1 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 4. Part 51 is amended by adding § 51.123 to Subpart G to read as follows:

§ 51.123 Findings and requirements for submission of State implementation plan revisions relating to emissions of oxides of nitrogen pursuant to the Clean Air Interstate Rule.

( 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NOX in amounts that will contribute significantly to nonattainment in, or interfere with 2 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite maintenance by, one or more other States with respect to the 8

hour ozone NAAQS.

( b) For each State identified in paragraph ( c) of this section, the SIP revision required under paragraph ( a) 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, Florida, Illinois, Indiana, Iowa, Kentucky,

Louisiana, Maryland, Michigan, Mississippi, Missouri, 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, Delaware, Massachusetts, and New Jersey 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 3 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite section must be submitted to EPA by no later than [ Insert the date 18 months ( 540 days) from the date on which the Administrator signs the final Clean Air Interstate Rule].

( 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 4 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 5 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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:

State Annual EGU NOX Budget for 2009 2014 ( tons) Annual EGU NOX Budget for 2015 and thereafter ( tons) Alabama 69,020 57,517 District of Columbia 144 120 Florida 99,445 82,871 Georgia 66,321 55,268 Illinois 76,230 63,525 Indiana 108,935 90,779 Iowa 32,692 27,243 Kentucky 83,205 69,337 Louisiana 35,512 29,593 Maryland 27,724 23,104 Michigan 65,304 54,420 Minnesota 31,443 26,203 Mississippi 17,807 14,839 Missouri 59,871 49,892 New York 45,617 38,014 North Carolina 62,183 51,819 Ohio 108,667 90,556 Pennsylvania 99,049 82,541 South Carolina 32,662 27,219 Tennessee 50,973 42,478 Texas 181,014 150,845 Virginia 36,074 30,062 West Virginia 74,220 61,850 Wisconsin 40,759 33,966 ( 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 NOX baseline EGU emissions inventory projected for the appropriate year, specified in XXXXXXXXXXXXXX, from the 6 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite amount of the State's Annual EGU NOX budget for the appropriate year, specified in paragraph ( e)( 2) of this section.

( 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:

State Compliance Supplement Pool ( tons) Alabama 10,179 District Of Columbia 0 Florida 8,345 Georgia 12,412 Illinois 11,313 Indiana 20,180 Iowa 6,987 Kentucky 14,953 Louisiana 2,254 Maryland 4,676 Michigan 8,358 Minnesota 6,536 Mississippi 3,070 Missouri 9,055 New York 0 North Carolina 0 Ohio 25,068 Pennsylvania 16,029 7 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite South Carolina 2,604 Tennessee 8,955 Texas 773 Virginia 5,141 West Virginia 16,950 Wisconsin 4,904 ( 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 8 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 trade 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. 9 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite ( 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 ( f) Each SIP revision must set forth control measures to 10 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 11 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 [ Insert the date of publication of the final Clean Air Interstate Rule], 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. 12 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite ( 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 13 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 [ Insert the date of publication of the final Clean Air Interstate Rule], 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 14 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 15 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 16 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite ( 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: 17 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite ( 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);

( 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 18 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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.

( 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 19 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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) § 96.188( b) and the provisions of subpart II of this part applicable only to CAIR NOX opt in units under § 96.188( b); or ( C) § 96.188( c) 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 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, 2000, 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 the year 4 years after the notification deadline; and 20 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite ( C) The State's methodology must require that, for EGUs commencing operation on or after January 1, 2000, the State will determine, and notify the Administrator of, each unit's allocation of CAIR NOX allowances by October 31 of the year immediately after the year for which the CAIR NOX allowances are allocated.

( 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. 21 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite ( 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 22 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 ( e)( 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:

State Ozone Season EGU NOX Budget for 2009

2014 ( tons) Ozone Season EGU NOX Budget for 2015 and thereafter ( tons) 23 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite Alabama 32,182 26,818 Arkansas 11,515 9,596 Connecticut 2,559 2,559 Delaware 2,226 1,855 District of Columbia 112 94 Florida 47,912 39,926 Illinois 30,701 28,981 Indiana 45,952 39,273 Iowa 14,263 11,886 Kentucky 36,045 30,587 Louisiana 17,085 14,238 Maryland 12,834 10,695 Massachusetts 7,551 6,293 Michigan 28,971 24,142 Mississippi 8,714 7,262 Missouri 26,678 22,231 New Jersey 6,654 5,545 New York 20,632 17,193 North Carolina 28,392 23,660 Ohio 45,664 39,945 Pennsylvania 42,171 35,143 South Carolina 15,249 12,707 Tennessee 22,842 19,035 Virginia 15,994 13,328 West Virginia 26,859 26,525 Wisconsin 17,987 14,989 ( 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 NOX baseline EGU emissions inventory projected for the ozone season in the appropriate year, specified in XXXXXXXXXXXXXX, from the amount of the State's Ozone Season EGU NOX budget for the appropriate year, specified in paragraph ( e)( 2) of this section.

( 4) Notwithstanding the State's obligation to comply with paragraph ( q)( 2) or ( 3) of this section, the State's SIP revision 24 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 25 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 [ Insert the date of publication of the final Clean Air Interstate Rule], 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: 26 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite ( 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 27 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 [ Insert the date of publication of the final Clean Air Interstate Rule], 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 28 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 29 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 30 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 31 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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);

( 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 32 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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. 33 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite ( 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.

( 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 § 96.104 to include all non EGUs subject to the requirements of the State's SIP meeting the requirements of § 51.121.

( 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) § 96.388( b) and the provisions of subpart IIII of this 34 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite part applicable only to CAIR NOX Ozone Season opt in units under § 96.388( b); or ( C) § 96.388( c) 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 NOX 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 § 96.104 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, 2000, the State will 35 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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 4 years after the notification deadline; and ( D) The State's methodology must require that, for EGUs commencing operation on or after January 1, 2000, the State will determine, and notify the Administrator of, each unit's allocation of CAIR Ozone Season NOX allowances by October 31 of the calendar year immediately after 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 36 Section I 3/ 4/ 2005 DRAFT Do Not Quote or Cite 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) 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 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 SIP revision also provides that:

( i) For a State whose amount of tons specified in paragraph ( q)( 2) of this section exceeds the 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, the State will replace the former amount for such ozone season by the latter amount for such ozone season in applying paragraph ( q) of this section.

( ii) An amount of NOX SIP Call allowances equal to, and allocated for the same or a previous ozone season, as the NOX SIP Call allowances allocated to such EGUs and non EGUs for each ozone season for which the State revises its SIP under paragraph ( bb)( 1) of this section and not deducted by the Administrator under the NOX Budget Trading Program shall be permanently retired and shall not be available for deduction by the Administrator under the NOX Budget Trading Program. DRAFT  12/ 2/ 04 37 ( 2) Notwithstanding a SIP revision by a State authorized under paragraph ( bb)( 1) of this section, if the State's SIP that,

without such SIP revision, imposes control measures on EGUs or non EGUs under § 51.121 is determined by the Administrator to meet the requirements of § 51.121, such SIP shall be deemed to continue to meet the requirements of § 51.121.

( cc) The terms used in this section shall have the following meanings:

Administrator means the Administrator of the United States Environmental Protection Agency or the Administrator's duly authorized representative.

Allocate or allocation means, with regard to allowances, the determination of the amount of allowances to be initially credited to a source.

Boiler means an enclosed fossil or other fuel fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.

Bottoming cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.

Clean Air Act or CAA means the Clean Air Act, 42 U. S. C.

7401, et seq.

Cogeneration unit means a stationary, fossil fuel fired DRAFT  12/ 2/ 04 38 boiler or stationary, fossil fuel fired combustion turbine:

( 1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and ( 2) Producing during the 12 month period starting on the date the unit first produces electricity and during any calendar year after which the unit first produces electricity   ( i) For a topping cycle cogeneration unit,

( A) Useful thermal energy not less than 5 percent of total energy output; and ( B) Useful power that, when added to one half of useful thermal energy produced, is not less then 42.5 percent of total energy input or, if useful thermal energy produced is less than 15 percent of total energy output, not less than 45 percent of total energy input.

( ii) For a bottoming cycle cogeneration unit, useful power not less than 45 percent of total energy input.

Combustion turbine means:

( 1) An enclosed device comprising a compressor, a combustor,

and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine,

rotating the turbine; and ( 2) If the enclosed device under paragraph ( 1) of this definition is combined cycle, any associated heat recovery steam generator and steam turbine. DRAFT  12/ 2/ 04 39 Commence operation means to have begun any mechanical,

chemical, or electronic process, including, with regard to a unit, start up of a unit's combustion chamber.

Electric generating unit or EGU means:

( 1) Except as provided in paragraph ( 2) of this definition,

a stationary, fossil fuel fired boiler or stationary,

fossilfuel fired combustion turbine serving at any time, since the start up of a unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

( 2) For a unit that qualifies as a cogeneration unit during the 12 month period starting on the date the unit first produces electricity and continues to qualify as a cogeneration unit, a cogeneration unit serving at any time a generator with nameplate capacity of more than 25 MWe and supplying in any calendar year more than one third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale. If a unit that qualifies as a cogeneration unit during the 12 month period starting on the date the unit first produces electricity but subsequently no longer qualifies as a cogeneration unit, the unit shall be subject to paragraph ( 1) of this definition starting on the day on which the unit first no longer qualifies as a cogeneration unit.

Fossil fuel means natural gas, petroleum, coal, or any form DRAFT  12/ 2/ 04 40 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:

( A) As specified by the manufacturer of the unit as of the initial installation of the unit;

( B) If the unit subsequently undergoes a physical change resulting in an increase in such maximum design heat input, as specified by the person conducting the physical change; or ( C) For purposes of applying the definition of the term " potential electrical output capacity" and if the unit subsequently undergoes a physical change resulting in a decrease in such maximum design heat input, as specified by the person conducting the physical change.

NAAQS means National Ambient Qir Quality Standard.

Nameplate capacity means the maximum electrical generating output ( in MWe) that a generator is capable of producing on a steady state basis and during continuous operation ( when not restricted by seasonal or other deratings), as specified by the manufacturer of the generator as of the initial installation of the generator or, if the generator subsequently undergoes a physical change resulting in an increase in such maximum DRAFT  12/ 2/ 04 41 electrical generating output, 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 oxide 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 of this chapter,

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) of this chapter 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 mmBtu/ 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 DRAFT  12/ 2/ 04 42 reject heat from useful thermal energy application or process in electricity production.

Topping cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful power, including electricity, and at least some of the reject heat from the electricity production is then used to provide useful thermal energy.

Total energy input means, with regard to a cogeneration unit, total energy of all forms supplied to the cogeneration unit, excluding energy produced by the cogeneration unit itself.

Total energy output means, with regard to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.

Unit means a stationary, fossil fuel fired boiler or a stationary, fossil fuel fired combustion turbine.

Useful power means, with regard to a cogeneration unit,

electricity or mechanical energy made available for use,

excluding any such energy used in the power production process ( which process includes, but is not limited to, any on site processing or treatment of fuel combusted at the unit and any onsite 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 DRAFT  12/ 2/ 04 43 water;

( 2) Used in a heat application ( e. g., space heating or domestic hot water heating); or ( 3) Used in a space cooling application ( i. e., thermal energy used by an absorption chiller).

Utility power distribution system means the portion of an electricity grid owned or operated by a utility and dedicated to delivering electricity to customers.

5. Part 51 is amended by adding § 51.124 to Subpart G to read as follows:

§ 51.124 Findings and requirements for submission of State implementation plan revisions relating to emissions of sulfur dioxide pursuant to the Clean Air Interstate Rule.

( a) Under section 110( a)( 1) of the CAA, 42 U. S. C.

7410( a)( 1), the Administrator determines that each State identified in paragraph ( c) of this section must submit a SIP revision to comply with the requirements of section 110( a)( 2)( D)( i)( I) of the CAA, 42 U. S. C. 7410( a)( 2)( D)( i)( I),

through the adoption of adequate provisions prohibiting sources and other activities from emitting SO2 in amounts that will contribute significantly to nonattainment in, or interfere with maintenance by, one or more other States with respect to the fine particles ( PM2.5) NAAQS.

( b) For each State identified in paragraph ( c) of this section, the SIP revision required under paragraph ( a) will DRAFT  12/ 2/ 04 44 contain adequate provisions, for purposes of complying with section 110( a)( 2)( D)( i)( I) of the CAA, 42 U. S. C.

7410( a)( 2)( D)( i)( I), only if the SIP revision contains control measures that assure compliance with the applicable requirements of this section.

( c) The following States are subject to the requirements of this section: Alabama, Florida, Georgia, Illinois, Indiana, Iowa,

Kentucky, Louisiana, Maryland, Michigan, Minnesota, Mississippi,

Missouri, New York, North Carolina, Ohio, Pennsylvania, South Carolina, Tennessee, Texas, Virginia, West Virginia, and Wisconsin, and the District of Columbia.

( d)( 1) The SIP revision under paragraph ( a) of this section must be submitted to EPA by no later than [ Insert the date 18 months ( 540 days) from the date on which the Administrator signs the final Clean Air Interstate Rule].

( 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 DRAFT  12/ 2/ 04 45 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 DRAFT  12/ 2/ 04 46 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:

State Annual EGU SO2 Budget for 2010 2014 ( tons) Annual EGU SO2 Budget for 2015 and thereafter ( tons) Alabama 157,582 110,307 District of Columbia 708 495 Florida 253,450 177,415 Georgia 213,057 149,140 Illinois 192,671 134,869 Indiana 254,599 178,219 Iowa 64,095 44,866 Kentucky 188,773 132,141 Louisiana 59,948 41,963 Maryland 70,697 49,488 Michigan 178,605 125,024 Minnesota 49,987 34,991 Mississippi 33,763 23,634 Missouri 137,214 96,050 New York 135,139 94,597 North Carolina 137,342 96,139 Ohio 333,520 233,464 Pennsylvania 275,990 193,193 South Carolina 57,271 40,089 DRAFT  12/ 2/ 04 47 Tennessee 137,216 96,051 Texas 320,946 224,662 Virginia 63,478 44,435 West Virginia 215,881 151,117 Wisconsin 87,264 61,085 ( 3) For a State that complies with the requirements of paragraph ( a) of this section by imposing control measures on only non EGUs, the amount of the Annual Non EGU SO2 Reduction Requirement, in tons of SO2 per year, shall be determined, for the State for 2010 and thereafter, by subtracting the amount of the State's SO2 baseline EGU emissions inventory projected for the ozone season in the appropriate year, specified in XXXXXXXXXXXXXX, from the amount of the State's Annual EGU SO2 budget for the appropriate year, 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. DRAFT  12/ 2/ 04 48 ( 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 [ Insert the date of publication of the final Clean Air Interstate Rule], 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 DRAFT  12/ 2/ 04 49 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

categoryspecific 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 DRAFT  12/ 2/ 04 50 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 [ Insert the date of publication of the final Clean Air Interstate Rule], 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 DRAFT  12/ 2/ 04 51 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. DRAFT  12/ 2/ 04 52 ( 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 DRAFT  12/ 2/ 04 53 ( 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 DRAFT  12/ 2/ 04 54 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);

( 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 DRAFT  12/ 2/ 04 55 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. DRAFT  12/ 2/ 04 56 ( 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) 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) 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).

( 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)( ii) of this section, then such emissions trading program is not automatically approved as set forth in paragraph ( o)( 1) or ( 2) of DRAFT  12/ 2/ 04 57 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 DRAFT  12/ 2/ 04 58 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 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.

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.

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. DRAFT  12/ 2/ 04 59 Boiler means an enclosed fossil or other fuel fired combustion device used to produce heat and to transfer heat to recirculating water, steam, or other medium.

Bottoming cycle cogeneration unit means a cogeneration unit in which the energy input to the unit is first used to produce useful thermal energy and at least some of the reject heat from the useful thermal energy application or process is then used for electricity production.

Clean Air Act or CAA means the Clean Air Act, 42 U. S. C.

7401, et seq.

Cogeneration unit means a stationary, fossil fuel fired boiler or stationary, fossil fuel fired combustion turbine:

( 1) Having equipment used to produce electricity and useful thermal energy for industrial, commercial, heating, or cooling purposes through the sequential use of energy; and ( 2) Producing during the 12 month period starting on the date the unit first produces electricity and during any calendar year after which the unit first produces electricity   ( i) For a topping cycle cogeneration unit,

( A) Useful thermal energy not less than 5 percent of total energy output; and ( B) Useful power that, when added to one half of useful thermal energy produced, is not less then 42.5 percent of total energy input or, if useful thermal energy produced is less than 15 percent of total energy output, not less than 45 percent of DRAFT  12/ 2/ 04 60 total energy input.

( ii) For a bottoming cycle cogeneration unit, useful power not less than 45 percent of total energy input.

Combustion turbine means:

( 1) An enclosed device comprising a compressor, a combustor,

and a turbine and in which the flue gas resulting from the combustion of fuel in the combustor passes through the turbine,

rotating the turbine; and ( 2) If the enclosed device under paragraph ( 1) of this definition is combined cycle, any associated heat recovery steam generator and steam turbine.

Commence operation means to have begun any mechanical,

chemical, or electronic process, including, with regard to a unit, start up of a unit's combustion chamber.

Electric generating unit or EGU means:

( 1) Except as provided in paragraph ( 2) of this definition,

a stationary, fossil fuel fired boiler or stationary,

fossilfuel fired combustion turbine serving at any time, since the start up of a unit's combustion chamber, a generator with nameplate capacity of more than 25 MWe producing electricity for sale.

( 2) For a unit that qualifies as a cogeneration unit during the 12 month period starting on the date the unit first produces electricity and continues to qualify as a cogeneration unit, a cogeneration unit serving at any time a generator with nameplate DRAFT  12/ 2/ 04 61 capacity of more than 25 MWe and supplying in any calendar year more than one third of the unit's potential electric output capacity or 219,000 MWh, whichever is greater, to any utility power distribution system for sale. If a unit that qualifies as a cogeneration unit during the 12 month period starting on the date the unit first produces electricity but subsequently no longer qualifies as a cogeneration unit, the unit shall be subject to paragraph ( 1) of this definition starting on the day on which the unit first no longer qualifies as a cogeneration unit.

Fossil fuel means natural gas, petroleum, coal, or any form of solid, liquid, or gaseous fuel derived from such material.

Fossil fuel fired means, with regard to a unit, combusting any amount of fossil fuel in any calendar year.

Generator means a device that produces electricity.

Maximum design heat input means the maximum amount of fuel per hour ( in Btu/ hr) that a unit is capable of combusting on a steady state basis:

( A) As specified by the manufacturer of the unit as of the initial installation of the unit;

( B) If the unit subsequently undergoes a physical change resulting in an increase in such maximum design heat input, as specified by the person conducting the physical change; or ( C) For purposes of applying the definition of the term " potential electrical output capacity" and if the unit DRAFT  12/ 2/ 04 62 subsequently undergoes a physical change resulting in a decrease in such maximum design heat input, as specified by the person conducting the physical change.

NAAQS means National Ambient Qir Quality Standard.

Nameplate capacity means the maximum electrical generating output ( in MWe) that a generator is capable of producing on a steady state basis and during continuous operation ( when not restricted by seasonal or other deratings), as specified by the manufacturer of the generator as of the initial installation of the generator or, if the generator subsequently undergoes a physical change resulting in an increase in such maximum electrical generating output, 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 mmBtu/ kWh,

divided by 1,000 kWh/ MWh, and multiplied by 8,760 hr/ yr.

Sequential use of energy means:

( 1) For a topping cycle cogeneration unit, the use of reject heat from electricity production in a useful thermal energy application or process; or ( 2) For a bottoming cycle cogeneration unit, the use of reject heat from useful thermal energy application or process in electricity production.

Topping cycle cogeneration unit means a cogeneration unit in DRAFT  12/ 2/ 04 63 which the energy input to the unit is first used to produce useful power, including electricity, and at least some of the reject heat from the electricity production is then used to provide useful thermal energy.

Total energy input means, with regard to a cogeneration unit, total energy of all forms supplied to the cogeneration unit, excluding energy produced by the cogeneration unit itself.

Total energy output means, with regard to a cogeneration unit, the sum of useful power and useful thermal energy produced by the cogeneration unit.

Unit means a stationary, fossil fuel fired boiler or a stationary, fossil fuel fired combustion turbine .

Useful power means, with regard to a cogeneration unit,

electricity or mechanical energy made available for use,

excluding any such energy used in the power production process ( which process includes, but is not limited to, any on site processing or treatment of fuel combusted at the unit and any onsite emission controls).

Useful thermal energy means, with regard to a cogeneration unit, thermal energy that is:

( 1) Made available to an industrial or commercial process,

excluding any heat contained in condensate return or makeup water;

( 2) Used in a heat application ( e. g., space heating or domestic hot water heating); or DRAFT  12/ 2/ 04 64 ( 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.


[Federal Register: May 8, 2007 (Volume 72, Number 88)]
[Proposed Rules]
[Page 26069]
[DOCID:fr08my07-34]

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ENVIRONMENTAL PROTECTION AGENCY

40 CFR Part 62

[EPA-R07-OAR-2007-0258; FRL-8310-7]

Approval and Promulgation of State Plans for Designated
Facilities and Pollutants; States of Iowa, Kansas, and Missouri

AGENCY: Environmental Protection Agency (EPA).

ACTION: Proposed rule.

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SUMMARY: EPA proposes to approve the Other Solid Waste Incineration
(OSWI) section 111(d) negative declarations submitted by the states of
Iowa, Kansas, and Missouri. These negative declarations certify that
OSWI units subject to the requirements of sections 111(d) and 129 of
the Clean Air Act (CAA) do not exist in these states.

DATES: Comments on this proposed action must be received in writing by
June 7, 2007.

ADDRESSES: Submit your comments, identified by Docket ID No. EPA-R07-
OAR-2007-0258 by one of the following methods:
    1. http://www.regulations.gov: Follow the on-line instructions for

submitting comments.
    2. E-mail<EMAIL_ADDRESS>    3. Mail: Heather Hamilton, Environmental Protection Agency, Air
Planning and Development Branch, 901 North 5th Street, Kansas City,
Kansas 66101.
    4. Hand Delivery or Courier: Deliver your comments to: Heather
Hamilton, Environmental Protection Agency, Air Planning and Development
Branch, 901 North 5th Street, Kansas City, Kansas 66101. Such
deliveries are only accepted during the Regional Office's normal hours
of operation. The Regional Office's official hours of business are
Monday through Friday, 8 to 4:30, excluding legal holidays.
    Please see the direct final rule which is located in the Rules
section of this Federal Register for detailed instructions on how to
submit comments.

FOR FURTHER INFORMATION CONTACT: Heather Hamilton at<PHONE_NUMBER>, or
by e-mail at<EMAIL_ADDRESS>
SUPPLEMENTARY INFORMATION: In the final rules section of the Federal
Register, EPA is approving the states' submittals as a direct final
rule without prior proposal because the Agency views this as a
noncontroversial action and anticipates no relevant adverse comments to
this action. A detailed rationale for the approval is set forth in the
direct final rule. If no relevant adverse comments are received in
response to this action, no further activity is contemplated in
relation to this action. If EPA receives relevant adverse comments, the
direct final rule will be withdrawn and all public comments received
will be addressed in a subsequent final rule based on this proposed
action. EPA will not institute a second comment period on this action.
Any parties interested in commenting on this action should do so at
this time. Please note that if EPA receives adverse comment on part of
this rule and if that part can be severed from the remainder of the
rule, EPA may adopt as final those parts of the rule that are not the
subject of an adverse comment. For additional information, see the
direct final rule which is located in the rules section of this Federal
Register.

    Dated: April 30, 2007.
John B. Askew,
Regional Administrator, Region 7.
 [FR Doc. E7-8798 Filed 5-7-07; 8:45 am]

BILLING CODE 6560-50-P


[Federal Register Volume 84, Number 242 (Tuesday, December 17, 2019)]
[Notices]
[Pages 68927-68928]
[FR Doc No: 2019-27149]

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DEPARTMENT OF ENERGY

Federal Energy Regulatory Commission

[Docket No. RM98-1-000]

Records Governing Off-the-Record Communications; Public Notice

    This constitutes notice, in accordance with 18 CFR 385.2201(b), of
the receipt of prohibited and exempt off-the-record communications.
    Order No. 607 (64 FR 51222, September 22, 1999) requires Commission
decisional employees, who make or receive a prohibited or exempt off-
the-record communication relevant to the merits of a contested
proceeding, to deliver to the Secretary of the Commission, a copy of
the communication, if written, or a summary of the substance of any
oral communication.
    Prohibited communications are included in a public, non-decisional
file associated with, but not a part of, the decisional record of the
proceeding. Unless the Commission determines that the prohibited
communication and any responses thereto should become a part of the
decisional record, the prohibited off-the-record communication will not
be considered by the Commission in reaching its decision. Parties to a
proceeding may seek the opportunity to respond to any facts or
contentions made in a prohibited off-the-record communication, and may
request that the Commission place the prohibited communication and
responses thereto in the decisional record. The Commission will grant
such a request only when it determines that fairness so requires. Any
person identified below as having made a prohibited off-the-record
communication shall serve the document on all parties listed on the
official service list for the applicable proceeding in accordance with
Rule 2010, 18 CFR 385.2010.

    Exempt off-the-record communications are included in the decisional
record of the proceeding, unless the communication was with a
cooperating agency as described by 40 CFR 1501.6, made under 18 CFR
385.2201(e)(1)(v).
    The following is a list of off-the-record communications recently
received by the Secretary of the Commission. The communications listed
are grouped by docket numbers in ascending order. These filings are
available for electronic review at the Commission in the Public
Reference Room or may be viewed on the Commission's website at http://www.ferc.gov using the eLibrary link. Enter the docket number,
excluding the last three digits, in the docket number field to access
the document. For assistance, please contact FERC Online Support at
<EMAIL_ADDRESS>or toll free at<PHONE_NUMBER>, or for TTY,
contact<PHONE_NUMBER>.
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    \1\ Authorized Represenative Elizabeth Moulds, Jennifer Mathian,
Olivia, Lana, Priya Howell, Katherine Rogers, Michael Mullaley,
Heather Kaas, Katie McBride, Janice DeYoung, A. Silvia Fabrizio, and
Kathleen Cronin.
    \2\ U.S. Senator James E. Risch, U.S. Senator Patty Murray, U.S.
Senator Mike Crapo, U.S. Senator Ron Wyden, U.S. Senator Jeffrey A.
Merkley.

----------------------------------------------------------------------------------------------------------------
             Docket No.                  File date                       Presenter or requester
----------------------------------------------------------------------------------------------------------------
                                                   Prohibited
----------------------------------------------------------------------------------------------------------------
CP16-9-000.........................         12-3-2019  Hingham 10 Persons Group.\1\
----------------------------------------------------------------------------------------------------------------
                                                     Exempt
----------------------------------------------------------------------------------------------------------------
CP16-22-000........................        11-25-2019  U.S. Senator Sherrod Brown.
ER19-2760-000......................         12-2-2019  U.S. Senate.\2\
EC19-120-000.......................         12-2-2019  U.S. Congresswoman Veronica Escobar.
----------------------------------------------------------------------------------------------------------------

    Dated: December 11, 2019.
Nathaniel J. Davis, Sr.,
Deputy Secretary.
[FR Doc. 2019-27149 Filed 12-16-19; 8:45 am]
 BILLING CODE 6717-01-P