(a) Each plan providing for the attainment of a primary or secondary standard must specify the projected attainment date.

(b)-(f) [Reserved]

(g) During developing of the plan, EPA encourages States to identify alternative control strategies, as well as the costs and benefits of each such alternative for attainment or maintenance of the national standard.

[51 FR 40661 Nov. 7, 1986, as amended at 61 FR 16060, Apr. 11, 1996; 61 FR 30163, June 14, 1996]

Each plan must set forth a control strategy which includes the following:

(a) A description of enforcement methods including, but not limited to:

(1) Procedures for monitoring compliance with each of the selected control measures,

(2) Procedures for handling violations, and

(3) A designation of agency responsibility for enforcement of implementation.

(b) [Reserved]

[51 FR 40665, Nov. 7, 1986, as amended at 60 FR 33922, June 29, 1995]

(a) Each plan must demonstrate that the measures, rules, and regulations contained in it are adequate to provide for the timely attainment and maintenance of the national standard that it implements.

(1) The adequacy of a control strategy shall be demonstrated by means of applicable air quality models, data bases, and other requirements specified in appendix W of this part (Guideline on Air Quality Models).

(2) Where an air quality model specified in appendix W of this part (Guideline on Air Quality Models) is inappropriate, the model may be modified or another model substituted. Such a modification or substitution of a model may be made on a case-by-case basis or, where appropriate, on a generic basis for a specific State program. Written approval of the Administrator must be obtained for any modification or substitution. In addition, use of a modified or substituted model must be subject to notice and opportunity for public comment under procedures set forth in § 51.102.

(b) The demonstration must include the following:

(1) A summary of the computations, assumptions, and judgments used to determine the degree of reduction of emissions (or reductions in the growth of emissions) that will result from the implementation of the control strategy.

(2) A presentation of emission levels expected to result from implementation of each measure of the control strategy.

(3) A presentation of the air quality levels expected to result from implementation of the overall control strategy presented either in tabular form or as an isopleth map showing expected maximum pollutant concentrations.

(4) A description of the dispersion models used to project air quality and to evaluate control strategies.

(5) For interstate regions, the analysis from each constituent State must, where practicable, be based upon the same regional emission inventory and air quality baseline.

[51 FR 40665, Nov. 7, 1986, as amended at 58 FR 38821, July 20, 1993; 60 FR 40468, Aug. 9, 1995; 61 FR 41840, Aug. 12, 1996]

(a) Except for lead, each plan must contain a detailed inventory of emissions from point and area sources. Lead requirements are specified in § 51.117. The inventory must be based upon measured emissions or, where measured emissions are not available, documented emission factors.

(b) Each plan must contain a summary of emission levels projected to result from application of the new control strategy.

(c) Each plan must identify the sources of the data used in the projection of emissions.

(a) Each plan must contain a summary of data showing existing air quality.

(b) Each plan must:

(1) Contain a summary of air quality concentrations expected to result from application of the control strategy, and

(2) Identify and describe the dispersion model, other air quality model, or receptor model used.

(c) Actual measurements of air quality must be used where available if made by methods specified in appendix C to part 58 of this chapter. Estimated air quality using appropriate modeling techniques may be used to supplement measurements.

(d) For purposes of developing a control strategy, background concentration shall be taken into consideration with respect to particulate matter. As used in this subpart, background concentration is that portion of the measured ambient levels that cannot be reduced by controlling emissions from man-made sources.

(e) In developing an ozone control strategy for a particular area, background ozone concentrations and ozone transported into an area must be considered. States may assume that the ozone standard will be attained in upwind areas.

(a) The State must retain all detailed data and calculations used in the preparation of each plan or each plan revision, and make them available for public inspection and submit them to the Administrator at his request.

(b) The detailed data and calculations used in the preparation of plan revisions are not considered a part of the plan.

(c) Each plan must provide for public availability of emission data reported by source owners or operators or otherwise obtained by a State or local agency. Such emission data must be correlated with applicable emission limitations or other measures. As used in this paragraph, correlated means presented in such a manner as to show the relationship between measured or estimated amounts of emissions and the amounts of such emissions allowable under the applicable emission limitations or other measures.

In addition to other requirements in §§ 51.100 through 51.116 the following requirements apply to lead. To the extent they conflict, there requirements are controlling over those of the proceeding sections.

(a) Control strategy demonstration. Each plan must contain a demonstration showing that the plan will attain and maintain the standard in the following areas:

(1) Areas in the vicinity of the following point sources of lead: Primary lead smelters, Secondary lead smelters, Primary copper smelters, Lead gasoline additive plants, Lead-acid storage battery manufacturing plants that produce 2,000 or more batteries per day. Any other stationary source that actually emits 25 or more tons per year of lead or lead compounds measured as elemental lead.

(2) Any other area that has lead air concentrations in excess of the national ambient air quality standard concentration for lead, measured since January 1, 1974.

(b) Time period for demonstration of adequacy. The demonstration of adequacy of the control strategy required under § 51.112 may cover a longer period if allowed by the appropriate EPA Regional Administrator.

(c) Special modeling provisions. (1) For urbanized areas with measured lead concentrations in excess of 4.0 µg/m 3, quarterly mean measured since January 1, 1974, the plan must employ the modified rollback model for the demonstration of attainment as a minimum, but may use an atmospheric dispersion model if desired, consistent with requirements contained in § 51.112(a). If a proportional model is used, the air quality data should be the same year as the emissions inventory required under the paragraph e.

(2) For each point source listed in § 51.117(a), that plan must employ an atmospheric dispersion model for demonstration of attainment, consistent with requirements contained in § 51.112(a).

(3) For each area in the vicinity of an air quality monitor that has recorded lead concentrations in excess of the lead national standard concentration, the plan must employ the modified rollback model as a minimum, but may use an atmospheric dispersion model if desired for the demonstration of attainment, consistent with requirements contained in § 51.112(a).

(d) Air quality data and projections. (1) Each State must submit to the appropriate EPA Regional Office with the plan, but not part of the plan, all lead air quality data measured since January 1, 1974. This requirement does not apply if the data has already been submitted.

(2) The data must be submitted in accordance with the procedures and data forms specified in Chapter 3.4.0 of the “AEROS User's Manual” concerning storage and retrieval of aerometric data (SAROAD) except where the Regional Administrator waives this requirement.

(3) If additional lead air quality data are desired to determine lead air concentrations in areas suspected of exceeding the lead national ambient air quality standard, the plan may include data from any previously collected filters from particulate matter high volume samplers. In determining the lead content of the filters for control strategy demonstration purposes, a State may use, in addition to the reference method, X-ray fluorescence or any other method approved by the Regional Administrator.

(e) Emissions data. (1) The point source inventory on which the summary of the baseline for lead emissions inventory is based must contain all sources that emit 0.5 or more tons of lead per year.

(2) Each State must submit lead emissions data to the appropriate EPA Regional Office with the original plan. The submission must be made with the plan, but not as part of the plan, and must include emissions data and information related to point and area source emissions. The emission data and information should include the information identified in the Hazardous and Trace Emissions System (HATREMS) point source coding forms for all point sources and the area source coding forms for all sources that are not point sources, but need not necessarily be in the format of those forms.

[41 FR 18388, May 3, 1976, as amended at 58 FR 38822, July 20, 1993; 73 FR 67057, Nov. 12, 2008]

(a) The plan must provide that the degree of emission limitation required of any source for control of any air pollutant must not be affected by so much of any source's stack height that exceeds good engineering practice or by any other dispersion technique, except as provided in § 51.118(b). The plan must provide that before a State submits to EPA a new or revised emission limitation that is based on a good engineering practice stack height that exceeds the height allowed by § 51.100(ii) (1) or (2), the State must notify the public of the availabilty of the demonstration study and must provide opportunity for a public hearing on it. This section does not require the plan to restrict, in any manner, the actual stack height of any source.

(b) The provisions of § 51.118(a) shall not apply to (1) stack heights in existence, or dispersion techniques implemented on or before December 31, 1970, except where pollutants are being emitted from such stacks or using such dispersion techniques by sources, as defined in section 111(a)(3) of the Clean Air Act, which were constructed, or reconstructed, or for which major modifications, as defined in §§ 51.165(a)(1)(v)(A), 51.166(b)(2)(i) and 52.21(b)(2)(i), were carried out after December 31, 1970; or (2) coal-fired steam electric generating units subject to the provisions of section 118 of the Clean Air Act, which commenced operation before July 1, 1957, and whose stacks were construced under a construction contract awarded before February 8, 1974.

(a) The use of an intermittent control system (ICS) may be taken into account in establishing an emission limitation for a pollutant under a State implementation plan, provided:

(1) The ICS was implemented before December 31, 1970, according to the criteria specified in § 51.119(b).

(2) The extent to which the ICS is taken into account is limited to reflect emission levels and associated ambient pollutant concentrations that would result if the ICS was the same as it was before December 31, 1970, and was operated as specified by the operating system of the ICS before December 31, 1970.

(3) The plan allows the ICS to compensate only for emissions from a source for which the ICS was implemented before December 31, 1970, and, in the event the source has been modified, only to the extent the emissions correspond to the maximum capacity of the source before December 31, 1970. For purposes of this paragraph, a source for which the ICS was implemented is any particular structure or equipment the emissions from which were subject to the ICS operating procedures.

(4) The plan requires the continued operation of any constant pollution control system which was in use before December 31, 1970, or the equivalent of that system.

(5) The plan clearly defines the emission limits affected by the ICS and the manner in which the ICS is taken into account in establishing those limits.

(6) The plan contains requirements for the operation and maintenance of the qualifying ICS which, together with the emission limitations and any other necessary requirements, will assure that the national ambient air quality standards and any applicable prevention of significant deterioration increments will be attained and maintained. These requirements shall include, but not necessarily be limited to, the following:

(i) Requirements that a source owner or operator continuously operate and maintain the components of the ICS specified at § 51.119(b)(3) (ii)-(iv) in a manner which assures that the ICS is at least as effective as it was before December 31, 1970. The air quality monitors and meteorological instrumentation specified at § 51.119(b) may be operated by a local authority or other entity provided the source has ready access to the data from the monitors and instrumentation.

(ii) Requirements which specify the circumstances under which, the extent to which, and the procedures through which, emissions shall be curtailed through the activation of ICS.

(iii) Requirements for recordkeeping which require the owner or operator of the source to keep, for periods of at least 3 years, records of measured ambient air quality data, meteorological information acquired, and production data relating to those processes affected by the ICS.

(iv) Requirements for reporting which require the owner or operator of the source to notify the State and EPA within 30 days of a NAAQS violation pertaining to the pollutant affected by the ICS.

(7) Nothing in this paragraph affects the applicability of any new source review requirements or new source performance standards contained in the Clean Air Act or 40 CFR subchapter C. Nothing in this paragraph precludes a State from taking an ICS into account in establishing emission limitations to any extent less than permitted by this paragraph.

(b) An intermittent control system (ICS) may be considered implemented for a pollutant before December 31, 1970, if the following criteria are met:

(1) The ICS must have been established and operational with respect to that pollutant prior to December 31, 1970, and reductions in emissions of that pollutant must have occurred when warranted by meteorological and ambient monitoring data.

(2) The ICS must have been designed and operated to meet an air quality objective for that pollutant such as an air quality level or standard.

(3) The ICS must, at a minimum, have included the following components prior to December 31, 1970:

(i) Air quality monitors. An array of sampling stations whose location and type were consistent with the air quality objective and operation of the system.

(ii) Meteorological instrumentation. A meteorological data acquisition network (may be limited to a single station) which provided meteorological prediction capabilities sufficient to determine the need for, and degree of, emission curtailments necessary to achieve the air quality design objective.

(iii) Operating system. A system of established procedures for determining the need for curtailments and for accomplishing such curtailments. Documentation of this system, as required by paragraph (n)(4), may consist of a compendium of memoranda or comparable material which define the criteria and procedures for curtailments and which identify the type and number of personnel authorized to initiate curtailments.

(iv) Meteorologist. A person, schooled in meteorology, capable of interpreting data obtained from the meteorological network and qualified to forecast meteorological incidents and their effect on ambient air quality. Sources may have obtained meteorological services through a consultant. Services of such a consultant could include sufficient training of source personnel for certain operational procedures, but not for design, of the ICS.

(4) Documentation sufficient to support the claim that the ICS met the criteria listed in this paragraph must be provided. Such documentation may include affidavits or other documentation.

(a) The EPA Administrator finds that the State Implementation Plans (SIPs) for the States of Connecticut, Delaware, Maine, Maryland, Massachusetts, New Hampshire, New Jersey, New York, Pennsylvania, Rhode Island, and Vermont, the portion of Virginia included (as of November 15, 1990) within the Consolidated Metropolitan Statistical Area that includes the District of Columbia, are substantially inadequate to comply with the requirements of section 110(a)(2)(D) of the Clean Air Act, 42 U.S.C. 7410(a)(2)(D), and to mitigate adequately the interstate pollutant transport described in section 184 of the Clean Air Act, 42 U.S.C. 7511C,to. This inadequacy will be deemed cured for each of the aforementioned States (including the District of Columbia) in the event that EPA determines through rulemaking that a national LEV-equivalent new motor vehicle emission control program is an acceptable alternative for OTC LEV and finds that such program is in effect. In the event no such finding is made, each of those States must adopt and submit to EPA by February 15, 1996 a SIP revision meeting the requirements of paragraph (b) of this section in order to cure the SIP inadequacy.

(b) If a SIP revision is required under paragraph (a) of this section, it must contain the OTC LEV program described in paragraph (c) of this section unless the State adopts and submits to EPA, as a SIP revision, other emission-reduction measures sufficient to meet the requirements of paragraph (d) of this section. If a State adopts and submits to EPA, as a SIP revision, other emission-reduction measures pursuant to paragraph (d) of this section, then for purposes of determining whether such a SIP revision is complete within the meaning of section 110(k)(1) (and hence is eligible at least for consideration to be approved as satisfying paragraph (d) of this section), such a SIP revision must contain other adopted emission-reduction measures that, together with the identified potentially broadly practicable measures, achieve at least the minimum level of emission reductions that could potentially satisfy the requirements of paragraph (d) of this section. All such measures must be fully adopted and enforceable.

(c) The OTC LEV program is a program adopted pursuant to section 177 of the Clean Air Act.

(1) The OTC LEV program shall contain the following elements:

(i) It shall apply to all new 1999 and later model year passenger cars and light-duty trucks (0-5750 pounds loaded vehicle weight), as defined in Title 13, California Code of Regulations, section 1900(b)(11) and (b)(8), respectively, that are sold, imported, delivered, purchased, leased, rented, acquired, received, or registered in any area of the State that is in the Northeast Ozone Transport Region as of December 19, 1994.

(ii) All vehicles to which the OTC LEV program is applicable shall be required to have a certificate from the California Air Resources Board (CARB) affirming compliance with California standards.

(iii) All vehicles to which this LEV program is applicable shall be required to meet the mass emission standards for Non-Methane Organic Gases (NMOG), Carbon Monoxide (CO), Oxides of Nitrogen (NOX), Formaldehyde (HCHO), and particulate matter (PM) as specified in Title 13, California Code of Regulations, section 1960.1(f)(2) (and formaldehyde standards under section 1960.1(e)(2), as applicable) or as specified by California for certification as a TLEV (Transitional Low-Emission Vehicle), LEV (Low-Emission Vehicle), ULEV (Ultra-Low-Emission Vehicle), or ZEV (Zero-Emission Vehicle) under section 1960.1(g)(1) (and section 1960.1(e)(3), for formaldehyde standards, as applicable).

(iv) All manufacturers of vehicles subject to the OTC LEV program shall be required to meet the fleet average NMOG exhaust emission values for production and delivery for sale of their passenger cars, light-duty trucks 0-3750 pounds loaded vehicle weight, and light-duty trucks 3751-5750 pounds loaded vehicle weight specified in Title 13, California Code of Regulations, section 1960.1(g)(2) for each model year beginning in 1999. A State may determine not to implement the NMOG fleet average in the first model year of the program if the State begins implementation of the program late in a calendar year. However, all States must implement the NMOG fleet average in any full model years of the LEV program.

(v) All manufacturers shall be allowed to average, bank and trade credits in the same manner as allowed under the program specified in Title 13, California Code of Regulations, section 1960.1(g)(2) footnote 7 for each model year beginning in 1999. States may account for credits banked by manufacturers in California or New York in years immediately preceding model year 1999, in a manner consistent with California banking and discounting procedures.

(vi) The provisions for small volume manufacturers and intermediate volume manufacturers, as applied by Title 13, California Code of Regulations to California's LEV program, shall apply. Those manufacturers defined as small volume manufacturers and intermediate volume manufacturers in California under California's regulations shall be considered small volume manufacturers and intermediate volume manufacturers under this program.

(vii) The provisions for hybrid electric vehicles (HEVs), as defined in Title 13 California Code of Regulations, section 1960.1, shall apply for purposes of calculating fleet average NMOG values.

(viii) The provisions for fuel-flexible vehicles and dual-fuel vehicles specified in Title 13, California Code of Regulations, section 1960.1(g)(1) footnote 4 shall apply.

(ix) The provisions for reactivity adjustment factors, as defined by Title 13, California Code of Regulations, shall apply.

(x) The aforementioned State OTC LEV standards shall be identical to the aforementioned California standards as such standards exist on December 19, 1994.

(xi) All States' OTC LEV programs must contain any other provisions of California's LEV program specified in Title 13, California Code of Regulations necessary to comply with section 177 of the Clean Air Act.

(2) States are not required to include the mandate for production of ZEVs specified in Title 13, California Code of Regulations, section 1960.1(g)(2) footnote 9.

(3) Except as specified elsewhere in this section, States may implement the OTC LEV program in any manner consistent with the Act that does not decrease the emissions reductions or jeopardize the effectiveness of the program.

(d) The SIP revision that paragraph (b) of this section describes as an alternative to the OTC LEV program described in paragraph (c) of this section must contain a set of State-adopted measures that provides at least the following amount of emission reductions in time to bring serious ozone nonattainment areas into attainment by their 1999 attainment date:

(1) Reductions at least equal to the difference between:

(i) The nitrogen oxides (NOX) emission reductions from the 1990 statewide emissions inventory achievable through implementation of all of the Clean Air Act-mandated and potentially broadly practicable control measures throughout all portions of the State that are within the Northeast Ozone Transport Region created under section 184(a) of the Clean Air Act as of December 19, 1994; and

(ii) A reduction in NOX emissions from the 1990 statewide inventory in such portions of the State of 50% or whatever greater reduction is necessary to prevent significant contribution to nonattainment in, or interference with maintenance by, any downwind State.

(2) Reductions at least equal to the difference between:

(i) The VOC emission reductions from the 1990 statewide emissions inventory achievable through implementation of all of the Clean Air Act-mandated and potentially broadly practicable control measures in all portions of the State in, or near and upwind of, any of the serious or severe ozone nonattainment areas lying in the series of such areas running northeast from the Washington, DC, ozone nonattainment area to and including the Portsmouth, New Hampshire ozone nonattainment area; and

(ii) A reduction in VOC emissions from the 1990 emissions inventory in all such areas of 50% or whatever greater reduction is necessary to prevent significant contribution to nonattainment in, or interference with maintenance by, any downwind State.

[60 FR 4736, Jan. 24, 1995]

(a)(1) The Administrator finds that the State implementation plan (SIP) for each jurisdiction listed in paragraph (c) of this section is substantially inadequate to comply with the requirements of section 110(a)(2)(D)(i)(I) of the Clean Air Act (CAA), 42 U.S.C. 7410(a)(2)(D)(i)(I), because the SIP does not include adequate provisions to prohibit sources and other activities from emitting nitrogen oxides (“NOX”) in amounts that will contribute significantly to nonattainment in one or more other States with respect to the 1-hour ozone national ambient air quality standards (NAAQS). Each of the jurisdictions listed in paragraph (c) of this section must submit to EPA a SIP revision that cures the inadequacy.

(2) [Reserved]

(3) As used in this section, these terms shall have the following meanings:

Nitrogen oxides or NOX means all oxides of nitrogen except nitrous oxide (N2O), reported on an equivalent molecular weight basis as nitrogen dioxide (NO2).

Ozone season means the period from May 1 to September 30 of a year.

Phase I SIP submission means a SIP revision submitted by a State on or before October 30, 2000 in compliance with paragraph (b)(1)(ii) of this section to limit projected NOX emissions during the ozone season from sources in the relevant portion or all of the State, as applicable, to no more than the State's Phase I NOX ozone season budget under paragraph (e) of this section.

Phase II SIP submission means a SIP revision submitted by a State in compliance with paragraph (b)(1)(ii) of this section to limit projected NOX emissions during the ozone season from sources in the relevant portion or all of the State, as applicable, to no more than the State's final NOX ozone season budget under paragraph (e) of this section.

(b)(1) For each jurisdiction listed in paragraph (c) of this section, each 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:

(i) Contains control measures adequate to prohibit emissions of NOX that would otherwise be projected, in accordance with paragraph (g) of this section, to cause the jurisdiction's overall NOX emissions during the ozone season to be in excess of the applicable NOX ozone season budget for that jurisdiction described in paragraph (e) of this section;

(ii) Requires full implementation of all such control measures by no later than May 31, 2004 for the sources covered by a Phase I SIP submission and May 1, 2007 for the sources covered by a Phase II SIP submission; and

(iii) Meets the other requirements of this section. The SIP revision's compliance with the requirement of paragraph (b)(1)(i) of this section shall be considered compliance with the jurisdiction's NOX ozone season budget for purposes of this section.

(2) [Reserved]

(c) The following jurisdictions (hereinafter referred to as “States”) are subject to the requirement of this section:

(1) Connecticut, Delaware, Illinois, Indiana, Kentucky, Maryland, Massachusetts, New Jersey, New York, North Carolina, Ohio, Pennsylvania, Rhode Island, South Carolina, Tennessee, Virginia, West Virginia, and the District of Columbia.

(2) The portions of Alabama, Michigan, and Missouri within the fine grid of the OTAG modeling domain. The fine grid is the area encompassed by a box with the following geographic coordinates: Southwest Corner, 92 degrees West longitude and 32 degrees North latitude; and Northeast Corner, 69.5 degrees West longitude and 44 degrees North latitude.

(d)(1) [Reserved]

(2) Each SIP submission under this section must comply with § 51.103 (regarding submission of plans).

(e)(1) Except as provided in paragraph (e)(2)(ii) of this section, the NOX ozone season budget for a State listed in paragraph (c) of this section is defined as the total amount of NOX emissions from all sources in that State, as indicated in paragraph (e)(2)(i) of this section with respect to that State, which the State must demonstrate that it will not exceed in the 2007 ozone season pursuant to paragraph (g)(1) of this section.

(2)(i) The State-by-State amounts of the Phase I and final NOX ozone season budgets, expressed in tons, are listed in Table 1 to this paragraph (e)(2)(i):

(ii) (A) For purposes of paragraph (e)(2)(i) of this section, in the case of each State listed in paragraphs (e)(2)(ii)(B) through (E) of this section, the NOX ozone season budget is defined as the total amount of NOX emissions from all sources in the specified counties in that State, as indicated in paragraph (e)(2)(i) of this section with respect to the State, which the State must demonstrate that it will not exceed in the 2007 ozone season pursuant to paragraph (g)(1) of this section.

(B) In the case of Alabama, the counties are: Autauga, Bibb, Blount, Calhoun, Chambers, Cherokee, Chilton, Clay, Cleburne, Colbert, Coosa, Cullman, Dallas, DeKalb, Elmore, Etowah, Fayette, Franklin, Greene, Hale, Jackson, Jefferson, Lamar, Lauderdale, Lawrence, Lee, Limestone, Macon, Madison, Marion, Marshall, Morgan, Perry, Pickens, Randolph, Russell, St. Clair, Shelby, Sumter, Talladega, Tallapoosa, Tuscaloosa, Walker, and Winston.

(C) [Reserved]

(D) In the case of Michigan, the counties are: Allegan, Barry, Bay, Berrien, Branch, Calhoun, Cass, Clinton, Eaton, Genesee, Gratiot, Hillsdale, Ingham, Ionia, Isabella, Jackson, Kalamazoo, Kent, Lapeer, Lenawee, Livingston, Macomb, Mecosta, Midland, Monroe, Montcalm, Muskegon, Newaygo, Oakland, Oceana, Ottawa, Saginaw, St. Clair, St. Joseph, Sanilac, Shiawassee, Tuscola, Van Buren, Washtenaw, and Wayne.

(E) In the case of Missouri, the counties are: Bollinger, Butler, Cape Girardeau, Carter, Clark, Crawford, Dent, Dunklin, Franklin, Gasconade, Iron, Jefferson, Lewis, Lincoln, Madison, Marion, Mississippi, Montgomery, New Madrid, Oregon, Pemiscot, Perry, Pike, Ralls, Reynolds, Ripley, St. Charles, St. Francois, St. Louis, St. Louis City, Ste. Genevieve, Scott, Shannon, Stoddard, Warren, Washington, and Wayne.

(f) Each SIP revision must set forth control measures to meet the NOX ozone season budget in accordance with paragraph (b)(1)(i) of this section, which include 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) Should a State elect to impose control measures on fossil fuel-fired NOX sources serving electric generators with a nameplate capacity greater than 25 MWe or boilers, combustion turbines or combined cycle units with a maximum design heat input greater than 250 mmBtu/hr as a means of meeting its NOX ozone season budget, then those measures must:

(i)(A) Impose a NOX mass emissions cap on each source;

(B) Impose a NOX emissions rate limit on each source and assume maximum operating capacity for every such source for purposes of estimating NOX mass emissions; or

(C) Impose any other regulatory requirement which the State has demonstrated to EPA provides equivalent or greater assurance than options in paragraph (f)(2)(i)(A) or (B) of this section that the State will comply with its NOX ozone season budget in the 2007 ozone season; and

(ii) Impose enforceable mechanisms, in accordance with paragraphs (b)(1)(i) and (ii) of this section, to assure that collectively all such sources, including new or modified units, will not exceed in the 2007 ozone season the total NOX emissions projected for such sources by the State pursuant to paragraph (g) of this section.

(3) For purposes of paragraph (f)(2) of this section, the term “fossil fuel-fired” means, with regard to a NOX source:

(i) 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 any year starting in 1995 or, if a NOX source had no heat input starting in 1995, during the last year of operation of the NOX source prior to 1995; or

(ii) The combustion 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 NOX source shall be “fossil fuel-fired” as of the date, during such year, on which the NOX source begins combusting fossil fuel.

(g)(1) Each SIP revision must demonstrate that the control measures contained in it are adequate to provide for the timely compliance with the State's NOX ozone season budget during the 2007 ozone season.

(2) The demonstration must include the following:

(i) Each revision must contain a detailed baseline inventory of NOX mass emissions during the ozone season from the following sources in the year 2007, absent the control measures specified in the SIP submission: electric generating units (EGU), non-electric generating units (non-EGU), area, nonroad and highway sources. The State must use the same baseline emissions inventory that EPA used in calculating the State's NOX ozone season budget, except that EPA may direct the State to use different baseline inventory information if the State fails to certify that it has implemented all of the control measures assumed in developing the baseline inventory.

(ii) [Reserved]

(iii) Each revision must contain a summary of NOX mass emissions during the ozone season in 2007 projected to result from implementation of each of the control measures specified in the SIP submission and from all NOX sources together following implementation of all such control measures, compared to the baseline 2007 NOX emissions inventory for the State described in paragraph (g)(2)(i) of this section. The State must provide EPA with a summary of the computations, assumptions, and judgments used to determine the degree of reduction in projected 2007 NOX emissions that will be achieved from the implementation of the new control measures compared to the baseline emissions inventory.

(iv) Each revision must identify the sources of the data used in the projection of emissions.

(h) Each revision must comply with § 51.116 (regarding data availability).

(i) Each revision must provide for monitoring the status of compliance with any control measures adopted to meet the NOX ozone season budget. Specifically, the revision must meet the following requirements:

(1) The 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 NOX 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 revision must comply with § 51.212 (regarding testing, inspection, enforcement, and complaints);

(3) If the revision contains any transportation control measures, then the revision must comply with § 51.213 (regarding transportation control measures);

(4) If the revision contains measures to control fossil fuel-fired NOX sources serving electric generators with a nameplate capacity greater than 25 MWe or boilers, combustion turbines or combined cycle units with a maximum design heat input greater than 250 mmBtu/hr, then the revision may require some or all such sources to comply with the full set of monitoring, recordkeeping, and reporting provisions of 40 CFR part 75, subpart H. A State requiring such compliance authorizes the Administrator to assist the State in implementing the revision by carrying out the functions of the Administrator under such part.

(5) For purposes of paragraph (i)(4) of this section, the term “fossil fuel-fired” has the meaning set forth in paragraph (f)(3) of this section.

(j) Each revision must show that the State has legal authority to carry out the revision, including authority to:

(1) Adopt emissions standards and limitations and any other measures necessary for attainment and maintenance of the State's NOX ozone season budget specified in 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;

(4) 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; also authority for the State to make such data available to the public as reported and as correlated with any applicable emissions standards or limitations.

(k)(1) The provisions of law or regulation which 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, 42 U.S.C. 7414.

(l)(1) A revision may assign legal authority to local agencies in accordance with § 51.232.

(2) Each revision must comply with § 51.240 (regarding general plan requirements).

(m) Each revision must comply with § 51.280 (regarding resources).

(n) For purposes of the SIP revisions required by this section, EPA may make a finding as applicable under section 179(a)(1)-(4) of the CAA, 42 U.S.C. 7509(a)(1)-(4), starting the sanctions process set forth in section 179(a) of the CAA. Any such finding will be deemed a finding under 40 CFR 52.31(c) and sanctions will be imposed in accordance with the order of sanctions and the terms for such sanctions established in 40 CFR 52.31.

(o) Each revision must provide for State compliance with the reporting requirements set forth in § 51.122.

(p)-(q) [Reserved]

(r)(1) Notwithstanding any provisions of subparts A through I of 40 CFR part 96 and any State's SIP to the contrary, with regard to any ozone season that occurs after September 30, 2008, the Administrator will not carry out any of the functions set forth for the Administrator in subparts A through I of 40 CFR part 96 or in any emissions trading program provisions in a State's SIP approved under this section.

(2) Except as provided in 40 CFR 52.38(b)(13)(ii), a State whose SIP is approved as meeting the requirements of this section and that includes or included an emissions trading program approved under this section must revise the SIP to adopt control measures that satisfy the same portion of the State's NOX emissions reduction requirements under this section as the State projected such emissions trading program would satisfy.

[63 FR 57491, Oct. 27, 1998, as amended at 63 FR 71225, Dec. 24, 1998; 64 FR 26305, May 14, 1999; 65 FR 11230, Mar. 2, 2000; 65 FR 56251, Sept. 18, 2000; 69 FR 21642, Apr. 21, 2004; 70 FR 25317, May 12, 2005; 70 FR 51597, Aug. 31, 2005; 73 FR 21538, Apr. 22, 2008; 76 FR 48353, Aug. 8, 2011; 79 FR 71671, Dec. 3, 2014; 84 FR 8442, Mar. 8, 2019; 86 FR 23164, Apr. 30, 2021]

(a) As used in this section, words and terms shall have the meanings set forth in § 51.50. In addition, the following terms shall apply to this section:

(1) Ozone season emissions means emissions during the period from May 1 through September 30 of a year.

(2) Summer day emissions means an average day's emissions for a typical summer work weekday. The state will select the particular month(s) in summer and the day(s) in the work week to be represented.

(b) For its transport SIP revision under § 51.121, each state must submit to EPA NOX emissions data as described in this section.

(c) Each revision must provide for periodic reporting by the state of NOX emissions data to demonstrate whether the state's emissions are consistent with the projections contained in its approved SIP submission.

(1) For the every-year reporting cycle, each revision must provide for reporting of NOX emissions data every year as follows:

(i) The state must report to EPA emissions data from all NOX sources within the state for which the state specified control measures in its SIP submission under § 51.121(g), including all sources for which the state has adopted measures that differ from the measures incorporated into the baseline inventory for the year 2007 that the state developed in accordance with § 51.121(g).The state must also report to EPA ozone season emissions of NOX and summer day emissions of NOX from any point, nonpoint, onroad mobile, or nonroad mobile source for which the state specified control measures in its SIP submission under § 51.121(g).

(ii) If sources report NOX emissions data to EPA for a given year pursuant to the monitoring and reporting requirements of 40 CFR part 75, then the state need not provide an every-year cycle report to EPA for such sources.

(2) For the 3-year cycle reporting, each plan must provide for triennial (i.e., every third year) reporting of NOX emissions data from all sources within the state. The state must also report to EPA ozone season emissions of NOX and summer day emissions of NOX from all point sources, nonpoint sources, onroad mobile sources, and nonroad mobile sources.

(3) The data availability requirements in § 51.116 must be followed for all data submitted to meet the requirements of paragraphs (c)(1) and (2) of this section.

(d) [Reserved]

(e) Each state must submit for EPA approval an example of the calculation procedure used to calculate ozone season emissions along with sufficient information to verify the calculated value of ozone season emissions.

(f) Data collection is to begin during the ozone season 1 year prior to the state's NOX SIP Call compliance date.

(g) The state shall report emissions as point sources according to the point source emissions thresholds of the Air Emissions Reporting Rule (AERR), 40 CFR part 51, subpart A. The detail of the emissions inventory shall be consistent with the data elements required by 40 CFR part 51, subpart A. When submitting a formal NOX Budget Emissions Report and associated data, states shall notify the appropriate EPA Regional Office.

[73 FR 76558, Dec. 17, 2008, as amended at 80 FR 8796, Feb. 19, 2015; 84 FR 8443, Mar. 8, 2019]

(a)(1) 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)(1) and (2) 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 NOX 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.

(2)(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)(1) and (3) 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 NOX in amounts that will contribute significantly to nonattainment in, or interfere with maintenance by, one or more other States with respect to the 8-hour ozone NAAQS.

(3) Notwithstanding the other provisions of this section, such provisions are not applicable as they relate to the State of Minnesota as of December 3, 2009.

(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) In addition to being subject to the requirements in paragraphs (b) and (d) of this section:

(1) Alabama, Delaware, Florida, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Virginia, West Virginia, Wisconsin, and the District of Columbia shall be subject to the requirements contained in paragraphs (e) through (cc) of this section;

(2) Georgia, Minnesota, and Texas shall be subject to the requirements in paragraphs (e) through (o) and (cc) of this section; and

(3) Arkansas, Connecticut, and Massachusetts shall be subject to the requirements contained in paragraphs (q) through (cc) of this section.

(d)(1) The State's 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 NOX Budget, if applicable, and achieve the State's Annual Non-EGU NOX Reduction Requirement, if applicable, for the appropriate periods. The amounts of the State's Annual EGU NOX Budget and Annual Non-EGU NOX Reduction Requirement shall be determined as follows:

(1)(i) The Annual EGU NOX Budget for the State is defined as the total amount of NOX emissions from all EGUs in that State for a year, if the State meets the requirements of paragraph (a)(1) 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 NOX 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 NOX Reduction Requirement, if applicable, is defined as the total amount of NOX 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)(1) of this section by imposing control measures on only non-EGUs, then the State's Annual Non-EGU NOX 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)(1) of this section by imposing control measures on both EGUs and non-EGUs, then:

(A) The Annual Non-EGU NOX 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 NOX Budget specified in the SIP revision for the appropriate period; and

(B) The Annual EGU NOX 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 NOX 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)(1) of this section by imposing control measures on only EGUs, the amount of the Annual EGU NOX Budget, in tons of NOX per year, shall be as follows, for the indicated State for the indicated period:

(3) For a State that complies with the requirements of paragraph (a)(1) of this section by imposing control measures on only non-EGUs, the amount of the Annual Non-EGU NOX Reduction Requirement, in tons of NOX per year, shall be determined, for the State for 2009 and thereafter, by subtracting the amount of the State's Annual EGU NOX Budget for the appropriate year, specified in paragraph (e)(2) of this section from the amount of the State's NOX baseline EGU emissions inventory projected for the appropriate year, specified in Table 5 of “Regional and State SO2 and NOX Budgets”, March 2005 (available at http://www.epa.gov/cleanairinterstaterule).

(4)(i) Notwithstanding the State's obligation to comply with paragraph (e)(2) or (3) of this section, the State's SIP revision may allow sources required by the revision to implement control measures to demonstrate compliance using credit issued from the State's compliance supplement pool, as set forth in paragraph (e)(4)(ii) of this section.

(ii) The State-by-State amounts of the compliance supplement pool are as follows:

(iii) The SIP revision may provide for the distribution of credits from the compliance supplement pool to sources that are required to implement control measures using one or both of the following two mechanisms:

(A) The State may issue credit from compliance supplement pool to sources that are required by the SIP revision to implement NOX emission control measures and that implement NOX emission reductions in 2007 and 2008 that are not necessary to comply with any State or federal emissions limitation applicable at any time during such years. Such a source may be issued one credit from the compliance supplement pool for each ton of such emission reductions in 2007 and 2008.

(1) The State shall complete the issuance process by January 1, 2010.

(2) The emissions reductions for which credits are issued must have been demonstrated by the owners and operators of the source to have occurred during 2007 and 2008 and not to be necessary to comply with any applicable State or federal emissions limitation.

(3) The emissions reductions for which credits are issued must have been quantified by the owners and operators of the source:

(i) For EGUs and for fossil-fuel-fired non-EGUs that are boilers or combustion turbines with a maximum design heat input greater than 250 mmBut/hr, using emissions data determined in accordance with subpart H of part 75 of this chapter; and

(ii) For non-EGUs not described in paragraph (e)(4)(iii)(A)(3)(i) of this section, using emissions data determined in accordance with subpart H of part 75 of this chapter or, if the State demonstrates that compliance with subpart H of part 75 of this chapter is not practicable, determined, to the extent practicable, with the same degree of assurance with which emissions data are determined for sources subject to subpart H of part 75.

(4) If the SIP revision contains approved provisions for an emissions trading program, the owners and operators of sources that receive credit according to the requirements of this paragraph may transfer the credit to other sources or persons according to the provisions in the emissions trading program.

(B) The State may issue credit from the compliance supplement pool to sources that are required by the SIP revision to implement NOX emission control measures and whose owners and operators demonstrate a need for an extension, beyond 2009, of the deadline for the source for implementing such emission controls.

(1) The State shall complete the issuance process by January 1, 2010.

(2) The State shall issue credit to a source only if the owners and operators of the source demonstrate that:

(i) For a source used to generate electricity, implementation of the SIP revision's applicable control measures by 2009 would create undue risk for the reliability of the electricity supply. This demonstration must include a showing that it would not be feasible for the owners and operators of the source to obtain a sufficient amount of electricity, to prevent such undue risk, from other electricity generation facilities during the installation of control technology at the source necessary to comply with the SIP revision.

(ii) For a source not used to generate electricity, compliance with the SIP revision's applicable control measures by 2009 would create undue risk for the source or its associated industry to a degree that is comparable to the risk described in paragraph (e)(4)(iii)(B)(2)(i) of this section.

(iii) This demonstration must include a showing that it would not be possible for the source to comply with applicable control measures by obtaining sufficient credits under paragraph (e)(4)(iii)(A) of this section, or by acquiring sufficient credits from other sources or persons, to prevent undue risk.

(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 NOX 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 NOX 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 NOX 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 2009 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)(1) of this section must demonstrate that such control measures are adequate to provide for the timely compliance with the State's Annual Non-EGU NOX 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 NOX 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 subpart H of part 75 of this chapter, if the source category is subject to monitoring requirements in accordance with subpart H of part 75 of this chapter.

(B) In the absence of monitoring data in accordance with subpart H of 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 subpart H of 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 NOX mass emissions from the source category in the years 2009 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 2009 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 otherwise required by final rules already promulgated, as of May 12, 2005, or adopted or implemented by any federal agency, 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 NOX 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 2009 or 2015, as appropriate.

(iii) A projection of NOX mass emissions in 2009 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 2009 and 2015 NOX 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 2009 and 2015, respectively, from the lower of the amounts in paragraph (g)(2)(i) or (g)(2)(ii) of this section for 2009 and 2015, respectively, may be credited towards the State's Annual Non-EGU NOX 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 NOX 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 subpart H 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 subpart H 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 subpart H 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 subpart H of 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 NOX Budget or the Annual Non-EGU NOX 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 AA through II of part 96 of this chapter (CAIR NOX Annual 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. Before January 1, 2009, a State's regulations shall be considered to be substantively identical to subparts AA through II of part 96 of this chapter, or differing substantively only as set forth in paragraph (o)(2) of this section, regardless of whether the State's regulations include the definition of “Biomass”, paragraph (3) of the definition of “Cogeneration unit”, and the second sentence of the definition of “Total energy input” in § 96.102 of this chapter promulgated on October 19, 2007, provided that the State timely submits to the Administrator a SIP revision that revises the State's regulations to include such provisions. Submission to the Administrator of a SIP revision that revises the State's regulations to include such provisions shall be considered timely if the submission is made by January 1, 2009.

(2) If a State adopts an emissions trading program that differs substantively from subparts AA through II 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 NOX opt-in provisions of:

(A) Subpart II of this part and the provisions applicable only to CAIR NOX opt-in units in subparts AA through HH of this part;

(B) Section 96.188(b) of this chapter and the provisions of subpart II of this part applicable only to CAIR NOX opt-in units under § 96.188(b); or

(C) Section 96.188(c) of this chapter and the provisions of subpart II of this part applicable only to CAIR NOX opt-in units under § 96.188(c).

(ii) The State may decline to adopt the allocation provisions set forth in subpart EE of part 96 of this chapter and may instead adopt any methodology for allocating CAIR NOX allowances to individual sources, as follows:

(A) The State's methodology must not allow the State to allocate CAIR NOX allowances for a year in excess of the amount in the State's Annual EGU NOX Budget for such year;

(B) The State's methodology must require that, for EGUs commencing operation before January 1, 2001, the State will determine, and notify the Administrator of, each unit's allocation of CAIR NOX allowances by October 31, 2006 for 2009, 2010, and 2011 and by October 31, 2008 and October 31 of each year thereafter for 4th the year after the year of the notification deadline;

(C) The State's methodology must require that, for EGUs commencing operation on or after January 1, 2001, the State will determine, and notify the Administrator of, each unit's allocation of CAIR NOX allowances by October 31 of the year for which the CAIR NOX allowances are allocated; and

(D) The State's methodology for allocating the compliance supplement pool must be substantively identical to § 97.143 (except that the permitting authority makes the allocations and the Administrator records the allocations made by the permitting authority) or otherwise in accordance with paragraph (e)(4) of this section.

(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 paragraph (aa)(1) or (2) of this section or § 96.124(o)(1) or (2).

(4) If a State adopts an emissions trading program that differs substantively from subparts AA through HH 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 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 NOX Ozone Season allowances under any emissions trading program approved under paragraphs (o)(1) or (2) or (aa)(1) or (2) of this section.

(p) Notwithstanding any other provision of this section, a State may adopt, and include in a SIP revision submitted by March 31, 2007, regulations relating to the Federal CAIR NOX Annual Trading Program under subparts AA through HH of part 97 of this chapter as follows:

(1) The State may adopt, as CAIR NOX allowance allocation provisions replacing the provisions in subpart EE of part 97 of this chapter:

(i) Allocation provisions substantively identical to subpart EE of part 96 of this chapter, under which the permitting authority makes the allocations; or

(ii) Any methodology for allocating CAIR NOX allowances to individual sources under which the permitting authority makes the allocations, provided that:

(A) The State's methodology must not allow the permitting authority to allocate CAIR NOX allowances for a year in excess of the amount in the State's Annual EGU NOX budget for such year.

(B) The State's methodology must require that, for EGUs commencing operation before January 1, 2001, the permitting authority will determine, and notify the Administrator of, each unit's allocation of CAIR NOX allowances by April 30, 2007 for 2009, 2010, and 2011 and by October 31, 2008 and October 31 of each year thereafter for the 4th year after the year of the notification deadline.

(C) The State's methodology must require that, for EGUs commencing operation on or after January 1, 2001, the permitting authority will determine, and notify the Administrator of, each unit's allocation of CAIR NOX allowances by October 31 of the year for which the CAIR NOX allowances are allocated.

(2) The State may adopt, as compliance supplement pool provisions replacing the provisions in § 97.143 of this chapter:

(i) Provisions for allocating the State's compliance supplement pool that are substantively identical to § 97.143 of this chapter, except that the permitting authority makes the allocations and the Administrator records the allocations made by the permitting authority;

(ii) Provisions for allocating the State's compliance supplement pool that are substantively identical to § 96.143 of this chapter; or

(iii) Other provisions for allocating the State's compliance supplement pool that are in accordance with paragraph (e)(4) of this section.

(3) The State may adopt CAIR opt-in unit provisions as follows:

(i) Provisions for CAIR opt-in units, including provisions for applications for CAIR opt-in permits, approval of CAIR opt-in permits, treatment of units as CAIR opt-in units, and allocation and recordation of CAIR NOX allowances for CAIR opt-in units, that are substantively identical to subpart II of part 96 of this chapter and the provisions of subparts AA through HH that are applicable to CAIR opt-in units or units 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;

(ii) Provisions for CAIR opt-in units, including provisions for applications for CAIR opt-in permits, approval of CAIR opt-in permits, treatment of units as CAIR opt-in units, and allocation and recordation of CAIR NOX allowances for CAIR opt-in units, that are substantively identical to subpart II of part 96 of this chapter and the provisions of subparts AA through HH that are applicable to CAIR opt-in units or units 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, except that the provisions exclude § 96.188(b) of this chapter and the provisions of subpart II of part 96 of this chapter that apply only to units covered by § 96.188(b) of this chapter; or

(iii) Provisions for applications for CAIR opt-in units, including provisions for CAIR opt-in permits, approval of CAIR opt-in permits, treatment of units as CAIR opt-in units, and allocation and recordation of CAIR NOX allowances for CAIR opt-in units, that are substantively identical to subpart II of part 96 of this chapter and the provisions of subparts AA through HH that are applicable to CAIR opt-in units or units 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, except that the provisions exclude § 96.188(c) of this chapter and the provisions of subpart II of part 96 of this chapter that apply only to units covered by § 96.188(c) of this chapter.

(q) The State's SIP revision shall contain control measures and demonstrate that they will result in compliance with the State's Ozone Season EGU NOX Budget, if applicable, and achieve the State's Ozone Season Non-EGU NOX Reduction Requirement, if applicable, for the appropriate periods. The amounts of the State's Ozone Season EGU NOX Budget and Ozone Season Non-EGU NOX Reduction Requirement shall be determined as follows:

(1)(i) The Ozone Season EGU NOX Budget for the State is defined as the total amount of NOX emissions from all EGUs in that State for an ozone season, if the State meets the requirements of paragraph (a)(2) 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 Ozone Season EGU NOX Budget for the State shall not exceed the amount, during the indicated periods, specified in paragraph (q)(2) of this section.

(ii) The Ozone Season Non-EGU NOX Reduction Requirement, if applicable, is defined as the total amount of NOX emission reductions that the State demonstrates, in accordance with paragraph (s) of this section, it will achieve from non-EGUs during the appropriate period. If the State meets the requirements of paragraph (a)(2) of this section by imposing control measures on only non-EGUs, then the State's Ozone Season Non-EGU NOX Reduction Requirement shall equal or exceed, during the appropriate periods, the amount determined in accordance with paragraph (q)(3) of this section.

(iii) If a State meets the requirements of paragraph (a)(2) of this section by imposing control measures on both EGUs and non-EGUs, then:

(A) The Ozone Season Non-EGU NOX Reduction Requirement shall equal or exceed the difference between the amount specified in paragraph (q)(2) of this section for the appropriate period and the amount of the State's Ozone Season EGU NOX Budget specified in the SIP revision for the appropriate period; and

(B) The Ozone Season EGU NOX Budget shall not exceed, during the indicated periods, the amount specified in paragraph (q)(2) of this section plus the amount of the Ozone Season Non-EGU NOX Reduction Requirement under paragraph (q)(1)(iii)(A) of this section for the appropriate period.

(2) For a State that complies with the requirements of paragraph (a)(2) of this section by imposing control measures on only EGUs, the amount of the Ozone Season EGU NOX Budget, in tons of NOX per ozone season, shall be as follows, for the indicated State for the indicated period:

(3) For a State that complies with the requirements of paragraph (a)(2) of this section by imposing control measures on only non-EGUs, the amount of the Ozone Season Non-EGU NOX Reduction Requirement, in tons of NOX per ozone season, shall be determined, for the State for 2009 and thereafter, by subtracting the amount of the State's Ozone Season EGU NOX Budget for the appropriate year, specified in paragraph (q)(2) of this section, from the amount of the State's NOX baseline EGU emissions inventory projected for the ozone season in the appropriate year, specified in Table 7 of “Regional and State SO2 and NOX Budgets”, March 2005 (available at: http://www.epa.gov/cleanairinterstaterule).

(4) Notwithstanding the State's obligation to comply with paragraph (q)(2) or (3) of this section, the State's SIP revision may allow sources required by the revision to implement NOX emission control measures to demonstrate compliance using NOX SIP Call allowances allocated under the NOX Budget Trading Program for any ozone season during 2003 through 2008 that have not been deducted by the Administrator under the NOX Budget Trading Program, if the SIP revision ensures that such allowances will not be available for such deduction under the NOX Budget Trading Program.

(r) Each SIP revision must set forth control measures to meet the amounts specified in paragraph (q) 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 ozone season NOX 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 ozone season NOX 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 (r)(2)(ii) of this section, then those measures must impose an ozone season NOX 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 (q) of this section, as applicable, in 2009 and subsequent years.

(s)(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)(2) of this section must demonstrate that such control measures are adequate to provide for the timely compliance with the State's Ozone Season Non-EGU NOX Reduction Requirement under paragraph (q) 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 (s)(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 NOX mass emissions from the source category in a representative ozone season consisting, at the State's election, of the ozone season in 2002, 2003, 2004, or 2005, or an average of 2 or more of those ozone seasons, 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 subpart H of part 75 of this chapter, if the source category is subject to monitoring requirements in accordance with subpart H of part 75 of this chapter.

(B) In the absence of monitoring data in accordance with subpart H of 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 subpart H of 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 NOX mass emissions from the source category in ozone seasons 2009 and 2015, absent the control measures specified in the SIP revision and reflecting changes in these emissions from the historical baseline ozone season to the ozone seasons 2009 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 NOX 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 ozone season and ozone season 2009 or ozone season 2015, as appropriate.

(iii) A projection of NOX mass emissions in ozone season 2009 and ozone season 2015 from the source category assuming the same projected changes as under paragraph (s)(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 ozone season 2009 and ozone season 2015 NOX 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 (s)(2)(iii) of this section for ozone season 2009 and ozone season 2015, respectively, from the lower of the amounts in paragraph (s)(2)(i) or (s)(2)(ii) of this section for ozone season 2009 and ozone season 2015, respectively, may be credited towards the State's Ozone Season Non-EGU NOX Reduction Requirement in paragraph (q)(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.

(t) Each SIP revision must comply with § 51.116 (regarding data availability).

(u) Each SIP revision must provide for monitoring the status of compliance with any control measures adopted to meet the State's requirements under paragraph (q) 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 NOX 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 subpart H 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 subpart H 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 (u)(4)(ii) of this section, then the SIP revision must require such sources to comply with the monitoring, recordkeeping, and reporting provisions of subpart H 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 subpart H of part 75 of this chapter.

(v) 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 Ozone Season EGU NOX Budget or the Ozone Season Non-EGU NOX Reduction Requirement, as applicable, under paragraph (q) 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 (v)(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.

(w)(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 (v)(3) and (4) of this section may be delegated to the State under section 114 of the CAA.

(x)(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).

(y) Each SIP revision must comply with § 51.280 (regarding resources).

(z) Each SIP revision must provide for State compliance with the reporting requirements in § 51.125.

(aa)(1) Notwithstanding any other provision of this section, if a State adopts regulations substantively identical to subparts AAAA through IIII of part 96 of this chapter (CAIR Ozone Season NOX 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 (aa)(2) of this section, then such emissions trading program in the State's SIP revision is automatically approved as meeting the requirements of paragraph (q) of this section, provided that the State has the legal authority to take such action and to implement its responsibilities under such regulations. Before January 1, 2009, a State's regulations shall be considered to be substantively identical to subparts AAAA through IIII of part 96 of the chapter, or differing substantively only as set forth in paragraph (o)(2) of this section, regardless of whether the State's regulations include the definition of “Biomass”, paragraph (3) of the definition of “Cogeneration unit”, and the second sentence of the definition of “Total energy input” in § 96.302 of this chapter promulgated on October 19, 2007, provided that the State timely submits to the Administrator a SIP revision that revises the State's regulations to include such provisions. Submission to the Administrator of a SIP revision that revises the State's regulations to include such provisions shall be considered timely if the submission is made by January 1, 2009.

(2) If a State adopts an emissions trading program that differs substantively from subparts AAAA through IIII of part 96 of this chapter only as follows, then the emissions trading program is approved as set forth in paragraph (aa)(1) of this section.

(i) The State may expand the applicability provisions in § 96.304 to include all non-EGUs subject to the State's emissions trading program approved under § 51.121(p).

(ii) The State 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) The State may decline to adopt the allocation provisions set forth in subpart EEEE of part 96 of this chapter and may instead adopt any methodology for allocating CAIR NOX Ozone Season allowances to individual sources, as follows:

(A) The State may provide for issuance of an amount of CAIR Ozone Season NOX allowances for an ozone season, in addition to the amount in the State's Ozone Season EGU NOX Budget for such ozone season, not exceeding the amount of NOX SIP Call allowances allocated for the ozone season under the NOX Budget Trading Program to non-EGUs that the applicability provisions in § 96.304 are expanded to include under paragraph (aa)(2)(i) of this section;

(B) The State's methodology must not allow the State to allocate CAIR Ozone Season NOX allowances for an ozone season in excess of the amount in the State's Ozone Season EGU NOX Budget for such ozone season plus any additional amount of CAIR Ozone Season NOX allowances issued under paragraph (aa)(2)(iii)(A) of this section for such ozone season;

(C) The State's methodology must require that, for EGUs commencing operation before January 1, 2001, the State 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

(D) The State's methodology must require that, for EGUs commencing operation on or after January 1, 2001, the State 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) A State that adopts an emissions trading program in accordance with paragraph (aa)(1) or (2) of this section is not required to adopt an emissions trading program in accordance with paragraph (o)(1) or (2) of this section or § 51.153(o)(1) or (2).

(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 or other entity.

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.

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 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 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)(i) 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 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 producing electricity for sale.

(ii) If a stationary boiler or stationary combustion turbine that, under paragraph (1)(i) of this section, is not an electric generating unit begins to combust fossil fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the unit shall become an electric generating unit as provided in paragraph (1)(i) of this section on the first date on which it both combusts fossil fuel and serves such generator.

(2) A unit that meets the requirements set forth in paragraphs (2)(i)(A), (2)(ii)(A), or (2)(ii)(B) of this definition paragraph shall not be an electric generating unit:

(i)(A) Any unit that is an electric generating unit under paragraph (1)(i) or (ii) of this definition:

(1) 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

(2) 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.

(B) 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 (2)(i)(A) of this section for at least one calendar year, but subsequently no longer meets all such requirements, the unit shall become an electric generating unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of paragraph (2)(i)(A)(2) of this section.

(ii)(A) Any unit that is an electric generating unit under paragraph (1)(i) or (ii) of this definition commencing operation before January 1, 1985:

(1) Qualifying as a solid waste incineration unit; and

(2) 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).

(B) Any unit that is an electric generating unit under paragraph (1)(i) or (ii) of this definition commencing operation on or after January 1, 1985:

(1) Qualifying as a solid waste incineration unit; and

(2) 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).

(C) If a unit qualifies as a solid waste incineration unit and meets the requirements of paragraph (2)(ii)(A) or (B) of this section for at least 3 consecutive calendar years, but subsequently no longer meets all such requirements, the unit shall become an electric generating unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a solid waste incineration unit or January 1 after the first 3 consecutive calendar years after 1990 for which the unit has an average annual fuel consumption of fossil fuel of 20 percent or more.

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 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.

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 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.

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.

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.

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:

LHV = HHV − 10.55(W + 9H) Where: LHV = lower heating value of fuel in Btu/lb, HHV = higher heating value of fuel in Btu/lb, W = Weight % of moisture in fuel, and H = Weight % of hydrogen in fuel.

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 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.

(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.

(ee) Notwithstanding any other provision of this section, a State may adopt, and include in a SIP revision submitted by March 31, 2007, regulations relating to the Federal CAIR NOX Ozone Season Trading Program under subparts AAAA through HHHH of part 97 of this chapter as follows:

(1) The State may adopt, as applicability provisions replacing the provisions in § 97.304 of this chapter, provisions for applicability that are substantively identical to the provisions in § 96.304 of this chapter expanded to include all non-EGUs subject to the State's emissions trading program approved under § 51.121(p). Before January 1, 2009, a State's applicability provisions shall be considered to be substantively identical to § 96.304 of this chapter (with the expansion allowed under this paragraph) regardless of whether the State's regulations include the definition of “Biomass”, paragraph (3) of the definition of “Cogeneration unit”, and the second sentence of the definition of “Total energy input” in § 97.102 of this chapter promulgated on October 19, 2007, provided that the State timely submits to the Administrator a SIP revision that revises the State's regulations to include such provisions. Submission to the Administrator of a SIP revision that revises the State's regulations to include such provisions shall be considered timely if the submission is made by January 1, 2009.

(2) The State may adopt, as CAIR NOX Ozone Season allowance allocation provisions replacing the provisions in subpart EEEE of part 97 of this chapter:

(i) Allocation provisions substantively identical to subpart EEEE of part 96 of this chapter, under which the permitting authority makes the allocations; or

(ii) Any methodology for allocating CAIR NOX Ozone Season allowances to individual sources under which the permitting authority makes the allocations, provided that:

(A) The State may provide for issuance of an amount of CAIR Ozone Season NOX allowances for an ozone season, in addition to the amount in the State's Ozone Season EGU NOX Budget for such ozone season, not exceeding the portion of the State's trading program budget, under the State's emissions trading program approved under § 51.121(p), attributed to the non-EGUs that the applicability provisions in § 96.304 of this chapter are expanded to include under paragraph (ee)(1) of this section.

(B) The State's methodology must not allow the State to allocate CAIR Ozone Season NOX allowances for an ozone season in excess of the amount in the State's Ozone Season EGU NOX Budget for such ozone season plus any additional amount of CAIR Ozone Season NOX allowances issued under paragraph (ee)(2)(ii)(A) of this section for such ozone season.

(C) The State's methodology must require that, for EGUs commencing operation before January 1, 2001, the permitting authority will determine, and notify the Administrator of, each unit's allocation of CAIR NOX Ozone Season allowances by April 30, 2007 for 2009, 2010, and 2011 and by October 31, 2008 and October 31 of each year thereafter for the 4th year after the year of the notification deadline.

(D) The State's methodology must require that, for EGUs commencing operation on or after January 1, 2001, the permitting authority will determine, and notify the Administrator of, each unit's allocation of CAIR NOX Ozone Season allowances by July 31 of the year for which the CAIR NOX Ozone Season allowances are allocated.

(3) The State may adopt CAIR opt-in unit provisions as follows:

(i) Provisions for CAIR opt-in units, including provisions for applications for CAIR opt-in permits, approval of CAIR opt-in permits, treatment of units as CAIR opt-in units, and allocation and recordation of CAIR NOX Ozone Season allowances for CAIR opt-in units, that are substantively identical to subpart IIII of part 96 of this chapter and the provisions of subparts AAAA through HHHH that are applicable to CAIR opt-in units or units 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;

(ii) Provisions for CAIR opt-in units, including provisions for applications for CAIR opt-in permits, approval of CAIR opt-in permits, treatment of units as CAIR opt-in units, and allocation and recordation of CAIR NOX Ozone Season allowances for CAIR opt-in units, that are substantively identical to subpart IIII of part 96 of this chapter and the provisions of subparts AAAA through HHHH that are applicable to CAIR opt-in units or units 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, except that the provisions exclude § 96.388(b) of this chapter and the provisions of subpart IIII of part 96 of this chapter that apply only to units covered by § 96.388(b) of this chapter; or

(iii) Provisions for applications for CAIR opt-in units, including provisions for CAIR opt-in permits, approval of CAIR opt-in permits, treatment of units as CAIR opt-in units, and allocation and recordation of CAIR NOX allowances for CAIR opt-in units, that are substantively identical to subpart IIII of part 96 of this chapter and the provisions of subparts AAAA through HHHH that are applicable to CAIR opt-in units or units 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, except that the provisions exclude § 96.388(c) of this chapter and the provisions of subpart IIII of part 96 of this chapter that apply only to units covered by § 96.388(c) of this chapter.

(ff) Notwithstanding any provisions of paragraphs (a) through (ee) of this section, subparts AA through II and AAAA through IIII of part 96 of this chapter, subparts AA through II and AAAA through IIII of part 97 of this chapter, and any State's SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2014, the Administrator:

(i) Rescinds the determination in paragraph (a) of this section that the States identified in paragraph (c) of this section must submit a SIP revision with respect to the fine particles (PM2.5) NAAQS and the 8-hour ozone NAAQS meeting the requirements of paragraphs (b) through (ee) of this section; and

(ii) Will not carry out any of the functions set forth for the Administrator in subparts AA through II and AAAA through IIII of part 96 of this chapter, subparts AA through II and AAAA through IIII of part 97 of this chapter, or in any emissions trading program provisions in a State's SIP approved under this section;

(2) The Administrator will not deduct for excess emissions any CAIR NOX allowances or CAIR NOX Ozone Season allowances allocated for 2015 or any year thereafter;

(3) By March 3, 2015, the Administrator will remove from the CAIR NOX Allowance Tracking System accounts all CAIR NOX allowances allocated for a control period in 2015 and any subsequent year, and, thereafter, no holding or surrender of CAIR NOX allowances will be required with regard to emissions or excess emissions for such control periods; and

(4) By March 3, 2015, the Administrator will remove from the CAIR NOX Ozone Season Allowance Tracking System accounts all CAIR NOX Ozone Season allowances allocated for a control period in 2015 and any subsequent year, and, thereafter, no holding or surrender of CAIR NOX Ozone Season allowances will be required with regard to emissions or excess emissions for such control periods.

[70 FR 25319, May 12, 2005, as amended at 71 FR 25301, 25370, Apr. 28, 2006; 71 FR 74793, Dec. 13, 2006; 72 FR 59203, Oct. 19, 2007; 74 FR 56726, Nov. 3, 2009; 76 FR 48353, Aug. 8, 2011; 79 FR 71671, Dec. 3, 2014]

(a)(1) 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.

(2) Notwithstanding the other provisions of this section, such provisions are not applicable as they relate to the State of Minnesota as of December 3, 2009.

(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, Delaware, Florida, Georgia, Illinois, Indiana, Iowa, Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi, Missouri, New Jersey, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, 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:

(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. Before January 1, 2009, a State's regulations shall be considered to be substantively identical to subparts AAA through III of part 96 of the chapter, or differing substantively only as set forth in paragraph (o)(2) of this section, regardless of whether the State's regulations include the definition of “Biomass”, paragraph (3) of the definition of “Cogeneration unit”, and the second sentence of the definition of “Total energy input” in § 96.202 of this chapter promulgated on October 19, 2007, provided that the State timely submits to the Administrator a SIP revision that revises the State's regulations to include such provisions. Submission to the Administrator of a SIP revision that revises the State's regulations to include such provisions shall be considered timely if the submission is made by January 1, 2009.

(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 or other entity.

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.

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 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 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)(i) 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 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 producing electricity for sale.

(ii) If a stationary boiler or stationary combustion turbine that, under paragraph (1)(i) of this section, is not an electric generating unit begins to combust fossil fuel or to serve a generator with nameplate capacity of more than 25 MWe producing electricity for sale, the unit shall become an electric generating unit as provided in paragraph (1)(i) of this section on the first date on which it both combusts fossil fuel and serves such generator.

(2) A unit that meets the requirements set forth in paragraphs (2)(i)(A), (2)(ii)(A), or (2)(ii)(B) of this definition paragraph shall not be an electric generating unit:

(i)(A) Any unit that is an electric generating unit under paragraph (1)(i) or (ii) of this definition:

(1) 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

(2) 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.

(B) 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 (2)(i)(A) of this section for at least one calendar year, but subsequently no longer meets all such requirements, the unit shall become an electric generating unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a cogeneration unit or January 1 after the first calendar year during which the unit no longer meets the requirements of paragraph (2)(i)(A)(2) of this section.

(ii)(A) Any unit that is an electric generating unit under paragraph (1)(i) or (ii) of this definition commencing operation before January 1, 1985:

(1) Qualifying as a solid waste incineration unit; and

(2) 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).

(B) Any unit that is an electric generating unit under paragraph (1)(i) or (ii) of this definition commencing operation on or after January 1, 1985:

(1) Qualifying as a solid waste incineration unit; and

(2) 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).

(C) If a unit qualifies as a solid waste incineration unit and meets the requirements of paragraph (2)(ii)(A) or (B) of this section for at least 3 consecutive calendar years, but subsequently no longer meets all such requirements, the unit shall become an electric generating unit starting on the earlier of January 1 after the first calendar year during which the unit first no longer qualifies as a solid waste incineration unit or January 1 after the first 3 consecutive calendar years after 1990 for which the unit has an average annual fuel consumption of fossil fuel of 20 percent or more.

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 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.

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 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.

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.

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.

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. Each form of energy supplied shall be measured by the lower heating value of that form of energy calculated as follows:

LHV = HHV − 10.55(W + 9H) Where: LHV = lower heating value of fuel in Btu/lb, HHV = higher heating value of fuel in Btu/lb, W = Weight % of moisture in fuel, and H = Weight % of hydrogen in fuel.

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 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.

(r) Notwithstanding any other provision of this section, a State may adopt, and include in a SIP revision submitted by March 31, 2007, regulations relating to the Federal CAIR SO2 Trading Program under subparts AAA through HHH of part 97 of this chapter as follows. The State may adopt the following CAIR opt-in unit provisions:

(1) Provisions for CAIR opt-in units, including provisions for applications for CAIR opt-in permits, approval of CAIR opt-in permits, treatment of units as CAIR opt-in units, and allocation and recordation of CAIR SO2 allowances for CAIR opt-in units, that are substantively identical to subpart III of part 96 of this chapter and the provisions of subparts AAA through HHH that are applicable to CAIR opt-in units or units 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;

(2) Provisions for CAIR opt-in units, including provisions for applications for CAIR opt-in permits, approval of CAIR opt-in permits, treatment of units as CAIR opt-in units, and allocation and recordation of CAIR SO2 allowances for CAIR opt-in units, that are substantively identical to subpart III of part 96 of this chapter and the provisions of subparts AAA through HHH that are applicable to CAIR opt-in units or units 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, except that the provisions exclude § 96.288(b) of this chapter and the provisions of subpart III of part 96 of this chapter that apply only to units covered by § 96.288(b) of this chapter; or

(3) Provisions for applications for CAIR opt-in units, including provisions for CAIR opt-in permits, approval of CAIR opt-in permits, treatment of units as CAIR opt-in units, and allocation and recordation of CAIR SO2 allowances for CAIR opt-in units, that are substantively identical to subpart III of part 96 of this chapter and the provisions of subparts AAA through HHH that are applicable to CAIR opt-in units or units 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, except that the provisions exclude § 96.288(c) of this chapter and the provisions of subpart III of part 96 of this chapter that apply only to units covered by § 96.288(c) of this chapter.

(s) Notwithstanding any provisions of paragraphs (a) through (r) of this section, subparts AAA through III of part 96 of this chapter, subparts AAA through III of part 97 of this chapter, and any State's SIP to the contrary:

(1) With regard to any control period that begins after December 31, 2014, the Administrator:

(i) Rescinds the determination in paragraph (a) of this section that the States identified in paragraph (c) of this section must submit a SIP revision with respect to the fine particles (PM2.5) NAAQS meeting the requirements of paragraphs (b) through (r) of this section; and

(ii) Will not carry out any of the functions set forth for the Administrator in subparts AAA through III of part 96 of this chapter, subparts AAA through III of part 97 of this chapter, or in any emissions trading program in a State's SIP approved under this section; and

(2) The Administrator will not deduct for excess emissions any CAIR SO2 allowances allocated for 2015 or any year thereafter.

[70 FR 25328, May 12, 2005, as amended at 71 FR 25302, 25372, Apr. 28, 2006; 71 FR 74793, Dec. 13, 2006; 72 FR 59204, Oct. 19, 2007; 74 FR 56726, Nov. 3, 2009; 76 FR 48353, Aug. 8, 2011; 79 FR 71671, Dec. 3, 2014]

(a) Pursuant to section 202(a)(6) of the Clean Air Act, the Administrator has determined that, effective May 16, 2012, onboard refueling vapor recovery (ORVR) systems are in widespread use in the motor vehicle fleet within the United States.

(b) Effective May 16, 2012, the Administrator waives the requirement of Clean Air Act section 182(b)(3) for Stage II vapor recovery systems in ozone nonattainment areas regardless of classification. States must submit and receive EPA approval of a revision to their approved State Implementation Plans before removing Stage II requirements that are contained therein.

[77 FR 28782, May 16, 2012]