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(continued)
(4) If a State adopts an emissions trading program that differs substantively from subparts AAAA through IIII of part 96 of this chapter, other than as set forth in paragraph (aa)(2) of this section, then such emissions trading program is not automatically approved as set forth in paragraph (aa)(1) or (2) of this section and will be reviewed by the Administrator for approvability in accordance with the other provisions of this section, provided that the NOX allowances issued under such emissions trading program shall not, and the SIP revision shall state that such NOX allowances shall not, qualify as CAIR NOX allowances or CAIR Ozone Season NOX allowances under any emissions trading program approved under paragraphs (o)(1) or (2) or (aa)(1) or (2) of this section.
(bb)(1)(i) The State may revise its SIP to provide that, for each ozone season during which a State implements control measures on EGUs or non-EGUs through an emissions trading program approved under paragraph (aa)(1) or (2) of this section, such EGUs and non-EGUs shall not be subject to the requirements of the State's SIP meeting the requirements of §51.121, if the State meets the requirement in paragraph (bb)(1)(ii) of this section.
(ii) For a State under paragraph (bb)(1)(i) of this section, if the State's amount of tons specified in paragraph (q)(2) of this section exceeds the State's amount of NOX SIP Call allowances allocated for the ozone season in 2009 or in any year thereafter for the same types and sizes of units as those covered by the amount of tons specified in paragraph (q)(2) of this section, then the State must replace the former amount for such ozone season by the latter amount for such ozone season in applying paragraph (q) of this section.
(2) Rhode Island may revise its SIP to provide that, for each ozone season during which Rhode Island implements control measures on EGUs and non-EGUs through an emissions trading program adopted in regulations that differ substantively from subparts AAAA through IIII of part 96 of this chapter as set forth in this paragraph, such EGUs and non-EGUs shall not be subject to the requirements of the State's SIP meeting the requirements of §51.121.
(i) Rhode Island must expand the applicability provisions in §96.304 to include all non-EGUs subject to Rhode Island's emissions trading program approved under §51.121(p).
(ii) Rhode Island may decline to adopt the CAIR NOX Ozone Season opt-in provisions of:
(A) Subpart IIII of this part and the provisions applicable only to CAIR NOX Ozone Season opt-in units in subparts AAAA through HHHH of this part;
(B) Section 96.388(b) of this chapter and the provisions of subpart IIII of this part applicable only to CAIR NOX Ozone Season opt-in units under §96.388(b); or
(C) Section 96.388(c) of this chapter and the provisions of subpart IIII of this part applicable only to CAIR NOX Ozone Season opt-in units under §96.388(c).
(iii) Rhode Island may adopt the allocation provisions set forth in subpart EEEE of part 96 of this chapter, provided that Rhode Island must provide for issuance of an amount of CAIR Ozone Season NOX allowances for an ozone season not exceeding 936 tons for 2009 and thereafter;
(iv) Rhode Island may adopt any methodology for allocating CAIR NOX Ozone Season allowances to individual sources, as follows:
(A) Rhode Island's methodology must not allow Rhode Island to allocate CAIR Ozone Season NOX allowances for an ozone season in excess of 936 tons for 2009 and thereafter;
(B) Rhode Island's methodology must require that, for EGUs commencing operation before January 1, 2001, Rhode Island will determine, and notify the Administrator of, each unit's allocation of CAIR NOX allowances by October 31, 2006 for the ozone seasons 2009, 2010, and 2011 and by October 31, 2008 and October 31 of each year thereafter for the ozone season in the 4th year after the year of the notification deadline; and
(C) Rhode Island's methodology must require that, for EGUs commencing operation on or after January 1, 2001, Rhode Island will determine, and notify the Administrator of, each unit's allocation of CAIR Ozone Season NOX allowances by July 31 of the calendar year of the ozone season for which the CAIR Ozone Season NOX allowances are allocated.
(3) Notwithstanding a SIP revision by a State authorized under paragraph (bb)(1) of this section or by Rhode Island under paragraph (bb)(2) of this section, if the State's or Rhode Island's SIP that, without such SIP revision, imposes control measures on EGUs or non-EGUs under §51.121 is determined by the Administrator to meet the requirements of §51.121, such SIP shall be deemed to continue to meet the requirements of §51.121.
(cc) The terms used in this section shall have the following meanings:
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 allowances, the determination of the amount of allowances to be initially credited to a source.
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.
Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et seq.
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 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.
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 heat recovery steam generator and steam turbine.
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.
Electric generating unit or EGU means:
(1) Except as provided in paragraph (2) of this definition, a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.
(2) For a unit that qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continues to qualify as a cogeneration unit, a cogeneration unit serving at any time a generator with nameplate capacity of more than 25 MWe and 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. If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity but subsequently no longer qualifies as a cogeneration unit, the unit shall be subject to paragraph (1) of this definition starting on the day on which the unit first no longer qualifies as a cogeneration unit.
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.
Generator means a device that produces electricity.
Maximum design heat input means:
(1) Starting from the initial installation of a unit, the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis as specified by the manufacturer of the unit;
(2)(i) Except as provided in paragraph (2)(ii) of this definition, starting from the completion of any subsequent physical change in the unit resulting in an increase in the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis, such increased maximum amount as specified by the person conducting the physical change; or
(ii) For purposes of applying the definition of the term “potential electrical output capacity,” starting from the completion of any subsequent physical change in the unit resulting in a decrease in the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis, such decreased maximum amount as specified by the person conducting the physical change.
NAAQS means National Ambient Air Quality Standard.
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 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 specified by the person conducting the physical change.
Non-EGU means a source of NOX emissions that is not an EGU.
NOX Budget Trading Program means a multi-state nitrogen oxides air pollution control and emission reduction program approved and administered by the Administrator in accordance with subparts A through I of this part and §51.121, as a means of mitigating interstate transport of ozone and nitrogen oxides.
NOX SIP Call allowance means a limited authorization issued by the Administrator under the NOX Budget Trading Program to emit up to one ton of nitrogen oxides during the ozone season of the specified year or any year thereafter, provided that the provision in §51.121(b)(2)(ii)(E) shall not be used in applying this definition.
Ozone season means the period, which begins May 1 and ends September 30 of any year.
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.
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.
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.
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 a stationary, fossil-fuel-fired combustion turbine.
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, excluding any heat contained in condensate return or makeup water;
(2) Used in a heat 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.
(dd) New Hampshire may revise its SIP to implements control measures on EGUs and non-EGUs through an emissions trading program adopted in regulations that differ substantively from subparts AAAA through IIII of part 96 of this chapter as set forth in this paragraph.
(1) New Hampshire must expand the applicability provisions in §96.304 of this chapter to include all non-EGUs subject to New Hampshire's emissions trading program at New Hampshire Code of Administrative Rules, chapter Env-A 3200 (2004).
(2) New Hampshire may decline to adopt the CAIR NOX Ozone Season opt-in provisions of:
(i) Subpart IIII of this part and the provisions applicable only to CAIR NOX Ozone Season opt-in units in subparts AAAA through HHHH of this part;
(ii) Section 96.388(b) of this chapter and the provisions of subpart IIII of this part applicable only to CAIR NOX Ozone Season opt-in units under §96.388(b); or
(iii) Section 96.388(c) of this chapter and the provisions of subpart IIII of this part applicable only to CAIR NOX Ozone Season opt-in units under §96.388(c).
(3) New Hampshire may adopt the allocation provisions set forth in subpart EEEE of part 96 of this chapter, provided that New Hampshire must provide for issuance of an amount of CAIR Ozone Season NOX allowances for an ozone season not exceeding 3,000 tons for 2009 and thereafter;
(4) New Hampshire may adopt any methodology for allocating CAIR NOX Ozone Season allowances to individual sources, as follows:
(i) New Hampshire's methodology must not allow New Hampshire to allocate CAIR Ozone Season NOX allowances for an ozone season in excess of 3,000 tons for 2009 and thereafter;
(ii) New Hampshire's methodology must require that, for EGUs commencing operation before January 1, 2001, New Hampshire will determine, and notify the Administrator of, each unit's allocation of CAIR NOX allowances by October 31, 2006 for the ozone seasons 2009, 2010, and 2011 and by October 31, 2008 and October 31 of each year thereafter for the ozone season in the 4th year after the year of the notification deadline; and
(iii) New Hampshire's methodology must require that, for EGUs commencing operation on or after January 1, 2001, New Hampshire will determine, and notify the Administrator of, each unit's allocation of CAIR Ozone Season NOX allowances by July 31 of the calendar year of the ozone season for which the CAIR Ozone Season NOX allowances are allocated.
[70 FR 25319, May 12, 2005]
§ 51.124 Findings and requirements for submission of State implementation plan revisions relating to emissions of sulfur dioxide pursuant to the Clean Air Interstate Rule.
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(a) Under section 110(a)(1) of the CAA, 42 U.S.C. 7410(a)(1), the Administrator determines that each State identified in paragraph (c) of this section must submit a SIP revision to comply with the requirements of section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), through the adoption of adequate provisions prohibiting sources and other activities from emitting SO2 in amounts that will contribute significantly to nonattainment in, or interfere with maintenance by, one or more other States with respect to the fine particles (PM2.5) NAAQS.
(b) For each State identified in paragraph (c) of this section, the SIP revision required under paragraph (a) of this section will contain adequate provisions, for purposes of complying with section 110(a)(2)(D)(i)(I) of the CAA, 42 U.S.C. 7410(a)(2)(D)(i)(I), only if the SIP revision contains control measures that assure compliance with the applicable requirements of this section.
(c) The following States are subject to the requirements of this section: Alabama, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin, and the District of Columbia.
(d)(1) The SIP revision under paragraph (a) of this section must be submitted to EPA by no later than September 11, 2006.
(2) The requirements of appendix V to this part shall apply to the SIP revision under paragraph (a) of this section.
(3) The State shall deliver 5 copies of the SIP revision under paragraph (a) of this section to the appropriate Regional Office, with a letter giving notice of such action.
(e) The State's SIP revision shall contain control measures and demonstrate that they will result in compliance with the State's Annual EGU SO2 Budget, if applicable, and achieve the State's Annual Non-EGU SO2 Reduction Requirement, if applicable, for the appropriate periods. The amounts of the State's Annual EGU SO2 Budget and Annual Non-EGU SO2 Reduction Requirement shall be determined as follows:
(1)(i) The Annual EGU SO2 Budget for the State is defined as the total amount of SO2 emissions from all EGUs in that State for a year, if the State meets the requirements of paragraph (a) of this section by imposing control measures, at least in part, on EGUs. If the State imposes control measures under this section on only EGUs, the Annual EGU SO2 Budget for the State shall not exceed the amount, during the indicated periods, specified in paragraph (e)(2) of this section.
(ii) The Annual Non-EGU SO2 Reduction Requirement, if applicable, is defined as the total amount of SO2 emission reductions that the State demonstrates, in accordance with paragraph (g) of this section, it will achieve from non-EGUs during the appropriate period. If the State meets the requirements of paragraph (a) of this section by imposing control measures on only non-EGUs, then the State's Annual Non-EGU SO2 Reduction Requirement shall equal or exceed, during the appropriate periods, the amount determined in accordance with paragraph (e)(3) of this section.
(iii) If a State meets the requirements of paragraph (a) of this section by imposing control measures on both EGUs and non-EGUs, then:
(A) The Annual Non-EGU SO2 Reduction Requirement shall equal or exceed the difference between the amount specified in paragraph (e)(2) of this section for the appropriate period and the amount of the State's Annual EGU SO2 Budget specified in the SIP revision for the appropriate period; and
(B) The Annual EGU SO2 Budget shall not exceed, during the indicated periods, the amount specified in paragraph (e)(2) of this section plus the amount of the Annual Non-EGU SO2 Reduction Requirement under paragraph (e)(1)(iii)(A) of this section for the appropriate period.
(2) For a State that complies with the requirements of paragraph (a) of this section by imposing control measures on only EGUs, the amount of the Annual EGU SO2 Budget, in tons of SO2 per year, shall be as follows, for the indicated State for the indicated period:
------------------------------------------------------------------------
Annual EGU SO2 Annual EGU SO2
State budget for 2010-2014 budget for 2015 and
(tons) thereafter (tons)
------------------------------------------------------------------------
Alabama..................... 157,582 110,307
District of Columbia........ 708 495
Florida..................... 253,450 177,415
Georgia..................... 213,057 149,140
Illinois.................... 192,671 134,869
Indiana..................... 254,599 178,219
Iowa........................ 64,095 44,866
Kentucky.................... 188,773 132,141
Louisiana................... 59,948 41,963
Maryland.................... 70,697 49,488
Michigan.................... 178,605 125,024
Minnesota................... 49,987 34,991
Mississippi................. 33,763 23,634
Missouri.................... 137,214 96,050
New York.................... 135,139 94,597
North Carolina.............. 137,342 96,139
Ohio........................ 333,520 233,464
Pennsylvania................ 275,990 193,193
South Carolina.............. 57,271 40,089
Tennessee................... 137,216 96,051
Texas....................... 320,946 224,662
Virginia.................... 63,478 44,435
West Virginia............... 215,881 151,117
Wisconsin................... 87,264 61,085
------------------------------------------------------------------------
(3) For a State that complies with the requirements of paragraph (a) of this section by imposing control measures on only non-EGUs, the amount of the Annual Non-EGU SO2 Reduction Requirement, in tons of SO2 per year, shall be determined, for the State for 2010 and thereafter, by subtracting the amount of the State's Annual EGU SO2 Budget for the appropriate year, specified in paragraph (e)(2) of this section, from an amount equal to 2 times the State's Annual EGU SO2 Budget for 2010 through 2014, specified in paragraph (e)(2) of this section.
(f) Each SIP revision must set forth control measures to meet the amounts specified in paragraph (e) of this section, as applicable, including the following:
(1) A description of enforcement methods including, but not limited to:
(i) Procedures for monitoring compliance with each of the selected control measures;
(ii) Procedures for handling violations; and
(iii) A designation of agency responsibility for enforcement of implementation.
(2)(i) If a State elects to impose control measures on EGUs, then those measures must impose an annual SO2 mass emissions cap on all such sources in the State.
(ii) If a State elects to impose control measures on fossil fuel-fired non-EGUs that are boilers or combustion turbines with a maximum design heat input greater than 250 mmBtu/hr, then those measures must impose an annual SO2 mass emissions cap on all such sources in the State.
(iii) If a State elects to impose control measures on non-EGUs other than those described in paragraph (f)(2)(ii) of this section, then those measures must impose an annual SO2 mass emissions cap on all such sources in the State, or the State must demonstrate why such emissions cap is not practicable, and adopt alternative requirements that ensure that the State will comply with its requirements under paragraph (e) of this section, as applicable, in 2010 and subsequent years.
(g)(1) Each SIP revision that contains control measures covering non-EGUs as part or all of a State's obligation in meeting its requirement under paragraph (a) of this section must demonstrate that such control measures are adequate to provide for the timely compliance with the State's Annual Non-EGU SO2 Reduction Requirement under paragraph (e) of this section and are not adopted or implemented by the State, as of May 12, 2005, and are not adopted or implemented by the federal government, as of the date of submission of the SIP revision by the State to EPA.
(2) The demonstration under paragraph (g)(1) of this section must include the following, with respect to each source category of non-EGUs for which the SIP revision requires control measures:
(i) A detailed historical baseline inventory of SO2 mass emissions from the source category in a representative year consisting, at the State's election, of 2002, 2003, 2004, or 2005, or an average of 2 or more of those years, absent the control measures specified in the SIP revision.
(A) This inventory must represent estimates of actual emissions based on monitoring data in accordance with part 75 of this chapter, if the source category is subject to part 75 monitoring requirements in accordance with part 75 of this chapter.
(B) In the absence of monitoring data in accordance with part 75 of this chapter, actual emissions must be quantified, to the maximum extent practicable, with the same degree of assurance with which emissions are quantified for sources subject to part 75 of this chapter and using source-specific or source-category-specific assumptions that ensure a source's or source category's actual emissions are not overestimated. If a State uses factors to estimate emissions, production or utilization, or effectiveness of controls or rules for a source category, such factors must be chosen to ensure that emissions are not overestimated.
(C) For measures to reduce emissions from motor vehicles, emission estimates must be based on an emissions model that has been approved by EPA for use in SIP development and must be consistent with the planning assumptions regarding vehicle miles traveled and other factors current at the time of the SIP development.
(D) For measures to reduce emissions from nonroad engines or vehicles, emission estimates methodologies must be approved by EPA.
(ii) A detailed baseline inventory of SO2 mass emissions from the source category in the years 2010 and 2015, absent the control measures specified in the SIP revision and reflecting changes in these emissions from the historical baseline year to the years 2010 and 2015, based on projected changes in the production input or output, population, vehicle miles traveled, economic activity, or other factors as applicable to this source category.
(A) These inventories must account for implementation of any control measures that are adopted or implemented by the State, as of May 12, 2005, or adopted or implemented by the federal government, as of the date of submission of the SIP revision by the State to EPA, and must exclude any control measures specified in the SIP revision to meet the SO2 emissions reduction requirements of this section.
(B) Economic and population forecasts must be as specific as possible to the applicable industry, State, and county of the source or source category and must be consistent with both national projections and relevant official planning assumptions, including estimates of population and vehicle miles traveled developed through consultation between State and local transportation and air quality agencies. However, if these official planning assumptions are inconsistent with official U.S. Census projections of population or with energy consumption projections contained in the U.S. Department of Energy's most recent Annual Energy Outlook, then the SIP revision must make adjustments to correct the inconsistency or must demonstrate how the official planning assumptions are more accurate.
(C) These inventories must account for any changes in production method, materials, fuels, or efficiency that are expected to occur between the historical baseline year and 2010 or 2015, as appropriate.
(iii) A projection of SO2 mass emissions in 2010 and 2015 from the source category assuming the same projected changes as under paragraph (g)(2)(ii) of this section and resulting from implementation of each of the control measures specified in the SIP revision.
(A) These inventories must address the possibility that the State's new control measures may cause production or utilization, and emissions, to shift to unregulated or less stringently regulated sources in the source category in the same or another State, and these inventories must include any such amounts of emissions that may shift to such other sources.
(B) The State must provide EPA with a summary of the computations, assumptions, and judgments used to determine the degree of reduction in projected 2010 and 2015 SO2 emissions that will be achieved from the implementation of the new control measures compared to the relevant baseline emissions inventory.
(iv) The result of subtracting the amounts in paragraph (g)(2)(iii) of this section for 2010 and 2015, respectively, from the lower of the amounts in paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2010 and 2015, respectively, may be credited towards the State's Annual Non-EGU SO2 Reduction Requirement in paragraph (e)(3) of this section for the appropriate period.
(v) Each SIP revision must identify the sources of the data used in each estimate and each projection of emissions.
(h) Each SIP revision must comply with §51.116 (regarding data availability).
(i) Each SIP revision must provide for monitoring the status of compliance with any control measures adopted to meet the State's requirements under paragraph (e) of this section, as follows:
(1) The SIP revision must provide for legally enforceable procedures for requiring owners or operators of stationary sources to maintain records of, and periodically report to the State:
(i) Information on the amount of SO2 emissions from the stationary sources; and
(ii) Other information as may be necessary to enable the State to determine whether the sources are in compliance with applicable portions of the control measures;
(2) The SIP revision must comply with §51.212 (regarding testing, inspection, enforcement, and complaints);
(3) If the SIP revision contains any transportation control measures, then the SIP revision must comply with §51.213 (regarding transportation control measures);
(4)(i) If the SIP revision contains measures to control EGUs, then the SIP revision must require such sources to comply with the monitoring, recordkeeping, and reporting provisions of part 75 of this chapter.
(ii) If the SIP revision contains measures to control fossil fuel-fired non-EGUs that are boilers or combustion turbines with a maximum design heat input greater than 250 mmBtu/hr, then the SIP revision must require such sources to comply with the monitoring, recordkeeping, and reporting provisions of part 75 of this chapter.
(iii) If the SIP revision contains measures to control any other non-EGUs that are not described in paragraph (i)(4)(ii) of this section, then the SIP revision must require such sources to comply with the monitoring, recordkeeping, and reporting provisions of part 75 of this chapter, or the State must demonstrate why such requirements are not practicable and adopt alternative requirements that ensure that the required emissions reductions will be quantified, to the maximum extent practicable, with the same degree of assurance with which emissions are quantified for sources subject to part 75 of this chapter.
(j) Each SIP revision must show that the State has legal authority to carry out the SIP revision, including authority to:
(1) Adopt emissions standards and limitations and any other measures necessary for attainment and maintenance of the State's relevant Annual EGU SO2 Budget or the Annual Non-EGU SO2 Reduction Requirement, as applicable, under paragraph (e) of this section;
(2) Enforce applicable laws, regulations, and standards and seek injunctive relief;
(3) Obtain information necessary to determine whether air pollution sources are in compliance with applicable laws, regulations, and standards, including authority to require recordkeeping and to make inspections and conduct tests of air pollution sources; and
(4)(i) Require owners or operators of stationary sources to install, maintain, and use emissions monitoring devices and to make periodic reports to the State on the nature and amounts of emissions from such stationary sources; and
(ii) Make the data described in paragraph (j)(4)(i) of this section available to the public within a reasonable time after being reported and as correlated with any applicable emissions standards or limitations.
(k)(1) The provisions of law or regulation that the State determines provide the authorities required under this section must be specifically identified, and copies of such laws or regulations must be submitted with the SIP revision.
(2) Legal authority adequate to fulfill the requirements of paragraphs (j)(3) and (4) of this section may be delegated to the State under section 114 of the CAA.
(l)(1) A SIP revision may assign legal authority to local agencies in accordance with §51.232.
(2) Each SIP revision must comply with §51.240 (regarding general plan requirements).
(m) Each SIP revision must comply with §51.280 (regarding resources).
(n) Each SIP revision must provide for State compliance with the reporting requirements in §51.125.
(o)(1) Notwithstanding any other provision of this section, if a State adopts regulations substantively identical to subparts AAA through III of part 96 of this chapter (CAIR SO2 Trading Program), incorporates such subparts by reference into its regulations, or adopts regulations that differ substantively from such subparts only as set forth in paragraph (o)(2) of this section, then such emissions trading program in the State's SIP revision is automatically approved as meeting the requirements of paragraph (e) of this section, provided that the State has the legal authority to take such action and to implement its responsibilities under such regulations.
(2) If a State adopts an emissions trading program that differs substantively from subparts AAA through III of part 96 of this chapter only as follows, then the emissions trading program is approved as set forth in paragraph (o)(1) of this section.
(i) The State may decline to adopt the CAIR SO2 opt-in provisions of subpart III of this part and the provisions applicable only to CAIR SO2 opt-in units in subparts AAA through HHH of this part.
(ii) The State may decline to adopt the CAIR SO2 opt-in provisions of §96.288(b) of this chapter and the provisions of subpart III of this part applicable only to CAIR SO2 opt-in units under §96.288(b).
(iii) The State may decline to adopt the CAIR SO2 opt-in provisions of §96.288(c) of this chapter and the provisions of subpart II of this part applicable only to CAIR SO2 opt-in units under §96.288(c).
(3) A State that adopts an emissions trading program in accordance with paragraph (o)(1) or (2) of this section is not required to adopt an emissions trading program in accordance with §96.123 (o)(1) or (2) or (aa)(1) or (2) of this chapter.
(4) If a State adopts an emissions trading program that differs substantively from subparts AAA through III of part 96 of this chapter, other than as set forth in paragraph (o)(2) of this section, then such emissions trading program is not automatically approved as set forth in paragraph (o)(1) or (2) of this section and will be reviewed by the Administrator for approvability in accordance with the other provisions of this section, provided that the SO2 allowances issued under such emissions trading program shall not, and the SIP revision shall state that such SO2 allowances shall not, qualify as CAIR SO2 allowances under any emissions trading program approved under paragraph (o)(1) or (2) of this section.
(p) If a State's SIP revision does not contain an emissions trading program approved under paragraph (o)(1) or (2) of this section but contains control measures on EGUs as part or all of a State's obligation in meeting its requirement under paragraph (a) of this section:
(1) The SIP revision shall provide, for each year that the State has such obligation, for the permanent retirement of an amount of Acid Rain allowances allocated to sources in the State for that year and not deducted by the Administrator under the Acid Rain Program and any emissions trading program approved under paragraph (o)(1) or (2) of this section, equal to the difference between—
(A) The total amount of Acid Rain allowances allocated under the Acid Rain Program to the sources in the State for that year; and
(B) If the State's SIP revision contains only control measures on EGUs, the State's Annual EGU SO2 Budget for the appropriate period as specified in paragraph (e)(2) of this section or, if the State's SIP revision contains control measures on EGUs and non-EGUs, the State's Annual EGU SO2 Budget for the appropriate period as specified in the SIP revision.
(2) The SIP revision providing for permanent retirement of Acid Rain allowances under paragraph (p)(1) of this section must ensure that such allowances are not available for deduction by the Administrator under the Acid Rain Program and any emissions trading program approved under paragraph (o)(1) or (2) of this section.
(q) The terms used in this section shall have the following meanings:
Acid Rain allowance means a limited authorization issued by the Administrator under the Acid Rain Program to emit up to one ton of sulfur dioxide during the specified year or any year thereafter, except as otherwise provided by the Administrator.
Acid Rain Program means a multi-State sulfur dioxide and nitrogen oxides air pollution control and emissions 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 allowances, the determination of the amount of allowances to be initially credited to a source.
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.
Clean Air Act or CAA means the Clean Air Act, 42 U.S.C. 7401, et seq.
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 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.
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 heat recovery steam generator and steam turbine.
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.
Electric generating unit or EGU means:
(1) Except as provided in paragraph (2) of this definition, a stationary, fossil-fuel-fired boiler or stationary, fossil-fuel-fired combustion turbine serving at any time, since the start-up of the unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.
(2) For a unit that qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity and continues to qualify as a cogeneration unit, a cogeneration unit serving at any time a generator with nameplate capacity of more than 25 MWe and 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. If a unit qualifies as a cogeneration unit during the 12-month period starting on the date the unit first produces electricity but subsequently no longer qualifies as a cogeneration unit, the unit shall be subject to paragraph (1) of this definition starting on the day on which the unit first no longer qualifies as a cogeneration unit.
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.
Generator means a device that produces electricity.
Maximum design heat input means:
(1) Starting from the initial installation of a unit, the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis as specified by the manufacturer of the unit;
(2)(i) Except as provided in paragraph (2)(ii) of this definition, starting from the completion of any subsequent physical change in the unit resulting in an increase in the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis, such increased maximum amount as specified by the person conducting the physical change; or
(ii) For purposes of applying the definition of the term “potential electrical output capacity,” starting from the completion of any subsequent physical change in the unit resulting in a decrease in the maximum amount of fuel per hour (in Btu/hr) that a unit is capable of combusting on a steady state basis, such decreased maximum amount as specified by the person conducting the physical change.
NAAQS means National Ambient Air Quality Standard.
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 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 specified by the person conducting the physical change.
Non-EGU means a source of SO2 emissions that is not an EGU.
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.
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.
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.
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 a stationary, fossil-fuel fired combustion turbine.
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, excluding any heat contained in condensate return or makeup water;
(2) Used in a heat 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.
[70 FR 25328, May 12, 2005]
§ 51.125 Emissions reporting requirements for SIP revisions relating to budgets for SO2 and NOX emissions.
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(a) For its transport SIP revision under §51.123 and/or 51.124, each State must submit to EPA SO2 and/or NOX emissions data as described in this section.
(1) Alabama, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, Wisconsin and the District of Columbia, must report annual (12 months) emissions of SO2 and NOX.
(2) Alabama, Arkansas, Connecticut, Deleware, Florida, Illinois, Indinia, Iowa, Kentucky, Lousianna, Maryland, Massachusetts, Michigan, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, Wisconsin and the District of Columbia must report ozone season (May 1 through September 30) emissions of NOX.
(b) Each revision must provide for periodic reporting by the State of SO2 and/or NOX emissions data as specified in paragraph (a) of this section to demonstrate whether the State's emissions are consistent with the projections contained in its approved SIP submission.
(1) Every-year reporting cycle. As applicable, each revision must provide for reporting of SO2 and NOX emissions data every year as follows:
(i) The States identified in paragraph (a)(1) of this section must report to EPA annual emissions data every year from all SO2 and NOX sources within the State for which the State specified control measures in its SIP submission under §§51.123 and/or 51.124.
(ii) The States identified in paragraph (a)(2) of this section must report to EPA ozone season and summer daily emissions data every year from all NOX sources within the State for which the State specified control measures in its SIP submission under §51.123.
(iii) If sources report SO2 and NOX emissions data to EPA in a given year pursuant to a trading program approved under §51.123(o) or §51.124(o) of this part or pursuant to the monitoring and reporting requirements of 40 CFR part 75, then the State need not provide annual reporting of these pollutants to EPA for such sources.
(2) Three-year reporting cycle. As applicable, each plan must provide for triennial (i.e., every third year) reporting of SO2 and NOX emissions data from all sources within the State.
(i) The States identified in paragraph (a)(1) of this section must report to EPA annual emissions data every third year from all SO2 and NOX sources within the State.
(ii) The States identified in paragraph (a)(2) of this section must report to EPA ozone season and ozone daily emissions data every third year from all NOX sources within the State.
(3) The data availability requirements in §51.116 must be followed for all data submitted to meet the requirements of paragraphs (b)(1) and (2) of this section.
(c) The data reported in paragraph (b) of this section must meet the requirements of subpart A of this part.
(d) Approval of annual and ozone season calculation by EPA. Each State must submit for EPA approval an example of the calculation procedure used to calculate annual and ozone season emissions along with sufficient information for EPA to verify the calculated value of annual and ozone season emissions.
(e) Reporting schedules. (1) Reports are to begin with data for emissions occurring in the year 2008, which is the first year of the 3-year cycle.
(2) After 2008, 3-year cycle reports are tobe submitted every third year and every-year cycle reports are to be submitted each year that a triennial report is not required. (continued)