mass of zinc bearing materials, flux materials (e.g., limestone, dolomite), and carbonaceous materials (e.g., coal, coke) charged to the kiln or furnace (tons).
(5) Sampling and analysis records for carbon content of zinc bearing materials, flux materials (e.g., limestone, dolomite), carbonaceous materials (e.g., coal, coke), charged to the kiln or furnace (percent by weight, expressed as a decimal fraction).
(6) Monthly mass of carbon electrode consumed in for each electrothermic furnace (tons).
(7) Sampling and analysis records for carbon content of electrode materials.
(8) You must keep records that include a detailed explanation of how company records of measurements are used to estimate the carbon input to each Waelz kiln or electrothermic furnace, as applicable to your facility, including documentation of any materials excluded from Equation GG-1 of this subpart that contribute less than 1 percent of the total carbon inputs to the process. You also must document the procedures used to ensure the accuracy of the measurements of materials fed, charged, or placed in an affected unit including, but not limited to, calibration of weighing equipment and other measurement devices. The estimated accuracy of measurements made with these devices must also be recorded, and the technical basis for these estimates must be provided.
(c) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (c)(1) through (9) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (c)(1) through (9) of this section.
(1) Annual mass of zinc bearing material charged to kiln or furnace (tons) (Equation GG-1 of § 98.333).
(2) Carbon content of the zinc bearing material, from the annual carbon analysis for kiln or furnace (percent by weight, expressed as a decimal fraction) (Equation GG-1).
(3) Annual mass of flux materials (e.g., limestone, dolomite) charged to each kiln or furnace (tons) (Equation GG-1).
(4) Carbon content of the flux materials charged to each kiln or furnace, from the annual carbon analysis (percent by weight, expressed as a decimal fraction) (Equation GG-1).
(5) Annual mass of carbon electrode consumed in each furnace (tons) (Equation GG-1).
(6) Carbon content of the carbon electrode consumed in each furnace, from the annual carbon analysis (percent by weight, expressed as a decimal fraction) (Equation GG-1).
(7) Annual mass of carbonaceous materials (e.g., coal, coke) charged to each kiln or furnace (tons) (Equation GG-1).
(8) Carbon content of the carbonaceous materials charged to each kiln or furnace, from the annual carbon analysis (percent by weight, expressed as a decimal fraction) (Equation GG-1).
(9) Identify whether each unit is a Waelz kiln or an electrothermic furnace.
§ 98.338 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart HH – Municipal Solid Waste Landfills
§ 98.340 Definition of the source category.
(a) This source category applies to municipal solid waste (MSW) landfills that accepted waste on or after January 1, 1980, unless all three of the following conditions apply.
(1) The MSW landfill did not receive waste on or after January 1, 2013.
(2) The MSW landfill had CH
(3) The owner or operator of the MSW landfill was not required to submit an annual report under any requirement of this part in any reporting year prior to 2013.
(b) This source category does not include Resource Conservation and Recovery Act (RCRA) Subtitle C or Toxic Substances Control Act (TSCA) hazardous waste landfills, construction and demolition waste landfills, or industrial waste landfills.
(c) This source category consists of the following sources at municipal solid waste (MSW) landfills: Landfills, landfill gas collection systems, and landfill gas destruction devices (including flares).
§ 98.341 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains a MSW landfill and the facility meets the requirements of § 98.2(a)(1).
§ 98.342 GHGs to report.
(a) You must report CH
(b) You must report CH
(c) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
§ 98.343 Calculating GHG emissions.
(a) For all landfills subject to the reporting requirements of this subpart, calculate annual modeled CH
(1) Calculate annual modeled CH
(2) For years when material-specific waste quantity data are available, apply Equation HH-1 of this section for each waste quantity type and sum the CH
(3) Beginning in the first emissions reporting year and for each year thereafter, if scales are in place, you must determine the annual quantity of waste (in metric tons as received, i.e., wet weight) disposed of in the landfill using paragraph (a)(3)(i) of this section for all containers and for all vehicles used to haul waste to the landfill, except for passenger cars, light duty pickup trucks, or waste loads that cannot be measured using the scales due to physical limitations (load cannot physically access or fit on the scale) and/or operational limitations of the scale (load exceeding the limits or sensitivity range of the scale). If scales are not in place, you must use paragraph (a)(3)(ii) of this section to determine the annual quantity of waste disposed. For waste hauled to the landfill in passenger cars or light duty pickup trucks, you may use either paragraph (a)(3)(i) or paragraph (a)(3)(ii) of this section to determine the annual quantity of waste disposed. For loads that cannot be measured using the scales due to physical and/or operational limitations of the scale, you must use paragraph (a)(3)(ii) of this section or similar engineering calculations to determine the annual quantity of waste disposed. The approach used to determine the annual quantity of waste disposed of must be documented in the monitoring plan.
(i) Use direct mass measurements of each individual load received at the landfill using either of the following methods:
(A) Weigh using mass scales each vehicle or container used to haul waste as it enters the landfill or disposal area; weigh using mass scales each vehicle or container after it has off-loaded the waste; determine the quantity of waste received from the individual load as the difference in the two mass measurements; and determine the annual quantity of waste received as the sum of all waste loads received during the year. Alternatively, you may determine annual quantity of waste by summing the weights of all vehicles and containers entering the landfill and subtracting from it the sum of all the weights of vehicles and containers after they have off-loaded the waste in the landfill.
(B) Weigh using mass scales each vehicle or container used to haul waste as it enters the landfill or disposal area; determine a representative tare weight by vehicle or container type by weighing no less than 5 of each type of vehicle or container after it has off-loaded the waste; determine the quantity of waste received from the individual load as the difference between the measured weight in and the tare weight determined for that container/vehicle type; and determine the annual quantity of waste received as the sum of all waste loads received during the year.
(ii) Determine the working capacity in units of mass for each type of container or vehicle used to haul waste to the landfill (e.g., using volumetric capacity and waste density measurements; direct measurement of a selected number of passenger vehicles and light duty pick-up trucks; or similar methods); record the number of loads received at the landfill by vehicle/container type; calculate the annual mass per vehicle/container type as the mass product of the number of loads of that vehicle/container multiplied by its working capacity; and calculate the annual quantity of waste received as the sum of the annual mass per vehicle/container type across all of the vehicle/container types used to haul waste to the landfill.
(4) For years prior to the first emissions reporting year, use methods in paragraph (a)(3) of this section when waste disposal quantity data are readily available. When waste disposal quantity data are not readily available, W
(i) Assume all prior years waste disposal quantities are the same as the waste quantity in the first year for which waste quantities are available.
(ii) Use the estimated population served by the landfill in each year, the values for national average per capita waste disposal rates found in Table HH-2 to this subpart, and calculate the waste quantity landfilled using Equation HH-2 of this section.
(iii) Use a constant average waste disposal quantity calculated using Equation HH-3 of this section for each year the landfill was in operation (i.e., from the first year accepting waste until the last year for which waste disposal data is unavailable, inclusive).
(b) For landfills with gas collection systems, calculate the quantity of CH
(1) If you continuously monitor the flow rate, CH
(2) If you do not continuously monitor according to paragraph (b)(1) of this section, you must determine the flow rate, CH
(i) Continuously monitor gas flow rate and determine the cumulative volume of landfill gas each month and the cumulative volume of landfill gas each year that is collected and routed to a destruction device (before any treatment equipment). Under this option, the gas flow meter is not required to automatically correct for temperature, pressure, or, if necessary, moisture content. If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content, you must determine these parameters as specified in paragraph (b)(2)(iii) of this section.
(ii) Determine the CH
(iii) If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content:
(A) Determine the temperature and pressure in the landfill gas that is collected and routed to a destruction device (before any treatment equipment) in a location near or representative of the location of the gas flow meter at least once each calendar month; if only one measurement is made each calendar month, there must be at least fourteen days between measurements.
(B) If the CH
(c) For all landfills, calculate CH
(1) Calculate CH
(2) For landfills that do not have landfill gas collection systems, the CH
(3) For landfills with landfill gas collection systems, calculate CH
(i) Calculate CH
(ii) Calculate CH
§ 98.344 Monitoring and QA/QC requirements.
(a) Mass measurement equipment used to determine the quantity of waste landfilled on or after January 1, 2010 must meet the requirements for weighing equipment as described in “Specifications, Tolerances, and Other Technical Requirements For Weighing and Measuring Devices” NIST Handbook 44 (2009) (incorporated by reference, see § 98.7).
(b) For landfills with gas collection systems, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH
(1) Method 18 at 40 CFR part 60, appendix A-6.
(2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(4) GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography.
(5) UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(6) As an alternative to the gas chromatography methods provided in paragraphs (b)(1) through (b)(5) of this section, you may use total gaseous organic concentration analyzers and calculate the methane concentration following the requirements in paragraphs (b)(6)(i) through (b)(6)(iii) of this section.
(i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine total gaseous organic concentration. You must calibrate the instrument with methane and determine the total gaseous organic concentration as carbon (or as methane; K = 1 in Equation 25A-1 of Method 25A at 40 CFR part 60, appendix A-7).
(ii) Determine a non-methane organic carbon correction factor at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (b)(6)(ii)(A) through (b)(6)(ii)(C) of this section.
(A) Take a minimum of three grab samples of the landfill gas with a minimum of 20 minutes between samples and determine the methane composition of the landfill gas using one of the methods specified in paragraphs (b)(1) through (b)(5) of this section.
(B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the total gaseous organic concentration of the landfill gas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (b)(6)(i) of this section.
(C) Determine the arithmetic average methane concentration and the arithmetic average total gaseous organic concentration of the samples analyzed according to paragraphs (b)(6)(ii)(A) and (b)(6)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the non-methane organic carbon correction factor.
(iii) Calculate the methane concentration as specified in Equation HH-9 of this section.
(c) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate of the recovered landfill gas using one of the methods specified in paragraphs (c)(1) through (c)(8) of this section or as specified by the manufacturer. Each gas flow meter shall be recalibrated either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Except as provided in § 98.343(b)(2)(i), each gas flow meter must be capable of correcting for the temperature and pressure and, if necessary, moisture content.
(1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).
(3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).
(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).
(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7). The mass flow must be corrected to volumetric flow based on the measured temperature, pressure, and gas composition.
(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).
(7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see § 98.7).
(8) Method 2A or 2D at 40 CFR part 60, appendix A-1.
(d) All temperature, pressure, and if necessary, moisture content monitors must be calibrated using the procedures and frequencies specified by the manufacturer.
(e) For landfills electing to measure the fraction by volume of CH
(2) Use Equation HH-10 of this section to correct the measured CH
(f) The owner or operator shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if applicable, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices, and the technical basis for these estimates shall be recorded.
§ 98.345 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraphs (a) through (c) of this section.
(a) For each missing value of the CH
(b) For missing gas flow rates, the substitute data value shall be the arithmetic average of the quality-assured values of that parameter immediately preceding and immediately following the missing data incident. If the “after” value is not obtained by the end of the reporting year, you may use the “before” value for the missing data substitution. If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value shall be the first quality-assured value obtained after the missing data period.
(c) For missing daily waste disposal quantity data for disposal in the reporting year, the substitute value shall be the average daily waste disposal quantity for that day of the week as measured on the week before and week after the missing daily data.
§ 98.346 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each landfill.
(a) A classification of the landfill as “open” (actively received waste in the reporting year) or “closed” (no longer receiving waste), the year in which the landfill first started accepting waste for disposal, the last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure), the capacity (in metric tons) of the landfill, an indication of whether leachate recirculation is used during the reporting year and its typical frequency of use over the past 10 years (e.g., used several times a year for the past 10 years, used at least once a year for the past 10 years, used occasionally but not every year over the past 10 years, not used), an indication as to whether scales are present at the landfill, and the waste disposal quantity for each year of landfilling required to be included when using Equation HH-1 of this subpart (in metric tons, wet weight).
(b) Method for estimating reporting year and historical waste disposal quantities, reason for its selection, and the range of years it is applied. For years when waste quantity data are determined using the methods in § 98.343(a)(3), report separately the quantity of waste determined using the methods in § 98.343(a)(3)(i) and the quantity of waste determined using the methods in § 98.343(a)(3)(ii). For historical waste disposal quantities that were not determined using the methods in § 98.343(a)(3), provide the population served by the landfill for each year the Equation HH-2 of this subpart is applied, if applicable, or, for open landfills using Equation HH-3 of this subpart, provide the value of landfill capacity (LFC) used in the calculation.
(c) Waste composition for each year required for Equation HH-1 of this subpart, in percentage by weight, for each waste category listed in Table HH-1 to this subpart that is used in Equation HH-1 of this subpart to calculate the annual modeled CH
(d) For each waste type used to calculate CH
(1) Degradable organic carbon (DOC) and fraction of DOC dissimilated (DOC
(2) Decay rate (k) value used in the calculations.
(e) Fraction of CH
(f) The surface area of the landfill containing waste (in square meters), identification of the type(s) of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures).
(g) The modeled annual methane generation rate for the reporting year (metric tons CH
(h) For landfills without gas collection systems, the annual methane emissions (i.e., the methane generation, adjusted for oxidation, calculated using Equation HH-5 of this subpart), reported in metric tons CH
(i) For landfills with gas collection systems, you must report:
(1) Total volumetric flow of landfill gas collected for destruction for the reporting year (cubic feet at 520 °R or 60 degrees Fahrenheit and 1 atm).
(2) Annual average CH
(3) Monthly average temperature and pressure for each month at which flow is measured for landfill gas collected for destruction, or statement that temperature and/or pressure is incorporated into internal calculations run by the monitoring equipment.
(4) An indication as to whether flow was measured on a wet or dry basis, an indication as to whether CH
(5) An indication of whether destruction occurs at the landfill facility, off-site, or both. If destruction occurs at the landfill facility, also report for each measurement location:
(i) The number of destruction devices associated with the measurement location.
(ii) The annual operating hours of the gas collection system associated with the measurement location.
(iii) For each destruction device associated with the measurement location, report:
(A) The destruction efficiency (decimal).
(B) The annual operating hours where active gas flow was sent to the destruction device.
(6) Annual quantity of recovered CH
(7) A description of the gas collection system (manufacturer, capacity, and number of wells), the surface area (square meters) and estimated waste depth (meters) for each area specified in Table HH-3 to this subpart, the estimated gas collection system efficiency for landfills with this gas collection system and an indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in § 98.6) are present at the landfill.
(8) Methane generation corrected for oxidation calculated using Equation HH-5 of this subpart, reported in metric tons CH
(9) Methane generation (G
(10) Methane generation corrected for oxidation calculated using Equation HH-7 of this subpart, reported in metric tons CH
(11) Methane emissions calculated using Equation HH-6 of this subpart, reported in metric tons CH
(12) Methane emissions calculated using Equation HH-8 of this subpart, reported in metric tons CH
(13) Methane emissions for the landfill (i.e., the subpart HH total methane emissions). Choose the methane emissions from either Equation HH-6 or Equation HH-8 of this subpart that best represents the emissions from the landfill. If the quantity of recovered CH
§ 98.347 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer’s specification used for calibration. You must retain records of all measurements made to determine tare weights and working capacities by vehicle/container type if these are used to determine the annual waste quantities.
§ 98.348 Definitions.
Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Construction and demolition (C&D) waste landfill means a solid waste disposal facility subject to the requirements of part 257, subparts A or B of this chapter that receives construction and demolition waste and does not receive hazardous waste (defined in § 261.3 of this chapter) or industrial solid waste (defined in § 258.2 of this chapter) or municipal solid waste (as defined in § 98.6) other than residential lead-based paint waste. A C&D waste landfill typically receives any one or more of the following types of solid wastes: Roadwork material, excavated material, demolition waste, construction/renovation waste, and site clearance waste.
Destruction device means a flare, thermal oxidizer, boiler, turbine, internal combustion engine, or any other combustion unit used to destroy or oxidize methane contained in landfill gas.
Final cover means materials used at a landfill to meet final closure regulations of the competent federal, state, or local authority.
Industrial waste landfill means any landfill other than a municipal solid waste landfill, a RCRA Subtitle C hazardous waste landfill, or a TSCA hazardous waste landfill, in which industrial solid waste, such a RCRA Subtitle D wastes (nonhazardous industrial solid waste, defined in § 257.2 of this chapter), commercial solid wastes, or conditionally exempt small quantity generator wastes, is placed. An industrial waste landfill includes all disposal areas at the facility.
Intermediate or interim cover means the placement of material over waste in a landfill for a period of time prior to the disposal of additional waste and/or final closure as defined by state regulation, permit, guidance or written plan, or state accepted best management practice.
Landfill capacity means the maximum amount of solid waste a landfill can accept. For the purposes of this subpart, for landfills that have a permit, the landfill capacity can be determined in terms of volume or mass in the most recent permit issued by the state, local, or Tribal agency responsible for regulating the landfill, plus any in-place waste not accounted for in the most recent permit. If the owner or operator chooses to convert from volume to mass to determine its capacity, the calculation must include a site-specific density.
Leachate recirculation means the practice of taking the leachate collected from the landfill and reapplying it to the landfill by any of one of a variety of methods, including pre-wetting of the waste, direct discharge into the working face, spraying, infiltration ponds, vertical injection wells, horizontal gravity distribution systems, and pressure distribution systems.
Passive vent means a pipe or a system of pipes that allows landfill gas to flow naturally, without the use of a fan or similar mechanical draft equipment, to the surface of the landfill where an opening or pipe (vent) allows for the free flow of landfill gas to the atmosphere or to a passive vent flare without diffusion through the top layer of surface soil.
Solid waste has the meaning established by the Administrator pursuant to the Solid Waste Disposal Act (42 U.S.C.A. 6901 et seq.).
Working capacity means the maximum volume or mass of waste that is actually placed in the landfill from an individual or representative type of container (such as a tank, truck, or roll-off bin) used to convey wastes to the landfill, taking into account that the container may not be able to be 100 percent filled and/or 100 percent emptied for each load.
Table HH-1 to Subpart HH of Part 98 – Emissions Factors, Oxidation Factors and Methods
Factor | Default value | Units |
---|---|---|
DOC (bulk waste) | 0.20 | Weight fraction, wet basis. |
k (precipitation plus recirculated leachate a | 0.02 | yr |
k (precipitation plus recirculated leachate a 20-40 inches/year) | 0.038 | yr |
k (precipitation plus recirculated leachate a >40 inches/year) | 0.057 | yr |
DOC (bulk MSW, excluding inerts and C&D waste) | 0.31 | Weight fraction, wet basis. |
DOC (inerts, e.g., glass, plastics, metal, concrete) | 0.00 | Weight fraction, wet basis. |
DOC (C&D waste) | 0.08 | Weight fraction, wet basis. |
k (bulk MSW, excluding inerts and C&D waste) | 0.02 to 0.057 b | yr |
k (inerts, e.g., glass, plastics, metal, concrete) | 0.00 | yr |
k (C&D waste) | 0.02 to 0.04 b | yr |
DOC (food waste) | 0.15 | Weight fraction, wet basis. |
DOC (garden) | 0.2 | Weight fraction, wet basis. |
DOC (paper) | 0.4 | Weight fraction, wet basis. |
DOC (wood and straw) | 0.43 | Weight fraction, wet basis. |
DOC (textiles) | 0.24 | Weight fraction, wet basis. |
DOC (diapers) | 0.24 | Weight fraction, wet basis. |
DOC (sewage sludge) | 0.05 | Weight fraction, wet basis. |
DOC (inerts, e.g., glass, plastics, metal, cement) | 0.00 | Weight fraction, wet basis. |
k (food waste) | 0.06 to 0.185 c | yr |
k (garden) | 0.05 to 0.10 c | yr |
k (paper) | 0.04 to 0.06 c | yr |
k (wood and straw) | 0.02 to 0.03 c | yr |
k (textiles) | 0.04 to 0.06 c | yr |
k (diapers) | 0.05 to 0.10 c | yr |
k (sewage sludge) | 0.06 to 0.185 c | yr |
k (inerts e.g., glass, plastics, metal, concrete) | 0.00 | yr |
MCF | 1. | |
DOC | 0.5 | |
F | 0.5 | |
OX | See Table HH-4 of this subpart | |
DE | 0.99 |
a Recirculated leachate (in inches/year) is the total volume of leachate recirculated from company records or engineering estimates divided by the area of the portion of the landfill containing waste with appropriate unit conversions. Alternatively, landfills that use leachate recirculation can elect to use the k value of 0.057 rather than calculating the recirculated leachate rate.
b Use the lesser value when precipitation plus recirculated leachate is less than 20 inches/year. Use the greater value when precipitation plus recirculated leachate is greater than 40 inches/year. Use the average of the range of values when precipitation plus recirculated leachate is 20 to 40 inches/year (inclusive). Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than calculating the recirculated leachate rate.
c Use the lesser value when the potential evapotranspiration rate exceeds the mean annual precipitation rate plus recirculated leachate. Use the greater value when the potential evapotranspiration rate does not exceed the mean annual precipitation rate plus recirculated leachate. Alternatively, landfills that use leachate recirculation can elect to use the greater value rather than assessing the potential evapotranspiration rate or recirculated leachate rate.
Table HH-2 to Subpart HH of Part 98 – U.S. Per Capita Waste Disposal Rates
Year | Waste per capita ton/cap/yr |
---|---|
1950 | 0.63 |
1951 | 0.63 |
1952 | 0.63 |
1953 | 0.63 |
1954 | 0.63 |
1955 | 0.63 |
1956 | 0.63 |
1957 | 0.63 |
1958 | 0.63 |
1959 | 0.63 |
1960 | 0.63 |
1961 | 0.64 |
1962 | 0.64 |
1963 | 0.65 |
1964 | 0.65 |
1965 | 0.66 |
1966 | 0.66 |
1967 | 0.67 |
1968 | 0.68 |
1969 | 0.68 |
1970 | 0.69 |
1971 | 0.69 |
1972 | 0.70 |
1973 | 0.71 |
1974 | 0.71 |
1975 | 0.72 |
1976 | 0.73 |
1977 | 0.73 |
1978 | 0.74 |
1979 | 0.75 |
1980 | 0.75 |
1981 | 0.76 |
1982 | 0.77 |
1983 | 0.77 |
1984 | 0.78 |
1985 | 0.79 |
1986 | 0.79 |
1987 | 0.80 |
1988 | 0.80 |
1989 | 0.83 |
1990 | 0.82 |
1991 | 0.76 |
1992 | 0.74 |
1993 | 0.76 |
1994 | 0.75 |
1995 | 0.70 |
1996 | 0.68 |
1997 | 0.69 |
1998 | 0.75 |
1999 | 0.75 |
2000 | 0.80 |
2001 | 0.91 |
2002 | 1.02 |
2003 | 1.02 |
2004 | 1.01 |
2005 | 0.98 |
2006 | 0.95 |
2007 | 0.95 |
2008 | 0.95 |
2009 and all later years | 0.95 |
Table HH-3 to Subpart HH of Part 98 – Landfill Gas Collection Efficiencies
Description | Landfill Gas Collection Efficiency |
---|---|
A1: Area with no waste in-place | Not applicable; do not use this area in the calculation. |
A2: Area without active gas collection, regardless of cover type | CE2: 0%. |
A3: Area with daily soil cover and active gas collection | CE3: 60%. |
A4: Area with an intermediate soil cover, or a final soil cover not meeting the criteria for A5 below, and active gas collection | CE4: 75%. |
A5: Area with a final soil cover of 3 feet or thicker of clay or final cover (as approved by the relevant agency) and/or geomembrane cover system and active gas collection | CE5: 95%. |
Weighted average collection efficiency for landfills: | |
Area weighted average collection efficiency for landfills | CEave1 = (A2*CE2 + A3*CE3 + A4*CE4 + A5*CE5) / (A2 + A3 + A4 + A5). |
Table HH-4 to Subpart HH of Part 98 – Landfill Methane Oxidation Fractions
Under these conditions: | Use this landfill methane oxidation fraction: |
---|---|
C1: For all landfills regardless of cover type or methane flux | 0.10 |
C2: For landfills that have a geomembrane (synthetic) cover or other non-soil barrier meeting the definition of final cover with less than 12 inches of cover soil for greater than 50% of the landfill area containing waste | 0.0 |
C3: For landfills that do not meet the conditions in C2 above and for which you elect not to determine methane flux | 0.10 |
C4: For landfills that do not meet the conditions in C2 or C3 above and that do not have final cover, or intermediate or interim cover a for greater than 50% of the landfill area containing waste | 0.10 |
C5: For landfills that do not meet the conditions in C2 or C3 above and that have final cover, or intermediate or interim cover a for greater than 50% of the landfill area containing waste and for which the methane flux rate b is less than 10 grams per square meter per day (g/m 2/d) | 0.35 |
C6: For landfills that do not meet the conditions in C2 or C3 above and that have final cover or intermediate or interim cover a for greater than 50% of the landfill area containing waste and for which the methane flux rate b is 10 to 70 g/m 2/d | 0.25 |
C7: For landfills that do not meet the conditions in C2 or C3 above and that have final cover or intermediate or interim cover a for greater than 50% of the landfill area containing waste and for which the methane flux rate b is greater than 70 g/m 2/d | 0.10 |
a Where a landfill is located in a state that does not have an intermediate or interim cover requirement, the landfill must have soil cover of 12 inches or greater in order to use an oxidation fraction of 0.25 or 0.35.
b Methane flux rate (in grams per square meter per day; g/m
2/d) is the mass flow rate of methane per unit area at the bottom of the surface soil prior to any oxidation and is calculated as follows:
Subpart II – Industrial Wastewater Treatment
§ 98.350 Definition of source category.
(a) This source category consists of anaerobic processes used to treat industrial wastewater and industrial wastewater treatment sludge at facilities that perform the operations listed in this paragraph.
(1) Pulp and paper manufacturing.
(2) Food processing.
(3) Ethanol production.
(4) Petroleum refining.
(b) An anaerobic process is a procedure in which organic matter in wastewater, wastewater treatment sludge, or other material is degraded by micro-organisms in the absence of oxygen, resulting in the generation of CO
(1) An anaerobic reactor is an enclosed vessel used for anaerobic wastewater treatment (e.g., upflow anaerobic sludge blanket, fixed film).
(2) Ananaerobic sludge digester is an enclosed vessel in which wastewater treatment sludge is degraded anaerobically.
(3) Ananaerobic lagoon is a lined or unlined earthen basin used for wastewater treatment, in which oxygen is absent throughout the depth of the basin, except for a shallow surface zone. Anaerobic lagoons are not equipped with surface aerators. Anaerobic lagoons are classified as deep (depth more than 2 meters) or shallow (depth less than 2 meters).
(c) This source category does not include municipal wastewater treatment plants or separate treatment of sanitary wastewater at industrial sites.
§ 98.351 Reporting threshold.
You must report GHG emissions under this subpart if your facility meets all of the conditions under paragraphs (a) or (b) of this section:
(a) Petroleum refineries and pulp and paper manufacturing. (1) The facility is subject to reporting under subpart Y of this part (Petroleum Refineries) or subpart AA of this part (Pulp and Paper Manufacturing).
(2) The facility meets the requirements of either § 98.2(a)(1) or (2).
(3) The facility operates an anaerobic process to treat industrial wastewater and/or industrial wastewater treatment sludge.
(b) Ethanol production and food processing facilities. (1) The facility performs an ethanol production or food processing operation, as defined in § 98.358 of this subpart.
(2) The facility meets the requirements of § 98.2(a)(2).
(3) The facility operates an anaerobic process to treat industrial wastewater and/or industrial wastewater treatment sludge.
§ 98.352 GHGs to report.
(a) You must report CH
(b) You must report CH
(c) You must report CH
(d) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
§ 98.353 Calculating GHG emissions.
(a) For each anaerobic reactor and anaerobic lagoon, estimate the annual mass of CH
(1) If you measure the concentration of organic material entering the anaerobic reactors or anaerobic lagoon using methods for the determination of chemical oxygen demand (COD), then estimate annual mass of CH
(2) If you measure the concentration of organic material entering an anaerobic reactor or anaerobic lagoon using methods for the determination of 5-day biochemical oxygen demand (BOD
(b) For each anaerobic reactor and anaerobic lagoon from which biogas is not recovered, estimate annual CH
(c) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some biogas is recovered, estimate the annual mass of CH
(1) If you continuously monitor CH
(2) If you do not continuously monitor CH
(i) Determine the CH
(ii) If the gas flow meter is not equipped with automatic correction for temperature, pressure, or, if necessary, moisture content:
(A) Determine the temperature and pressure in the biogas that is collected and routed to a destruction device in a location near or representative of the location of the gas flow meter at least once each calendar week; if only one measurement is made each calendar week, there must be at least three days between measurements.
(B) If the CH
(d) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some quantity of biogas is recovered, you must estimate both the annual mass of CH
(1) Estimate the annual mass of CH
(2) For each anaerobic sludge digester, anaerobic reactor, or anaerobic lagoon from which some quantity of biogas is recovered, estimate the annual mass of CH
(e) Estimate the total mass of CH
§ 98.354 Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the request must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2011. The use of best available monitoring methods will not be approved beyond December 31, 2011.
(b) You must determine the concentration of organic material in wastewater treated anaerobically using analytical methods for COD or BOD
(c) You must collect samples representing wastewater influent to the anaerobic wastewater treatment process, following all preliminary and primary treatment steps (e.g., after grit removal, primary clarification, oil-water separation, dissolved air flotation, or similar solids and oil separation processes). You must collect and analyze samples for COD or BOD
(d) You must measure the flowrate of wastewater entering anaerobic wastewater treatment process at least once each calendar week that the process is operating; if only one measurement is made each calendar week, there must be at least three days between measurements. You must measure the flowrate for the 24-hour period for which you collect samples analyzed for COD or BOD
(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).
(2) ASME MFC-5M-1985 (Reaffirmed 1994) Measurement of Liquid Flow in Closed Conduits Using Transit-Time Ultrasonic Flowmeters (incorporated by reference, see § 98.7).
(3) ASME MFC-16-2007 Measurement of Liquid Flow in Closed Conduits with Electromagnetic Flowmeters (incorporated by reference, see § 98.7).
(4) ASTM D1941-91 (Reapproved 2007) Standard Test Method for Open Channel Flow Measurement of Water with the Parshall Flume, approved June 15, 2007, (incorporated by reference, see § 98.7).
(5) ASTM D5614-94 (Reapproved 2008) Standard Test Method for Open Channel Flow Measurement of Water with Broad-Crested Weirs, approved October 1, 2008, (incorporated by reference, see § 98.7).
(e) All wastewater flow measurement devices must be calibrated prior to the first year of reporting and recalibrated either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Wastewater flow measurement devices must be calibrated using the procedures specified by the device manufacturer.
(f) For each anaerobic process (such as anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, you must make the measurements or determinations specified in paragraphs (f)(1) through (f)(3) of this section.
(1) You must continuously measure the biogas flow rate as specified in paragraph (h) of this section and determine the cumulative volume of biogas recovered.
(2) You must determine the CH
(3) As specified in § 98.353(c) and paragraph (h) of this section, you must determine temperature, pressure, and moisture content as necessary to accurately determine the biogas flow rate and CH
(g) For each anaerobic process (such as an anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH
(1) Method 18 at 40 CFR part 60, appendix A-6.
(2) ASTM D1945-03, Standard Test Method for Analysis of Natural Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(3) ASTM D1946-90 (Reapproved 2006), Standard Practice for Analysis of Reformed Gas by Gas Chromatography (incorporated by reference, see § 98.7).
(4) GPA Standard 2261-00, Analysis for Natural Gas and Similar Gaseous Mixtures by Gas Chromatography (incorporated by reference, see § 98.7).
(5) ASTM UOP539-97 Refinery Gas Analysis by Gas Chromatography (incorporated by reference, see § 98.7).
(6) As an alternative to the gas chromatography methods provided in paragraphs (g)(1) through (g)(5) of this section, you may use total gaseous organic concentration analyzers and calculate the CH
(i) Use Method 25A or 25B at 40 CFR part 60, appendix A-7 to determine total gaseous organic concentration. You must calibrate the instrument with CH
(ii) Determine a non-methane organic carbon correction factor at the routine sampling location no less frequently than once a reporting year following the requirements in paragraphs (g)(6)(ii)(A) through (g)(6)(ii)(C) of this section.
(A) Take a minimum of three grab samples of the biogas with a minimum of 20 minutes between samples and determine the methane composition of the biogas using one of the methods specified in paragraphs (g)(1) through (g)(5) of this section.
(B) As soon as practical after each grab sample is collected and prior to the collection of a subsequent grab sample, determine the total gaseous organic concentration of the biogas using either Method 25A or 25B at 40 CFR part 60, appendix A-7 as specified in paragraph (g)(6)(i) of this section.
(C) Determine the arithmetic average methane concentration and the arithmetic average total gaseous organic concentration of the samples analyzed according to paragraphs (g)(6)(ii)(A) and (g)(6)(ii)(B) of this section, respectively, and calculate the non-methane organic carbon correction factor as the ratio of the average methane concentration to the average total gaseous organic concentration. If the ratio exceeds 1, use 1 for the non-methane organic carbon correction factor.
(iii) Calculate the CH
(h) For each anaerobic process (such as an anaerobic reactor, sludge digester, or lagoon) from which biogas is recovered, install, operate, maintain, and calibrate a gas flow meter capable of continuously measuring the volumetric flow rate of the recovered biogas using one of the methods specified in paragraphs (h)(1) through (h)(8) of this section or as specified by the manufacturer. Recalibrate each gas flow meter either biennially (every 2 years) or at the minimum frequency specified by the manufacturer. Except as provided in § 98.353(c)(2)(iii), each gas flow meter must be capable of correcting for the temperature and pressure and, if necessary, moisture content.
(1) ASME MFC-3M-2004, Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).
(2) ASME MFC-4M-1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).
(3) ASME MFC-6M-1998, Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).
(4) ASME MFC-7M-1987 (Reaffirmed 1992), Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).
(5) ASME MFC-11M-2006 Measurement of Fluid Flow by Means of Coriolis Mass Flowmeters (incorporated by reference, see § 98.7). The mass flow must be corrected to volumetric flow based on the measured temperature, pressure, and biogas composition.
(6) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).
(7) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see § 98.7).
(8) Method 2A or 2D at 40 CFR part 60, appendix A-1.
(i) All temperature, pressure, and, moisture content monitors required as specified in paragraph (f) of this section must be calibrated using the procedures and frequencies where specified by the device manufacturer, if not specified use an industry accepted or industry standard practice.
(j) All equipment (temperature, pressure, and moisture content monitors and gas flow meters and gas composition monitors) must be maintained as specified by the manufacturer.
(k) If applicable, the owner or operator must document the procedures used to ensure the accuracy of measurements of COD or BOD
§ 98.355 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required sample is not taken), a substitute data value for the missing parameter must be used in the calculations, according to the following requirements in paragraphs (a) through (c) of this section:
(a) For each missing weekly value of COD or BOD
(b) For each missing value of the CH
(c) If, for a particular parameter, no quality-assured data are available prior to the missing data incident, the substitute data value must be the first quality-assured value obtained after the missing data period. If, for a particular parameter, the “after” value is not obtained by the end of the reporting year, you may use the last quality-assured value obtained “before” the missing data period for the missing data substitution. You must document and keep records of the procedures you use for all such estimates.
§ 98.356 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each wastewater treatment system.
(a) Identify the anaerobic processes used in the industrial wastewater treatment system to treat industrial wastewater and industrial wastewater treatment sludge, provide a unique identifier for each anaerobic process, indicate the average depth in meters of each anaerobic lagoon, and indicate whether biogas generated by each anaerobic process is recovered. Provide a description or diagram of the industrial wastewater treatment system, identifying the processes used, indicating how the processes are related to each other, and providing a unique identifier for each anaerobic process. Each anaerobic process must be identified as one of the following:
(1) Anaerobic reactor.
(2) Anaerobic deep lagoon (depth more than 2 meters).
(3) Anaerobic shallow lagoon (depth less than 2 meters).
(4) Anaerobic sludge digester.
(b) For each anaerobic wastewater treatment process (reactor, deep lagoon, or shallow lagoon) you must report:
(1) Weekly average COD or BOD
(2) Volume of wastewater entering each anaerobic wastewater treatment process for each week the anaerobic process was operated.
(3) Maximum CH
(4) Methane conversion factor (MCF) used as an input to Equation II-1 or II-2 of this subpart, from Table II-1 to this subpart.
(5) Annual mass of CH
(6) If the facility performs an ethanol production processing operation as defined in § 98.358, you must indicate if the facility uses a wet milling process or a dry milling process.
(c) For each anaerobic wastewater treatment process from which biogas is not recovered, you must report the annual CH
(d) For each anaerobic wastewater treatment process and anaerobic sludge digester from which some biogas is recovered, you must report:
(1) Annual quantity of CH
(2) Total weekly volumetric biogas flow for each week (up to 52 weeks/year) that biogas is collected for destruction.
(3) Weekly average CH
(4) Weekly average biogas temperature for each week at which flow is measured for biogas collected for destruction, or statement that temperature is incorporated into monitoring equipment internal calculations.
(5) Whether flow was measured on a wet or dry basis, whether CH
(6) Weekly average biogas pressure for each week at which flow is measured for biogas collected for destruction, or statement that pressure is incorporated into monitoring equipment internal calculations.
(7) CH
(8) Whether destruction occurs at the facility or off-site. If destruction occurs at the facility, also report whether a back-up destruction device is present at the facility, the annual operating hours for the primary destruction device, the annual operating hours for the back-up destruction device (if present), the destruction efficiency for the primary destruction device, and the destruction efficiency for the back-up destruction device (if present).
(9) For each anaerobic process from which some biogas is recovered, you must report the annual CH
(e) The total mass of CH
§ 98.357 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer’s specification used for calibration.
§ 98.358 Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
Biogas means the combination of CO
Dry milling means the process in which shelled corn is milled by dry process, without an initial steeping step.
Ethanol production means an operation that produces ethanol from the fermentation of sugar, starch, grain, or cellulosic biomass feedstocks, or the production of ethanol synthetically from petrochemical feedstocks, such as ethylene or other chemicals.
Food processing means an operation used to manufacture or process meat, poultry, fruits, and/or vegetables as defined under NAICS 3116 (Meat Product Manufacturing) or NAICS 3114 (Fruit and Vegetable Preserving and Specialty Food Manufacturing). For information on NAICS codes, see http://www.census.gov/eos/www/naics/.
Industrial wastewater means water containing wastes from an industrial process. Industrial wastewater includes water which comes into direct contact with or results from the storage, production, or use of any raw material, intermediate product, finished product, by-product, or waste product. Examples of industrial wastewater include, but are not limited to, paper mill white water, wastewater from equipment cleaning, wastewater from air pollution control devices, rinse water, contaminated stormwater, and contaminated cooling water.
Industrial wastewater treatment sludge means solid or semi-solid material resulting from the treatment of industrial wastewater, including but not limited to biosolids, screenings, grit, scum, and settled solids.
Wastewater treatment system means the collection of all processes that treat or remove pollutants and contaminants, such as soluble organic matter, suspended solids, pathogenic organisms, and chemicals from wastewater prior to its reuse or discharge from the facility.
Wet milling means the process in which shelled corn is steeped in a dilute solution of sulfurous acid (sulfur dioxide dissolved in water) prior to further processing.
Weekly average means the sum of all values measured in a calendar week divided by the number of measurements.
Table II-1 to Subpart II of Part 98 – Emission Factors
Factors | Default value | Units |
---|---|---|
B | 0.25 | Kg CH |
B | 0.60 | Kg CH |
MCF – anaerobic reactor | 0.8 | Fraction. |
MCF – anaerobic deep lagoon (depth more than 2 m) | 0.8 | Fraction. |
MCF – anaerobic shallow lagoon (depth less than 2 m) | 0.2 | Fraction. |
Table II-2 to Subpart II of Part 98 – Collection Efficiencies of Anaerobic Processes
Anaerobic process type | Cover type | Methane collection efficiency |
---|---|---|
Covered anaerobic lagoon (biogas capture) | Bank to bank, impermeable | 0.975 |
Modular, impermeable | 0.70 | |
Anaerobic sludge digester; anaerobic reactor | Enclosed Vessel | 0.99 |
Subpart JJ – Manure Management
§ 98.360 Definition of the source category.
(a) This source category consists of livestock facilities with manure management systems that emit 25,000 metric tons CO
(1) Table JJ-1 presents the minimum average annual animal population by animal group that is estimated to emit 25,000 metric tons CO
(2) (i) If a facility has more than one animal group present (e.g., swine and poultry), the facility must determine if they are required to report by calculating the combined animal group factor (CAGF) using equation JJ-1:
(ii) If the calculated CAGF for a facility is less than 1, the facility is not required to report under this rule. If the CAGF is equal to or greater than 1, the facility must use more detailed applicability tables and tools to determine if they are required to report under this rule.
(b) A manure management system (MMS) is a system that stabilizes and/or stores livestock manure, litter, or manure wastewater in one or more of the following system components: Uncovered anaerobic lagoons, liquid/slurry systems with and without crust covers (including but not limited to ponds and tanks), storage pits, digesters, solid manure storage, dry lots (including feedlots), high-rise houses for poultry production (poultry without litter), poultry production with litter, deep bedding systems for cattle and swine, manure composting, and aerobic treatment.
(c) This source category does not include system components at a livestock facility that are unrelated to the stabilization and/or storage of manure such as daily spread or pasture/range/paddock systems or land application activities or any method of manure utilization that is not listed in § 98.360(b).
(d) This source category does not include manure management activities located off site from a livestock facility or off-site manure composting operations.
§ 98.361 Reporting threshold.
Livestock facilities must report GHG emissions under this subpart if the facility meets the reporting threshold as defined in 98.360(a) above, contains a manure management system as defined in 98.360(b) above, and meets the requirements of § 98.2(a)(1).
§ 98.362 GHGs to report.
(a) Livestock facilities must report annual aggregate CH
(1) Uncovered anaerobic lagoons.
(2) Liquid/slurry systems (with and without crust covers, and including but not limited to ponds and tanks).
(3) Storage pits.
(4) Digesters, including covered anaerobic lagoons.
(5) Solid manure storage.
(6) Dry lots, including feedlots.
(7) High-rise houses for poultry production (poultry without litter)
(8) Poultry production with litter.
(9) Deep bedding systems for cattle and swine.
(10) Manure composting.
(11) Aerobic treatment.
(b) A livestock facility that is subject to this rule only because of emissions from manure management system components is not required to report emissions from subparts C through PP (other than subpart JJ) of this part.
(c) A livestock facility that is subject to this part because of emissions from source categories described in subparts C through PP of this part is not required to report emissions under subpart JJ of this part unless emissions from manure management systems are 25,000 metric tons CO
§ 98.363 Calculating GHG emissions.
(a) For all manure management system components listed in 98.360(b) except digesters, estimate the annual CH
(1) Average annual animal populations for static populations (e.g., dairy cows, breeding swine, layers) must be estimated by performing an animal inventory or review of facility records once each reporting year.
(2) Average annual animal populations for growing populations (meat animals such as beef and veal cattle, market swine, broilers, and turkeys) must be estimated each year using the average number of days each animal is kept at the facility and the number of animals produced annually, and an equation similar or equal to Equation JJ-4 below, adapted from Equation 10.1 in 2006 IPCC Guidelines for National Greenhouse Gas Inventories, Volume 4, Chapter 10.
(b) For each digester, calculate the total amount of CH
(1) For each digester, calculate the annual CH
(2) For each digester, calculate the average annual volumetric flow rate, CH
(3) For each digester, calculate the CH
(4) For each digester, calculate the CH
(c) For each MMS component, estimate the annual N
(d) Estimate the annual total facility emissions using Equation JJ-15 of this section.
§ 98.364 Monitoring and QA/QC requirements.
(a) Perform an annual animal inventory or review of facility records (for static populations) or population calculation (for growing populations) to determine the average annual animal population for each animal type (see description in § 98.363(a)(1) and (2)).
(b) Perform an analysis on your operation to determine the fraction of total manure by weight for each animal type that is managed in each on-site manure management system component. If your system changes from previous reporting periods, you must reevaluate the fraction of total manure managed in each system component.
(c) The CH
(d) All temperature and pressure monitors must be calibrated using the procedures and frequencies specified by the manufacturer. All equipment (temperature and pressure monitors) shall be maintained as specified by the manufacturer.
(e) For digesters with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate to provide data for the GHG emissions calculations, using the applicable methods specified in paragraphs (e)(1) through (e)(6) of this section or as specified by the manufacturer.
(1) ASME MFC-3M-2004 Measurement of Fluid Flow in Pipes Using Orifice, Nozzle, and Venturi (incorporated by reference, see § 98.7).
(2) ASME MFC-4M-1986 (Reaffirmed 1997) Measurement of Gas Flow by Turbine Meters (incorporated by reference, see § 98.7).
(3) ASME MFC-6M-1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters (incorporated by reference, see § 98.7).
(4) ASME MFC-7M-1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical Flow Venturi Nozzles (incorporated by reference, see § 98.7).
(5) ASME MFC-14M-2003 Measurement of Fluid Flow Using Small Bore Precision Orifice Meters (incorporated by reference, see § 98.7).
(6) ASME MFC-18M-2001 Measurement of Fluid Flow using Variable Area Meters (incorporated by reference, see § 98.7).
(f) If applicable, the owner or operator shall document the procedures used to ensure the accuracy of gas flow rate, gas composition, temperature, and pressure measurements. These procedures include, but are not limited to, calibration of fuel flow meters and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
(g) Each gas flow meter shall be calibrated prior to the first reporting year and recalibrated either annually or at the minimum frequency specified by the manufacturer, whichever is more frequent. Each gas flow meter must have a rated accuracy of ±5 percent or lower and be capable of correcting for the temperature and pressure and, if the gas composition monitor determines CH
§ 98.365 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, according to the requirements in paragraph (b) of this section.
(b) For missing gas flow rates or CH
§ 98.366 Data reporting requirements.
(a) In addition to the information required by § 98.3(c), each annual report must contain the following information:
(1) List of manure management system components at the facility.
(2) Fraction of manure from each animal type that is handled in each manure management system component.
(3) Average annual animal population (for each animal type) for static populations or the results of Equation JJ-4 for growing populations.
(4) Average number of days that growing animals are kept at the facility (for each animal type).
(5) The number of animals produced annually for growing populations (for each animal type).
(6) Typical animal mass (for each animal type).
(7) Total facility emissions (results of Equation JJ-15).
(8) CH
(9) VS value used (for each animal type).
(10) B
(11) Methane conversion factor used for each MMS component.
(12) Average ambient temperature used to select each methane conversion factor.
(13) N
(14) N value used for each animal type.
(15) N
(b) Facilities with anaerobic digesters must also report:
(1) CH
(2) CH
(3) CH
(4) CH
(5) Total annual volumetric biogas flow for each digester (results of Equation JJ-7).
(6) Average annual CH
(7) Average annual temperature at which gas flow is measured for each digester (results of Equation JJ-9).
(8) Average annual gas flow pressure at which gas flow is measured for each digester (results of Equation JJ-10).
(9) Destruction efficiency used for each digester.
(10) Number of days per year that each digester was operating.
(11) Collection efficiency used for each digester.
§ 98.367 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the calibration records for all monitoring equipment, including the method or manufacturer’s specification used for calibration.
§ 98.368 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table JJ-1 to Subpart JJ of Part 98 – Animal Population Threshold Level Below Which Facilities Are Not Required To Report Emissions Under Subpart JJ
1 2
Animal group | Average annual animal population (Head) 3 |
---|---|
Beef | 29,300 |
Dairy | 3,200 |
Swine | 34,100 |
Poultry: | |
Layers | 723,600 |
Broilers | 38,160,000 |
Turkeys | 7,710,000 |
1 The threshold head populations in this table were calculated using the most conservative assumptions (high VS and N values, maximum ambient temperatures, and the application of an uncertainty factor) to ensure that facilities at or near the 25,000 metric ton CO
2 For facilities with more than one animal group present refer to § 98.360 (2) to estimate the combined animal group factor (CAGF), which is used to determine if a facility may be required to report.
3 For all animal groups except dairy, the average annual animal population represents the total number of animals present at the facility. For dairy facilities, the average annual animal population represents the number of mature dairy cows present at the facility (note that heifers and calves were included in the emission estimates for dairy facilities using the assumption that the average annual animal population of heifers and calves at dairy facilities are equal to 30 percent of the mature dairy cow average annual animal population, therefore the average annual population for dairy facilities should not include heifers and calves, only dairy cows).
Table JJ-2 to Subpart JJ of Part 98 – Waste Characteristics Data
Animal type | Typical animal mass (kg) | Volatile solids excretion rate (kg VS/day/1000 kg animal mass) | Nitrogen excretion rate (kg N/day/1000 kg animal mass) | Maximum methane generation potential, B (m 3 CH |
---|---|---|---|---|
Dairy Cows | 604 | See Table JJ-3 | See Table JJ-3 | 0.24 |
Dairy Heifers | 476 | See Table JJ-3 | See Table JJ-3 | 0.17 |
Dairy Calves | 118 | 6.41 | 0.30 | 0.17 |
Feedlot Steers | 420 | See Table JJ-3 | See Table JJ-3 | 0.33 |
Feedlot heifers | 420 | See Table JJ-3 | See Table JJ-3 | 0.33 |
Market Swine | 16 | 8.80 | 0.60 | 0.48 |
Market Swine 60-119 lbs | 41 | 5.40 | 0.42 | 0.48 |
Market Swine 120-179 lbs | 68 | 5.40 | 0.42 | 0.48 |
Market Swine >180 lbs | 91 | 5.40 | 0.42 | 0.48 |
Breeding Swine | 198 | 2.60 | 0.24 | 0.48 |
Feedlot Sheep | 25 | 9.20 | 0.42 | 0.36 |
Goats | 64 | 9.50 | 0.45 | 0.17 |
Horses | 450 | 10.00 | 0.30 | 0.33 |
Hens >/= 1 yr | 1.8 | 10.09 | 0.83 | 0.39 |
Pullets | 1.8 | 10.09 | 0.62 | 0.39 |
Other Chickens | 1.8 | 10.80 | 0.83 | 0.39 |
Broilers | 0.9 | 15.00 | 1.10 | 0.36 |
Turkeys | 6.8 | 9.70 | 0.74 | 0.36 |
Table JJ-3 to Subpart JJ of Part 98 – State-Specific Volatile Solids (VS) and Nitrogen (N) Excretion Rates for Cattle
State | Volatile solids excretion rate (kg VS/day/1000 kg animal mass) | Nitrogen excretion rate (kg VS/day/1000 kg animal mass) | ||||||
---|---|---|---|---|---|---|---|---|
Dairy cows | Dairy heifers | Feedlot steer | Feedlot heifers | Dairy cows | Dairy heifers | Feedlot steer | Feedlot heifers | |
Alabama | 8.40 | 8.35 | 4.27 | 4.74 | 0.50 | 0.46 | 0.36 | 0.38 |
Alaska | 7.30 | 8.35 | 4.15 | 4.58 | 0.45 | 0.46 | 0.35 | 0.37 |
Arizona | 10.37 | 8.35 | 3.91 | 4.27 | 0.58 | 0.46 | 0.33 | 0.34 |
Arkansas | 7.59 | 8.35 | 3.98 | 4.35 | 0.46 | 0.46 | 0.33 | 0.35 |
California | 10.02 | 8.35 | 3.96 | 4.33 | 0.56 | 0.46 | 0.33 | 0.34 |
Colorado | 10.25 | 8.35 | 3.97 | 4.34 | 0.58 | 0.46 | 0.33 | 0.35 |
Connecticut | 9.22 | 8.35 | 4.41 | 4.93 | 0.53 | 0.46 | 0.37 | 0.40 |
Delaware | 8.63 | 8.35 | 4.19 | 4.64 | 0.51 | 0.46 | 0.35 | 0.37 |
Florida | 8.90 | 8.35 | 4.15 | 4.58 | 0.52 | 0.46 | 0.35 | 0.37 |
Georgia | 9.07 | 8.35 | 4.18 | 4.63 | 0.53 | 0.46 | 0.35 | 0.37 |
Hawaii | 7.00 | 8.35 | 4.15 | 4.58 | 0.44 | 0.46 | 0.35 | 0.37 |
Idaho | 10.11 | 8.35 | 4.03 | 4.42 | 0.57 | 0.46 | 0.34 | 0.35 |
Illinois | 9.07 | 8.35 | 4.15 | 4.59 | 0.52 | 0.46 | 0.35 | 0.37 |
Indiana | 9.38 | 8.35 | 3.98 | 4.35 | 0.54 | 0.46 | 0.33 | 0.35 |
Iowa | 9.46 | 8.35 | 3.93 | 4.28 | 0.54 | 0.46 | 0.33 | 0.34 |
Kansas | 9.63 | 8.35 | 3.97 | 4.35 | 0.55 | 0.46 | 0.33 | 0.35 |
Kentucky | 7.89 | 8.35 | 4.20 | 4.65 | 0.48 | 0.46 | 0.35 | 0.37 |
Louisiana | 7.39 | 8.35 | 4.07 | 4.48 | 0.45 | 0.46 | 0.34 | 0.36 |
Maine | 8.99 | 8.35 | 4.07 | 4.47 | 0.52 | 0.46 | 0.34 | 0.36 |
Maryland | 9.02 | 8.35 | 4.05 | 4.45 | 0.52 | 0.46 | 0.34 | 0.35 |
Massachusetts | 8.63 | 8.35 | 4.15 | 4.58 | 0.51 | 0.46 | 0.35 | 0.37 |
Michigan | 10.05 | 8.35 | 4.00 | 4.38 | 0.57 | 0.46 | 0.34 | 0.35 |
Minnesota | 9.17 | 8.35 | 3.89 | 4.24 | 0.53 | 0.46 | 0.33 | 0.34 |
Mississippi | 8.19 | 8.35 | 4.14 | 4.57 | 0.49 | 0.46 | 0.35 | 0.37 |
Missouri | 8.02 | 8.35 | 4.08 | 4.49 | 0.48 | 0.46 | 0.34 | 0.36 |
Montana | 9.03 | 8.35 | 4.23 | 4.69 | 0.52 | 0.46 | 0.36 | 0.38 |
Nebraska | 9.09 | 8.35 | 3.98 | 4.35 | 0.53 | 0.46 | 0.33 | 0.35 |
Nevada | 9.65 | 8.35 | 4.07 | 4.48 | 0.55 | 0.46 | 0.34 | 0.36 |
New Hampshire | 9.44 | 8.35 | 3.94 | 4.30 | 0.54 | 0.46 | 0.33 | 0.34 |
New Jersey | 8.51 | 8.35 | 3.98 | 4.36 | 0.50 | 0.46 | 0.33 | 0.35 |
New Mexico | 10.34 | 8.35 | 3.88 | 4.22 | 0.58 | 0.46 | 0.32 | 0.33 |
New York | 9.42 | 8.35 | 3.75 | 4.05 | 0.54 | 0.46 | 0.31 | 0.32 |
North Carolina | 9.38 | 8.35 | 4.20 | 4.65 | 0.55 | 0.46 | 0.35 | 0.37 |
North Dakota | 8.40 | 8.35 | 3.88 | 4.22 | 0.50 | 0.46 | 0.32 | 0.34 |
Ohio | 9.01 | 8.35 | 3.96 | 4.33 | 0.52 | 0.46 | 0.33 | 0.34 |
Oklahoma | 8.58 | 8.35 | 3.98 | 4.35 | 0.50 | 0.46 | 0.33 | 0.35 |
Oregon | 9.40 | 8.35 | 4.06 | 4.46 | 0.54 | 0.46 | 0.34 | 0.36 |
Pennsylvania | 9.26 | 8.35 | 3.98 | 4.35 | 0.53 | 0.46 | 0.33 | 0.35 |
Rhode Island | 8.94 | 8.35 | 4.36 | 4.87 | 0.52 | 0.46 | 0.37 | 0.39 |
South Carolina | 9.05 | 8.35 | 4.15 | 4.58 | 0.53 | 0.46 | 0.35 | 0.37 |
South Dakota | 9.45 | 8.35 | 4.01 | 4.39 | 0.54 | 0.46 | 0.34 | 0.35 |
Tennessee | 8.60 | 8.35 | 4.48 | 5.02 | 0.51 | 0.46 | 0.38 | 0.40 |
Texas | 9.51 | 8.35 | 3.95 | 4.32 | 0.54 | 0.46 | 0.33 | 0.34 |
Utah | 9.70 | 8.35 | 3.88 | 4.22 | 0.55 | 0.46 | 0.32 | 0.34 |
Vermont | 9.03 | 8.35 | 4.10 | 4.52 | 0.52 | 0.46 | 0.34 | 0.36 |
Virginia | 9.02 | 8.35 | 3.98 | 4.35 | 0.53 | 0.46 | 0.33 | 0.35 |
Washington | 10.36 | 8.35 | 4.07 | 4.47 | 0.58 | 0.46 | 0.34 | 0.36 |
West Virginia | 8.13 | 8.35 | 4.65 | 5.25 | 0.48 | 0.46 | 0.40 | 0.42 |
Wisconsin | 9.34 | 8.35 | 3.95 | 4.31 | 0.54 | 0.46 | 0.33 | 0.34 |
Wyoming | 9.29 | 8.35 | 4.17 | 4.61 | 0.53 | 0.46 | 0.35 | 0.37 |
Table JJ-4 to Subpart JJ of Part 98 – Volatile Solids and Nitrogen Removal through Solids Separation
Type of solids separation | Volatile solids removal (decimal) | Nitrogen removal (decimal) |
---|---|---|
Gravity | 0.60 | 0.60 |
Mechanical: | ||
Stationary Screen | 0.20 | 0.10 |
Vibrating Screen | 0.15 | 0.15 |
Screw Press | 0.25 | 0.15 |
Centrifuge | 0.50 | 0.25 |
Roller drum | 0.25 | 0.15 |
Belt press/screen | 0.50 | 0.30 |
Table JJ-6 to Subpart JJ of Part 98 – Collection Efficiencies of Anaerobic Digesters
Anaerobic digester type | Cover type | Methane collection efficiency |
---|---|---|
Covered anaerobic lagoon (biogas capture) | Bank to bank, impermeable | 0.975 |
Modular, impermeable | 0.70 | |
Complete mix, fixed film, or plug flow digester | Enclosed Vessel | 0.99 |
Table JJ-7 to Subpart JJ of Part 98 – Nitrous Oxide Emission Factors (kg N2 O-N/kg Kjdl N)
Manure management system component | N |
---|---|
Uncovered anaerobic lagoon | 0 |
Liquid/Slurry (with crust cover) | 0.005 |
Liquid/Slurry (without crust cover) | 0 |
Storage pits | 0.002 |
Digesters | 0 |
Solid manure storage | 0.005 |
Dry lots (including feedlots) | 0.02 |
High-rise house for poultry (poultry without litter) | 0.001 |
Poultry production with litter | 0.001 |
Deep bedding for cattle and swine (active mix) | 0.07 |
Deep bedding for cattle and swine (no mix) | 0.01 |
Manure Composting (in vessel) | 0.006 |
Manure Composting (intensive) | 0.1 |
Manure Composting (passive) | 0.01 |
Manure Composting (static) | 0.006 |
Aerobic Treatment (forced aeration) | 0.005 |
Aerobic Treatment (natural aeration) | 0.01 |
Subpart KK [Reserved]
Subpart LL – Suppliers of Coal-based Liquid Fuels
§ 98.380 Definition of the source category.
This source category consists of producers, importers, and exporters of products listed in Table MM-1 of subpart MM that are coal-based (coal-to-liquid products).
(a) A producer is the owner or operator of a coal-to-liquids facility. A coal-to-liquids facility is any facility engaged in converting coal into liquid products using a process involving conversion of coal into gas and then into liquids (e.g., Fischer-Tropsch) or conversion of coal directly into liquids (i.e., direct liquefaction).
(b) An importer or exporter shall have the same meaning given in § 98.6.
§ 98.381 Reporting threshold.
Any supplier of coal-to-liquid products who meets the requirements of § 98.2(a)(4) must report GHG emissions.
§ 98.382 GHGs to report.
Suppliers of coal-based liquid fuels must report the CO
§ 98.383 Calculating GHG emissions.
Suppliers of coal-based liquid fuels must follow the calculation methods of § 98.393 as if they applied to the appropriate coal-to-liquid product supplier (i.e., calculation methods for refiners apply to producers of coal-to-liquid products and calculation methods for importers and exporters of petroleum products apply to importers and exporters of coal-to-liquid products).
(a) In calculation methods in § 98.393 for petroleum products or petroleum-based products, suppliers of coal-to-liquid products shall also include coal-to-liquid products.
(b) In calculation methods in § 98.393 for non-crude feedstocks or non-crude petroleum feedstocks, producers of coal-to-liquid products shall also include coal-to-liquid products that enter the facility to be further processed or otherwise used on site.
(c) In calculation methods in § 98.393 for petroleum feedstocks, suppliers of coal-to-liquid products shall also include coal and coal-to-liquid products that enter the facility to be further processed or otherwise used on site.
§ 98.384 Monitoring and QA/QC requirements.
Suppliers of coal-based liquid fuels must follow the monitoring and QA/QC requirements in § 98.394 as if they applied to the appropriate coal-to-liquid product supplier. Any monitoring and QA/QC requirement for petroleum products in § 98.394 also applies to coal-to-liquid products.
§ 98.385 Procedures for estimating missing data.
Suppliers of coal-based liquid fuels must follow the procedures for estimating missing data in § 98.395 as if they applied to the appropriate coal-to-liquid product supplier. Any procedure for estimating missing data for petroleum products in § 98.395 also applies to coal-to-liquid products.
§ 98.386 Data reporting requirements.
In addition to the information required by § 98.3(c), the following requirements apply:
(a) Producers shall report the following information for each coal-to-liquid facility:
(1) [Reserved]
(2) For each product listed in Table MM-1 of subpart MM of this part that enters the coal-to-liquid facility to be further processed or otherwise used on site, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
(3) For each feedstock reported in paragraph (a)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product).
(4)-(5) [Reserved]
(6) For each product (leaving the coal-to-liquid facility) listed in Table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. Those products that enter the facility, but are not reported in (a)(2), shall not be reported under this paragraph.
(7) For each product reported in paragraph (a)(6) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product).
(8) [Reserved]
(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report:
(i) The number of samples collected according to § 98.394(c).
(ii) The sampling standard method used.
(iii) The carbon share test results in percent mass.
(iv) The standard method used to test carbon share.
(v) The calculated CO
(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report:
(i) The density test results in metric tons per barrel.
(ii) The standard method used to test density.
(11) For every product reported in paragraph (a)(6) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report:
(i) The number of samples collected according to § 98.394(c).
(ii) The sampling standard method used.
(iii) The carbon share test results in percent mass.
(iv) The standard method used to test carbon share.
(v) The calculated CO
(12) For every non-solid product reported in paragraph (a)(6) of this section for which Calculation Method 2 of subpart MM of this part was used to determine an emissions factor, report:
(i) The density test results in metric tons per barrel.
(ii) The standard method used to test density.
(13) [Reserved]
(14) For each specific type of biomass that enters the coal-to-liquid facility to be co-processed with fossil fuel-based feedstock to produce a product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels.
(15) [Reserved]
(16) The CO
(17) The CO
(18) Annual CO
(19) Annual CO
(20) Annual quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. Report only quantities of bulk NGLs not reported in paragraph (a)(2) of this section.
(b) In addition to the information required by § 98.3(c), each importer shall report all of the following information at the corporate level:
(1) [Reserved]
(2) For each product listed in Table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product as listed in Table MM-1 of subpart MM of this part.
(3) For each product reported in paragraph (b)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product).
(4) [Reserved]
(5) For each product reported in paragraph (b)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) used was used to determine an emissions factor, report:
(i) The number of samples collected according to § 98.394(c)
(ii) The sampling standard method used.
(iii) The carbon share test results in percent mass.
(iv) The standard method used to test carbon share.
(v) The calculated CO
(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report:
(i) The density test results in metric tons per barrel.
(ii) The standard method used to test density.
(7) The CO
(8) The total sum of CO
(c) In addition to the information required by § 98.3(c), each exporter shall report all of the following information at the corporate level:
(1) [Reserved]
(2) For each product listed in table MM-1 of subpart MM of this part, report the total annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
(3) For each product reported in paragraph (c)(2) of this section that was produced by blending a fossil fuel-based product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this section that is fossil fuel-based (excluding any denaturant that may be present in any ethanol product).
(4) [Reserved]
(5) For each product reported in paragraph (c)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) was used to determine an emissions factor, report:
(i) The number of samples collected according to § 98.394(c).
(ii) The sampling standard method used.
(iii) The carbon share test results in percent mass.
(iv) The standard method used to test carbon share.
(v) The calculated CO
(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Method 2 in § 98.393(f)(2) used was used to determine an emissions factor, report:
(i) The density test results in metric tons per barrel.
(ii) The standard method used to test density.
(7) The CO
(8) Total sum of CO
(d) Blended feedstock and products. (1) Producers, exporters, and importers must report the following information for each blended product and feedstock where emissions were calculated according to § 98.393(i):
(i) Volume or mass of each blending component.
(ii) The CO
(iii) Whether it is a blended feedstock or a blended product.
(2) For a product that enters the facility to be further refined or otherwise used on site that is a blended feedstock, producers must meet the reporting requirements of paragraph (a)(2) of this section by reflecting the individual components of the blended feedstock.
(3) For a product that is produced, imported, or exported that is a blended product, producers, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.
§ 98.387 Records that must be retained.
Suppliers of coal-based liquid fuels must retain records according to the requirements in § 98.397 as if they applied to the appropriate coal-to-liquid product supplier (e.g., retaining copies of all reports submitted to EPA under § 98.386 and records to support information contained in those reports). Any records for petroleum products that are required to be retained in § 98.397 are also required for coal-to-liquid products.
§ 98.388 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart MM – Suppliers of Petroleum Products
§ 98.390 Definition of the source category.
This source category consists of petroleum refineries and importers and exporters of petroleum products and natural gas liquids as listed in Table MM-1 of this subpart.
(a) A petroleum refinery for the purpose of this subpart is any facility engaged in producing petroleum products through the distillation of crude oil.
(b) A refiner is the owner or operator of a petroleum refinery.
(c) Importer has the same meaning given in § 98.6 and includes any entity that imports petroleum products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an importer if it otherwise satisfies the aforementioned definition.
(d) Exporter has the same meaning given in § 98.6 and includes any entity that exports petroleum products or natural gas liquids as listed in Table MM-1 of this subpart. Any blender or refiner of refined or semi-refined petroleum products shall be considered an exporter if it otherwise satisfies the aforementioned definition.
§ 98.391 Reporting threshold.
Any supplier of petroleum products who meets the requirements of § 98.2(a)(4) must report GHG emissions.
§ 98.392 GHGs To report.
Suppliers of petroleum products must report the CO
§ 98.393 Calculating GHG emissions.
(a) Calculation for individual products produced, imported, or exported. (1) Except as provided in paragraphs (h) and (i) of this section, any refiner, importer, or exporter shall calculate CO
(2) In the event that an individual petroleum product is produced as a solid rather than liquid any refiner, importer, or exporter shall calculate CO
(b) Calculation for individual products that enter a refinery as a non-crude feedstock. (1) Except as provided in paragraphs (h) and (i) of this section, any refiner shall calculate CO
(2) In the event that a non-crude feedstock enters a refinery as a solid rather than liquid, the refiner shall calculate CO
(c) Calculation for biomass co-processed with petroleum feedstocks. (1) Refiners shall calculate CO
(2) In the event that biomass enters a refinery as a solid rather than liquid and is co-processed with petroleum feedstocks, the refiner shall calculate CO
(d) Summary calculation for refinery products. Refiners shall calculate annual CO
(e) Summary calculation for importer and exporter products. Importers and exporters shall calculate annual CO
(f) Emission factors for petroleum products and natural gas liquids. The emission factor (EF
(1) Calculation Method 1. To determine the emission factor (i.e., EF
(2) Calculation Method 2. (i) For solid products, develop emission factors according to Equation MM-6 of this section using a value of 1 for density and direct measurements of carbon share according to methods set forth in § 98.394(c). For all other products, develop emission factors according to Equation MM-6 of this section using direct measurements of density and carbon share according to methods set forth in § 98.394(c).
(ii) If you use a standard method that involves gas chromatography to determine the percent mass of each component in a product, calculate the product’s carbon share using Equation MM-7 of this section.
(g) Emission factors for biomass co-processed with petroleum feedstocks. Refiners shall use the most appropriate default CO
(h) Special procedures for blended biomass-based fuels. In the event that some portion of a petroleum product is biomass-based and was not derived by co-processing biomass and petroleum feedstocks together (i.e., the petroleum product was produced by blending a petroleum-based product with a biomass-based fuel), the reporting party shall calculate emissions for the petroleum product according to one of the methods in paragraphs (h)(1) through (h)(4) of this section, as appropriate.
(1) A reporter using Calculation Method 1 to determine the emission factor of a petroleum product shall calculate the CO
(2) A refinery using Calculation Method 1 of this subpart to determine the emission factor of a non-crude petroleum feedstock shall calculate the CO
(3) Calculation Method 2 procedures for products. (i) A reporter using Calculation Method 2 of this subpart to determine the emission factor of a petroleum product that does not contain denatured ethanol must calculate the CO
(ii) In the event that a petroleum product contains denatured ethanol, importers and exporters must follow Calculation Method 1 procedures in paragraph (h)(1) of this section; and refineries must sample the petroleum portion of the blended biomass-based fuel prior to blending and calculate CO
(4) Calculation Method 2 procedures for non-crude feedstocks. (i) A refiner using Calculation Method 2 of this subpart to determine the emission factor of a non-crude petroleum feedstock that does not contain denatured ethanol must calculate the CO
(ii) In the event that a non-crude feedstock contains denatured ethanol, refiners must follow Calculation Method 1 procedures in paragraph (h)(2) of this section.
(i) Optional procedures for blended products that do not contain biomass. (1) In the event that a reporter produces, imports, or exports a blended product that does not include biomass, the reporter may calculate emissions for the blended product according to the method in paragraph (i)(2) of this section. In the event that a refiner receives a blended non-crude feedstock that does not include biomass, the refiner may calculate emission for the blended non-crude feedstock according to the method in paragraph (i)(3) of this section. The procedures in this section may be used only if all of the following criteria are met:
(i) The reporter knows the relative proportion of each component of the blend (i.e., the mass or volume percentage).
(ii) Each component of blended product “i” or blended non-crude feedstock “j” meets the strict definition of a product listed in Table MM-1 to subpart MM.
(iii) The blended product or non-crude feedstock is not comprised entirely of natural gas liquids.
(iv) The reporter uses Calculation Method 1.
(v) Solid components are blended only with other solid components.
(2) The reporter must calculate emissions for the blended product using Equation MM-12 of this section in place of Equation MM-1 of this section.
(3) For refineries, the reporter must calculate emissions for the blended non-crude feedstock using Equation MM-13 of this section in place of Equation MM-2 of this section.
(4) For refineries, if a blending component “k” used in paragraph (i)(2) of this section enters the refinery before blending as non-crude feedstock:
(i) The emissions that would result from the complete combustion or oxidation of non-crude feedstock “k” must still be calculated separately using Equation MM-2 of this section and applied in Equation MM-4 of this section.
(ii) The quantity of blending component “k” applied in Equation MM-12 of this section and the quantity of non-crude feedstock “k” applied in Equation MM-2 of this section must be determined using the same method or practice.
§ 98.394 Monitoring and QA/QC requirements.
(a) Determination of quantity. (1) The quantity of petroleum products, natural gas liquids, and biomass, shall be determined as follows:
(i) Where an appropriate standard method published by a consensus-based standards organization exists, such a method shall be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(ii) Where no appropriate standard method developed by a consensus-based standards organization exists, industry standard practices shall be followed.
(iii) For products that are liquid at 60 degrees Fahrenheit and one standard atmosphere, all measurements of quantity shall be temperature-adjusted and pressure-adjusted to these conditions. For all other products, reporters shall use appropriate standard conditions specified in the standard method; if temperature and pressure conditions are not specified in the standard method or if a reporter uses an industry standard practice to determine quantity, the reporter shall use appropriate standard conditions according to established industry practices.
(2) All measurement equipment (including, but not limited to, flow meters and tank gauges) used for compliance with this subpart shall be appropriate for the standard method or industry standard practice followed under paragraph (a)(1)(i) or (a)(1)(ii) of this section.
(3) The annual quantity of crude oil received shall be determined according to one of the following methods. You may use an appropriate standard method published by a consensus-based standards organization or you may use an industry standard practice.
(b) Equipment Calibration. (1) All measurement equipment shall be calibrated prior to its first use for reporting under this subpart, using an appropriate standard method published by a consensus based standards organization or according to the equipment manufacturer’s directions.
(2) Measurement equipment shall be recalibrated at the minimum frequency specified by the standard method used or by the equipment manufacturer’s directions.
(3) For units and processes that operate continuously with infrequent outages, it may not be possible to complete the calibration of a flow meter or other measurement device without disrupting normal process operation. In such cases, the owner or operator may postpone the calibration until the next scheduled maintenance outage. The best available information from company records may be used in the interim. Such postponements shall be documented in the monitoring plan that is required under § 98.3(g)(5).
(c) Procedures for Calculation Method 2 of this subpart. (1) Reporting parties shall collect one sample of each petroleum product or natural gas liquid on any day of each calendar month of the reporting year in which the quantity of that product was measured in accordance with the requirements of this subpart. For example, if a given product was measured as entering the refinery continuously throughout the reporting year, twelve samples of that product shall be collected over the reporting year, one on any day of each calendar month of that year. If a given product was only measured from April 15 through June 10 of the reporting year, a refiner would collect three samples during that year, one during each of the calendar months of April, May and June on a day when the product was measured as either entering or exiting the refinery. Each sample shall be collected using an appropriate standard method published by a consensus-based standards organization.
(2) Mixing and handling of samples shall be performed using an appropriate standard method published by a consensus-based standards organization.
(3) Density measurement.
(i) For all products that are not solid, reporters shall test for density using an appropriate standard method published by a consensus-based standards organization.
(ii) The density value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative density value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the density value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample.
(iii) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a consensus-based standards organization.
(iv) All measurements of density shall be temperature-adjusted and pressure-adjusted to the conditions assumed for determining the quantities of the product reported under this subpart.
(4) Carbon share measurement.
(i) Reporters shall test for carbon share using an appropriate standard method published by a consensus-based standards organization.
(ii) If a standard method that involves gas chromatography is used to determine the percent mass of each component in a product, the molecular formula for each component shall be obtained from the information provided in the standard method and the atomic mass of each element in a given molecular component shall be obtained from the periodic table of the elements.
(iii) The carbon share value for a given petroleum product shall be generated by either making a physical composite of all of the samples collected for the reporting year and testing that single sample or by measuring the individual samples throughout the year and defining the representative carbon share value for the sample set by numerical means, i.e., a mathematical composite. If a physical composite is chosen as the option to obtain the carbon share value, the reporter shall submit each of the individual samples collected during the reporting year to the laboratory responsible for generating the composite sample.
(iv) For physical composites, the reporter shall handle the individual samples and the laboratory shall mix them in accordance with an appropriate standard method published by a consensus-based standards organization.
§ 98.395 Procedures for estimating missing data.
(a) Determination of quantity. Whenever the quality assurance procedures in § 98.394(a) cannot be followed to measure the quantity of one or more petroleum products, natural gas liquids, types of biomass, feedstocks, or crude oil during any period (e.g., if a meter malfunctions), the following missing data procedures shall be used:
(1) For quantities of a product that are purchased or sold, a period of missing data shall be substituted using a reporter’s established procedures for billing purposes in that period as agreed to by the party selling or purchasing the product.
(2) For quantities of a product that are not purchased or sold but of which the custody is transferred, a period of missing data shall be substituted using a reporter’s established procedures for tracking purposes in that period as agreed to by the party involved in custody transfer of the product.
(b) Determination of emission factor. Whenever any of the procedures in § 98.394(c) cannot be followed to develop an emission factor for any reason, Calculation Method 1 of this subpart must be used in place of Calculation Method 2 of this subpart for the entire reporting year.
§ 98.396 Data reporting requirements.
In addition to the information required by § 98.3(c), the following requirements apply:
(a) Refiners shall report the following information for each facility:
(1) [Reserved]
(2) For each petroleum product or natural gas liquid listed in Table MM-1 of this subpart that enters the refinery to be further refined or otherwise used on site, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
(3) For each feedstock reported in paragraph (a)(2) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(2) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product).
(4)-(5) [Reserved]
(6) For each petroleum product and natural gas liquid (ex refinery gate) listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product. Petroleum products and natural gas liquids that enter the refinery, but are not reported in (a)(2), shall not be reported under this paragraph.
(7) For each product reported in paragraph (a)(6) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (a)(6) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product).
(8) [Reserved]
(9) For every feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
(i) The number of samples collected according to § 98.394(c)
(ii) The sampling standard method used.
(iii) The carbon share test results in percent mass.
(iv) The standard method used to test carbon share.
(v) The calculated CO
(10) For every non-solid feedstock reported in paragraph (a)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
(i) The density test results in metric tons per barrel.
(ii) The standard method used to test density.
(11) For every petroleum product and natural gas liquid reported in paragraph (a)(6) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
(i) The number of samples collected according to § 98.394(c).
(ii) The sampling standard method used.
(iii) The carbon share test results in percent mass.
(iv) The standard method used to test carbon share.
(v) The calculated CO
(12) For every non-solid petroleum product and natural gas liquid reported in paragraph (a)(6) for which Calculation Method 2 was used to determine an emissions factor, report:
(i) The density test results in metric tons per barrel.
(ii) The standard method used to test density.
(13) [Reserved]
(14) For each specific type of biomass that enters the refinery to be co-processed with petroleum feedstocks to produce a petroleum product reported in paragraph (a)(6) of this section, report the annual quantity in metric tons or barrels.
(15) [Reserved]
(16) The CO
(17) The CO
(18) The CO
(19) The sum of CO
(20) For all crude oil that enters the refinery, report the annual quantity in barrels.
(21) The quantity of bulk NGLs in metric tons or barrels received for processing during the reporting year. Report only quantities of bulk NGLs not reported in (a)(2) of this section.
(22) Volume of crude oil in barrels that you injected into a crude oil supply or reservoir.
(b) In addition to the information required by § 98.3(c), each importer shall report all of the following information at the corporate level:
(1) [Reserved]
(2) For each petroleum product and natural gas liquid listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
(3) For each product reported in paragraph (b)(2) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (b)(2) of this section that is petroleum-based (excluding any denaturant that may be present in any ethanol product).
(4) [Reserved]
(5) For each product reported in paragraph (b)(2) of this section for which Calculation Method 2 of this subpart used was used to determine an emissions factor, report:
(i) The number of samples collected according to § 98.394(c).
(ii) The sampling standard method used.
(iii) The carbon share test results in percent mass.
(iv) The standard method used to test carbon share.
(v) The calculated CO
(6) For each non-solid product reported in paragraph (b)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
(i) The density test results in metric tons per barrel.
(ii) The standard method used to test density.
(7) The CO
(8) The sum of CO
(c) In addition to the information required by § 98.3(c), each exporter shall report all of the following information at the corporate level:
(1) [Reserved]
(2) For each petroleum product and natural gas liquid listed in Table MM-1 of this subpart, report the annual quantity in metric tons or barrels. For natural gas liquids, quantity shall reflect the individual components of the product.
(3) For each product reported in paragraph (c)(2) of this section that was produced by blending a petroleum-based product with a biomass-based product, report the percent of the volume reported in paragraph (c)(2) of this section that is petroleum based (excluding any denaturant that may be present in any ethanol product).
(4) [Reserved]
(5) For each product reported in paragraph (c)(2) of this section for which Calculation Method 2 of this subpart was used to determine an emissions factor, report:
(i) The number of samples collected according to § 98.394(c).
(ii) The sampling standard method used.
(iii) The carbon share test results in percentmass.
(iv) The standard method used to test carbon share.
(v) The calculated CO
(6) For each non-solid product reported in paragraph (c)(2) of this section for which Calculation Method 2 of this subpart used was used to determine an emissions factor, report:
(i) The density test results in metric tons per barrel.
(ii) The standard method used to test density.
(7) The CO
(8) The sum of CO
(d) Blended non-crude feedstock and products. (1) Refineries, exporters, and importers must report the following information for each blended product and non-crude feedstock where emissions were calculated according to § 98.393(i):
(i) Volume or mass of each blending component.
(ii) The CO
(iii) Whether it is a blended non-crude feedstock or a blended product.
(2) For a product that enters the refinery to be further refined or otherwise used on site that is a blended non-crude feedstock, refiners must meet the reporting requirements of paragraph (a)(2) of this section by reflecting the individual components of the blended non-crude feedstock.
(3) For a product that is produced, imported, or exported that is a blended product, refiners, importers, and exporters must meet the reporting requirements of paragraphs (a)(6), (b)(2), and (c)(2) of this section, as applicable, by reflecting the individual components of the blended product.
§ 98.397 Records that must be retained.
(a) All reporters shall retain copies of all reports submitted to EPA under § 98.396. In addition, all reporters shall maintain sufficient records to support information contained in those reports, including but not limited to information on the characteristics of their feedstocks and products.
(b) Reporters shall maintain records to support quantities that are reported under this subpart, including records documenting any estimations of missing data and the number of calendar days in the reporting year for which substitute data procedures were followed. For all reported quantities of petroleum products, natural gas liquids, and biomass, reporters shall maintain metering, gauging, and other records normally maintained in the course of business to document product and feedstock flows including the date of initial calibration and the frequency of recalibration for the measurement equipment used.
(c) Reporters shall retain laboratory reports, calculations and worksheets used to estimate the CO
(d) Reporters shall maintain laboratory reports, calculations and worksheets used in the measurement of density and carbon share for any petroleum product or natural gas liquid for which CO
(e) Estimates of missing data shall be documented and records maintained showing the calculations.
(f) Reporters described in this subpart shall also retain all records described in § 98.3(g).
§ 98.398 Definitions.
Except as specified in this section, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Bulk NGLs for purposes of reporting under this subpart means mixtures of NGLs that are sold or delivered as undifferentiated product.
Natural Gas Liquids (NGLs) for the purposes of reporting under this subpart means hydrocarbons that are separated from natural gas as liquids through the process of absorption, condensation, adsorption, or other methods, and are sold or delivered as differentiated product. Generally, such liquids consist of ethane, propane, butanes, or pentanes plus.
Table MM-1 to Subpart MM of Part 98 – Default Factors for Petroleum Products and Natural Gas Liquids
1 2
Products | Column A: density (metric tons/bbl) | Column B: carbon share (% of mass) | Column C: emission factor (metric tons CO |
---|---|---|---|
Conventional – Summer | |||
Regular | 0.1181 | 86.66 | 0.3753 |
Midgrade | 0.1183 | 86.63 | 0.3758 |
Premium | 0.1185 | 86.61 | 0.3763 |
Conventional – Winter | |||
Regular | 0.1155 | 86.50 | 0.3663 |
Midgrade | 0.1161 | 86.55 | 0.3684 |
Premium | 0.1167 | 86.59 | 0.3705 |
Reformulated – Summer | |||
Regular | 0.1167 | 86.13 | 0.3686 |
Midgrade | 0.1165 | 86.07 | 0.3677 |
Premium | 0.1164 | 86.00 | 0.3670 |
Reformulated – Winter | |||
Regular | 0.1165 | 86.05 | 0.3676 |
Midgrade | 0.1165 | 86.06 | 0.3676 |
Premium | 0.1166 | 86.06 | 0.3679 |
Gasoline – Other | 0.1185 | 86.61 | 0.3763 |
CBOB – Summer | |||
Regular | 0.1181 | 86.66 | 0.3753 |
Midgrade | 0.1183 | 86.63 | 0.3758 |
Premium | 0.1185 | 86.61 | 0.3763 |
CBOB – Winter | |||
Regular | 0.1155 | 86.50 | 0.3663 |
Midgrade | 0.1161 | 86.55 | 0.3684 |
Premium | 0.1167 | 86.59 | 0.3705 |
RBOB – Summer | |||
Regular | 0.1167 | 86.13 | 0.3686 |
Midgrade | 0.1165 | 86.07 | 0.3677 |
Premium | 0.1164 | 86.00 | 0.3670 |
RBOB – Winter | |||
Regular | 0.1165 | 86.05 | 0.3676 |
Midgrade | 0.1165 | 86.06 | 0.3676 |
Premium | 0.1166 | 86.06 | 0.3679 |
Blendstocks – Other | 0.1185 | 86.61 | 0.3763 |
Methanol | 0.1268 | 37.48 | 0.1743 |
GTBA | 0.1257 | 64.82 | 0.2988 |
MTBE | 0.1181 | 68.13 | 0.2950 |
ETBE | 0.1182 | 70.53 | 0.3057 |
TAME | 0.1229 | 70.53 | 0.3178 |
DIPE | 0.1156 | 70.53 | 0.2990 |
Distillate No. 1 | |||
Ultra Low Sulfur | 0.1346 | 86.40 | 0.4264 |
Low Sulfur | 0.1346 | 86.40 | 0.4264 |
High Sulfur | 0.1346 | 86.40 | 0.4264 |
Distillate No. 2 | |||
Ultra Low Sulfur | 0.1342 | 87.30 | 0.4296 |
Low Sulfur | 0.1342 | 87.30 | 0.4296 |
High Sulfur | 0.1342 | 87.30 | 0.4296 |
Distillate Fuel Oil No. 4 | 0.1452 | 86.47 | 0.4604 |
Residual Fuel Oil No. 5 (Navy Special) | 0.1365 | 85.67 | 0.4288 |
Residual Fuel Oil No. 6 (a.k.a. Bunker C) | 0.1528 | 84.67 | 0.4744 |
Kerosene-Type Jet Fuel | 0.1294 | 86.30 | 0.4095 |
Kerosene | 0.1346 | 86.40 | 0.4264 |
Diesel – Other | 0.1452 | 86.47 | 0.4604 |
Naphthas ( | 0.1158 | 84.11 | 0.3571 |
Other Oils (>401 °F) | 0.1390 | 87.30 | 0.4450 |
Heavy Gas Oils | 0.1476 | 85.80 | 0.4643 |
Residuum | 0.1622 | 85.70 | 0.5097 |
Aviation Gasoline | 0.1120 | 85.00 | 0.3490 |
Special Naphthas | 0.1222 | 84.76 | 0.3798 |
Lubricants | 0.1428 | 85.80 | 0.4492 |
Waxes | 0.1285 | 85.30 | 0.4019 |
Petroleum Coke | 0.1818 | 92.28 | 0.6151 |
Asphalt and Road Oil | 0.1634 | 83.47 | 0.5001 |
Still Gas | 0.1405 | 77.70 | 0.4003 |
Ethane 3 | 0.0579 | 79.89 | 0.170 |
Ethylene 4 | 0.0492 | 85.63 | 0.154 |
Propane 3 | 0.0806 | 81.71 | 0.241 |
Propylene 3 | 0.0827 | 85.63 | 0.260 |
Butane 3 | 0.0928 | 82.66 | 0.281 |
Butylene 3 | 0.0972 | 85.63 | 0.305 |
Isobutane 3 | 0.0892 | 82.66 | 0.270 |
Isobutylene 3 | 0.0949 | 85.63 | 0.298 |
Isobutylene | 0.0936 | 85.63 | 0.2939 |
Pentanes Plus | 0.1055 | 83.63 | 0.3235 |
Miscellaneous Products | 0.1380 | 85.49 | 0.4326 |
1 In the case of products blended with some portion of biomass-based fuel, the carbon share in Table MM-1 of this subpart represents only the petroleum-based components.
2 Products that are derived entirely from biomass should not be reported, but products that were derived from both biomass and a petroleum product (i.e., co-processed) should be reported as the petroleum product that it most closely represents.
3 The density and emission factors for components of LPG determined at 60 degrees Fahrenheit and saturation pressure (LPGs other than ethylene).
4 The density and emission factor for ethylene determined at 41 degrees Fahrenheit and saturation pressure.
Table MM-2 to Subpart MM of Part 98 – Default Factors for Biomass-Based Fuels and Biomass
Biomass-based fuel and biomass | Column A: Density (metric tons/bbl) | Column B: Carbon share (% of mass) | Column C: Emission factor (metric tons CO |
---|---|---|---|
Ethanol (100%) | 0.1267 | 52.14 | 0.2422 |
Biodiesel (100%, methyl ester) | 0.1396 | 77.30 | 0.3957 |
Rendered Animal Fat | 0.1333 | 76.19 | 0.3724 |
Vegetable Oil | 0.1460 | 76.77 | 0.4110 |
Subpart NN – Suppliers of Natural Gas and Natural Gas Liquids
§ 98.400 Definition of the source category.
This supplier category consists of natural gas liquids fractionators and local natural gas distribution companies.
(a) Natural gas liquids fractionators are installations that fractionate natural gas liquids (NGLs) into their constituent liquid products or mixtures of products (ethane, propane, normal butane, isobutane or pentanes plus) for supply to downstream facilities.
(b) Local Distribution Companies (LDCs) are companies that own or operate distribution pipelines, not interstate pipelines or intrastate pipelines, that physically deliver natural gas to end users and that are within a single state that are regulated as separate operating companies by State public utility commissions or that operate as independent municipally-owned distribution systems. LDCs do not include pipelines (both interstate and intrastate) delivering natural gas directly to major industrial users and farm taps upstream of the local distribution company inlet.
(c) This supply category does not consist of the following facilities:
(1) Field gathering and boosting stations.
(2) Natural gas processing plants that separate NGLs from natural gas and produce bulk or y-grade NGLs but do not fractionate these NGLs into their constituent products.
(3) Facilities that meet the definition of refineries and report under subpart MM of this part.
(4) Facilities that meet the definition of petrochemical plants and report under subpart X of this part.
§ 98.401 Reporting threshold.
Any supplier of natural gas and natural gas liquids that meets the requirements of § 98.2(a)(4) must report GHG emissions associated with the products they supply.
§ 98.402 GHGs to report.
(a) NGL fractionators must report the CO
(b) LDCs must report the CO
§ 98.403 Calculating GHG emissions.
(a) LDCs and fractionators shall, for each individual product reported under this part, calculate the estimated CO
(1) Calculation Methodology 1. NGL fractionators shall estimate CO
(2) Calculation Methodology 2. NGL fractionators shall estimate CO
(b) Each LDC shall follow the procedures below.
(1) For natural gas that is received for redelivery to downstream gas transmission pipelines and other local distribution companies, use Equation NN-3 of this section and the default values for the CO
(2)(i) For natural gas delivered to large end-users, use Equation NN-4 of this section and the default values for the CO
(ii) Alternatively, reporter-specific CO
(3) For the net change in natural gas stored on system by the LDC during the reporting year, use Equation NN-5a of this section. For natural gas that is received by means other than through the city gate, and is not otherwise accounted for by Equation NN-1 or NN-2 of this section, use Equation NN-5b of this section.
(i) For natural gas received by the LDC that is injected into on-system storage, and/or liquefied and stored, and for gas removed from storage and used for deliveries, use Equation NN-5a of this section and the default value for the CO
(ii) For natural gas received by the LDC that bypassed the city gate, use Equation NN-5b of this section. This includes natural gas received directly by LDC systems from producers or natural gas processing plants from local production, received as a liquid and vaporized for delivery, or received from any other source that bypassed the city gate. Use the default value for the CO
(4) Calculate the total CO
(c) Each NGL fractionator shall follow the following procedures.
(1)(i) For fractionated NGLs received by the reporter from other NGL fractionators, you shall use Equation NN-7 of this section and the default values for the CO
(ii) Alternatively, reporter-specific CO
(2) Calculate the total CO
§ 98.404 Monitoring and QA/QC requirements.
(a) Determination of quantity.
(1) NGL fractionators and LDCs shall determine the quantity of NGLs and natural gas using methods in common use in the industry for billing purposes as audited under existing Sarbanes Oxley regulation.
(i) Where an appropriate standard method published by a consensus-based standards organization exists, such a method shall be used. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(ii) Where no appropriate standard method developed by a consensus-based standards organization exists, industry standard practices shall be followed.
(2) NGL fractionators and LDCs shall base the minimum frequency of the product quantity measurements, to be summed to the annual quantity reported, on the reporter’s standard practices for commercial operations.
(i) For NGL fractionators the minimum frequency of measurements shall be the measurements taken at custody transfers summed to the annual reportable volume.
(ii) For natural gas the minimum frequency of measurement shall be based on the LDC’s standard measurement schedules used for billing purposes and summed to the annual reportable volume.
(3) NGL fractionators shall use measurement for NGLs at custody transfer meters or at such meters that are used to determine the NGL product slate delivered from the fractionation facility.
(4) If a NGL fractionator supplies a product that is a mixture or blend of two or more products listed in Tables NN-1 and NN-2 of this subpart, the NGL fractionator shall report the quantities of the constituents of the mixtures or blends separately.
(5) For an LDC using Equation NN-1 or NN-2 of this subpart, the point(s) of measurement for the natural gas volume received shall be the LDC city gate meter(s).
(i) If the LDC makes its own quantity measurements according to established business practices, its own measurements shall be used.
(ii) If the LDC does not make its own quantity measurements according to established business practices, it shall use its delivering pipeline invoiced measurements for natural gas deliveries to the LDC city gate, used in determining daily system sendout.
(6) An LDC using Equation NN-3 of this subpart shall measure natural gas at the custody transfer meters.
(7) An LDC using Equation NN-4 of this subpart shall measure natural gas at the large end-user’s meter(s). Where a large end-user is known to have more than one meter located at their facility, based on readily available information in the LDCs possession, the reporter shall measure the natural gas at each meter and sum the annual volume delivered to all meters located at the end-user’s facility to determine the total volume delivered to the large end-user. Otherwise, the reporter shall consider the total annual volume delivered through each single meter at a single particular location to be the volume delivered to an individual large end-user.
(8) An LDC using Equation NN-5a and/or NN-5b of this subpart shall measure natural gas as follows:
(i) Fuel
(ii) Fuel
(iii) Fuel
(9) An LDC shall measure all natural gas under the following standard industry temperature and pressure conditions: Cubic foot of gas at a temperature of 60 degrees Fahrenheit and at an absolute pressure of one atmosphere.
(b) Determination of higher heating values (HHV). (1) When a reporter uses the default HHV provided in this section to calculate Equation NN-1 of this subpart, the appropriate value shall be taken from Table NN-1 of this subpart.
(2) When a reporter uses a reporter-specific HHV to calculate Equation NN-1 of this subpart, an appropriate standard test published by a consensus-based standards organization shall be used. Consensus-based standards organizations include, but are not limited to, the following: AGA and GPA.
(i) If an LDC makes its own HHV measurements according to established business practices, then its own measurements shall be used.
(ii) If an LDC does not make its own measurements according to established business practices, it shall use its delivering pipeline measurements.
(c) Determination of emission factor (EF). (1) When a reporter used the default EF provided in this section to calculate Equation NN-1 of this subpart, the appropriate value shall be taken from Table NN-1 of this subpart.
(2) When a reporter used the default EF provided in this section to calculate Equation NN-2, NN-3, NN-4, NN-5a, NN-5b, or NN-7 of this subpart, the appropriate value shall be taken from Table NN-2 of this subpart.
(3) When a reporter uses a reporter-specific EF, the reporter shall use an appropriate standard method published by a consensus-based standards organization to conduct compositional analysis necessary to determine reporter-specific CO
(d) Equipment Calibration. (1) Equipment used to measure quantities in Equations NN-1, NN-2, NN-5a and NN-5b of this subpart shall be calibrated prior to its first use for reporting under this subpart, using a suitable standard method published by a consensus based standards organization or according to the equipment manufacturer’s directions.
(2) Equipment used to measure quantities in Equations NN-1, NN-2, NN-5a, and NN-5b of this subpart shall be recalibrated at the frequency specified by the standard method used or by the manufacturer’s directions.
(3) Equipment used to measure quantities in Equations NN-3 and NN-4 of this subpart shall be recalibrated at the frequency commonly used within the industry.
§ 98.405 Procedures for estimating missing data.
(a) Whenever a quality-assured value of the quantity of natural gas liquids or natural gas supplied during any period is unavailable (e.g., if a flow meter malfunctions), a substitute data value for the missing quantity measurement must be used in the calculations according to paragraphs (b) and (c) of this section.
(b) Determination of quantity. (1) NGL fractionators shall substitute meter records provided by pipeline(s) for all pipeline receipts of NGLs; by manifests for deliveries made to trucks or rail cars; or metered quantities accepted by the entities purchasing the output from the fractionator whether by pipeline or by truck or rail car. In cases where the metered data from the receiving pipeline(s) or purchasing entities are not available, fractionators may substitute estimates based on contract quantities required to be delivered under purchase or delivery contracts with other parties.
(2) LDCs shall either substitute their delivering pipeline metered deliveries at the city gate or substitute nominations and scheduled delivery quantities for the period when metered values of actual deliveries are not available.
(c) Determination of HHV and EF. (1) Whenever an LDC that makes its own HHV measurements according to established business practices cannot follow the quality assurance procedures for developing a reporter-specific HHV, as specified in § 98.404, during any period for any reason, the reporter shall use either its delivering pipeline measurements or the default HHV provided in Table NN-1 of this part for that period.
(2) Whenever an LDC that does not make its own HHV measurements according to established business practices or an NGL fractionator cannot follow the quality assurance procedures for developing a reporter-specific HHV, as specified in § 98.404, during any period for any reason, the reporter shall use the default HHV provided in Table NN-1 of this part for that period.
(3) [Reserved]
(4) Whenever a reporter cannot follow the quality assurance procedures for developing a reporter-specific EF, as specified in § 98.404, during any period for any reason, the reporter shall use the default EF provided in § 98.408 for that period.
§ 98.406 Data reporting requirements.
(a) In addition to the information required by § 98.3(c), the annual report for each NGL fractionator covered by this rule shall contain the following information.
(1) Annual quantity (in barrels) of each NGL product supplied (including fractionated NGL products received from other NGL fractionators) in the following product categories: Ethane, propane, normal butane, isobutane, and pentanes plus (Fuel
(2) Annual quantity (in barrels) of each NGL product received from other NGL fractionators in the following product categories: Ethane, propane, normal butane, isobutane, and pentanes plus (Fuel
(3) Annual volumes in Mscf of natural gas received for processing.
(4) Annual quantities (in barrels) of y-grade, o-grade, and other bulk NGLs:
(i) Received.
(ii) Supplied to downstream users.
(5) Annual quantity (in barrels) of propane that the NGL fractionator odorizes at the facility and delivers to others.
(6) Annual CO
(7) Annual CO
(8) The specific industry standard used to measure each quantity reported in paragraph (a)(1) of this section.
(9) If the NGL fractionator developed reporter-specific EFs or HHVs, report the following for each product type:
(i) The specific industry standard(s) used to develop reporter-specific higher heating value(s) and/or emission factor(s), pursuant to § 98.404(b)(2) and (c)(3).
(ii) The developed HHV(s).
(iii) The developed EF(s).
(b) In addition to the information required by § 98.3(c), the annual report for each LDC shall contain the following information.
(1) Annual volume in Mscf of natural gas received by the LDC at its city gate stations for redelivery on the LDC’s distribution system, including for use by the LDC (Fuel
(2) Annual volume in Mscf of natural gas placed into storage or liquefied and stored (Fuel
(3) Annual volume in Mscf of natural gas withdrawn from on-system storage and annual volume in Mscf of vaporized liquefied natural gas (LNG) withdrawn from storage for delivery on the distribution system (Fuel
(4) [Reserved]
(5) Annual volume in Mscf of natural gas that bypassed the city gate(s) and was supplied through the LDC distribution system. This includes natural gas from producers and natural gas processing plants from local production, or natural gas that was vaporized upon receipt and delivered, and any other source that bypassed the city gate (Fuel
(6) Annual volume in Mscf of natural gas delivered to downstream gas transmission pipelines and other local distribution companies (Fuel in Equation NN-3 of this subpart).
(7) Annual volume in Mscf of natural gas delivered by the LDC to each large end-user as defined in § 98.403(b)(2)(i) of this section.
(8) The total annual CO
(9) Annual CO
(10) The specific industry standard used to develop the volume reported in paragraph (b)(1) of this section.
(11) If the LDC developed reporter-specific EFs or HHVs, report the following:
(i) The specific industry standard(s) used to develop reporter-specific higher heating value(s) and/or emission factor(s), pursuant to § 98.404 (b)(2) and (c)(3).
(ii) The developed HHV(s).
(iii) The developed EF(s).
(12) For each large end-user reported in paragraph (b)(7) of this section, report:
(i) The customer name, address, and meter number(s).
(ii) Whether the quantity of natural gas reported in paragraph (b)(7) of this section is the total quantity delivered to a large end-user’s facility, or the quantity delivered to a specific meter located at the facility.
(iii) If known, report the EIA identification number of each LDC customer.
(13) The annual volume in Mscf of natural gas delivered by the LDC (including natural gas that is not owned by the LDC) to each of the following end-use categories. For definitions of these categories, refer to EIA Form 176 (Annual Report of Natural Gas and Supplemental Gas Supply & Disposition) and Instructions.
(i) Residential consumers.
(ii) Commercial consumers.
(iii) Industrial consumers.
(iv) Electricity generating facilities.
(14) The name of the U.S. state or territory covered in this report submission.
(c) Each reporter shall report the number of days in the reporting year for which substitute data procedures were used for the following purpose:
(1) To measure quantity.
(2) To develop HHV(s).
(3) To develop EF(s).
§ 98.407 Records that must be retained.
In addition to the information required by § 98.3(g), the reporter shall retain the following records:
(a) Records of all meter readings and documentation to support volumes of natural gas and NGLs that are reported under this part.
(b) Records documenting any estimates of missing metered data and showing the calculations of the values used for the missing data.
(c) Calculations and worksheets used to estimate CO
(d) Records related to the large end-users identified in § 98.406(b)(7).
(e) Records relating to measured Btu content or carbon content showing specific industry standards used to develop reporter-specific higher heating values and emission factors.
(f) Records of such audits as required by Sarbanes Oxley regulations on the accuracy of measurements of volumes of natural gas and NGLs delivered to customers or on behalf of customers.
§ 98.408 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Table NN-1 to Subpart NN of Part 98 – Default Factors for Calculation Methodology 1 of This Subpart
Fuel | Default higher heating value 1 | Default CO2 emission factor (kg CO2/MMBtu) |
---|---|---|
Natural Gas | 1.026 MMBtu/Mscf | 53.06 |
Propane | 3.84 MMBtu/bbl | 62.87 |
Normal butane | 4.34 MMBtu/bbl | 64.77 |
Ethane | 2.85 MMBtu/bbl | 59.60 |
Isobutane | 4.16 MMBtu/bbl | 64.94 |
Pentanes plus | 4.62 MMBtu/bbl | 70.02 |
1 Conditions for higher heating values presented in MMBtu/bbl are 60 °F and saturation pressure.
Table NN-2 to Subpart NN of Part 98 – Default Factors for Calculation Methodology 2 of This Subpart
Fuel | Unit | Default CO2 emission factor (MT CO2/Unit) 1 |
---|---|---|
Natural Gas | Mscf | 0.0544 |
Propane | Barrel | 0.241 |
Normal butane | Barrel | 0.281 |
Ethane | Barrel | 0.170 |
Isobutane | Barrel | 0.270 |
Pentanes plus | Barrel | 0.324 |
1 Conditions for emission value presented in MT CO2/bbl are 60 °F and saturation pressure.
Subpart OO – Suppliers of Industrial Greenhouse Gases
§ 98.410 Definition of the source category.
(a) The industrial gas supplier source category consists of any facility that produces fluorinated GHGs or nitrous oxide; any bulk importer of fluorinated GHGs or nitrous oxide; and any bulk exporter of fluorinated GHGs or nitrous oxide. Starting with reporting year 2018, this source category also consists of any facility that produces fluorinated HTFs; any bulk importer of fluorinated HTFs; any bulk exporter of fluorinated HTFs; and any facility that destroys fluorinated GHGs or fluorinated HTFs.
(b) To produce a fluorinated GHG means to manufacture a fluorinated GHG from any raw material or feedstock chemical. Producing a fluorinated GHG includes the manufacture of a fluorinated GHG as an isolated intermediate for use in a process that will result in its transformation either at or outside of the production facility. Producing a fluorinated GHG also includes the creation of a fluorinated GHG (with the exception of HFC-23) that is captured and shipped off site for any reason, including destruction. Producing a fluorinated GHG does not include the reuse or recycling of a fluorinated GHG, the creation of HFC-23 during the production of HCFC-22, the creation of intermediates that are created and transformed in a single process with no storage of the intermediates, or the creation of fluorinated GHGs that are released or destroyed at the production facility before the production measurement at § 98.414(a).
(c) To produce nitrous oxide means to produce nitrous oxide by thermally decomposing ammonium nitrate (NH
(d) To produce a fluorinated HTF means to manufacture, from any raw material or feedstock chemical, a fluorinated GHG used for temperature control, device testing, cleaning substrate surfaces and other parts, and soldering in processes including but not limited to certain types of electronics manufacturing production processes. Fluorinated heat transfer fluids do not include fluorinated GHGs used as lubricants or surfactants. For fluorinated heat transfer fluids under this subpart, the lower vapor pressure limit of 1 mm Hg in absolute at 25 °C in the definition of fluorinated greenhouse gas in § 98.6 shall not apply. Fluorinated heat transfer fluids include, but are not limited to, perfluoropolyethers, perfluoroalkanes, perfluoroethers, tertiary perfluoroamines, and perfluorocyclic ethers. Producing a fluorinated HTF does not include the reuse or recycling of a fluorinated HTF, the creation of intermediates, or the creation of fluorinated HTFs that are released or destroyed at the production facility before the production measurement at § 98.414(a).
(e) For purposes of this subpart, to destroy fluorinated GHGs or fluorinated HTFs means to cause the expiration of a previously produced (as defined in paragraphs (b) and (d) of this section) fluorinated GHG or fluorinated HTF to the destruction efficiency actually achieved. Such destruction does not result in a commercially useful end product. For purposes of this subpart, such destruction does not include HFC-23 destruction as defined at § 98.150 or the dissociation of fluorinated GHGs that occurs during electronics manufacturing as defined at § 98.90. For example, such destruction does not include the dissociation of fluorinated GHGs that occurs during etch or chamber cleaning processes or during use of abatement systems that treat the fluorinated GHGs vented from such processes at electronics manufacturing facilities.
§ 98.411 Reporting threshold.
Any supplier of industrial greenhouse gases who meets the requirements of § 98.2(a)(4) must report GHG emissions.
§ 98.412 GHGs to report.
You must report the GHG emissions that would result from the release of the nitrous oxide and each fluorinated GHG that you produce, import, export, transform, or destroy during the calendar year. Starting with reporting year 2018, you must also report the emissions that would result from the release of each fluorinated HTF that is not also a fluorinated GHG and that you produce, import, export, transform, or destroy during the calendar year.
§ 98.413 Calculating GHG emissions.
(a) Calculate the total mass of the nitrous oxide and each fluorinated GHG or fluorinated HTF produced annually, except for amounts that are captured solely to be shipped off site for destruction, by using Equation OO-1 of this section:
(b) Calculate the total mass of the nitrous oxide and each fluorinated GHG or fluorinated HTF produced over the period “p” by using Equation OO-2 of this section:
(c) Calculate the total mass of the nitrous oxide and each fluorinated GHG or fluorinated HTF transformed by using Equation OO-3 of this section:
(d) Calculate the total mass of each fluorinated GHG or fluorinated HTF destroyed by using Equation OO-4 of this section:
§ 98.414 Monitoring and QA/QC requirements.
(a) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide coming out of the production process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than one fluorinated GHG or fluorinated HTF, the concentrations of each of the fluorinated GHGs or fluorinated HTFs, other than low-concentration constituents, shall be measured as set forth in paragraph (n) of this section. For each fluorinated GHG or fluorinated HTF, the mean of the concentrations of that fluorinated GHG (mass fraction) measured under paragraph (n) shall be multiplied by the mass measurement to obtain the mass of that fluorinated GHG or fluorinated HTF coming out of the production process.
(b) The mass of any used fluorinated GHGs, fluorinated HTFs, or used nitrous oxide added back into the production process upstream of the output measurement in paragraph (a) of this section shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the mass in paragraph (a) is measured by weighing containers that include returned heels as well as newly produced fluorinated GHGs or fluorinated HTFs, the returned heels shall be considered used fluorinated GHGs or fluorinated HTFs for purposes of this paragraph (b) and § 98.413(b).
(c) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide fed into the transformation process shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.
(d) The fraction of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide fed into the transformation process that is actually transformed shall be estimated considering yield calculations or quantities of unreacted fluorinated GHGs, fluorinated HTFs, or nitrous oxide permanently removed from the process and recovered, destroyed, or emitted.
(e) The mass of fluorinated GHGs, fluorinated HTFs, or nitrous oxide sent to another facility for transformation shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better.
(f) The mass of fluorinated GHGs or fluorinated HTFs sent to another facility for destruction shall be measured using flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG or fluorinated HTF, the concentration of the fluorinated GHG or fluorinated HTF shall be estimated considering current or previous representative concentration measurements and other relevant process information. This concentration (mass fraction) shall be multiplied by the mass measurement to obtain the mass of the fluorinated GHG or fluorinated HTF sent to another facility for destruction.
(g) You must estimate the share of the mass of fluorinated GHGs or fluorinated HTFs in paragraph (f) of this section that is comprised of fluorinated GHGs or fluorinated HTFs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as by-products or other wastes.
(h) You must measure the mass of each fluorinated GHG or fluorinated HTF that is fed into the destruction device and that was previously produced as defined at § 98.410(b). Such fluorinated GHGs or fluorinated HTFs include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed. You must use flowmeters, weigh scales, or a combination of volumetric and density measurements with an accuracy and precision of one percent of full scale or better. If the measured mass includes more than trace concentrations of materials other than the fluorinated GHG or fluorinated HTF being destroyed, you must estimate the concentrations of the fluorinated GHG or fluorinated HTF being destroyed considering current or previous representative concentration measurements and other relevant process information. You must multiply this concentration (mass fraction) by the mass measurement to obtain the mass of the fluorinated GHG or fluorinated HTF fed into the destruction device.
(i) Very small quantities of fluorinated GHGs or fluorinated HTFs that are difficult to measure because they are entrained in other media such as destroyed filters and destroyed sample containers are exempt from paragraphs (f) and (h) of this section.
(j) [Reserved]
(k) For purposes of Equation OO-4 of this subpart, the destruction efficiency can be equated to the destruction efficiency determined during a previous performance test of the destruction device or, if no performance test has been done, the destruction efficiency provided by the manufacturer of the destruction device.
(l) In their estimates of the mass of fluorinated GHGs or fluorinated HTFs destroyed, facilities that destroy fluorinated GHGs or fluorinated HTFs shall account for any temporary reductions in the destruction efficiency that result from any startups, shutdowns, or malfunctions of the destruction device, including departures from the operating conditions defined in state or local permitting requirements and/or oxidizer manufacturer specifications.
(m) Calibrate all flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities that are to be reported under this subpart prior to the first year for which GHG emissions are reported under this part. Calibrations performed prior to the effective date of this rule satisfy this requirement. Recalibrate all flow meters, weigh scales, and combinations of volumetric and density measures at the minimum frequency specified by the manufacturer. Use NIST-traceable standards and suitable methods published by a consensus standards organization (e.g., ASTM, ASME, ISO, or others).
(n) If the mass coming out of the production process includes more than one fluorinated GHG or fluorinated HTF, you shall measure the concentrations of all of the fluorinated GHGs or fluorinated HTFs, other than low-concentration constituents, as follows:
(1) Analytical Methods. Use a quality-assured analytical measurement technology capable of detecting the analyte of interest at the concentration of interest and use a procedure validated with the analyte of interest at the concentration of interest. Where standards for the analyte are not available, a chemically similar surrogate may be used. Acceptable analytical measurement technologies include but are not limited to gas chromatography (GC) with an appropriate detector, infrared (IR), fourier transform infrared (FTIR), and nuclear magnetic resonance (NMR). Acceptable methods include EPA Method 18 in appendix A-1 of 40 CFR part 60; EPA Method 320 in appendix A of 40 CFR part 63; the Protocol for Measuring Destruction or Removal Efficiency (DRE) of Fluorinated Greenhouse Gas Abatement Equipment in Electronics Manufacturing, Version 1, EPA-430-R-10-003, (March 2010) (incorporated by reference, see § 98.7); ASTM D6348-03 Standard Test Method for Determination of Gaseous Compounds by Extractive Direct Interface Fourier Transform Infrared (FTIR) Spectroscopy (incorporated by reference, see § 98.7); or other analytical methods validated using EPA Method 301 in appendix A of 40 CFR part 63 or some other scientifically sound validation protocol. The validation protocol may include analytical technology manufacturer specifications or recommendations.
(2) Documentation in GHG Monitoring Plan. Describe the analytical method(s) used under paragraph (n)(1) of this section in the site GHG Monitoring Plan as required under § 98.3(g)(5). At a minimum, include in the description of the method a description of the analytical measurement equipment and procedures, quantitative estimates of the method’s accuracy and precision for the analytes of interest at the concentrations of interest, as well as a description of how these accuracies and precisions were estimated, including the validation protocol used.
(3) Frequency of measurement. Perform the measurements at least once by February 15, 2011 if the fluorinated GHG product is being produced on December 17, 2010. Perform the measurements within 60 days of commencing production of any fluorinated GHG product that was not being produced on December 17, 2010. For fluorinated HTF products that are not also fluorinated GHG products, perform the measurements at least once by February 28, 2018, if the fluorinated HTF product is being produced on January 1, 2018. Perform the measurements within 60 days of commencing production of any fluorinated HTF product that was not being produced on January 1, 2018. Repeat the measurements if an operational or process change occurs that could change the identities or significantly change the concentrations of the fluorinated GHG or fluorinated HTF constituents of the fluorinated GHG or fluorinated HTF product. Complete the repeat measurements within 60 days of the operational or process change.
(4) Measure all product grades. Where a fluorinated GHG or fluorinated HTF is produced at more than one purity level (e.g., pharmaceutical grade and refrigerant grade), perform the measurements for each purity level.
(5) Number of samples. Analyze a minimum of three samples of the fluorinated GHGs or fluorinated HTF product that have been drawn under conditions that are representative of the process producing the fluorinated GHGs or fluorinated HTF product. If the relative standard deviation of the measured concentrations of any of the fluorinated GHGs or fluorinated HTF constituents (other than low-concentration constituents) is greater than or equal to 15 percent, draw and analyze enough additional samples to achieve a total of at least six samples of the fluorinated GHG or fluorinated HTF product.
(o) All analytical equipment used to determine the concentration of fluorinated GHGs or fluorinated HTFs, including but not limited to gas chromatographs and associated detectors, IR, FTIR and NMR devices, shall be calibrated at a frequency needed to support the type of analysis specified in the site GHG Monitoring Plan as required under paragraph (n) of this section and § 98.3(g)(5). Quality assurance samples at the concentrations of concern shall be used for the calibration. Such quality assurance samples shall consist of or be prepared from certified standards of the analytes of concern where available; if not available, calibration shall be performed by a method specified in the GHG Monitoring Plan.
(p) Isolated intermediates that are produced and transformed at the same facility are exempt from the monitoring requirements of this section.
(q) Low-concentration constituents are exempt from the monitoring and QA/QC requirements of this section.
§ 98.415 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions), a substitute data value for the missing parameter shall be used in the calculations, according to paragraph (b) of this section.
(b) For each missing value of the mass produced, fed into the production process (for used material being reclaimed), fed into the transformation process, fed into destruction devices, sent to another facility for transformation, or sent to another facility for destruction, the substitute value of that parameter shall be a secondary mass measurement where such a measurement is available. For example, if the mass produced is usually measured with a flowmeter at the inlet to the day tank and that flowmeter fails to meet an accuracy or precision test, malfunctions, or is rendered inoperable, then the mass produced may be estimated by calculating the change in volume in the day tank and multiplying it by the density of the product. Where a secondary mass measurement is not available, the substitute value of the parameter shall be an estimate based on a related parameter. For example, if a flowmeter measuring the mass fed into a destruction device is rendered inoperable, then the mass fed into the destruction device may be estimated using the production rate and the previously observed relationship between the production rate and the mass flow rate into the destruction device.
§ 98.416 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information:
(a) Each fluorinated GHG, fluorinated HTF, or nitrous oxide production facility shall report the following information:
(1) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF produced at that facility by process, except for amounts that are captured solely to be shipped off site for destruction.
(2) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF transformed at that facility, by process.
(3) Mass in metric tons of each fluorinated GHG or fluorinated HTF that is destroyed at that facility and that was previously produced as defined at § 98.410(b). Quantities to be reported under paragraph (a)(3) of this section include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(4) [Reserved]
(5) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF sent to another facility for transformation.
(6) Total mass in metric tons of each fluorinated GHG or fluorinated HTF sent to another facility for destruction, except fluorinated GHGs and fluorinated HTFs that are not included in the mass produced in § 98.413(a) because they are removed from the production process as byproducts or other wastes. Quantities to be reported under paragraph (a)(6) of this section could include, for example, fluorinated GHGs that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore sent to another facility for destruction.
(7) Total mass in metric tons of each fluorinated GHG or fluorinated HTF that is sent to another facility for destruction and that is not included in the mass produced in § 98.413(a) because it is removed from the production process as a byproduct or other waste.
(8)-(9) [Reserved]
(10) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF fed into the transformation process, by process.
(11) Mass in metric tons of each fluorinated GHG or fluorinated HTF that is fed into the destruction device and that was previously produced as defined at § 98.410(b). Quantities to be reported under paragraph (a)(11) of this section include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(12) Mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF that is measured coming out of the production process, by process.
(13) Mass in metric tons of used nitrous oxide and of each used fluorinated GHG or fluorinated HTF added back into the production process (e.g., for reclamation), including returned heels in containers that are weighed to measure the mass in § 98.414(a), by process.
(14) Names and addresses of facilities to which any nitrous oxide, fluorinated GHGs, or fluorinated HTFs were sent for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG or fluorinated HTF that were sent to each for transformation.
(15) Names and addresses of facilities to which any fluorinated GHGs or fluorinated HTFs were sent for destruction, and the quantities (metric tons) of each fluorinated GHG or fluorinated HTF that were sent to each for destruction.
(16) Where missing data have been estimated pursuant to § 98.415, the reason the data were missing, the length of time the data were missing, the method used to estimate the missing data, and the estimates of those data.
(b) Any facility or importer that destroys fluorinated GHGs or fluorinated HTFs shall submit a one-time report containing the information in paragraphs (b)(1) through (6) of this section for each destruction process by the applicable date set forth in paragraph (b)(7) of this section. Facilities and importers that previously submitted one-time reports under this paragraph for all destruction devices used to destroy fluorinated GHGs or fluorinated HTFs are exempt from this requirement unless they meet the conditions in paragraph (b)(6) of this section.
(1) Destruction efficiency (DE).
(2) Methods used to determine the destruction efficiency.
(3) Methods used to record the mass of fluorinated GHG or fluorinated HTF destroyed.
(4) Chemical identity of the fluorinated GHG(s) used in the performance test conducted to determine DE.
(5) Name of all applicable federal or state regulations that may apply to the destruction process.
(6) If any process changes (including the acquisition of a new destruction device) affect unit destruction efficiency or the methods used to record the mass of fluorinated GHG or fluorinated HTF destroyed, then a revised report must be submitted to reflect the changes. The revised report must be submitted to EPA within 60 days of the change.
(7)(i) Any fluorinated GHG production facility or importer that destroys fluorinated GHGs must submit the one-time destruction report by March 31, 2011 or within 60 days of commencing fluorinated GHG destruction, whichever is later.
(ii) Any fluorinated GHG production facility or importer that destroys fluorinated HTFs that are not also fluorinated GHGs must submit the one-time destruction report by March 31, 2019 or within 60 days of commencing fluorinated HTF destruction, whichever is later.
(iii) Any facility that destroys fluorinated GHGs or fluorinated HTFs but does not produce or import fluorinated GHGs must submit the one-time destruction report by March 31, 2019 or within 60 days of commencing fluorinated GHG or fluorinated HTF destruction, whichever is later.
(c) Each bulk importer of fluorinated GHGs, fluorinated HTFs, or nitrous oxide shall submit an annual report that summarizes its imports at the corporate level, except for shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide, transshipments, and heels that meet the conditions set forth at § 98.417(e). The report shall contain the following information for each import:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF imported in bulk, including each fluorinated GHG or fluorinated HTF constituent of the fluorinated GHG or fluorinated HTF product that makes up between 0.5 percent and 100 percent of the product by mass.
(2) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF imported in bulk and sold or transferred to persons other than the importer for use in processes resulting in the transformation or destruction of the chemical.
(3) Date on which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were imported.
(4) Port of entry through which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide passed.
(5) Country from which the imported fluorinated GHGs, fluorinated HTFs, or nitrous oxide were imported.
(6) Commodity code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped.
(7) Importer number for the shipment.
(8) Total mass in metric tons of each fluorinated GHG or fluorinated HTF destroyed by the importer.
(9) If applicable, the names and addresses of the persons and facilities to which the nitrous oxide, fluorinated GHGs, or fluorinated HTFs were sold or transferred for transformation, and the quantities (metric tons) of nitrous oxide and of each fluorinated GHG or fluorinated HTF that were sold or transferred to each facility for transformation.
(10) If applicable, the names and addresses of the persons and facilities to which the fluorinated GHGs or fluorinated HTFs were sold or transferred for destruction, and the quantities (metric tons) of each fluorinated GHG or fluorinated HTF that were sold or transferred to each facility for destruction.
(d) Each bulk exporter of fluorinated GHGs, fluorinated HTFs, or nitrous oxide shall submit an annual report that summarizes its exports at the corporate level, except for shipments including less than twenty-five kilograms of fluorinated GHGs, fluorinated HTFs, or nitrous oxide, transshipments, and heels. The report shall contain the following information for each export:
(1) Total mass in metric tons of nitrous oxide and each fluorinated GHG or fluorinated HTF exported in bulk.
(2) Names and addresses of the exporter and the recipient of the exports.
(3) Exporter’s Employee Identification Number.
(4) Commodity code of the fluorinated GHGs, fluorinated HTFs, or nitrous oxide shipped.
(5) Date on which, and the port from which, the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were exported from the United States or its territories.
(6) Country to which the fluorinated GHGs, fluorinated HTFs, or nitrous oxide were exported.
(e) By March 31, 2011, or within 60 days of commencing fluorinated GHG production, whichever is later, a fluorinated GHG production facility shall submit a one-time report describing the following information:
(1) The method(s) by which the producer in practice measures the mass of fluorinated GHGs produced, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.
(2) The method(s) by which the producer in practice estimates the mass of fluorinated GHGs fed into the transformation process, including the instrumentation used (Coriolis flowmeter, other flowmeter, weigh scale, etc.) and its accuracy and precision.
(3) The method(s) by which the producer in practice estimates the fraction of fluorinated GHGs fed into the transformation process that is actually transformed, and the estimated precision and accuracy of this estimate.
(4) The method(s) by which the producer in practice estimates the masses of fluorinated GHGs fed into the destruction device, including the method(s) used to estimate the concentration of the fluorinated GHGs in the destroyed material, and the estimated precision and accuracy of this estimate.
(5) The estimated percent efficiency of each production process for the fluorinated GHG produced.
(f) By March 31, 2011, all fluorinated GHG production facilities shall submit a one-time report that includes the concentration of each fluorinated GHG constituent in each fluorinated GHG product as measured under § 98.414(n). If the facility commences production of a fluorinated GHG product that was not included in the initial report or performs a repeat measurement under § 98.414(n) that shows that the identities or concentrations of the fluorinated GHG constituents of a fluorinated GHG product have changed, then the new or changed concentrations, as well as the date of the change, must be reflected in a revision to the report. The revised report must be submitted to EPA by the March 31st that immediately follows the measurement under § 98.414(n).
(g) Isolated intermediates that are produced and transformed at the same facility are exempt from the reporting requirements of this section.
(h) Low-concentration constituents are exempt from the reporting requirements of this section.
(i) Each facility that destroys fluorinated GHGs or fluorinated HTFs but does not otherwise report under this section shall report the mass in metric tons of each fluorinated GHG or fluorinated HTF that is destroyed at that facility and that was previously produced as defined at § 98.410(b) or (d), as applicable. Quantities to be reported under this paragraph (i) include but are not limited to quantities that are shipped to the facility by another facility for destruction and quantities that are returned to the facility for reclamation but are found to be irretrievably contaminated and are therefore destroyed.
(j) By March 31, 2019, all facilities that produce fluorinated HTFs that are not also fluorinated GHGs shall submit a one-time report that includes the concentration of each fluorinated HTF or fluorinated GHG constituent in each fluorinated HTF product as measured under § 98.414(n). If the facility commences production of a fluorinated HTF product that was not included in the initial report or performs a repeat measurement under § 98.414(n) that shows that the identities or concentrations of the fluorinated HTF or fluorinated GHG constituents of a fluorinated HTF product have changed, then the new or changed concentrations, as well as the date of the change, must be provided in a revised report. The revised report must be submitted to EPA by the March 31st that immediately follows the new or repeat measurement under § 98.414(n).
§ 98.417 Records that must be retained.
(a) In addition to the data required by § 98.3(g), the fluorinated GHG or fluorinated HTF production facility shall retain the following records:
(1) Dated records of the data used to estimate the data reported under § 98.416.
(2) Records documenting the initial and periodic calibration of the analytical equipment (including but not limited to GC, IR, FTIR, or NMR), weigh scales, flowmeters, and volumetric and density measures used to measure the quantities reported under this subpart, including the manufacturer directions or industry standards used for calibration pursuant to § 98.414(m) and (o).
(3) Dated records of the total mass in metric tons of each reactant fed into the fluorinated GHG, fluorinated HTF, or nitrous oxide production process, by process.
(4) Dated records of the total mass in metric tons of the reactants, by-products, and other wastes permanently removed from the fluorinated GHG, fluorinated HTF, or nitrous oxide production process, by process.
(b) In addition to the data required by paragraph (a) of this section, any facility that destroys fluorinated GHGs or fluorinated HTFs shall keep records of test reports and other information documenting the facility’s one-time destruction efficiency report in § 98.416(b).
(c) In addition to the data required by § 98.3(g), the bulk importer shall retain the following records substantiating each of the imports that they report:
(1) A copy of the bill of lading for the import.
(2) The invoice for the import.
(3) The U.S. Customs entry form.
(d) In addition to the data required by § 98.3(g), the bulk exporter shall retain the following records substantiating each of the exports that they report:
(1) A copy of the bill of lading for the export and
(2) The invoice for the export.
(e) Every person who imports a container with a heel that is not reported under § 98.416(c) shall keep records of the amount brought into the United States that document that the residual amount in each shipment is less than 10 percent of the volume of the container and will:
(1) Remain in the container and be included in a future shipment.
(2) Be recovered and transformed.
(3) Be recovered and destroyed.
(4) Be recovered and included in a future shipment.
(f) Isolated intermediates that are produced and transformed at the same facility are exempt from the recordkeeping requirements of this section.
(g) Low-concentration constituents are exempt from the recordkeeping requirements of this section.
§ 98.418 Definitions.
Except as provided below, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart shall take precedence for the reporting requirements in this subpart.
Isolated intermediate means a product of a process that is stored before subsequent processing. An isolated intermediate is usually a product of chemical synthesis. Storage of an isolated intermediate marks the end of a process. Storage occurs at any time the intermediate is placed in equipment used solely for storage.
Low-concentration constituent means, for purposes of fluorinated GHG or fluorinated HTF production and export, a fluorinated GHG or fluorinated HTF constituent of a fluorinated GHG or fluorinated HTF product that occurs in the product in concentrations below 0.1 percent by mass. For purposes of fluorinated GHG or fluorinated HTF import, low-concentration constituent means a fluorinated GHG or fluorinated HTF constituent of a fluorinated GHG or fluorinated HTF product that occurs in the product in concentrations below 0.5 percent by mass. Low-concentration constituents do not include fluorinated GHGs or fluorinated HTFs that are deliberately combined with the product (e.g., to affect the performance characteristics of the product).
Subpart PP – Suppliers of Carbon Dioxide
§ 98.420 Definition of the source category.
(a) The carbon dioxide (CO
(1) Facilities with production process units that capture a CO
(2) Facilities with CO
(3) Importers or exporters of bulk CO
(b) This source category is focused on upstream supply. It does not cover:
(1) Storage of CO
(2) Use of CO
(3) Transportation or distribution of CO
(4) Purification, compression, or processing of CO
(5) On-site use of CO
(c) This source category does not include CO
§ 98.421 Reporting threshold.
Any supplier of CO
§ 98.422 GHGs to report.
(a) Mass of CO
(b) Mass of CO
(c) Mass of CO
(d) Mass of CO
§ 98.423 Calculating CO2 supply.
(a) Except as allowed in paragraph (b) of this section, calculate the annual mass of CO
(1) For each mass flow meter, you shall calculate quarterly the mass of CO
(2) For each volumetric flow meter, you shall calculate quarterly the mass of CO
(3) To aggregate data, use either Equation PP-3a or PP-3b in this paragraph, as appropriate.
(i) For facilities with production process units or production wells that capture or extract a CO
(ii) For facilities with production process units that capture a CO
(b) As an alternative to paragraphs (a)(1) through (3) of this section for CO
(1) For each CO
(2) For each CO
(3) To aggregate data, sum the mass of CO
(c) Importers or exporters that import or export CO
§ 98.424 Monitoring and QA/QC requirements.
(a) Determination of quantity. (1) Reporters following the procedures in § 98.423(a) shall determine quantity using a flow meter or meters located in accordance with this paragraph.
(i) If the CO
(A) For reporters following the procedures in § 98.423(a)(3)(i), you must locate the flow meter(s) after the point of segregation.
(B) For reporters following the procedures in paragraph (a)(3)(ii) of § 98.423, you must locate the main flow meter(s) on the captured CO
(ii) Reporters that have a mass flow meter or volumetric flow meter installed to measure the flow of a CO
(iii) Reporters that do not have a mass flow meter or volumetric flow meter installed to measure the flow of the CO
(2) Reporters following the procedures in paragraph (b) of § 98.423 shall determine quantity in accordance with this paragraph.
(i) Reporters that supply CO
(ii) Reporters that supply CO
(3) Importers or exporters that import or export CO
(4) All flow meters, scales, and load cells used to measure quantities that are reported in § 98.423 of this subpart shall be operated and calibrated according to the following procedure:
(i) You shall use an appropriate standard method published by a consensus-based standards organization if such a method exists. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(ii) Where no appropriate standard method developed by a consensus-based standards organization exists, you shall follow industry standard practices.
(iii) You must ensure that any flow meter calibrations performed are NIST traceable.
(5) Reporters using Equation PP-2 of this subpart and measuring CO
(i) You may use a method published by a consensus-based standards organization. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Gas Association (AGA, 400 North Capitol Street, NW., 4th Floor, Washington, DC 20001, (202) 824-7000, http://www.aga.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), the American Petroleum Institute (API, 1220 L Street, NW., Washington, DC 20005-4070, (202) 682-8000, http://www.api.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org). The method(s) used shall be documented in the Monitoring Plan required under § 98.3(g)(5).
(ii) You may follow an industry standard method.
(b) Determination of concentration. (1) Reporters using Equation PP-1 or PP-2 of this subpart shall sample the CO
(2) Methods to measure the composition of the CO
(c) You shall convert the density of the CO
§ 98.425 Procedures for estimating missing data.
(a) Whenever the quality assurance procedures in § 98.424(a)(1) of this subpart cannot be followed to measure quarterly mass flow or volumetric flow of CO
(1) A quarterly CO
(2) A quarterly CO
(3) If a mass or volumetric flow meter is installed to measure the CO
(4) The mass or volumetric flow used for purposes of product tracking and billing according to the reporter’s established procedures may be substituted for any period during which measurement equipment is inoperable.
(b) Whenever the quality assurance procedures in § 98.424(b) cannot be followed to determine concentration of the CO
(1) A quarterly concentration value that is missing may be substituted with a quarterly value measured during another quarter of the current reporting year.
(2) A quarterly concentration value that is missing may be substituted with a quarterly value measured during the same quarter from the previous reporting year.
(3) The concentration used for purposes of product tracking and billing according to the reporter’s established procedures may be substituted for any quarterly value.
(c) Missing data on density of the CO
(d) Whenever the quality assurance procedures in § 98.424(a)(2) of this subpart cannot be followed to measure quarterly quantity of CO
(1) A quarterly quantity of CO
(2) A quarterly quantity of CO
(3) The quarterly quantity of CO
§ 98.426 Data reporting requirements.
In addition to the information required by § 98.3(c) of subpart A of this part, the annual report shall contain the following information, as applicable:
(a) If you use Equation PP-1 of this subpart, report the following information for each mass flow meter or CO
(1) Annual mass in metric tons of CO
(2) Quarterly mass in metric tons of CO
(3) Quarterly concentration of the CO
(4) The standard used to measure CO
(5) The location of the flow meter in your process chain in relation to the points of CO
(b) If you use Equation PP-2 of this subpart, report the following information for each volumetric flow meter or CO
(1) Annual mass in metric tons of CO
(2) Quarterly volume in standard cubic meters of CO
(3) Quarterly concentration of the CO
(4) Report density as follows:
(i) Quarterly density of the CO
(ii) Quarterly density of CO
(5) The method used to measure density.
(6) The standard used to measure CO
(7) The location of the flow meter in your process chain in relation to the points of CO
(c) For the aggregated annual mass of CO
(1) If you use Equation PP-3a of this subpart, report the annual CO
(2) If you use Equation PP-3b of this subpart, report:
(i) The total annual CO
(ii) The total annual CO
(iii) The total annual CO
(iv) The location of each flow meter in relation to the point of segregation.
(d) If you use Equation PP-4 of this subpart, report at the corporate level the annual mass of CO
(e) Each reporter shall report the following information:
(1) The type of equipment used to measure the total flow of the CO
(2) The standard used to operate and calibrate the equipment reported in (e)(1) of this section.
(3) The number of days in the reporting year for which substitute data procedures were used for the following purpose:
(i) To measure quantity.
(ii) To measure concentration.
(iii) To measure density.
(f) Report the aggregated annual quantity of CO
(1) Food and beverage.
(2) Industrial and municipal water/wastewater treatment.
(3) Metal fabrication, including welding and cutting.
(4) Greenhouse uses for plant growth.
(5) Fumigants (e.g., grain storage) and herbicides.
(6) Pulp and paper.
(7) Cleaning and solvent use.
(8) Fire fighting.
(9) Transportation and storage of explosives.
(10) Injection of carbon dioxide for enhanced oil and natural gas recovery that is covered by subpart UU of this part.
(11) Geologic sequestration of carbon dioxide that is covered by subpart RR of this part.
(12) Research and development.
(13) Other.
(g) Each production process unit that captures a CO
(h) If you capture a CO
(1) Report the facility identification number associated with the annual GHG report for the subpart D facility;
(2) Report each facility identification number associated with the annual GHG reports for each subpart RR facility to which CO
(3) Report the annual quantity of CO
§ 98.427 Records that must be retained.
In addition to the records required by § 98.3(g) of subpart A of this part, you must retain the records specified in paragraphs (a) through (c) of this section, as applicable.
(a) The owner or operator of a facility containing production process units must retain quarterly records of captured or transferred CO
(b) The owner or operator of a CO
(c) Importers or exporters of CO
(d) Facilities subject to § 98.426(h) must retain records of CO
§ 98.428 Definitions.
All terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Subpart QQ – Importers and Exporters of Fluorinated Greenhouse Gases Contained in Pre-Charged Equipment or Closed-Cell Foams
§ 98.430 Definition of the source category.
(a) The source category, importers and exporters of fluorinated GHGs contained in pre-charged equipment or closed-cell foams, consists of any entity that imports or exports pre-charged equipment that contains a fluorinated GHG, and any entity that imports or exports closed-cell foams that contain a fluorinated GHG.
§ 98.431 Reporting threshold.
Any importer or exporter of fluorinated GHGs contained in pre-charged equipment or closed-cell foams who meets the requirements of § 98.2(a)(4) must report each fluorinated GHG contained in the imported or exported pre-charged equipment or closed-cell foams.
§ 98.432 GHGs to report.
You must report the mass of each fluorinated GHG contained in pre-charged equipment or closed-cell foams that you import or export during the calendar year. For imports and exports of closed-cell foams where you do not know the identity and mass of the fluorinated GHG, you must report the mass of fluorinated GHG in CO
§ 98.433 Calculating GHG contained in pre-charged equipment or closed-cell foams.
(a) The total mass of each fluorinated GHG imported and exported inside equipment or foams must be estimated using Equation QQ-1 of this section:
(b) When the identity and mass of fluorinated GHGs in a closed-cell foam is unknown to the importer or exporter, the total mass in CO
§ 98.434 Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, you may follow the provisions of § 98.3(d)(1) through (d)(2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference in § 98.3(d)(1) through (d)(2) to the year 2010 means 2011, to March 31 means June 30, and to April 1 means July 1. Any reference to the effective date or date of promulgation in § 98.3(d)(1) through (d)(2) means February 28, 2011.
(b) The inputs to the annual submission must be reviewed against the import or export transaction records to ensure that the information submitted to EPA is being accurately transcribed as the correct chemical or blend in the correct pre-charged equipment or closed-cell foam in the correct quantities and units.
§ 98.435 Procedures for estimating missing data.
Procedures for estimating missing data are not provided for importers and exporters of fluorinated GHGs contained in pre-charged equipment or closed-cell foams. A complete record of all measured parameters used in tracking fluorinated GHGs contained in pre-charged equipment or closed-cell foams is required.
§ 98.436 Data reporting requirements.
(a) Each importer of fluorinated GHGs contained in pre-charged equipment or closed-cell foams must submit an annual report that summarizes its imports at the corporate level, except for transshipments, as specified:
(1) Total mass in metric tons of each fluorinated GHG imported in pre-charged equipment or closed-cell foams.
(2) For each type of pre-charged equipment with a unique combination of charge size and charge type, the identity of the fluorinated GHG used as a refrigerant or electrical insulator, charge size (holding charge, if applicable), and number imported.
(3) For closed-cell foams that are imported inside of equipment, the identity of the fluorinated GHG contained in the foam, the mass of the fluorinated GHG contained in the foam in each piece of equipment, and the number of pieces of equipment imported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams.
(4) For closed cell-foams that are not imported inside of equipment, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam imported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity.
(5) Dates on which the pre-charged equipment or closed-cell foams were imported.
(6) If the importer does not know the identity and mass of the fluorinated GHGs within the closed-cell foam, the importer must report the following:
(i) Total mass in metric tons of CO
(ii) For closed-cell foams that are imported inside of equipment, the mass of the fluorinated GHGs in CO
(iii) For closed-cell foams that are not imported inside of equipment, the density in CO
(iv) Dates on which the closed-cell foams were imported.
(v) Name of the foam manufacturer for each type of closed-cell foam where the identity and mass of the fluorinated GHGs is unknown.
(vi) Certification that the importer was unable to obtain information on the identity and mass of the fluorinated GHGs within the closed-cell foam from the closed-cell foam manufacturer or manufacturers.
(b) Each exporter of fluorinated GHGs contained in pre-charged equipment or closed-cell foams must submit an annual report that summarizes its exports at the corporate level, except for transshipments, as specified:
(1) Total mass in metric tons of each fluorinated GHG exported in pre-charged equipment or closed-cell foams.
(2) For each type of pre-charged equipment with a unique combination of charge size and charge type, the identity of the fluorinated GHG used as a refrigerant or electrical insulator, charge size (including holding charge, if applicable), and number exported.
(3) For closed-cell foams that are exported inside of equipment, the identity of the fluorinated GHG contained in the foam in each piece of equipment, the mass of the fluorinated GHG contained in the foam in each piece of equipment, and the number of pieces of equipment exported with each unique combination of mass and identity of fluorinated GHG within the closed-cell foams.
(4) For closed-cell foams that are not exported inside of equipment, the identity of the fluorinated GHG in the foam, the density of the fluorinated GHG in the foam (kg fluorinated GHG/cubic foot), and the volume of foam exported (cubic feet) for each type of closed-cell foam with a unique combination of fluorinated GHG density and identity.
(5) Dates on which the pre-charged equipment or closed-cell foams were exported.
(6) If the exporter does not know the identity and mass of the fluorinated GHG within the closed-cell foam, the exporter must report the following:
(i) Total mass in metric tons of CO
(ii) For closed-cell foams that are exported inside of equipment, the mass of the fluorinated GHGs in CO
(iii) For closed-cell foams that are not exported inside of equipment, the density in CO
(iv) Dates on which the closed-cell foams were exported.
(v) Name of the foam manufacturer for each type of closed-cell foam where the identity and mass of the fluorinated GHGg is unknown.
(vi) Certification that the exporter was unable to obtain information on the identity and mass of the fluorinated GHGs within the closed-cell foam from the closed-cell foam manufacturer or manufacturers.
§ 98.437 Records that must be retained.
(a) In addition to the data required by § 98.3(g), importers of fluorinated GHGs in pre-charged equipment and closed-cell foams must retain the following records substantiating each of the imports that they report:
(1) A copy of the bill of lading for the import.
(2) The invoice for the import.
(3) The U.S. Customs entry form.
(4) Ports of entry through which the pre-charged equipment or closed-cell foams passed.
(5) Countries from which the pre-charged equipment or closed-cell foams were imported.
(6) For importers that report the mass of fluorinated GHGs within closed-cell foams on a CO
(b) In addition to the data required by § 98.3(g), exporters of fluorinated GHGs in pre-charged equipment and closed-cell foams must retain the following records substantiating each of the exports that they report:
(1) A copy of the bill of lading for the export and
(2) The invoice for the export.
(3) Ports of exit through which the pre-charged equipment or closed-cell foams passed.
(4) Countries to which the pre-charged equipment or closed-cell foams were exported.
(5) For exporters that report the mass of fluorinated GHGs within closed-cell foams on a CO
(c) For importers and exports of fluorinated GHGs inside pre-charged equipment and closed-cell foams, the GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
(d) Persons who transship pre-charged equipment and closed-cell foams containing fluorinated GHGs must maintain records that indicated that the pre-charged equipment or foam originated in a foreign country and was destined for another foreign country and did not enter into commerce in the United States.
§ 98.438 Definitions.
Except as provided in this section, all of the terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part. If a conflict exists between a definition provided in this subpart and a definition provided in subpart A, the definition in this subpart must take precedence for the reporting requirements in this subpart.
Appliance means any device which contains and uses a fluorinated greenhouse gas refrigerant and which is used for household or commercial purposes, including any air conditioner, refrigerator, chiller, or freezer.
Closed-cell foam means any foam product, excluding packaging foam, that is constructed with a closed-cell structure and a blowing agent containing a fluorinated GHG. Closed-cell foams include but are not limited to polyurethane (PU) foam contained in equipment, PU continuous and discontinuous panel foam, PU one component foam, PU spray foam, extruded polystyrene (XPS) boardstock foam, and XPS sheet foam. Packaging foam means foam used exclusively during shipment or storage to temporarily enclose items.
Electrical equipment means gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers.
Fluorinated GHG refrigerant means, for purposes of this subpart, any substance consisting in part or whole of a fluorinated greenhouse gas and that is used for heat transfer purposes and provides a cooling effect.
Pre-charged appliance means any appliance charged with fluorinated greenhouse gas refrigerant prior to sale or distribution or offer for sale or distribution in interstate commerce. This includes both appliances that contain the full charge necessary for operation and appliances that contain a partial “holding” charge of the fluorinated greenhouse gas refrigerant (e.g., for shipment purposes).
Pre-charged appliance component means any portion of an appliance, including but not limited to condensers, compressors, line sets, and coils, that is charged with fluorinated greenhouse gas refrigerant prior to sale or distribution or offer for sale or distribution in interstate commerce.
Pre-charged electrical equipment means any electrical equipment, including but not limited to gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers containing a fluorinated GHG prior to sale or distribution, or offer for sale or distribution in interstate commerce. This includes both equipment that contain the full charge necessary for operation and equipment that contain a partial “holding” charge of the fluorinated GHG (e.g., for shipment purposes).
Pre-charged electrical equipment component means any portion of electrical equipment that is charged with a fluorinated greenhouse gas prior to sale or distribution or offer for sale or distribution in interstate commerce.
Pre-charged equipment means any pre-charged appliance, pre-charged appliance component, pre-charged electrical equipment, or pre-charged electrical equipment component.
Subpart RR – Geologic Sequestration of Carbon Dioxide
§ 98.440 Definition of the source category.
(a) The geologic sequestration of carbon dioxide (CO
(b) This source category includes all wells permitted as Class VI under the Underground Injection Control program.
(c) This source category does not include a well or group of wells where a CO
(1) The owner or operator injects the CO
(2) The well is permitted as Class VI under the Underground Injection Control program.
(d) Exemption for research and development projects. Research and development projects shall receive an exemption from reporting under this subpart for the duration of the research and development activity.
(1) Process for obtaining an exemption. If you are a research and development project, you must submit the information in paragraph (d)(2) of this section to EPA by the time you would be otherwise required to submit an MRV plan under § 98.448. EPA will use this information to verify that the project is a research and development project.
(2) Content of submission. A submission in support of an exemption as a research and development project must contain the following information:
(i) The planned duration of CO
(ii) The planned annual CO
(iii) The research purposes of the project.
(iv) The source and type of funding for the project.
(v) The class and duration of Underground Injection Control permit or, for an offshore facility not subject to the Safe Drinking Water Act, a description of the legal instrument authorizing geologic sequestration.
(3) Determination by the Administrator.
(i) The Administrator shall determine if a project meets the definition of research and development project within 60 days of receipt of the submission of a request for exemption. In making this determination, the Administrator shall take into account any information you submit demonstrating that the planned duration of CO
(ii) Any appeal of the Administrator’s determination is subject to the provisions of part 78 of this chapter.
(iii) A project that the Administrator determines is not eligible for an exemption as a research and development project must submit a proposed MRV plan to EPA within 180 days of the Administrator’s determination. You may request one extension of up to an additional 180 days in which to submit the proposed MRV plan.
§ 98.441 Reporting threshold.
(a) You must report under this subpart if any well or group of wells within your facility injects any amount of CO
(b) Request for discontinuation of reporting. The requirements of § 98.2(i) do not apply to this subpart. Once a well or group of wells is subject to the requirements of this subpart, the owner or operator must continue for each year thereafter to comply with all requirements of this subpart, including the requirement to submit annual reports, until the Administrator has issued a final decision on an owner or operator’s request to discontinue reporting.
(1) Timing of request. The owner or operator of a facility may submit a request to discontinue reporting any time after the well or group of wells is plugged and abandoned in accordance with applicable requirements.
(2) Content of request. A request for discontinuation of reporting must contain either paragraph (b)(2)(i) or (b)(2)(ii) of this section.
(i) For wells permitted as Class VI under the Underground Injection Control program, a copy of the applicable Underground Injection Control program Director’s authorization of site closure.
(ii) For all other wells, and as an alternative for wells permitted as Class VI under the Underground Injection Control program, a demonstration that current monitoring and model(s) show that the injected CO
(3) Notification. The Administrator will issue a final decision on the request to discontinue reporting within a reasonable time. Any appeal of the Administrator’s final decision is subject to the provisions of part 78 of this chapter.
§ 98.442 GHGs to report.
You must report:
(a) Mass of CO
(b) Mass of CO
(c) Mass of CO
(d) Mass of CO
(e) Mass of CO
(f) Mass of CO
(g) Mass of CO
(h) Cumulative mass of CO
§ 98.443 Calculating CO2 geologic sequestration.
You must calculate the mass of CO
(a) You must calculate and report the annual mass of CO
(1) For a mass flow meter, you must calculate the total annual mass of CO
(2) For a volumetric flow meter, you must calculate the total annual mass of CO
(3) If you receive CO
(b) You must calculate and report the annual mass of CO
(1) If you are measuring the mass of contents in a container under the provisions of § 98.444(a)(2)(i), you must calculate the CO
(2) If you are measuring the volume of contents in a container under the provisions of § 98.444(a)(2)(ii), you must calculate the CO
(c) You must report the annual mass of CO
(1) If you use a mass flow meter to measure the flow of an injected CO
(2) If you use a volumetric flow meter to measure the flow of an injected CO
(3) To aggregate injection data for all wells covered under this subpart, you must sum the mass of all CO
(d) You must calculate the annual mass of CO
(1) For each gas-liquid separator for which flow is measured using a mass flow meter, you must calculate annually the total mass of CO
(2) For each gas-liquid separator for which flow is measured using a volumetric flow meter, you must calculate annually the total mass of CO
(3) To aggregate production data, you must sum the mass of all of the CO
(e) You must report the annual mass of CO
(f) You must report the annual mass of CO
(1) If you are actively producing oil or natural gas or if you are producing any other fluids, you must calculate the annual mass of CO
(2) If you are not actively producing oil or natural gas or any other fluids, you must calculate the annual mass of CO
§ 98.444 Monitoring and QA/QC requirements.
(a) CO
(i) You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly.
(ii) If you took ownership of the CO
(iii) If you inject CO
(2) Except as provided in paragraph (a)(4) of this section, you must determine the quarterly mass or volume of contents in all containers if you receive CO
(i) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells.
(ii) You may determine the volume of the contents of containers summed quarterly.
(iii) If you took ownership of the CO
(3) Except as provided in paragraph (a)(4) of this section, you must determine a quarterly concentration of the CO
(i) You may sample the CO
(ii) If you took ownership of the CO
(iii) If you inject CO
(4) If the CO
(5) You must assume that the CO
(b) CO
(2) You must measure flow rate of CO
(3) You must sample the injected CO
(c) CO
(2) You must sample the produced gas stream at least once per quarter immediately upstream or downstream of the flow meter used to measure flow rate of that gas stream and measure the CO
(3) You must measure flow rate of gas produced with a flow meter and collect the flow rate quarterly.
(d) CO
(e) Measurement devices. (1) All flow meters must be operated continuously except as necessary for maintenance and calibration.
(2) You must calibrate all flow meters used to measure quantities reported in § 98.446 according to the calibration and accuracy requirements in § 98.3(i).
(3) You must operate all measurement devices according to one of the following. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(4) You must ensure that any flow meter calibrations performed are National Institute of Standards and Technology (NIST) traceable.
(f) General. (1) If you measure the concentration of any CO
(2) You must convert all measured volumes of CO
(3) For 2011, you may follow the provisions of § 98.3(d)(1) through (2) for best available monitoring methods only for parameters required by paragraphs (a) and (b) of § 98.443 rather than follow the monitoring requirements of paragraph (a) of this section. For purposes of this subpart, any reference to the year 2010 in § 98.3(d)(1) through (2) shall mean 2011.
§ 98.445 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG quantities calculations is required. Whenever the monitoring procedures cannot be followed, you must use the following missing data procedures:
(a) A quarterly flow rate of CO
(1) Another calculation methodology listed in § 98.444(a)(1) must be used if possible.
(2) If another method listed in § 98.444(a)(1) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period.
(b) A quarterly mass or volume of contents in containers received that is missing must be estimated as follows:
(1) Another calculation methodology listed in § 98.444(a)(2) must be used if possible.
(2) If another method listed in § 98.444(a)(2) cannot be used, a quarterly mass or volume value that is missing must be estimated using a representative mass or volume value from the nearest previous time period.
(c) A quarterly CO
(1) Another calculation methodology listed in § 98.444(a)(3) must be used if possible.
(2) If another method listed in § 98.444(a)(3) cannot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period.
(d) A quarterly quantity of CO
(e) For any values associated with CO
(f) The quarterly quantity of CO
(g) You must estimate the mass of CO
(h) You must estimate other missing data as required by your approved MRV plan.
§ 98.446 Data reporting requirements.
In addition to the information required by § 98.3(c), report the information listed in this section.
(a) If you receive CO
(1) The total net mass of CO
(2) If a volumetric flow meter is used to receive CO
(i) The volumetric flow through a receiving flow meter at standard conditions (in standard cubic meters) in each quarter.
(ii) The volumetric flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter.
(iii) The CO
(3) If a mass flow meter is used to receive CO
(i) The mass flow through a receiving flow meter (in metric tons) in each quarter.
(ii) The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in metric tons) in each quarter.
(iii) The CO
(4) If the CO
(5) The standard or method used to calculate each value in paragraphs (a)(2) through (a)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section.
(7) Whether the flow meter is mass or volumetric.
(8) A numerical identifier for the flow meter.
(b) If you receive CO
(1) The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers received in each quarter.
(2) The concentration of CO
(3) The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is redelivered to another facility without being injected into your well in each quarter.
(4) The net mass of CO
(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section.
(c) If you use more than one receiving flow meter, report the total net mass of CO
(d) The source of the CO
(1) CO
(2) Electric generating unit.
(3) Ethanol plant.
(4) Pulp and paper mill.
(5) Natural gas processing.
(6) Gasification operations.
(7) Other anthropogenic source.
(8) Discontinued enhanced oil and gas recovery project.
(9) Unknown.
(e) Report the date that you began collecting data for calculating total amount sequestered according to § 98.448(a)(7) of this subpart.
(f) Report the following. If the date specified in paragraph (e) of this section is during the reporting year for this annual report, report the following starting on the date specified in paragraph (e) of this section.
(1) For each injection flow meter (mass or volumetric), report:
(i) The mass of CO
(ii) The CO
(iii) If a volumetric flow meter is used, the volumetric flow rate at standard conditions (in standard cubic meters) in each quarter.
(iv) If a mass flow meter is used, the mass flow rate (in metric tons) in each quarter.
(v) A numerical identifier for the flow meter.
(vi) Whether the flow meter is mass or volumetric.
(vii) The standard used to calculate each value in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
(viii) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(1)(ii) through (f)(1)(iv) of this section.
(ix) The location of the flow meter.
(2) The total CO
(3) For CO
(i) The mass of CO
(ii) The mass of CO
(4) For each separator flow meter (mass or volumetric), report:
(i) CO
(ii) CO
(iii) If a volumetric flow meter is used, volumetric flow rate at standard conditions (standard cubic meters) in each quarter.
(iv) If a mass flow meter, mass flow rate (metric tons) in each quarter.
(v) A numerical identifier for the flow meter.
(vi) Whether the flow meter is mass or volumetric.
(vii) The standard used to calculate each value in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
(viii) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (f)(4)(ii) through (f)(4)(iv) of this section.
(5) The entrained CO
(6) Annual CO
(7) For each leakage pathway through which CO
(i) A numerical identifier for the leakage pathway.
(ii) The CO
(8) Annual CO
(9) Annual CO
(10) Cumulative mass of CO
(11) Date that the most recent MRV plan was approved by EPA and the MRV plan approval number that was issued by EPA.
(12) An annual monitoring report that contains the following components:
(i) A narrative history of the monitoring efforts conducted over the previous calendar year, including a listing of all monitoring equipment that was operated, its period of operation, and any relevant tests or surveys that were conducted.
(ii) A description of any changes to the monitoring program that you concluded were not material changes warranting submission of a revised MRV plan under § 98.448(d).
(iii) A narrative history of any monitoring anomalies that were detected in the previous calendar year and how they were investigated and resolved.
(iv) A description of any surface leakages of CO
(13) If a well is permitted under the Underground Injection Control program, for each injection well, report:
(i) The well identification number used for the Underground Injection Control permit.
(ii) The Underground Injection Control permit class.
(14) If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration.
§ 98.447 Records that must be retained.
(a) You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must retain the records specified in paragraphs (a)(1) through (7) of this section, as applicable. You must retain all required records for at least 3 years.
(1) Quarterly records of CO
(2) Quarterly records of produced CO
(3) Quarterly records of injected CO
(4) Annual records of information used to calculate the CO
(5) Annual records of information used to calculate the CO
(6) Annual records of information used to calculate the CO
(7) Any other records as specified for retention in your EPA-approved MRV plan.
(b) You must complete your monitoring plans, as described in § 98.3(g)(5), by April 1 of the year you begin collecting data.
§ 98.448 Geologic sequestration monitoring, reporting, and verification (MRV) plan.
(a) Contents of MRV plan. You must develop and submit to the Administrator a proposed MRV plan for monitoring, reporting, and verification of geologic sequestration at your facility. Your proposed MRV plan must contain the following components:
(1) Delineation of the maximum monitoring area and the active monitoring areas. The first period for your active monitoring area will begin from the date determined in your MRV plan through the date at which the plan calls for the first expansion of the monitoring area. The length of each monitoring period can be any time interval chosen by you that is greater than 1 year.
(2) Identification of potential surface leakage pathways for CO
(3) A strategy for detecting and quantifying any surface leakage of CO
(4) A strategy for establishing the expected baselines for monitoring CO
(5) A summary of the considerations you intend to use to calculate site-specific variables for the mass balance equation. This includes, but is not limited to, considerations for calculating CO
(6) If a well is permitted under the Underground Injection Control program, for each injection well, report the well identification number used for the Underground Injection Control permit and the Underground Injection Control permit class. If the well is not yet permitted, and you have applied for an Underground Injection Control permit, report the well identification numbers in the permit application. If an offshore well is not subject to the Safe Drinking Water Act, for each injection well, report any well identification number and any identification number used for the legal instrument authorizing geologic sequestration. If you are submitting your Underground Injection Control permit application as part of your proposed MRV plan, you must notify EPA when the permit has been approved. If you are an offshore facility not subject to the Safe Drinking Water Act, and are submitting your application for the legal instrument authorizing geologic sequestration as part of your proposed MRV plan, you must notify EPA when the legal instrument authorizing geologic sequestration has been approved.
(7) Proposed date to begin collecting data for calculating total amount sequestered according to equation RR-11 or RR-12 of this subpart. This date must be after expected baselines as required by paragraph (a)(4) of this section are established and the leakage detection and quantification strategy as required by paragraph (a)(3) of this section is implemented in the initial AMA.
(b) Timing. You must submit a proposed MRV plan to EPA according to the following schedule:
(1) You must submit a proposed MRV plan to EPA by June 30, 2011 if you were issued a final Underground Injection Control permit authorizing the injection of CO
(2) You must submit a proposed MRV plan to EPA within 180 days of receiving a final Underground Injection Control permit authorizing the injection of CO
(3) If you are injecting a CO
(4) If EPA determines that your proposed MRV plan is incomplete, you must submit an updated MRV plan within 45 days of EPA notification, unless otherwise specified by EPA.
(c) Final MRV plan. The Administrator will issue a final MRV plan within a reasonable period of time. The Administrator’s final MRV plan is subject to the provisions of part 78 of this chapter. Once the MRV plan is final and no longer subject to administrative appeal under part 78 of this chapter, you must implement the plan starting on the day after the day on which the plan becomes final and is no longer subject to such appeal.
(d) MRV plan revisions. You must revise and submit the MRV plan within 180 days to the Administrator for approval if any of the following in paragraphs (d)(1) through (d)(4) of this section applies. You must include the reason(s) for the revisions in your submittal.
(1) A material change was made to monitoring and/or operational parameters that was not anticipated in the original MRV plan. Examples of material changes include but are not limited to: Large changes in the volume of CO
(2) A change in the permit class of your Underground Injection Control permit.
(3) If you are notified by EPA of substantive errors in your MRV plan or monitoring report.
(4) You choose to revise your MRV plan for any other reason in any reporting year.
(e) Revised MRV plan. The requirements of paragraph (c) of this section apply to any submission of a revised MRV plan. You must continue reporting under your currently approved plan while awaiting approval of a revised MRV plan.
(f) Format. Each proposed MRV plan or revision and each annual report must be submitted electronically in a format specified by the Administrator.
(g) Certificate of representation. You must submit a certificate of representation according to the provisions in § 98.4 at least 60 days before submission of your MRV plan, your research and development exemption request, your MRV plan submission extension request, or your initial annual report under this part, whichever is earlier.
§ 98.449 Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
Active monitoring area is the area that will be monitored over a specific time interval from the first year of the period (n) to the last year in the period (t). The boundary of the active monitoring area is established by superimposing two areas:
(1) The area projected to contain the free phase CO
(2) The area projected to contain the free phase CO
CO
Equipment leak means those emissions that could not reasonably pass through a stack, chimney, vent, or other functionally-equivalent opening.
Expected baseline is the anticipated value of a monitored parameter that is compared to the measured monitored parameter.
Maximum monitoring area means the area that must be monitored under this regulation and is defined as equal to or greater than the area expected to contain the free phase CO
Research and development project means a project for the purpose of investigating practices, monitoring techniques, or injection verification, or engaging in other applied research, that will enable safe and effective long-term containment of a CO
Separator means a vessel in which streams of multiple phases are gravity separated into individual streams of single phase.
Surface leakage means the movement of the injected CO
Underground Injection Control permit means a permit issued under the authority of Part C of the Safe Drinking Water Act at 42 U.S.C. 300h et seq.
Underground Injection Control program means the program responsible for regulating the construction, operation, permitting, and closure of injection wells that place fluids underground for storage or disposal for purposes of protecting underground sources of drinking water from endangerment pursuant to Part C of the Safe Drinking Water Act at 42 U.S.C. 300h et seq.
Vented emissions means intentional or designed releases of CH
Subpart SS – Electrical Equipment Manufacture or Refurbishment
§ 98.450 Definition of the source category.
The electrical equipment manufacturing or refurbishment category consists of processes that manufacture or refurbish gas-insulated substations, circuit breakers, other switchgear, gas-insulated lines, or power transformers (including gas-containing components of such equipment) containing sulfur-hexafluoride (SF
§ 98.451 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an electrical equipment manufacturing or refurbishing process and the facility meets the requirements of § 98.2(a)(1). Electrical equipment manufacturing and refurbishing facilities covered by this rule are those that have total annual purchases of SF
§ 98.452 GHGs to report.
(a) You must report SF
(b) You must report CO
§ 98.453 Calculating GHG emissions.
(a) For each electrical equipment manufacturer or refurbisher, estimate the annual SF
(b) Use the mass-balance method in paragraph (a) of this section to estimate emissions of PFCs associated with the manufacture or refurbishment of power transformers, substituting the relevant PFC(s) for SF
(c) Estimate the disbursements of SF
(d) Estimate the mass of SF
(e) If the mass of SF
(f) If the mass of SF
(g) Estimate the mass of SF
(h) If the mass of SF
(1) Determine the equipment’s actual nameplate capacity, by measuring the nameplate capacities of a representative sample of each make and model and calculating the mean value for each make and model as specified at § 98.454(f).
(2) If equipment is shipped with a partial charge, calculate the partial shipping charge by multiplying the nameplate capacity of the equipment by the ratio of the densities of the partial charge to the full charge.
(i) Estimate the annual SF
§ 98.454 Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, you may follow the provisions of § 98.3(d)(1) through (d)(2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference in § 98.3(d)(1) through (d)(2) to 2010 means 2011, March 31 means June 30, and April 1 means July 1. Any reference to the effective date in § 98.3(d)(1) through (d)(2) means February 28, 2011.
(b) Ensure that all the quantities required by the equations of this subpart have been measured using either flowmeters with an accuracy and precision of ±1 percent of full scale or better or scales with an accuracy and precision of ±1 percent of the filled weight (gas plus tare) of the containers of SF
(c) All flow meters, weigh scales, and combinations of volumetric and density measures that are used to measure or calculate quantities under this subpart must be calibrated using calibration procedures specified by the flowmeter, scale, volumetric or density measure equipment manufacturer. Calibration must be performed prior to the first reporting year. After the initial calibration, recalibration must be performed at the minimum frequency specified by the manufacturer.
(d) For purposes of Equations SS-5 of this subpart, the emission factor for the valve-hose combination (EF
(e) Electrical equipment manufacturers and refurbishers must account for SF
(f) If the mass of SF
(g) Ensure the following QA/QC methods are employed throughout the year:
(1) Procedures are in place and followed to track and weigh all cylinders or other containers at the beginning and end of the year.
(h) You must adhere to the following QA/QC methods for reviewing the completeness and accuracy of reporting:
(1) Review inputs to Equation SS-1 of this subpart to ensure inputs and outputs to the company’s system are included.
(2) Do not enter negative inputs and confirm that negative emissions are not calculated. However, the decrease in SF
(3) Ensure that beginning-of-year inventory matches end-of-year inventory from the previous year.
(4) Ensure that in addition to SF
§ 98.455 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG emissions calculations is required. Replace missing data, if needed, based on data from similar manufacturing operations, and from similar equipment testing and decommissioning activities for which data are available.
§ 98.456 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each chemical at the facility level:
(a) Pounds of SF
(b) Pounds of SF
(c) Pounds of SF
(d) Pounds of SF
(e) Pounds of SF
(f) Pounds of SF
(g) Pounds of SF
(h) Pounds of SF
(i) Pounds of SF
(j) Pounds of SF
(k) The nameplate capacity of the equipment, in pounds, delivered to customers with SF
(l) A description of the engineering methods and calculations used to determine emissions from hoses or other flow lines that connect the container to the equipment that is being filled.
(m) The values for EF
(n) The total number of fill operations for each hose and valve combination, or, F
(o) If the mass of SF
(p) If the mass of SF
(q) Pounds of SF
(r) Pounds of SF
(s) The nameplate capacity of the equipment, in pounds, installed at off-site electric power transmission or distribution locations used to determine emissions from installation, or N
(t) For any missing data, you must report the reason the data were missing, the parameters for which the data were missing, the substitute parameters used to estimate emissions in their absence, and the quantity of emissions thereby estimated.
§ 98.457 Records that must be retained.
In addition to the information required by § 98.3(g), you must retain the following records:
(a) All information reported and listed in § 98.456.
(b) Accuracy certifications and calibration records for all scales and monitoring equipment, including the method or manufacturer’s specification used for calibration.
(c) Certifications of the quantity of gas, in pounds, charged into equipment at the electrical equipment manufacturer or refurbishment facility as well as the actual quantity of gas, in pounds, charged into equipment at installation.
(d) Check-out and weigh-in sheets and procedures for cylinders.
(e) Residual gas amounts, in pounds, in cylinders sent back to suppliers.
(f) Invoices for gas purchases and sales.
(g) GHG Monitoring Plans, as described in § 98.3(g)(5), must be completed by April 1, 2011.
§ 98.458 Definitions.
All terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
Subpart TT – Industrial Waste Landfills
§ 98.460 Definition of the source category.
(a) This source category applies to industrial waste landfills that accepted waste on or after January 1, 1980, and that are located at a facility whose total landfill design capacity is greater than or equal to 300,000 metric tons.
(b) An industrial waste landfill is a landfill other than a municipal solid waste landfill, a RCRA Subtitle C hazardous waste landfill, or a TSCA hazardous waste landfill, in which industrial solid waste, such as RCRA Subtitle D wastes (non-hazardous industrial solid waste, defined in 40 CFR 257.2), commercial solid wastes, or conditionally exempt small quantity generator wastes, is placed. An industrial waste landfill includes all disposal areas at the facility.
(c) This source category does not include:
(1) Construction and demolition waste landfills.
(2) Industrial waste landfills that only receive one or more of the following inert waste materials:
(i) Coal combustion or incinerator ash (e.g., fly ash).
(ii) Cement kiln dust.
(iii) Rocks and/or soil from excavation and construction and similar activities.
(iv) Glass.
(v) Non-chemically bound sand (e.g., green foundry sand).
(vii) Clay, gypsum, or pottery cull.
(viii) Bricks, mortar, or cement.
(ix) Furnace slag.
(x) Materials used as refractory (e.g., alumina, silicon, fire clay, fire brick).
(xi) Plastics (e.g., polyethylene, polypropylene, polyethylene terephthalate, polystyrene, polyvinyl chloride).
(xii) Other waste material that has a volatile solids concentration of 0.5 weight percent (on a dry basis) or less.
(xiii) Other waste material that has a DOC value of 0.3 weight percent (on a wet basis) or less. DOC value must be determined using a 60-day anaerobic biodegradation test procedure identified in § 98.464(b)(4)(i).
(d) This source category consists of the following sources at industrial waste landfills: Landfills, gas collection systems at landfills, and destruction devices for landfill gases (including flares).
§ 98.461 Reporting threshold.
You must report GHG emissions under this subpart if your facility contains an industrial waste landfill meeting the criteria in § 98.460 and the facility meets the requirements of § 98.2(a)(2). For the purposes of § 98.2(a)(2), the emissions from the industrial waste landfill are to be determined using the methane generation corrected for oxidation as determined using Equation TT-6 of this subpart times the global warming potential for methane in Table A-1 of subpart A of this part.
§ 98.462 GHGs to report.
(a) You must report CH
(b) You must report CH
(c) You must report under subpart C of this part (General Stationary Fuel Combustion Sources) the emissions of CO
§ 98.463 Calculating GHG emissions.
(a) For each industrial waste landfill subject to the reporting requirements of this subpart, calculate annual modeled CH
(1) Calculate annual modeled CH
(2) Waste stream quantities. Determine annual waste quantities as specified in paragraphs (a)(2)(i) through (ii) of this section for each year starting with January 1, 1960 or the year the landfills first accepted waste if after January 1, 1960, up until the most recent reporting year. The choice of method for determining waste quantities will vary according to the availability of historical data. Beginning in the first emissions reporting year (2011 or later) and for each year thereafter, use the procedures in paragraph (a)(2)(i) of this section to determine waste stream quantities. These procedures should also be used for any year prior to the first emissions reporting year for which the data are available. For other historical years, use paragraph (a)(2)(i) of this section, where waste disposal records are available, and use the procedures outlined in paragraph (a)(2)(ii) of this section when waste disposal records are unavailable, to determine waste stream quantities. Historical disposal quantities deposited (i.e., prior to the first year in which monitoring begins) should only be determined once, as part of the first annual report, and the same values should be used for all subsequent annual reports, supplemented by the next year’s data on new waste disposal.
(i) Determine the quantity of waste (in metric tons as received, i.e., wet weight) disposed of in the landfill separately for each waste stream by any one or a combination of the following methods.
(A) Direct mass measurements.
(B) Direct volume measurements multiplied by waste stream density determined from periodic density measurement data or process knowledge.
(C) Mass balance procedures, determining the mass of waste as the difference between the mass of the process inputs and the mass of the process outputs.
(D) The number of loads (e.g., trucks) multiplied by the mass of waste per load based on the working capacity of the container or vehicle.
(ii) Determine the historical disposal quantities for landfills using the Waste Disposal Factor approach in paragraphs (a)(2)(ii)(A) and (B) of this section when historical production or processing data are available. If production or processing data are available for a given year, you must use Equation TT-3 of this section for that year. Determine historical disposal quantities using the method specified in paragraph (a)(2)(ii)(C) of this section when historical production or processing data are not available, and for waste streams received from an off-site facility when historical disposal quantities cannot be determined using the methods specified in paragraph (a)(2)(i) of this section.
(A) Determining Waste Disposal Factor: For each waste stream disposed of in the landfill, calculate the average waste disposal rate per unit of production or unit throughput using all available waste quantity data and corresponding production or processing rates for the process generating that waste or, if appropriate, the facility, using Equation TT-2 of this section.
(B) Calculate waste: For each waste stream disposed of in the landfill, calculate the waste disposal quantities for historic years in which direct waste disposal measurements are not available using historical production data and Equation TT-3 of this section.
(C) For any year in which historic production or processing data are not available such that historic waste quantities cannot be estimated using Equation TT-3 of this section, calculate an average annual bulk waste disposal quantity using either Equation TT-4a of this section when data are available consecutively for the most recent disposal years or Equation TT-4b of this section when data are available for sporadic (non-consecutive) years.
(3) Degradable organic content (DOC). For any year, X, in Equation TT-1 of this section, use either the applicable default DOC values provided in Table TT-1 of this subpart or determine values for DOC
(i) For the first year in which GHG emissions from this industrial waste landfill must be reported, determine the DOC
(ii) For subsequent years (after the first year in which GHG emissions from this industrial waste landfill must be reported), either use the DOC
(iii) If DOC
(iv) For historical years for which DOC
(A) For years in which waste stream-specific disposal quantities are determined (as required in paragraphs (a)(2) (ii)(A) and (B) of this section), calculate the average DOC value for a given waste stream as the arithmetic average of all DOC measurements of that waste stream that follow the methods provided in § 98.464(b), including any measurement values for years prior to the first reporting year and the four measurement values required in the first reporting year. Use the resulting waste-specific average DOC value for all applicable years (i.e., years in which waste stream-specific disposal quantities are determined) for which direct DOC measurement data are not available.
(B) For years for which bulk waste disposal quantities are determined according to paragraphs (a)(2)(ii)(C) of this section, calculate the weighted average bulk DOC value according to the following: Calculate the average DOC value for each waste stream as the arithmetic average of all DOC measurements of that waste stream that follows the methods provided in § 98.464(b) (generally, this will include only the DOC values determined in the first year in which GHG emissions from this industrial waste landfill must be reported); calculate the average annual disposal quantity for each waste stream as the arithmetic average of the annual disposal quantities for each year in which waste stream-specific disposal quantities have been determined; and calculate the bulk waste DOC value using Equation TT-5 of this section. Use the bulk waste DOC value as DOC
(b) For each landfill, calculate CH
(1) For each landfill, calculate CH
(2) For landfills that do not have landfill gas collection systems operating during the reporting year, the CH
(3) For landfills with landfill gas collection systems in operation during any portion of the reporting year, perform all of the calculations specified in paragraphs (b)(3)(i) through (iv) of this section.
(i) Calculate the quantity of CH
(ii) Calculate CH
(iii) Calculate CH
(iv) Calculate CH
§ 98.464 Monitoring and QA/QC requirements.
(a) For calendar year 2011 monitoring, the facility may submit a request to the Administrator to use one or more best available monitoring methods as listed in § 98.3(d)(1)(i) through (iv). The request must be submitted no later than October 12, 2010 and must contain the information in § 98.3(d)(2)(ii). To obtain approval, the request must demonstrate to the Administrator’s satisfaction that it is not reasonably feasible to acquire, install, and operate a required piece of monitoring equipment by January 1, 2011. The use of best available monitoring methods will not be approved beyond December 31, 2011.
(b) For each waste stream placed in the landfill during the reporting year for which you choose to determine volatile solids concentration and/or a waste stream-specific DOC
(1) Develop and follow a sampling plan to collect a representative sample (in terms of composition and moisture content) of each waste stream placed in the landfill for which testing is elected.
(2) Determine the percent total solids and the percent volatile solids of each sample following Standard Method 2540G “Total, Fixed, and Volatile Solids in Solid and Semisolid Samples” (incorporated by reference; see § 98.7).
(3) For the purposes of § 98.460(c)(2)(xii), the volatile solids concentration (weight percent on a dry basis) is the percent volatile solids determined using Standard Method 2540G “Total, Fixed, and Volatile Solids in Solid and Semisolid Samples” (incorporated by reference; see § 98.7).
(4) Determine DOC value of a waste stream by either using at least a 60-day anaerobic biodegradation test as specified in paragraph (b)(4)(i) of this section or by estimating the DOC value based on the total and volatile solids measurements as specified in paragraph (b)(4)(ii) of this section.
(i) Perform an anaerobic biodegradation test and determine the DOC value of a waste stream following the procedures and requirements in paragraphs (b)(4)(i)(A) through (E) of this section.
(A) You may use the procedures published by a consensus-based standards organization to conduct a minimum of a 60-day anaerobic biodegradation test. Consensus-based standards organizations include, but are not limited to, the following: ASTM International (100 Barr Harbor Drive, P.O. Box CB700, West Conshohocken, Pennsylvania 19428-B2959, (800) 262-1373, http://www.astm.org), the American National Standards Institute (ANSI, 1819 L Street, NW., 6th floor, Washington, DC 20036, (202) 293-8020, http://www.ansi.org), the American Society of Mechanical Engineers (ASME, Three Park Avenue, New York, NY 10016-5990, (800) 843-2763, http://www.asme.org), and the North American Energy Standards Board (NAESB, 801 Travis Street, Suite 1675, Houston, TX 77002, (713) 356-0060, http://www.api.org).
(B) Use a minimum of four samples: Two waste stream samples, a control sample using a known substrate (such as ethanol), and a digester sludge blank sample. Each waste stream sample must be appropriately ground to ensure the waste material is fully exposed to the anaerobic digester sludge.
(C) Determine the net mass of carbon degraded in the control sample as the difference in the results of the control sample and the digester sludge blank sample. Determine the net mass of carbon degraded in each waste stream sample as the difference in the results of each waste stream sample and the digester sludge blank sample.
(D) Determine the fraction of carbon degraded in the control sample as the net mass of carbon degraded in the control sample divided by the mass of carbon added via the substrate material in the control sample. If less than 50 percent of the theoretical mass of carbon in the control sample is degraded, the test run is invalid.
(E) Determine the DOC of each waste sample using Equation TT-7 of this section. If the DOC values for the two waste stream samples differ by more than 20 percent, the test run is invalid. The DOC of the waste stream is determined as the average DOC value of the two waste stream samples determined during a valid test.
(ii) Calculate the waste stream-specific DOC
(c) For each waste stream that was historically managed in the landfill for which you choose to determine volatile solids concentration and/or a waste stream-specific DOC
(1) If you can identify a similar waste stream to the waste stream that was historically managed in the landfill, you must determine the volatile solids concentration or DOC
(2) If you cannot identify a similar waste stream to the waste stream that was historically managed in the landfill, you may determine the volatile solids concentration or DOC
(d) For landfills with gas collection systems, operate, maintain, and calibrate a gas composition monitor capable of measuring the concentration of CH
(e) For landfills with gas collection systems, install, operate, maintain, and calibrate a gas flow meter capable of measuring the volumetric flow rate of the recovered landfill gas according to the requirements specified at § 98.344(c).
(f) For landfills with gas collection systems, all temperature, pressure, and if applicable, moisture content monitors must be calibrated using the procedures and frequencies specified by the manufacturer.
(g) For landfills electing to measure the fraction by volume of CH
(1) Use a gas composition monitor capable of measuring the concentration of CH
(2) Use Equation TT-9 of this section to correct the measured CH
(h) The facility shall document the procedures used to ensure the accuracy of the estimates of disposal quantities and, if the industrial waste landfill has a gas collection system, gas flow rate, gas composition, temperature, pressure, and moisture content measurements. These procedures include, but are not limited to, calibration of weighing equipment, fuel flow meters, and other measurement devices. The estimated accuracy of measurements made with these devices shall also be recorded, and the technical basis for these estimates shall be provided.
§ 98.465 Procedures for estimating missing data.
(a) A complete record of all measured parameters used in the GHG emissions calculations is required. Therefore, whenever a quality-assured value of a required parameter is unavailable (e.g., if a meter malfunctions during unit operation or if a required fuel sample is not taken), a substitute data value for the missing parameter shall be used in the calculations, in accordance with paragraph (b) of this section.
(b) For industrial waste landfills with gas collection systems, follow the procedures for estimating missing data specified in § 98.345(a) and (b).
§ 98.466 Data reporting requirements.
In addition to the information required by § 98.3(c), each annual report must contain the following information for each landfill.
(a) Report the following general landfill information:
(1) A classification of the landfill as “open” (actively received waste in the reporting year) or “closed” (no longer receiving waste).
(2) The year in which the landfill first started accepting waste for disposal.
(3) The last year the landfill accepted waste (for open landfills, enter the estimated year of landfill closure).
(4) The capacity (in metric tons) of the landfill.
(5) An indication of whether leachate recirculation is used during the reporting year and its typical frequency of use over the past 10 years (e.g., used several times a year for the past 10 years, used at least once a year for the past 10 years, used occasionally but not every year over the past 10 years, not used).
(b) Report the following waste characterization and modeling information:
(1) The number of waste steams (including “Other Industrial Solid Waste (not otherwise listed)” and “Inerts”) for which Equation TT-1 of this subpart is used to calculate modeled CH
(2) A description of each waste stream (including the types of materials in each waste stream) for which Equation TT-1 of this subpart is used to calculate modeled CH
(3) The fraction of CH
(4) The methane correction factor (MCF) value used in the calculations. If an MCF value other than the default of 1 is used, provide a description of the aeration system, including aeration blower capacity, the fraction of the landfill containing waste affected by the aeration, the total number of hours during the year the aeration blower was operated, and other factors used as a basis for the selected MCF value.
(5) For each waste stream, the decay rate (k) value used in the calculations.
(c) Report the following historical waste information:
(1) [Reserved]
(2) For each waste stream identified in paragraph (b) of this section, the method(s) for estimating historical waste disposal quantities and the range of years for which each method applies.
(3) For each waste stream identified in paragraph (b) of this section for which Equation TT-2 of this subpart is used, provide:
(i) [Reserved]
(ii) The year of the data used in Equation TT-2 of § 98.463 for the waste disposal quantity and production quantity, for each year used in Equation TT-2 to calculate the average waste disposal factor (WDF).
(iii) [Reserved]
(4) If Equation TT-4a of this subpart is used, provide:
(i) The value of landfill capacity (LFC).
(ii) YrData.
(iii) YrOpen.
(5) If Equation TT-4b of this subpart is used, provide:
(i) WIP (i.e., the quantity of waste in-place at the start of the reporting year from design drawings or engineering estimates (metric tons) or, for closed landfills for which waste in-place quantities are not available, the landfill’s design capacity).
(ii) The cumulative quantity of waste placed in the landfill for the years for which disposal quantities are available from company record or from Equation TT-3 of this part.
(iii) YrLast.
(iv) YrOpen.
(v) NYrData.
(d) For each year of landfilling starting with the “Start Year” (S) and each year thereafter up to the current reporting year, report the following information:
(1) The calendar year for which the following data elements apply.
(2) The quantity of waste (W
(3) For each waste stream, the degradable organic carbon (DOC
(e) Report the following information describing the landfill cover material:
(1) The type of cover material used (as either organic cover, clay cover, sand cover, or other soil mixtures).
(2) For each type of cover material used, the surface area (in square meters) at the start of the reporting year for the landfill sections that contain waste and that are associated with the selected cover type.
(f) The modeled annual methane generation (G
(g) For landfills without gas collection systems, provide:
(1) The annual methane emissions (i.e., the methane generation (MG), adjusted for oxidation, calculated using Equation TT-6 of this subpart), reported in metric tons CH
(2) An indication of whether passive vents and/or passive flares (vents or flares that are not considered part of the gas collection system as defined in § 98.6) are present at this landfill.
(h) For landfills with gas collection systems, in addition to the reporting requirements in paragraphs (a) through (f) of this section, provide:
(1) The annual methane generation, adjusted for oxidation, calculated using Equation TT-6 of this subpart, reported in metric tons CH
(2) The oxidation factor used in Equation TT-6 of this subpart.
(3) All information required under 40 CFR 98.346(i)(1) through (7) and 40 CFR 98.346(i)(9) through (12).
§ 98.467 Records that must be retained.
(a) The calibration records for all monitoring equipment, including the method or manufacturer’s specification used for calibration, and all measurement data used for the purposes of § 98.460(c)(2)(xii) or (xiii) or used to determine waste stream-specific DOC
(b) Verification software records. You must keep a record of the file generated by the verification software specified in § 98.5(b) for the applicable data specified in paragraphs (b)(1) and (2) of this section. Retention of this file satisfies the recordkeeping requirement for the data in paragraphs (b)(1) and (2) of this section.
(1) Quantity of each product produced or feedstock entering the process or facility per waste stream per year, from measurement data and/or other company records. You must use the same basis for all years in the calculation (i.e., based on production or based on quantity of feedstock) (metric tons) (Equation TT-2 of § 98.463).
(2) [Reserved]
§ 98.468 Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the CAA and subpart A of this part.
Construction and demolition (C&D) waste landfill means a solid waste disposal facility subject to the requirements of subparts A or B of part 257 of this chapter that receives construction and demolition waste and does not receive hazardous waste (defined in § 261.3 of this chapter) or industrial solid waste (defined in § 258.2 of this chapter) or municipal solid waste (defined in § 98.6 of this part) other than residential lead-based paint waste. A C&D waste landfill typically receives any one or more of the following types of solid wastes: roadwork material, excavated material, demolition waste, construction/renovation waste, and site clearance waste.
Design capacity means the maximum amount of solid waste a landfill can accept. For the purposes of this subpart, for landfills that have a permit, the design capacity can be determined in terms of volume or mass in the most recent permit issued by the state, local, or Tribal agency responsible for regulating the landfill, plus any in-place waste not accounted for in the most recent permit. If the owner or operator chooses to convert the design capacity from volume to mass to determine its design capacity, the calculation must include a site-specific density. If the design capacity is within 10 percent of the applicability threshold in § 98.460(a) and there is a change in the production process that can reasonably be expected to change the site-specific waste density, the site-specific waste density must be redetermined and the design capacity must be recalculated based on the new waste density.
Industrial sludge means the residual, semi-solid material left from industrial wastewater treatment processes or wet air pollution control devices (e.g., wet scrubbers). Industrial sludge includes underflow material collected in primary or secondary clarifiers, settling basins, or precipitation tanks as well as dredged materials from wastewater tanks or impoundments. Industrial sludge also includes the semi-solid materials remaining after these materials are dewatered via a belt process, centrifuge, or similar dewatering process.
Solid waste has the meaning established by the Administrator pursuant to the Solid Waste Disposal Act (42 U.S.C.A. 6901 et seq.).
Waste stream means industrial solid waste material that is generated by a specific manufacturing process or client. For wastes generated at the facility that includes the industrial waste landfill, a waste stream is the industrial solid waste material generated by a specific processing unit at that facility. For industrial solid wastes that are received from off-site facilities, a waste stream can be defined as each waste shipment or group of waste shipments received from a single client or group of clients that produce industrial solid wastes with similar waste properties.
Table TT-1 to Subpart TT of Part 98 – Default DOC and Decay Rate Values for Industrial Waste Landfills
Industry/Waste Type | DOC (weight fraction, wet basis) | k [dry climate a] (yr | k [moderate climate a] (yr | k [wet climate a] (yr |
---|---|---|---|---|
Food Processing (other than industrial sludge) | 0.22 | 0.06 | 0.12 | 0.18 |
Pulp and Paper Industry: | ||||
Pulp and paper wastes segregated into separate streams: | ||||
Boiler Ash | 0.06 | 0.02 | 0.03 | 0.04 |
Wastewater Sludge | 0.12 | 0.02 | 0.04 | 0.06 |
Kraft Recovery Wastes b | 0.025 | 0.02 | 0.03 | 0.04 |
Other Pulp and Paper Wastes (not otherwise listed) | 0.20 | 0.02 | 0.03 | 0.04 |
Pulp and paper wastes not segregated into separate streams: | ||||
Pulp and paper manufacturing wastes, general (other than industrial sludge) | 0.15 | 0.02 | 0.03 | 0.04 |
Wood and Wood Product (other than industrial sludge) | 0.43 | 0.02 | 0.03 | 0.04 |
Construction and Demolition | 0.08 | 0.02 | 0.03 | 0.04 |
Industrial Sludge c | 0.09 | 0.02 | 0.04 | 0.06 |
Inert Waste [ | 0 | 0 | 0 | 0 |
Other Industrial Solid Waste (not otherwise listed) | 0.20 | 0.02 | 0.04 | 0.06 |
a The applicable climate classification is determined based on the annual rainfall plus the recirculated leachate application rate. Recirculated leachate application rate (in inches/year) is the total volume of leachate recirculated from company records or engineering estimates and applied to the landfill divided by the area of the portion of the landfill containing waste [with appropriate unit conversions].
Dry climate = precipitation plus recirculated leachate less than 20 inches/year;
Moderate climate = precipitation plus recirculated leachate from 20 to 40 inches/year (inclusive);
Wet climate = precipitation plus recirculated leachate greater than 40 inches/year.
Alternatively, landfills that use leachate recirculation can elect to use the k value for wet climate rather than calculating the recirculated leachate rate.
b Kraft Recovery Wastes include green liquor dregs, slaker grits, and lime mud, which may also be referred to collectively as causticizing or recausticizing wastes.
c A facility that can segregate out pulp and paper industry wastewater sludge must apply the 0.12 DOC value to that portion of the sludge.
Subpart UU – Injection of Carbon Dioxide
§ 98.470 Definition of the source category.
(a) The injection of carbon dioxide (CO
(b) If you report under subpart RR of this part for a well or group of wells, you are not required to report under this subpart for that well or group of wells.
(c) A facility that is subject to this part only because it is subject to subpart UU of this part is not required to report emissions under subpart C of this part or any other subpart listed in § 98.2(a)(1) or (a)(2).
§ 98.471 Reporting threshold.
(a) You must report under this subpart if your facility injects any amount of CO
(b) For purposes of this subpart, any reference to CO
§ 98.472 GHGs to report.
You must report the mass of CO
§ 98.473 Calculating CO2 received.
(a) You must calculate and report the annual mass of CO
(1) For a mass flow meter, you must calculate the total annual mass of CO
(2) For a volumetric flow meter, you must calculate the total annual mass of CO
(3) If you receive CO
(b) You must calculate and report the annual mass of CO
(1) If you are measuring the mass of contents in a container under the provisions of § 98.474(a)(2)(i), you must calculate the CO
(2) If you are measuring the volume of contents in a container under the provisions of § 98.474(a)(2)(ii), you must calculate the CO
§ 98.474 Monitoring and QA/QC requirements.
(a) CO
(i) You may measure flow rate at the receiving custody transfer meter prior to any subsequent processing operations at the facility and collect the flow rate quarterly.
(ii) If you took ownership of the CO
(iii) If you inject CO
(2) You must determine the quarterly mass or volume of contents in all containers if you receive CO
(i) You may measure the mass of contents of containers summed quarterly using weigh bills, scales, or load cells.
(ii) You may determine the volume of the contents of containers summed quarterly.
(iii) If you took ownership of the CO
(3) You must determine a quarterly concentration of the CO
(i) You may sample the CO
(ii) If you took ownership of the CO
(iii) If you inject CO
(4) You must assume that the CO
(b) Measurement devices. (1) All flow meters must be operated continuously except as necessary for maintenance and calibration.
(2) You must calibrate all flow meters used to measure quantities reported in § 98.476 according to the calibration and accuracy requirements in § 98.3(i).
(3) You must operate all measurement devices according to one of the following. You may use an appropriate standard method published by a consensus-based standards organization if such a method exists or an industry standard practice. Consensus-based standards organizations include, but are not limited to, the following: ASTM International, the American National Standards Institute (ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the North American Energy Standards Board (NAESB).
(4) You must ensure that any flow meter calibrations performed are National Institute of Standards and Technology (NIST) traceable.
(c) General. (1) If you measure the concentration of any CO
(2) You must convert all measured volumes of CO
(3) For 2011, you may follow the provisions of § 98.3(d)(1) through (2) for best available monitoring methods rather than follow the monitoring requirements of this section. For purposes of this subpart, any reference to the year 2010 in § 98.3(d)(1) through (2) shall mean 2011.
§ 98.475 Procedures for estimating missing data.
A complete record of all measured parameters used in the GHG quantities calculations is required.
(a) Whenever the monitoring procedures for all facilities that used flow meters covered under this subpart cannot be followed to measure flow, the following missing data procedures must be followed:
(1) Another calculation methodology listed in § 98.474(a)(1) must be used if possible.
(2) If another method listed in § 98.474(a)(1) cannot be used, a quarterly flow rate value that is missing must be estimated using a representative flow rate value from the nearest previous time period.
(b) Whenever the monitoring procedures of this subpart cannot be followed to measure quarterly quantity of CO
(1) Another calculation methodology listed in § 98.474(a)(2) must be used if possible.
(2) If another method listed in § 98.474(a)(2) cannot be used, a quarterly mass or volume that is missing must be estimated using a representative mass or volume from the nearest previous time period.
(c) Whenever the monitoring procedures cannot be followed to measure CO
(1) Another calculation methodology listed in § 98.474(a)(3) must be used if possible.
(2) If another method listed in § 98.474(a)(3) cannot be used, a quarterly concentration value that is missing must be estimated using a representative concentration value from the nearest previous time period.
§ 98.476 Data reporting requirements.
If you are subject to this part and report under this subpart, you are not required to report the information in § 98.3(c)(4) for this subpart. In addition to the information required by § 98.3(c)(1) through § 98.3(c)(3) and by § 98.3(c)(5) through § 98.3(c)(9), you must report the information listed in this section.
(a) If you receive CO
(1) The total net mass of CO
(2) If a volumetric flow meter is used to receive CO
(i) The volumetric flow through a receiving flow meter at standard conditions (in standard cubic meters) in each quarter.
(ii) The volumetric flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in standard cubic meters) in each quarter.
(iii) The CO
(3) If a mass flow meter is used to receive CO
(i) The mass flow through a receiving flow meter (in metric tons) in each quarter.
(ii) The mass flow through a receiving flow meter that is redelivered to another facility without being injected into your well (in metric tons) in each quarter.
(iii) The CO
(4) The standard or method used to calculate each value in paragraphs (a)(2) through (a)(3) of this section.
(5) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (a)(2) through (a)(3) of this section.
(6) Whether the flow meter is mass or volumetric.
(b) If you receive CO
(1) The mass (in metric tons) or volume at standard conditions (in standard cubic meters) of contents in containers in each quarter.
(2) The concentration of CO
(3) The mass (in metric tons) or volume (in standard cubic meters) of contents in containers that is redelivered to another facility without being injected into your well in each quarter.
(4) The net total mass of CO
(5) The standard or method used to calculate each value in paragraphs (b)(1), (b)(2), and (b)(3) of this section.
(6) The number of times in the reporting year for which substitute data procedures were used to calculate values reported in paragraphs (b)(1) and (b)(2) of this section.
(c) If you use more than one receiving flow meter, report the net total mass of CO
(d) The source of the CO
(1) CO
(2) Electric generating unit.
(3) Ethanol plant.
(4) Pulp and paper mill.
(5) Natural gas processing.
(6) Gasification operations.
(7) Other anthropogenic source.
(8) Discontinued enhanced oil and gas recovery project.
(9) Unknown.
(e) Report the following:
(1) Whether the facility received a Research and Development project exemption from reporting under 40 CFR part 98, subpart RR, for this reporting year. If you received an exemption, report the start and end dates of the exemption approved by EPA.
(2) Whether the facility includes a well or group of wells where a CO
(3) Whether the facility includes a well or group of wells where a CO
(4) Whether the facility includes a well or group of wells where a CO
(5) Whether the facility includes a well or group of wells where a CO
§ 98.477 Records that must be retained.
(a) You must follow the record retention requirements specified by § 98.3(g). In addition to the records required by § 98.3(g), you must retain quarterly records of CO
(b) You must complete your monitoring plans, as described in § 98.3(g)(5), by April 1 of the year you begin collecting data.
§ 98.478 Definitions.
Except as provided below, all terms used in this subpart have the same meaning given in the Clean Air Act and subpart A of this part.
CO