II 

109TH CONGRESS 

1ST SESSION S. 131 

To amend the Clean Air Act to reduce air pollution through expansion 

of cap and trade programs, to provide an alternative regulatory classification for units subject to the cap and trade program, and for other 

purposes. 

IN THE SENATE OF THE UNITED STATES 

JANUARY 24, 2005 

Mr. INHOFE (for himself and Mr. VOINOVICH) introduced the following bill; 

which was read twice and referred to the Committee on Environment and 

Public Works 

A BILL 

To amend the Clean Air Act to reduce air pollution through 

expansion of cap and trade programs, to provide an 

alternative regulatory classification for units subject to 

the cap and trade program, and for other purposes. 

1 Be it enacted by the Senate and House of Representa2 tives of the United States of America in Congress assembled, 

3 SECTION 1. SHORT TITLE; TABLE OF CONTENTS. 

4 (a) SHORT TITLE.—This Act may be cited as the 

5 ‘‘Clear Skies Act of 2005’’. 

6 (b) TABLE OF CONTENTS.—The table of contents of 

7 this Act is as follows: 
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Sec. 1. Short title; table of contents. 

Sec. 2. Emission reduction programs. 

‘‘TITLE IV—EMISSION REDUCTION PROGRAMS 

‘‘PART A—GENERAL PROVISIONS

‘‘Sec. 401. (Reserved) 

‘‘Sec. 402. Definitions. 

‘‘Sec. 403. Allowance system. 

‘‘Sec. 404. Permits and compliance plans. 

‘‘Sec. 405. Monitoring, reporting, and recordkeeping requirements. 

‘‘Sec. 406. Excess emissions penalty; general compliance with other provisions; enforcement. 

‘‘Sec. 407. Election for additional units. 

‘‘Sec. 408. Clean coal technology regulatory incentives. 

‘‘Sec. 409. Electricity reliability. 

‘‘PART B—SULFUR DIOXIDE EMISSION REDUCTIONS

‘‘SUBPART 1—ACID RAIN PROGRAM

‘‘Sec. 411. Definitions. 

‘‘Sec. 412. Allowance allocation. 

‘‘Sec. 413. Phase I sulfur dioxide requirements. 

‘‘Sec. 414. Phase II sulfur dioxide requirements. 

‘‘Sec. 415. Allowances for States with emissions rates at or below 0.80 lbs/

mmBtu. 

‘‘Sec. 416. Election for additional sources. 

‘‘Sec. 417. Auctions, reserve. 

‘‘Sec. 418. Industrial sulfur dioxide emissions. 

‘‘Sec. 419. Termination. 

‘‘SUBPART 2—CLEAR SKIES SULFUR DIOXIDE ALLOWANCE PROGRAM

‘‘Sec. 421. Definitions. 

‘‘Sec. 422. Applicability. 

‘‘Sec. 423. Limitations on total emissions. 

‘‘Sec. 424. Egu allocations. 

‘‘Sec. 425. Disposition of sulfur dioxide allowances allocated under subpart 

1. 

‘‘Sec. 426. Incentives for sulfur dioxide emission control technology. 

‘‘SUBPART 3—WESTERN REGIONAL AIR PARTNERSHIP

‘‘Sec. 431. Definitions. 

‘‘Sec. 432. Applicability. 

‘‘Sec. 433. Limitations on total emissions. 

‘‘Sec. 434. EGU allocations. 

‘‘PART C—NITROGEN OXIDES CLEAR SKIES EMISSION REDUCTIONS

‘‘SUBPART 1—ACID RAIN PROGRAM

‘‘Sec. 441. Nitrogen oxides emission reduction program. 

‘‘Sec. 442. Termination. 
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‘‘SUBPART 2—CLEAR SKIES NITROGEN OXIDES ALLOWANCE PROGRAM

‘‘Sec. 451. Definitions. 

‘‘Sec. 452. Applicability. 

‘‘Sec. 453. Limitations on total emissions. 

‘‘Sec. 454. EGU allocations. 

‘‘Sec. 455. Nitrogen oxides early action reduction credits. 

‘‘SUBPART 3—OZONE SEASON NOx BUDGET PROGRAM

‘‘Sec. 461. Definitions. 

‘‘Sec. 462. General provisions. 

‘‘Sec. 463. Applicable implementation plan. 

‘‘Sec. 464. Termination of Federal administration of NOx trading program 

for EGUs. 

‘‘Sec. 465. Carryforward of pre-2008 nitrogen oxides allowances. 

‘‘Sec. 466. Non-ozone season voluntary action credits. 

‘‘PART D—MERCURY EMISSIONS REDUCTIONS

‘‘Sec. 471. Definitions. 

‘‘Sec. 472. Applicability. 

‘‘Sec. 473. Limitations on total emissions. 

‘‘Sec. 474. EGU allocations. 

‘‘Sec. 475. Mercury early action reduction credits. 

‘‘PART E—NATIONAL EMISSION STANDARDS; RESEARCH, ENVIRONMENTAL

ACCOUNTABILITY; MAJOR SOURCE PRECONSTRUCTION REVIEW AND BEST

AVAILABLE RETROFIT CONTROL TECHNOLOGY REQUIREMENTS

‘‘Sec. 481. National emission standards for affected units. 

‘‘Sec. 482. Research, environmental monitoring, and assessment. 

‘‘Sec. 483. Major source preconstruction review requirements and best 

available retrofit control technology requirements; applicability to affected units. 

Sec. 3. Other amendments.

1 SEC. 2. EMISSION REDUCTION PROGRAMS. 

2 Title IV of the Clean Air Act (relating to acid deposi3 tion control) (42 U.S.C. 7651, et seq.) is amended to read 

4 as follows: 
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1 ‘‘TITLE IV—EMISSION 

2 REDUCTION PROGRAMS 

3 ‘‘PART A—GENERAL PROVISIONS 

4 ‘‘SEC. 401. (Reserved) 

5 ‘‘SEC. 402. DEFINITIONS. 

6 ‘‘In this title: 

7 ‘‘(1) AFFECTED EGU.—The term ‘affected 

8 EGU’ shall have the meaning set forth in section 

9 421, 430, 451, or 471, as appropriate. 

10 ‘‘(2) AFFECTED FACILITY.—The term ‘affected 

11 facility’ or ‘affected source’ means a facility or 

12 source that includes one or more affected units. 

13 ‘‘(3) AFFECTED UNIT.—The term ‘affected 

14 unit’ means— 

15 ‘‘(A) under this part, a unit that is subject 

16 to emission reduction requirements or limita17 tions under part B, C, or D or, if applicable, 

18 under a specified part or subpart; or 

19 ‘‘(B) under subpart 1 of part B or subpart 

20 1 of part C, a unit that is subject to emission 

21 reduction requirements or limitations under 

22 that subpart. 

23 ‘‘(4) ALLOWANCE.—The term ‘allowance’ 

24 means— 
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1 ‘‘(A) an authorization, by the Adminis2 trator under this title, to emit one ton of sulfur 

3 dioxide, one ton of nitrogen oxides, or one 

4 ounce of mercury; or 

5 ‘‘(B) under subpart 1 of part B, an au6 thorization by the Administrator under this 

7 title, to emit one ton of sulfur dioxide. 

8 ‘‘(5) BASELINE HEAT INPUT.— 

9 ‘‘(A) IN GENERAL.—The term ‘baseline 

10 heat input’ means, except under subpart 1 of 

11 part B and section 407, the average annual 

12 heat input used by a unit during the three 

13 years in which the unit had the highest heat 

14 input for the period 1998 through 2002. 

15 ‘‘(B) COMMENCEMENT OF OPERATION AFTER

16 JANUARY 1, 2001.—Notwithstanding subparagraph 

17 (A), if a unit commenced or commences operation 

18 after January 1, 2001, then ‘baseline heat input’ 

19 means the manufacturer’s design heat input capacity 

20 for the unit multiplied by 80 percent for coal-fired 

21 units, 50 percent for boilers that are not coal-fired, 

22 80 percent for combustion turbine cogeneration 

23 units elected under section 407, 50 percent for com24 bustion turbines other than simple cycle turbines, 

25 and 5 percent for simple cycle combustion turbines. 
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1 ‘‘(C) HEAT INPUT DETERMINATION.—A unit’s 

2 heat input for a year shall be the heat input— 

3 ‘‘(i) required to be reported under section 

4 405 for the unit, if the unit was required to re5 port heat input during the year under that sec6 tion; 

7 ‘‘(ii) reported to the Energy Information 

8 Administration for the unit, if the unit was not 

9 required to report heat input under section 405; 

10 ‘‘(iii) based on data for the unit reported 

11 to the State where the unit is located as re12 quired by State law, if the unit was not re13 quired to report heat input during the year 

14 under section 405 and did not report to the En15 ergy Information Administration; or 

16 ‘‘(iv) based on fuel use and fuel heat con17 tent data for the unit from fuel purchase or use 

18 records, if the unit was not required to report 

19 heat input during the year under section 405 

20 and did not report to the Energy Information 

21 Administration and the State. 

22 ‘‘(D) REGULATIONS.—Not later than three 

23 months after the enactment of the Clear Skies Act 

24 of 2005, the Administrator shall promulgate regula25 tions, without notice and opportunity for comment, 
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1 specifying the format in which the information under 

2 subparagraphs (B)(ii) and (C)(ii), (iii), or (iv) shall 

3 be submitted. Not later than nine months after the 

4 enactment of the Clear Skies Act of 2005, the owner 

5 or operator of any unit under subparagraph (B)(ii) 

6 or (C)(ii), (iii), or (iv) to which allowances may be 

7 allocated under section 424, 434, 454, or 474 shall 

8 submit to the Administrator such information. The 

9 Administrator is not required to allocate allowances 

10 under such sections to a unit for which the owner 

11 or operator fails to submit information in accordance 

12 with the regulations promulgated under this sub13 paragraph. 

14 ‘‘(6) COAL.—The term ‘coal’ means any solid 

15 fuel classified as anthracite, bituminous, subbitu16 minous, or lignite. 

17 ‘‘(7) COAL-DERIVED FUEL.—The term ‘coal-de18 rived fuel’ means any fuel (whether in a solid, liquid, 

19 or gaseous state) produced by the mechanical, ther20 mal, or chemical processing of coal. 

21 ‘‘(8) COAL-FIRED.—The term ‘coal-fired’ with 

22 regard to a unit means, except under subpart 1 of 

23 part B, subpart 1 of part C, and sections 424 and 

24 434, combusting coal or any coal-derived fuel alone 
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1 or in combination with any amount of any other fuel 

2 in any year. 

3 ‘‘(9) COGENERATION UNIT.—The term ‘cogen4 eration unit’ means, except under subpart 1 of part 

5 B and subpart 1 of part C, a unit that produces 

6 through the sequential use of energy— 

7 ‘‘(A) electricity; and 

8 ‘‘(B) useful thermal energy (such as heat 

9 or steam) for industrial, commercial, heating, or 

10 cooling purposes. 

11 ‘‘(10) COMBUSTION TURBINE.— 

12 ‘‘(A) IN GENERAL.—The term ‘combustion 

13 turbine’ means any combustion turbine that is 

14 not self-propelled. 

15 ‘‘(B) INCLUSION.—The term ‘combustion 

16 turbine’ includes a simple cycle combustion tur17 bine, a combined cycle combustion turbine and 

18 any duct burner or heat recovery device used to 

19 extract heat from the combustion turbine ex20 haust, and a regenerative combustion turbine. 

21 ‘‘(C) EXCLUSIONS.—The term ‘combustion 

22 turbine’ does not include a combined turbine in 

23 an integrated gasification combined cycle plant. 

24 ‘‘(11) COMMENCE COMMERCIAL OPERATION.— 

25 The term ‘commence commercial operation’ with re-
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1 gard to a unit means the start up of the unit’s com2 bustion chamber and the commencement of the gen3 eration of electricity for sale. 

4 ‘‘(12) COMPLIANCE PLAN.—The term ‘compli5 ance plan’ means either— 

6 ‘‘(A) a statement that the facility will com7 ply with all applicable requirements under this 

8 title; or 

9 ‘‘(B) under subpart 1 of part B or subpart 

10 1 of part C, where applicable, a schedule and 

11 description of the method or methods for com12 pliance and certification by the owner or oper13 ator that the facility is in compliance with the 

14 requirements of that subpart. 

15 ‘‘(13) CONTINUOUS EMISSION MONITORING SYS16 TEM.—The term ‘continuous emission monitoring 

17 system’ (CEMS) means the equipment as required 

18 by section 405, used to sample, analyze, measure, 

19 and provide on a continuous basis a permanent 

20 record of emissions and flow (expressed in pounds 

21 per million British thermal units (lbs/mmBtu), 

22 pounds per hour (lbs/hr) or such other form as the 

23 Administrator may prescribe by regulations under 

24 section 405. 
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1 ‘‘(14) DESIGNATED REPRESENTATIVE.—The 

2 term ‘designated representative’ means a responsible 

3 person or official authorized by the owner or oper4 ator of a unit and the facility that includes the unit 

5 to represent the owner or operator in matters per6 taining to the holding, transfer, or disposition of al7 lowances, and the submission of and compliance with 

8 permits, permit applications, and compliance plans. 

9 ‘‘(15) DUCT BURNER.—The term ‘duct burner’ 

10 means a combustion device that uses the exhaust 

11 from a combustion turbine to burn fuel for heat re12 covery. 

13 ‘‘(16) FACILITY.—The term ‘facility’ means all 

14 buildings, structures, or installations located on 1 or 

15 more contiguous or adjacent properties under com16 mon control of the same person or persons. 

17 ‘‘(17) FOSSIL FUEL.—The term ‘fossil fuel’ 

18 means natural gas, petroleum, coal, or any form of 

19 solid, liquid, or gaseous fuel derived from such mate20 rial. 

21 ‘‘(18) FOSSIL FUEL-FIRED.—The term ‘fossil 

22 fuel-fired’, with regard to a unit, means the combus23 tion of fuel that is composed of at least 10 percent 

24 fossil fuel. 
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1 ‘‘(19) FUEL OIL.—The term ‘fuel oil’ means a 

2 petroleum-based fuel, including diesel fuel or petro3 leum derivatives. 

4 ‘‘(20) GAS-FIRED.—The term ‘gas-fired’, with 

5 regard to a unit, means, except under subpart 1 of 

6 part B and subpart 1 of part C, combusting only 

7 natural gas or fuel oil, with natural gas comprising 

8 at least 90 percent, and fuel oil comprising no more 

9 than 10 percent, of the unit’s total heat input in any 

10 year. 

11 ‘‘(21) GASIFY.—The term ‘gasify’ means to 

12 convert carbon-containing material into a gas con13 sisting primarily of carbon monoxide and hydrogen. 

14 ‘‘(22) GENERATOR.—The term ‘generator’ 

15 means a device that produces electricity and, under 

16 subpart 1 of part B and subpart 1 of part C, that 

17 is reported as a generating unit pursuant to Depart18 ment of Energy Form 860. 

19 ‘‘(23) HEAT INPUT.— 

20 ‘‘(A) IN GENERAL.—The term ‘heat input’, 

21 with regard to a specific period of time, means 

22 the product (in mmBtu/time) obtained by multi23 plying— 

24 ‘‘(i) the gross calorific value of the 

25 fuel (in mmBtu/lb); and 
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1 ‘‘(ii) the fuel feed rate into a unit (in 

2 lb of fuel/time). 

3 ‘‘(B) EXCLUSIONS.—The term ‘heat input’ 

4 does not include the heat derived from 

5 preheated combustion air, recirculated flue 

6 gases, or exhaust. 

7 ‘‘(24) INTEGRATED GASIFICATION COMBINED

8 CYCLE PLANT.—The term ‘integrated gasification 

9 combined cycle plant’ means any combination of 

10 equipment used to gasify fossil fuels (with or with11 out other material) and then burn the gas in a com12 bined cycle combustion turbine. 

13 ‘‘(25) OIL-FIRED.—The term ‘oil-fired’, with re14 gard to a unit, means, except under sections 424 

15 and 434, combusting fuel oil for more than 10 per16 cent the unit’s total heat input, and combusting no 

17 coal or coal-derived fuel, in any year. 

18 ‘‘(26) OWNER OR OPERATOR.—The term ‘owner 

19 or operator’ with regard to a unit or facility means, 

20 except for subpart 1 of part B and subpart 1 of part 

21 C, any person who owns, leases, operates, controls, 

22 or supervises the unit or the facility. 

23 ‘‘(27) PERMITTING AUTHORITY.—The term 

24 ‘permitting authority’ means the Administrator, or 

25 the State or local air pollution control agency, with 
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1 an approved permitting program under title V of the 

2 Act. 

3 ‘‘(28) POTENTIAL ELECTRICAL OUTPUT.—The 

4 term ‘potential electrical output’ with regard to a 

5 generator means the nameplate capacity of the gen6 erator multiplied by 8,760 hours. 

7 ‘‘(29) SIMPLE CYCLE COMBUSTION TURBINE.— 

8 The term ‘simple cycle combustion turbine’ means a 

9 combustion turbine that does not extract heat from 

10 the combustion turbine exhaust gases. 

11 ‘‘(30) STATIONARY SOURCE.—The term ‘sta12 tionary source’ means any building, structure, facil13 ity, or installation located on one or more contiguous 

14 or adjacent properties under common control or 

15 ownership of the same person or persons which 

16 emits or may emit any air pollutant subject to regu17 lations under the Clear Skies Act of 2005. 

18 ‘‘(31) STATE.—The term ‘State’ means— 

19 ‘‘(A) 1 of the 48 contiguous States, Alas20 ka, Hawaii, the District of Columbia, the Com21 monwealth of Puerto Rico, the Virgin Islands, 

22 Guam, American Samoa, or the Commonwealth 

23 of the Northern Mariana Islands; or 
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1 ‘‘(B) under subpart 1 of part B and sub2 part 1 of part C, 1 of the 48 contiguous States 

3 or the District of Columbia. 

4 ‘‘(32) UNIT.—The term ‘unit’ means— 

5 ‘‘(A) a fossil fuel-fired boiler, combustion 

6 turbine, or integrated gasification combined 

7 cycle plant; 

8 ‘‘(B) under subpart 1 of part B and sub9 part 1 of part C, a fossil fuel-fired combustion 

10 device; and 

11 ‘‘(C) a stationary source that— 

12 ‘‘(i) emits nitrogen oxides, sulfur diox13 ide, mercury, or any combination of those 

14 substances; and 

15 ‘‘(ii) is elected under section 407. 

16 ‘‘(33) UTILITY UNIT.—The term ‘utility unit’ 

17 shall have the meaning set forth in section 411. 

18 ‘‘(34) YEAR.—The term ‘year’ means a cal19 endar year. 

20 ‘‘SEC. 403. ALLOWANCE SYSTEM. 

21 ‘‘(a) ALLOCATIONS.— 

22 ‘‘(1) IN GENERAL.—For the emission limitation 

23 programs under this title, the Administrator shall al24 locate annual allowances for an affected unit, to be 

25 held or distributed by the designated representative 
15 

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1 of the owner or operator in accordance with this title 

2 as follows— 

3 ‘‘(A) sulfur dioxide allowances in an 

4 amount equal to the annual tonnage emission 

5 limitation calculated under section 413, 414, 

6 415, or 416, except as otherwise specifically 

7 provided elsewhere in subpart 1 of part B, or 

8 in an amount calculated under section 424 or 

9 434; 

10 ‘‘(B) nitrogen oxides allowances in an 

11 amount calculated under section 454; and 

12 ‘‘(C) mercury allowances in an amount cal13 culated under section 474. 

14 ‘‘(2) NO JUDICIAL REVIEW.—Notwithstanding 

15 any other provision of law to the contrary, the cal16 culation of the allocation for any unit or facility, and 

17 the determination of any values used in such calcula18 tion, under sections 424, 434, 454, and 474 shall 

19 not be subject to judicial review. 

20 ‘‘(3) ALLOCATION WITHOUT COST.—Allowances 

21 shall be allocated by the Administrator without cost 

22 to the recipient, in accordance with this title. 

23 ‘‘(b) ALLOWANCE TRANSFER SYSTEM.—Allowances 

24 allocated or sold by the Administrator under this title may 

25 be transferred among designated representatives of the 
16 

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1 owners or operators of affected facilities under this title 

2 and any other person, as provided by the allowance system 

3 regulations promulgated by the Administrator. With re4 gard to sulfur dioxide allowances, the Administrator shall 

5 implement this subsection under 40 CFR part 73 (2002), 

6 amended as appropriate by the Administrator. With re7 gard to nitrogen oxides allowances and mercury allow8 ances, the Administrator shall implement this subsection 

9 by promulgating regulations not later than twenty-four 

10 months after the date of enactment of the Clear Skies Act 

11 of 2005. The regulations under this subsection shall estab12 lish the allowance system prescribed under this section, 

13 including, but not limited to, requirements for the alloca14 tion, transfer, and use of allowances under this title. Such 

15 regulations shall prohibit the use of any allowance prior 

16 to the calendar year for which the allowance was allocated 

17 and shall provide, consistent with the purposes of this 

18 title, for the identification of unused allowances, and for 

19 such unused allowances to be carried forward and added 

20 to allowances allocated in subsequent years. Such regula21 tions shall provide, or shall be amended to provide, that 

22 transfers of allowances shall not be effective until certifi23 cation of the transfer, signed by a responsible official of 

24 the transferor, is received and recorded by the Adminis25 trator. 
17 

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1 ‘‘(c) ALLOWANCE TRACKING SYSTEM.—The Admin2 istrator shall promulgate regulations establishing a system 

3 for issuing, recording, and tracking allowances, which 

4 shall specify all necessary procedures and requirements for 

5 an orderly and competitive functioning of the allowance 

6 system. Such system shall provide, by twenty-four months 

7 prior to the compliance year, for one or more facility-wide 

8 accounts for holding sulfur dioxide allowances, nitrogen 

9 oxides allowances, and, if applicable, mercury allowances 

10 for all affected units at an affected facility. With regard 

11 to sulfur dioxide allowances, the Administrator shall im12 plement this subsection under 40 CFR part 73 (2002), 

13 amended as appropriate by the Administrator. With re14 gard to nitrogen oxides allowances and mercury allow15 ances, the Administrator shall implement this subsection 

16 by promulgating regulations not later than twenty-four 

17 months after the date of enactment of the Clear Skies Act 

18 of 2005. All allowance allocations and transfers shall, 

19 upon recording by the Administrator, be deemed a part 

20 of each unit’s or facility’s permit requirements pursuant 

21 to section 404, without any further permit review and revi22 sion. 

23 ‘‘(d) NATURE OF ALLOWANCES.—A sulfur dioxide al24 lowance, nitrogen oxides allowance, or mercury allowance 

25 allocated or sold by the Administrator under this title is 
18 

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1 a limited authorization to emit one ton of sulfur dioxide, 

2 one ton of nitrogen oxides, or one ounce of mercury, as 

3 the case may be, in accordance with the provisions of this 

4 title. Such allowance does not constitute a property right. 

5 Nothing in this title or in any other provision of law shall 

6 be construed to limit the authority of the United States 

7 to terminate or limit such authorization. Nothing in this 

8 section relating to allowances shall be construed as affect9 ing the application of, or compliance with, any other provi10 sion of this Act to an affected unit or facility, including 

11 the provisions related to applicable National Ambient Air 

12 Quality Standards and State implementation plans. Noth13 ing in this section shall be construed as requiring a change 

14 of any kind in any State law regulating electric utility 

15 rates and charges or affecting any State law regarding 

16 such State regulation or as limiting State regulation (in17 cluding any prudency review) under such a State law. 

18 Nothing in this section shall be construed as modifying 

19 the Federal Power Act or as affecting the authority of the 

20 Federal Energy Regulatory Commission under that Act. 

21 Nothing in this title shall be construed to interfere with 

22 or impair any program for competitive bidding for power 

23 supply in a State in which such program is established. 

24 Allowances, once allocated or sold to a person by the Ad25 ministrator, may be received, held, and temporarily or per-
19 

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1 manently transferred in accordance with this title and the 

2 regulations of the Administrator without regard to wheth3 er or not a permit is in effect under title V of the Clean 

4 Air Act or section 404 of the Clear Skies Act of 2005 

5 with respect to the unit for which such allowance was 

6 originally allocated and recorded. 

7 ‘‘(e) PROHIBITIONS.— 

8 ‘‘(1) IN GENERAL.—It shall be unlawful for any 

9 person to hold, use, or transfer any allowance allo10 cated or sold by the Administrator under this title, 

11 except in accordance with regulations promulgated 

12 by the Administrator. 

13 ‘‘(2) EMISSIONS.—It shall be unlawful for any 

14 affected unit or for the affected units at a facility 

15 to emit sulfur dioxide, nitrogen oxides, and mercury, 

16 as the case may be, during a year in excess of the 

17 number of allowances held for that unit or facility 

18 for that year by the designated representative as 

19 provided in sections 412(c), 422, 432, 452, and 472. 

20 ‘‘(3) PURCHASE OF ALLOWANCES.—The owner 

21 or operator of a facility may purchase allowances di22 rectly from the Administrator to be used only to 

23 meet the requirements of sections 422, 432, 452, 

24 and 472, as the case may be, for the year in which 

25 the purchase is made or the prior year. Not later 
20 

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1 than thirty-six months after the date of enactment 

2 of the Clear Skies Act of 2005, the Administrator 

3 shall promulgate regulations providing for direct 

4 sales of sulfur dioxide allowances, nitrogen oxides al5 lowances, and mercury allowances to an owner or 

6 operator of a facility. The regulations shall provide 

7 that— 

8 ‘‘(A) such allowances may be used only to 

9 meet the requirements of section 422, 432, 452, 

10 and 472, as the case may be, for such facility 

11 and for the year in which the purchase is made 

12 or the prior year; 

13 ‘‘(B) each such sulfur dioxide allowance 

14 shall be sold for $2,000, each such nitrogen ox15 ides allowance shall be sold for $4,000, and 

16 each such mercury allowance shall be sold for 

17 $2,187.50, with such prices adjusted for infla18 tion based on the Consumer Price Index on the 

19 date of enactment of the Clear Skies Act of 

20 2005 and annually thereafter; 

21 ‘‘(C) the proceeds from any sales of allow22 ances under subparagraph (B) shall be, in ac23 cordance with paragraph (j), deposited in the 

24 Compliance Assistance Account; 
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1 ‘‘(D) except for allowances subject to (E), 

2 the allowances directly purchased for use for 

3 the year specified in subparagraph (A) shall be, 

4 on a pro rata basis, taken from, and reduce, the 

5 amount of sulfur dioxide allowances, nitrogen 

6 oxides allowances, or mercury allowances, as the 

7 case may be, that would otherwise be allocated 

8 under section 423, 453, or 473 starting for the 

9 second year after the specified year and con10 tinuing for each subsequent year as necessary; 

11 and 

12 ‘‘(E) if the designated representative does 

13 not use any such allowance in accordance with 

14 paragraph (A) the designated representative 

15 shall hold the allowance for deduction by the 

16 Administrator. The Administrator shall deduct 

17 the allowance without refund or other form of 

18 recompense. 

19 ‘‘(4) USE OF ALLOWANCES.—Allowances may 

20 not be used prior to the calendar year for which they 

21 are allocated but may be used in succeeding years. 

22 Nothing in this section or in the allowance system 

23 regulations shall relieve the Administrator of the Ad24 ministrator’s permitting, monitoring and enforce25 ment obligations under this Act, nor relieve affected 
22 

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1 facilities of their requirements and liabilities under 

2 the Act. 

3 ‘‘(f) COMPETITIVE BIDDING FOR POWER SUPPLY.— 

4 Nothing in this title shall be construed to interfere with 

5 or impair any program for competitive bidding for power 

6 supply in a State in which such program is established. 

7 ‘‘(g) APPLICABILITY OF THE ANTITRUST LAWS.— 

8 ‘‘(1) IN GENERAL.—Nothing in this section af9 fects— 

10 ‘‘(A) the applicability of the antitrust laws 

11 to the transfer, use, or sale of allowances; or 

12 ‘‘(B) the authority of the Federal Energy 

13 Regulatory Commission under any provision of 

14 law respecting unfair methods of competition or 

15 anticompetitive acts or practices. 

16 ‘‘(2) DEFINITION OF ANTITRUST LAWS.—In 

17 this section, the term ‘antitrust laws’ means those 

18 Acts set forth in section 1 of the Clayton Act (15 

19 U.S.C. 12). 

20 ‘‘(h) PUBLIC UTILITY HOLDING COMPANY ACT.— 

21 The acquisition or disposition of allowances pursuant to 

22 this title including the issuance of securities or the under23 taking of any other financing transaction in connection 

24 with such allowances shall not be subject to the provisions 

25 of the Public Utility Holding Company Act of 1935. 
23 

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1 ‘‘(i) INTERPOLLUTANT TRADING.—Not later than 

2 July 1, 2009, the Administrator shall furnish to the Con3 gress a study evaluating the environmental and economic 

4 consequences of amending this title to permit trading sul5 fur dioxide allowances for nitrogen oxides allowances and 

6 nitrogen oxides allowances for sulfur dioxide allowances. 

7 ‘‘(j) COMPLIANCE ASSISTANCE ACCOUNT.—An ac8 count shall be established by the Secretary of Energy in 

9 consultation with the Administrator: 

10 ‘‘(1) USE OF AMOUNTS.—Payments or monies 

11 deposited in this account in accordance with this 

12 title shall be used for the purpose of developing 

13 emission control technologies through direct grants 

14 to affected units that demonstrate new control tech15 nologies regulated under this title. 

16 ‘‘(2) REGULATIONS.—The Secretary of Energy 

17 in consultation with the Administrator shall promul18 gate regulations with notice and opportunity for 

19 comment to establish criteria for affected units to 

20 qualify for this subsection. 

21 ‘‘SEC. 404. PERMITS AND COMPLIANCE PLANS. 

22 ‘‘(a) PERMIT PROGRAM.—The provisions of this title 

23 shall be implemented, subject to section 403, by permits 

24 issued to units and facilities subject to this title and en25 forced in accordance with the provisions of title V, as 
24 

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1 modified by this title. Any such permit issued by the Ad2 ministrator, or by a State with an approved permit pro3 gram, shall prohibit— 

4 ‘‘(1) annual emissions of sulfur dioxide, nitro5 gen oxides, and mercury in excess of the number of 

6 allowances required to be held in accordance with 

7 sections 412(c), 422, 432, 452, and 472; 

8 ‘‘(2) exceeding applicable emissions rates under 

9 section 441; 

10 ‘‘(3) the use of any allowance prior to the year 

11 for which it was allocated; and 

12 ‘‘(4) contravention of any other provision of the 

13 permit. 

14 No permit shall be issued that is inconsistent with the re15 quirements of this title, and title V as applicable. 

16 ‘‘(b) COMPLIANCE PLAN.— 

17 ‘‘(1) IN GENERAL.—Each initial permit applica18 tion shall be accompanied by a compliance plan for 

19 the facility to comply with its requirements under 

20 this title. Where an affected facility consists of more 

21 than one affected unit, such plan shall cover all such 

22 units, and such facility shall be considered a ‘facility’ 

23 under section 502(c). Nothing in this section regard24 ing compliance plans or in title V shall be construed 

25 as affecting allowances. 
25 

•S 131 IS 

1 ‘‘(2) STATEMENTS.— 

2 ‘‘(A) IN GENERAL.—Submission of a state3 ment by the owner or operator, or the des4 ignated representative of the owners and opera5 tors, of a unit subject to the emissions limita6 tion requirements of sections 412(c), 413, 414, 

7 and 441, that the unit will meet the applicable 

8 emissions limitation requirements of such sec9 tions in a timely manner or that, in the case of 

10 the emissions limitation requirements of sec11 tions 412(c), 413, and 414, the owners and op12 erators will hold sulfur dioxide allowances in the 

13 amount required by section 412(c), shall be 

14 deemed to meet the proposed and approved 

15 compliance planning requirements of this sec16 tion and title V, except that, for any unit that 

17 will meet the requirements of this title by 

18 means of an alternative method of compliance 

19 authorized under section 413 (b), (c), (d), or 

20 (f), section 416, and section 441 (d) or (e), the 

21 proposed and approved compliance plan, permit 

22 application and permit shall include, pursuant 

23 to regulations promulgated by the Adminis24 trator, for each alternative method of compli25 ance a comprehensive description of the sched-
26 

•S 131 IS 

1 ule and means by which the unit will rely on 

2 one or more alternative methods of compliance 

3 in the manner and time authorized under sub4 part 1 of part B or subpart 1 of part C. 

5 ‘‘(B) OTHER STATEMENTS.—Submission 

6 of a statement by the owner or operator, or the 

7 designated representative, of a facility that in8 cludes a unit subject to the emissions limitation 

9 requirements of sections 422, 432, 452, and 

10 472 that the owner or operator will hold sulfur 

11 dioxide allowances, nitrogen oxide allowances, 

12 and mercury allowances, as the case may be, in 

13 the amount required by such sections shall be 

14 deemed to meet the proposed and approved 

15 compliance planning requirements of this sec16 tion and title V with regard to subparts A 

17 through D. 

18 ‘‘(3) RECORDING OF TRANSFERS.—Recording 

19 by the Administrator of transfers of allowances shall 

20 amend automatically, and will not reopen or require 

21 reopening of, any or all applicable proposed or ap22 proved permit applications, compliance plans, and 

23 permits. 

24 ‘‘(c) PERMITS.—The owner or operator of each facil25 ity under this title that includes an affected unit subject 
27 

•S 131 IS 

1 to title V shall submit a permit application and compliance 

2 plan with regard to the applicable requirements under sec3 tions 412(c), 422, 432, 441, 452, and 472 for sulfur diox4 ide emissions, nitrogen oxide emissions, and mercury emis5 sions from such unit to the permitting authority in accord6 ance with the deadline for submission of permit applica7 tions and compliance plans under title V. The permitting 

8 authority shall issue a permit to such owner or operator, 

9 or the designated representative of such owner or oper10 ator, that satisfies the requirements of title V and this 

11 title. 

12 ‘‘(d) AMENDMENT OF APPLICATION AND COMPLI13 ANCE PLAN.—At any time after the submission of an ap14 plication and compliance plan under this section, the ap15 plicant may submit a revised application and compliance 

16 plan, in accordance with the requirements of this section. 

17 ‘‘(e) PROHIBITION.— 

18 ‘‘(1) IN GENERAL.—It shall be unlawful for any 

19 person to operate any facility subject to this title ex20 cept in compliance with the terms and requirements 

21 of a permit application and compliance plan (includ22 ing amendments thereto) or permit issued by the 

23 Administrator or a State with an approved permit 

24 program. For purposes of this subsection, compli25 ance, as provided in section 504(f), with a permit 
28 

•S 131 IS 

1 issued under title V which complies with this title 

2 for facilities subject to this title shall be deemed 

3 compliance with this subsection as well as section 

4 502(a). 

5 ‘‘(2) NO TERMINATION OF OPERATIONS.—In 

6 order to ensure reliability of electric power, nothing 

7 in this title or title V shall be construed as requiring 

8 termination of operations of a unit serving a gener9 ator for failure to have an approved permit or com10 pliance plan under this section. 

11 ‘‘(f) CERTIFICATE OF REPRESENTATION.—No per12 mit shall be issued under this section to an affected unit 

13 or facility until the designated representative of the own14 ers or operators has filed a certificate of representation 

15 with regard to matters under this title, including the hold16 ing and distribution of allowances and the proceeds of 

17 transactions involving allowances. 

18 ‘‘(g) MULTIPLE OWNERS.— 

19 ‘‘(1) IN GENERAL.—No permit shall be issued 

20 under this section to an affected unit until the des21 ignated representative of the owners or operators 

22 has filed a certificate of representation with regard 

23 to matters under this title, including the holding and 

24 distribution of allowances and the proceeds of trans25 actions involving allowances. Where there are mul-
29 

•S 131 IS 

1 tiple holders of a legal or equitable title to, or a 

2 leasehold interest in, such a unit, or where a utility 

3 or industrial customer purchases power from an af4 fected unit (or units) under life-of-the-unit, firm 

5 power contractual arrangements, the certificate shall 

6 state— 

7 ‘‘(A) that allowances and the proceeds or 

8 transactions involving allowance will be deemed 

9 to be held or distributed in proportion to each 

10 holder’s legal, equitable, leasehold, or contrac11 tual reservation or entitlement, or 

12 ‘‘(B) if such multiple holders have ex13 pressly provided for a different distribution of 

14 allowances by contract, that allowances and the 

15 proceeds of transactions involving allowances 

16 will be deemed to be held or distributed in ac17 cordance with the contract. 

18 ‘‘(2) PASSIVE LESSOR.—A passive lessor, of a 

19 person who has an equitable interest through such 

20 lessor, whose rental payments are not based, either 

21 directly or indirectly, upon the revenues or income 

22 from the affected unit shall not be deemed to be a 

23 holder of a legal, equitable, leasehold, or contractual 

24 interest for the purposes of holding or distributing 

25 allowances as provided in this subsection, unless ex-
30 

•S 131 IS 

1 pressly provided for in the leasehold agreement. Ex2 cept as otherwise provided in this subsection, where 

3 all legal or equitable title to or interest in an af4 fected unit is held by a single person, the certifi5 cation shall state that all allowances received by the 

6 unit are deemed to be held for that person. 

7 ‘‘SEC. 405. MONITORING, REPORTING, AND RECORD8 KEEPING REQUIREMENTS. 

9 ‘‘(a) REQUIREMENTS.— 

10 ‘‘(1) APPLICABILITY.— 

11 ‘‘(A) IN GENERAL.—The owner and oper12 ator of any facility subject to this title shall be 

13 required to install and operate CEMS on each 

14 affected unit subject to subpart 1 of part B or 

15 subpart 1 of part C at the facility, and to qual16 ity assure the data, for sulfur dioxide, nitrogen 

17 oxides, opacity, and volumetric flow at each 

18 such unit. 

19 ‘‘(B) SPECIFICATION OF REQUIRE20 MENTS.—The Administrator shall, by regula21 tion, specify the requirements for CEMS under 

22 subparagraph (A), for any alternative moni23 toring system that is demonstrated as providing 

24 information with the same precision, reliability, 

25 accessibility, and time lines as that provided by 
31 

•S 131 IS 

1 CEMS, and for recordkeeping and reporting of 

2 information from such systems. Such regula3 tions may include limitations on the use of al4 ternative compliance methods by units equipped 

5 with an alternative monitoring system as may 

6 be necessary to preserve the orderly functioning 

7 of the allowance system, and which will ensure 

8 the emissions reductions contemplated by this 

9 title. Where 2 or more units utilize a single 

10 stack, a separate CEMS shall not be required 

11 for each unit, and for such units the regulations 

12 shall require that the owner or operator collect 

13 sufficient information to permit reliable compli14 ance determinations for each such unit. 

15 ‘‘(2) INSTALLATION AND OPERATION.— 

16 ‘‘(A) IN GENERAL.—The owner and oper17 ator of any facility subject to this title shall be 

18 required to install and operate CEMS to mon19 itor the emissions from each affected unit at 

20 the facility, and to quality assure the data for— 

21 ‘‘(i) sulfur dioxide, opacity, and volu22 metric flow for all affected units subject to 

23 subpart 2 of part B at the facility, 
32 

•S 131 IS 

1 ‘‘(ii) nitrogen oxides for all affected 

2 units subject to subpart 2 of part C at the 

3 facility, and 

4 ‘‘(iii) mercury for all affected units 

5 subject to part D at the facility. 

6 ‘‘(B) ALTERNATIVE MONITORING.— 

7 ‘‘(i) IN GENERAL.—The Administrator 

8 may specify an alternative monitoring or 

9 compliance system for determining mer10 cury emissions. In specifying such alter11 native monitoring or compliance systems, 

12 the lack of commercially available appro13 priate and reasonable vendor guarantees 

14 shall constitute a reasonable and permis15 sible basis for specifying alternative moni16 toring or compliance systems for mercury. 

17 ‘‘(ii) LIMITATIONS.—The regulations 

18 under clause (iv) may include limitations 

19 on the use of alternative compliance meth20 ods by units equipped with an alternative 

21 monitoring system as may be necessary to 

22 preserve the orderly functioning of the al23 lowance system, and which will ensure to a 

24 reasonable extent the emissions reductions 

25 contemplated by this title. 
33 

•S 131 IS 

1 ‘‘(iii) NO SEPARATE MONITORING SYS2 TEM.—The regulations under clause (iv) 

3 shall not require a separate CEMS or 

4 other monitoring system for each unit 

5 where two or more units utilize a single 

6 stack and shall require that the owner or 

7 operator collect sufficient information to 

8 permit reliable compliance determinations 

9 for such units. 

10 ‘‘(iv) SPECIFICATION OF REQUIRE11 MENTS.—The Administrator shall, by reg12 ulation, specify the requirements for 

13 CEMS under subparagraph (A), for any 

14 alternative monitoring or compliance sys15 tem that is demonstrated as providing in16 formation which is reasonably of the same 

17 precision, reliability, accessibility, and 

18 timeliness as that provided by CEMS, and 

19 for recordkeeping and reporting of infor20 mation from such systems. Such regula21 tions may include limitations on the use of 

22 alternative compliance methods by units 

23 equipped with an alternative monitoring 

24 system as may be necessary to preserve the 

25 orderly functioning of the allowance sys-
34 

•S 131 IS 

1 tem, and which will ensure to a reasonable 

2 extent the emissions reductions con3 templated by this title. Where two or more 

4 units utilize a single stack, a separate 

5 CEMS shall not be required for each unit, 

6 and for such units the regulations shall re7 quire that the owner or operator collect 

8 sufficient information to permit reliable 

9 compliance determinations for each such 

10 unit. 

11 ‘‘(b) DEADLINES.— 

12 ‘‘(1) NEW UTILITY UNITS.—Upon commence13 ment of commercial operation of each new utility 

14 unit under subpart I of part B, the unit shall comply 

15 with the requirements of subsection (a)(1). 

16 ‘‘(2) DEADLINE FOR AFFECTED UNITS UNDER

17 SUBPART 2 OF PART B FOR INSTALLATION AND OP18 ERATION OF CEMS.—By the later of the date that is 

19 1 year before the commencement date of the sulfur 

20 dioxide allowance requirement of section 422, or the 

21 date on which the unit commences operation, the 

22 owner or operator of each affected unit under sub23 part 2 of part B shall install and operate CEMS, 

24 quality assure the data, and keep records and re25 ports in accordance with the regulations issued 
35 

•S 131 IS 

1 under paragraph (a)(2) with regard to sulfur diox2 ide, opacity, and volumetric flow. 

3 ‘‘(3) DEADLINE FOR AFFECTED UNITS UNDER

4 SUBPART 3 OF PART B FOR INSTALLATION AND OP5 ERATION OF CEMS.—By the later of the date that is 

6 1 year before the first covered year, or the date on 

7 which the unit commences commercial operation, the 

8 owner or operator of each affected unit under sub9 part 3 of part B shall install and operate CEMS, 

10 quality assure the data, and keep records and re11 ports in accordance with the regulations issued 

12 under paragraph (a)(2) with regard to sulfur dioxide 

13 and volumetric flow. 

14 ‘‘(4) DEADLINE FOR AFFECTED UNITS UNDER

15 SUBPART 2 OF PART C FOR INSTALLATION AND OP16 ERATION OF CEMS.—By the later of the date that is 

17 1 year before the commencement date of the nitro18 gen oxides allowance requirement under section 452, 

19 or the date on which the unit commences operation, 

20 the owner or operator of each affected unit under 

21 subpart 2 of part C shall install and operate CEMS, 

22 quality assure the data, and keep records and re23 ports in accordance with the regulations issued 

24 under paragraph (a)(2) with regard to nitrogen ox25 ides. 
36 

•S 131 IS 

1 ‘‘(5) DEADLINE FOR AFFECTED UNITS UNDER

2 PART D FOR INSTALLATION AND OPERATION OF

3 CEMS.—By the later of the date that is 1 year be4 fore the commencement date of the mercury allow5 ance requirement of section 472 applies to such unit 

6 and commences commercial operation, or the date on 

7 which the unit commences operation, the owner or 

8 operator of each affected unit under part D shall in9 stall and operate CEMS, quality assure the data, 

10 and keep records and reports in accordance with the 

11 regulations issued under paragraph (a)(2) with re12 gard to mercury. 

13 ‘‘(c) UNAVAILABILITY OF EMISSIONS DATA.— 

14 ‘‘(1) SULFUR DIOXIDE AND NITROGEN OX15 IDES.—With respect to sulfur dioxide and nitrogen 

16 oxides, if CEMS data or data from an alternative 

17 monitoring system approved by the Administrator 

18 under subsection (a) is not available for any affected 

19 unit during any period of a calendar year in which 

20 such data is required under this title, and the owner 

21 or operator cannot provide information, reasonably 

22 satisfactory to the Administrator, on emissions dur23 ing that period, the Administrator, in coordination 

24 with the owner, shall calculate emissions for that pe25 riod pursuant to regulations promulgated for such 
37 

•S 131 IS 

1 purpose. The owner or operator shall be liable for 

2 excess emissions fees and offsets under section 406 

3 in accordance with such regulations. Any fee due 

4 and payable under this subsection shall not diminish 

5 the liability of the unit’s owner or operator for any 

6 fine, penalty, fee, or assessment against the unit for 

7 the same violation under any other section of this 

8 Act. 

9 ‘‘(2) MERCURY.—With respect to mercury, if 

10 CEMS data or data from an alternative monitoring 

11 system approved by the Administrator under sub12 section (a) is not available for any affected unit dur13 ing any period of a calendar year in which such data 

14 is required under this title, and the owner or oper15 ator cannot provide information, reasonably satisfac16 tory to the Administrator, on emissions during that 

17 period, the Administrator in coordination with the 

18 owner, shall calculate emissions for that period pur19 suant to regulations promulgated for such purpose. 

20 The owner or operator shall be liable for excess 

21 emissions fees and offsets under section 406 in ac22 cordance with such regulations. Any fee due and 

23 payable under this subsection shall not diminish the 

24 liability of the unit’s owner or operator for any fine, 
38 

•S 131 IS 

1 penalty, fee, or assessment against the unit for the 

2 same violation under any other section of this Act. 

3 ‘‘(d) IMPLEMENTATION.—With regard to sulfur diox4 ide, nitrogen oxides, opacity, and volumetric flow, the Ad5 ministrator shall implement subsections (a) and (c) under 

6 40 CFR part 75 (2002), amended, as appropriate by the 

7 Administrator. With regard to mercury, the Administrator 

8 shall implement subsections (a) and (c) by issuing pro9 posed regulations not later than 36 months before the 

10 commencement date of the mercury allowance requirement 

11 under section 472 and final regulations not later than 24 

12 months before that commencement date. 

13 ‘‘(e) PROHIBITION.—It shall be unlawful for the 

14 owner or operator of any facility subject to this title to 

15 operate a facility without complying with the requirements 

16 of this section, and any regulations implementing this sec17 tion. 

18 ‘‘SEC. 406. EXCESS EMISSIONS PENALTY; GENERAL COMPLI19 ANCE WITH OTHER PROVISIONS; ENFORCE20 MENT. 

21 ‘‘(a) EXCESS EMISSIONS PENALTY.— 

22 ‘‘(1) AMOUNT FOR OXIDES OF NITROGEN.—The 

23 owner or operator of any unit subject to the require24 ments of section 441 that emits nitrogen oxides for 

25 any calendar year in excess of the unit’s emissions 
39 

•S 131 IS 

1 limitation requirement shall be liable for the pay2 ment of an excess emissions penalty, except where 

3 such emissions were authorized pursuant to section 

4 110(f). That penalty shall be calculated on the basis 

5 of the number of tons emitted in excess of the unit’s 

6 emissions limitation requirement multiplied by 

7 $2,000. 

8 ‘‘(2) AMOUNT FOR SULFUR DIOXIDE BEFORE

9 2008.—The owner or operator of any unit subject to 

10 the requirements of section 412(c) that emits sulfur 

11 dioxide for any calendar year before 2008 in excess 

12 of the sulfur dioxide allowances the owner or oper13 ator holds for use for the unit for that calendar year 

14 shall be liable for the payment of an excess emis15 sions penalty, except where such emissions were au16 thorized pursuant to section 110(f) or (g). That pen17 alty shall be calculated as follows: 

18 ‘‘(A) The product of the unit’s excess emis19 sions (in tons) multiplied by $2,000, if within 

20 30 days after the date on which the owner or 

21 operator was required to hold sulfur dioxide al22 lowances— 

23 ‘‘(i) the owner or operator offsets the 

24 excess emissions in accordance with para25 graph (b)(1); and 
40 

•S 131 IS 

1 ‘‘(ii) the Administrator receives the 

2 penalty payment required under this sub3 paragraph. 

4 ‘‘(B) If the requirements of clause (A)(i) 

5 or (A)(ii) are not met, the product of the unit’s 

6 excess emissions (in tons) multiplied by $3,000. 

7 ‘‘(3) AMOUNT FOR SULFUR DIOXIDE AFTER

8 2007.—If the units at a facility that are subject to 

9 the requirements of section 412(c) emit sulfur diox10 ide for any calendar year after 2007 in excess of the 

11 sulfur dioxide allowances that the owner or operator 

12 of the facility holds for use for the facility for that 

13 calendar year, the owner or operator shall be liable 

14 for the payment of an excess emissions penalty, ex15 cept where such emissions were authorized pursuant 

16 to section 110(f). That penalty shall be calculated 

17 under paragraph (4)(A) or (4)(B). 

18 ‘‘(4) UNITS SUBJECT TO SECTIONS 422, 432, 452, 

19 OR 472.—If the units at a facility that are subject 

20 to the requirements of section 422, 432, 452, or 472 

21 emit sulfur dioxide, nitrogen oxides, or mercury for 

22 any calendar year in excess of the sulfur dioxide al23 lowances, nitrogen oxides allowances, or mercury al24 lowances, as the case may be, that the owner or op25 erator of the facility holds for use for the facility or 
41 

•S 131 IS 

1 units for that calendar year, the owner or operator 

2 shall be liable for the payment of an excess emis3 sions penalty, except where such emissions were au4 thorized pursuant to section 110(f). That penalty 

5 shall be equal to— 

6 ‘‘(A) the quantity of the units’ excess emis7 sions in tons (or, for mercury emissions, in 

8 ounces) multiplied by $2,000 (in the case of 

9 sulfur dioxide), $4,000 (in the case of nitrogen 

10 oxides), or $2187.50 (in the case of mercury) if, 

11 on or before the date that is 30 days after the 

12 date on which the owner or operator was re13 quired to hold sulfur dioxide, nitrogen oxides al14 lowance, or mercury allowances, as the case 

15 may be— 

16 ‘‘(i) the owner or operator offsets the 

17 excess emissions in accordance with para18 graph (2) or (3) of subsection (b), as ap19 plicable; and 

20 ‘‘(ii) the Administrator receives the 

21 penalty required under this subparagraph; 

22 or 

23 ‘‘(B) if a requirement under subparagraph 

24 (A) is not met, the quantity of the units’ excess 

25 emissions in tons (or, for mercury emissions, in 
42 

•S 131 IS 

1 ounces) multiplied by the product obtained by 

2 multiplying— 

3 ‘‘(i) 1.5; and 

4 ‘‘(ii) the respective amount for sulfur 

5 dioxide, nitrogen oxides, or mercury speci6 fied in subparagraph (A). 

7 ‘‘(5) PAYMENT.—Any penalty under paragraph 

8 (1), (2), (3), or (4) shall be due and payable without 

9 demand to the Administrator as provided in regula10 tions issued by the Administrator. With regard to 

11 the penalty under paragraph 1, the Administrator 

12 shall implement this paragraph under 40 CFR part 

13 77 (2002), amended as appropriate by the Adminis14 trator. With regard to the penalty under paragraphs 

15 2, 3, and 4, the Administrator shall implement this 

16 paragraph by issuing regulations no later than 24 

17 months after the date of enactment of the Clear 

18 Skies Act of 2005. Any such payment shall be de19 posited in the Compliance Assistance Account. 

20 ‘‘(b) EXCESS EMISSIONS OFFSET.— 

21 ‘‘(1) IN GENERAL.—The owner or operator of 

22 any unit subject to the requirements of section 

23 412(c) that emits sulfur dioxide during any calendar 

24 year before 2008 in excess of the sulfur dioxide al25 lowances held for the unit for the calendar year shall 
43 

•S 131 IS 

1 be liable to offset the excess emissions by an equal 

2 tonnage amount in the following calendar year, or 

3 such longer period as the Administrator may pre4 scribe. The Administrator shall deduct sulfur dioxide 

5 allowances equal to the excess tonnage from those 

6 held for the facility for the calendar year, or suc7 ceeding years during which offsets are required, fol8 lowing the year in which the excess emissions oc9 curred. 

10 ‘‘(2) EXCESS EMISSIONS OF SULFUR DIOX11 IDE.—If the units at a facility that are subject to 

12 the requirements of section 412(c) emit sulfur diox13 ide for a year after 2007 in excess of the sulfur di14 oxide allowances that the owner or operator of the 

15 facility holds for use for the facility for that calendar 

16 year, the owner or operator shall be liable to offset 

17 the excess emissions by an equal amount of tons in 

18 the following calendar year, or such longer period as 

19 the Administrator may prescribe. The Administrator 

20 shall deduct sulfur dioxide allowances equal to the 

21 excess emissions in tons from those held for the fa22 cility for the year, or succeeding years during which 

23 offsets are required, following the year in which the 

24 excess emissions occurred. 
44 

•S 131 IS 

1 ‘‘(3) EXCESS EMISSIONS OF SULFUR DIOXIDE, 

2 NITROGEN OXIDES, OR MERCURY.—If the units at a 

3 facility that are subject to the requirements of sec4 tion 422, 432, 452, or 472 emit sulfur dioxide, ni5 trogen oxides, or mercury for any calendar year in 

6 excess of the sulfur dioxide allowances, nitrogen ox7 ides allowances, or mercury allowances, as the case 

8 may be, that the owner or operator of the facility 

9 holds for use for the facility for that calendar year, 

10 the owner or operator shall be liable to offset the ex11 cess emissions by an equal amount of tons or, for 

12 mercury, ounces in the following calendar year, or 

13 such longer period as the Administrator may pre14 scribe. The Administrator shall deduct sulfur dioxide 

15 allowances, nitrogen oxide allowances, or mercury al16 lowances, as the case may be, equal to the excess 

17 emissions in tons or, for mercury, ounces from those 

18 held for the facility for the year, or succeeding years 

19 during which offsets are required, following the year 

20 in which the excess emissions occurred. 

21 ‘‘(c) PENALTY ADJUSTMENT.—The Administrator 

22 shall, by regulation, adjust the penalty specified in sub23 section (a)(1) and (a)(2) for inflation, based on the Con24 sumer Price Index, on November 15, 1990, and annually 

25 thereafter. 
45 

•S 131 IS 

1 ‘‘(d) PROHIBITION.—It shall be unlawful for the 

2 owner or operator of any unit or facility liable for a pen3 alty and offset under this section to fail— 

4 ‘‘(1) to pay the penalty under subsection (a); or 

5 ‘‘(2) to offset excess emissions as required by 

6 subsection (b). 

7 ‘‘(e) SAVINGS PROVISION.—Nothing in this title shall 

8 limit or otherwise affect the application of section 113, 

9 114, 120, or 304 except as otherwise explicitly provided 

10 in this title. 

11 ‘‘(f) OTHER REQUIREMENTS.—Except as expressly 

12 provided, compliance with the requirements of this title 

13 shall not exempt or exclude the owner or operator of any 

14 facility subject to this title from compliance with any other 

15 applicable requirements of this Act. Notwithstanding any 

16 other provision of this Act, no State or political subdivision 

17 thereof shall restrict or interfere with the transfer, sale, 

18 or purchase of allowances under this title. 

19 ‘‘(g) VIOLATIONS.—Violation by any person subject 

20 to this title of any prohibition of, requirement of, or regu21 lation promulgated pursuant to this title shall be a viola22 tion of this Act. In addition to the other requirements and 

23 prohibitions provided for in this title, the operation of any 

24 affected unit or the affected units at a facility to emit sul25 fur dioxide, nitrogen oxides, or mercury in violation of sec-
46 

•S 131 IS 

1 tion 412(c), 422, 432, 452, and 472, as the case may be, 

2 shall be deemed a violation, with each ton or, in the case 

3 of mercury, each ounce emitted in excess of allowances 

4 held constituting a separate violation. 

5 ‘‘SEC. 407. ELECTION FOR ADDITIONAL UNITS. 

6 ‘‘(a) APPLICABILITY.— 

7 ‘‘(1) IN GENERAL.—The owner or operator of 

8 any unit that is not an affected EGU under subpart 

9 2 of part B and subpart 2 of part C and whose 

10 emissions of sulfur dioxide and nitrogen oxides are 

11 vented only through a stack or duct may elect to 

12 designate the unit as an affected unit under subpart 

13 2 of part B and subpart 2 of part C. 

14 ‘‘(2) EFFECT OF DESIGNATION.—If the owner 

15 or operator elects to designate a unit that is solid 

16 fuel-fired and emits mercury vented only through a 

17 stack or duct, the owner or operator shall also des18 ignate the unit as an affected unit under part D. If 

19 an elected unit fires only gaseous fuels, the unit may 

20 be designated under subpart 2 of part C only. 

21 ‘‘(b) APPLICATION.—An owner or operator making 

22 an election under subsection (a) shall submit an applica23 tion for the election to the Administrator for approval. 

24 ‘‘(c) APPROVAL.—Subject to subsections (d) through 

25 (m), if the Administrator determines that an application 
47 

•S 131 IS 

1 for an election under subsection (b) meets the require2 ments of subsection (a), the Administrator shall approve 

3 the designation as an affected unit under subpart 2 of part 

4 B and subpart 2 of part C and, if applicable, under part 

5 D. 

6 ‘‘(d) ESTABLISHMENT OF BASELINE.— 

7 ‘‘(1) IN GENERAL.—After approval of a des8 ignation under subsection (c), an owner or operator 

9 shall install and operate monitoring on the des10 ignated unit required under paragraph (5), except 

11 that, in a case in which 2 or more units use a single 

12 stack, separate monitoring shall be required for each 

13 unit unless all units using the same stack are des14 ignated as affected units. 

15 ‘‘(2) BASELINES.— 

16 ‘‘(A) IN GENERAL.—Units shall have base17 lines established using heat input unless the 

18 unit qualifies for a product output baseline 

19 under paragraph (4). 

20 ‘‘(B) HEAT INPUT OR PRODUCT OUT21 PUT.—The baselines for heat input or product 

22 output and sulfur dioxide and nitrogen oxides 

23 emission rates, as the case may be, for the unit 

24 shall be the unit’s heat input or product output 

25 and the emission rates of sulfur dioxide and ni-
48 

•S 131 IS 

1 trogen oxides in accordance with paragraphs 

2 (3) and (4). 

3 ‘‘(C) REGULATIONS.—The Administrator 

4 shall promulgate regulations requiring the 

5 unit’s baselines for heat input or product out6 put and for sulfur dioxide and nitrogen oxides 

7 emission rates to be based on the same year 

8 and specifying minimum data requirements con9 sistent with paragraph (5) for baseline deter10 mination. 

11 ‘‘(3) HEAT INPUT AND EMISSIONS BASE12 LINES.—For the purposes of this subsection, heat 

13 input and emissions baselines shall be calculated, at 

14 the election of the owner or operator of the relevant 

15 unit, as— 

16 ‘‘(A)(i) for heat input, the average of the 

17 unit’s highest heat input for 3 of the 5 years 

18 before the year for which the Administrator is 

19 determining the allocations; and 

20 ‘‘(ii) for emissions baselines, the average of 

21 the relevant emissions during those same 3 

22 years; or 

23 ‘‘(B)(i) for heat input, the average of any 

24 period of 24 consecutive months during the 10- 

25 year period immediately prior to the date of 
49 

•S 131 IS 

1 submission of an application under subsection 

2 (b), on the condition that the heat input does 

3 not exceed 1.2 times the average of the 10-year 

4 period; and 

5 ‘‘(ii) for emissions baselines, the average of 

6 the relevant emissions for the 4-year period 

7 prior to the date of enactment of the Clear 

8 Skies Act of 2005 (for units that submit an ap9 plication on or before January 1, 2009), or the 

10 average of the relevant emissions for the 4 

11 years before the date of submission of the appli12 cation under that Act (for units that submit an 

13 application after January 1, 2009). 

14 ‘‘(4) DESIGNATION FOR PRODUCT OUTPUT

15 BASIS.— 

16 ‘‘(A) IN GENERAL.—The owner or operator 

17 of a unit that is subject to new source perform18 ance standards or other measures imposed by 

19 this Act on a product output basis rather than 

20 a heat input basis may elect to designate the 

21 unit as an affected unit under subpart 2 of part 

22 B and subpart 2 of part C. 

23 ‘‘(B) BASELINE PRODUCT OUTPUT AND

24 EMISSIONS BASELINES.—For the purposes of 

25 this paragraph, for those units using a product 
50 

•S 131 IS 

1 output basis, the baseline product output and 

2 emissions baselines in this subparagraph shall 

3 be calculated, at the election of the owner or 

4 operator of the relevant unit, as— 

5 ‘‘(i)(I) for product input, the average 

6 of the unit’s highest product output for 3 

7 of the 5 years preceding the year for which 

8 the Administrator is determining the allo9 cations; and 

10 ‘‘(II) for emissions baselines, the aver11 age of the relevant emissions for the same 

12 years used to determine product output; or 

13 ‘‘(B)(i) for product input, the average of 

14 any period of 24 consecutive months during the 

15 10-year period immediately prior to the date of 

16 submission of an application under subsection 

17 (b), on the condition that the product input 

18 does not exceed 1.2 times the average of the 

19 10-year period; and 

20 ‘‘(ii) for emissions baselines, the average of 

21 the relevant emissions for the 4-year period 

22 prior to the date of enactment of the Clear 

23 Skies Act of 2005 (for units that submit an ap24 plication on or before January 1, 2009), or the 

25 average of the relevant emissions for the 4 
51 

•S 131 IS 

1 years before the date of submission of the appli2 cation under that Act (for units that submit an 

3 application after January 1, 2009). 

4 ‘‘(5) BASELINE DETERMINATIONS.— 

5 ‘‘(A) IN GENERAL.—In making baseline 

6 determinations under this section, the Adminis7 trator may accept any reliable data on emis8 sions of sulfur dioxide and nitrogen oxides in 

9 addition to, and other than, data collected from 

10 CEMS. 

11 ‘‘(B) TYPES OF DATA.—Reliable data de12 scribed in subparagraph (A) includes— 

13 ‘‘(i) alternative data that has been 

14 used to determine compliance with a regu15 latory or monitoring requirement under 

16 this Act or a comparable State law, if the 

17 data establishes a reliable measure of heat 

18 input or product output and sulfur dioxide 

19 and nitrogen oxides emissions over a simul20 taneous period of time; or 

21 ‘‘(ii) if that data is not available, such 

22 other alternative reliable data as the Ad23 ministrator may prescribe. 

24 ‘‘(C) USE OF CEMS FOR COMPLIANCE MON25 ITORING.—The Administrator— 
52 

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1 ‘‘(i) shall not require the use of 

2 CEMS for compliance monitoring by units 

3 of less than 250 mmBtu heat input or 

4 equivalent product output capacity subject 

5 to this section unless the Administrator 

6 concludes that a CEMS requirement is 

7 necessary to generate reliable data for 

8 compliance determinations; 

9 ‘‘(ii) shall require the use of CEMS 

10 for compliance monitoring by units of be11 tween 250 mmBtu and 750 mmBtu heat 

12 input or equivalent product output capacity 

13 unless the Administrator determines that a 

14 CEMS requirement is not necessary to 

15 generate reliable data for compliance deter16 minations; and 

17 ‘‘(iii) shall require the use of CEMS 

18 for compliance monitoring for all units 

19 greater than 750 mmBtu heat input or 

20 equivalent product output capacity. 

21 ‘‘(D) RELIABILITY.—In determining the reli22 ability of data for purposes of this subsection, the 

23 Administrator shall consider the cost of generating 

24 more reliable data compared to the quantitative im-
53 

•S 131 IS 

1 portance of the resulting gain in quantifying emis2 sions. 

3 ‘‘(e) EMISSION LIMITATIONS.—After approval of the 

4 designation of the unit under subsection (c), the unit shall 

5 become— 

6 ‘‘(1) an affected unit under subpart 2 of part 

7 B, and shall be allocated sulfur dioxide allowances 

8 under subsection (f), beginning on the later of Janu9 ary 1, 2010, or January 1 of the year after approval 

10 of the designation; 

11 ‘‘(2) an affected unit under subpart 2 of part 

12 C, and shall be allocated nitrogen oxides allowances 

13 under subsection (f), beginning on the later of Janu14 ary 1, 2010, or January 1 of the year after approval 

15 of the designation; and 

16 ‘‘(3) if applicable, an affected unit under part 

17 D, and shall be allocated mercury allowances, begin18 ning on the later of January l, 2010, or January 1 

19 of the year after approval of designation. 

20 ‘‘(f) ALLOCATIONS.— 

21 ‘‘(1) SULFUR DIOXIDE AND NITROGEN OX22 IDES.— 

23 ‘‘(A) IN GENERAL.—The Administrator 

24 shall promulgate regulations determining the al25 locations of sulfur dioxide allowances and nitro-
54 

•S 131 IS 

1 gen oxides allowances for each year during 

2 which a unit is an affected unit under sub3 section (e). 

4 ‘‘(B) ALLOCATIONS.—The regulations shall 

5 provide for allocations equal to 70 percent (be6 ginning January 1, 2010) and 50 percent (be7 ginning January 1, 2018) of the unit’s baseline 

8 heat input or product output under subsection 

9 (d) multiplied by the lesser of— 

10 ‘‘(i) the unit’s baseline sulfur dioxide 

11 emission rate or nitrogen oxides emission 

12 rate, as the case may be; or 

13 ‘‘(ii) the unit’s most stringent Federal 

14 or State emission limitation for sulfur di15 oxide or nitrogen oxides applicable to the 

16 year on which the unit’s baseline heat 

17 input or product output is based under 

18 subsection (d). 

19 ‘‘(2) MERCURY.— 

20 ‘‘(A) IN GENERAL.—The Administrator 

21 shall promulgate regulations providing for the 

22 allocation of mercury allowances to solid fuel23 fired units designated under this section for 

24 each year after January 1, 2010, during which 

25 a unit is a designated unit under this section. 
55 

•S 131 IS 

1 ‘‘(B) ALLOCATIONS.—The regulations shall 

2 provide for allocations equal to the lesser of— 

3 ‘‘(i) the product obtained by multi4 plying— 

5 ‘‘(I) the unit’s allowable emis6 sions rate for mercury under the na7 tional emissions standards for haz8 ardous air pollutants for boilers and 

9 process heaters, industrial furnaces, 

10 kilns, or other stationary source; by 

11 ‘‘(II) the unit’s baseline heat 

12 input or product output; and 

13 ‘‘(i) the product obtained by multi14 plying— 

15 ‘‘(I) the unit’s most stringent 

16 Federal or State emission limitation 

17 for mercury emissions rate; by 

18 ‘‘(II) the unit’s baseline heat 

19 input or product output. 

20 ‘‘(3) LIMITATION.—Allowances allocated to 

21 electing units under paragraphs (1) and (2) shall 

22 comprise a separate limitation on emissions from 

23 sections 423, 433, 453, 473, and other provisions of 

24 this Act. These allowances for sulfur dioxide, nitro25 gen oxides, or mercury, as the case may be, shall be 
56 

•S 131 IS 

1 tradable with allowances allocated under sections 

2 414, 424, 454, 474, as applicable, on the conditions 

3 that— 

4 ‘‘(A) electing units may only trade nitrogen 

5 oxides within the respective zones established 

6 under section 452 within which the electing unit 

7 is located; and 

8 ‘‘(B) affected units within the WRAP 

9 States may only purchase sulfur dioxide allow10 ances allocated or otherwise distributed by the 

11 Administrator to electing units within the 

12 WRAP States, and will not be counted for pur13 poses of the affected unit’s emissions within the 

14 meaning of the WRAP Annex. 

15 ‘‘(4) INCENTIVES FOR EARLY REDUCTIONS.— 

16 ‘‘(A) IN GENERAL.—Not later than 180 

17 months after the date of enactment of this sec18 tion, the Administrator shall promulgate regula19 tions authorizing the allocation of sulfur diox20 ide, nitrogen oxides, and mercury allowances to 

21 units designated under this section that install 

22 or modify pollution control equipment or com23 bustion technology improvements identified in 

24 such regulations after the date of enactment of 

25 this section and prior to January 1, 2010. 
57 

•S 131 IS 

1 ‘‘(B) PROHIBITION ON CERTAIN ALLOCA2 TIONS.—No allowances shall be allocated under 

3 this paragraph for emissions reductions attrib4 utable to— 

5 ‘‘(i) pollution control equipment or 

6 combustion technology improvements that 

7 were operational or under construction at 

8 any time prior to the date of enactment of 

9 this section; 

10 ‘‘(ii) fuel switching; or 

11 ‘‘(iii) compliance with any Federal 

12 regulation. 

13 ‘‘(C) ALLOWANCES.—The allowances allo14 cated to any unit under this paragraph shall— 

15 ‘‘(i) be in addition to the allowances 

16 allocated under paragraphs (1) and (2) 

17 and sections 414, 424, 434, 454, and 474; 

18 and 

19 ‘‘(ii) be allocated in an amount equal 

20 to 1 allowance of sulfur dioxide and nitro21 gen oxides for each 1.05 tons of reduction 

22 in emissions of sulfur dioxide and nitrogen 

23 oxides, respectively, and 1.05 ounces of re24 duction in the emissions of mercury, 

25 achieved by the pollution control equip-
58 

•S 131 IS 

1 ment or combustion technology improve2 ments starting with the year in which the 

3 equipment or improvement is implemented. 

4 ‘‘(g) WITHDRAWAL.—The Administrator shall pro5 mulgate regulations withdrawing from the approved des6 ignation under subsection (c) any unit that qualifies as 

7 an affected EGU under subpart 2 of part B or subpart 

8 2 of part C, or part D after the approval of the designation 

9 of the unit under subsection (c). 

10 ‘‘(h) REGULATIONS.—Not later than 18 months after 

11 the date of enactment of the Clear Skies Act of 2005, the 

12 Administrator shall promulgate regulations implementing 

13 this section. 

14 ‘‘(i) APPLICATION PERIOD.— 

15 ‘‘(1) IN GENERAL.—Applications for designa16 tion of units under this section shall be accepted by 

17 the Administrator beginning not later than 180 days 

18 after the date of enactment of this section. 

19 ‘‘(2) APPROVAL AND DISAPPROVAL.—Except as 

20 provided in paragraph (30, not later than 270 days 

21 after accepting an application under paragraph (1), 

22 the Administrator shall approve or disapprove the 

23 application. 

24 ‘‘(3) DETERMINATION OF COMPLETION.— 
59 

•S 131 IS 

1 ‘‘(A) IN GENERAL.—Not later than 90 

2 days after accepting an application under para3 graph (1), the Administrator shall determine 

4 whether the application is complete. 

5 ‘‘(B) DETERMINATION OF COMPLETION.— 

6 Unless an application accepted under paragraph 

7 (1) is determined to be incomplete under sub8 paragraph (A), the application shall be subject 

9 to paragraph (2). 

10 ‘‘(4) STAY OF DEADLINES.—During the period 

11 beginning on the date of acceptance by the Adminis12 trator of an application under paragraph (1) and 

13 ending on the date on which the Administrator acts 

14 on the petition, the applicable compliance deadlines 

15 for NESHAPs under subsection (j) shall not apply 

16 to the applicable unit that is the subject of the appli17 cation. 

18 ‘‘(j) NESHAP APPLICABILITY.— 

19 ‘‘(1) APPLICABILITY.— 

20 ‘‘(A) IN GENERAL.—Except as provided in 

21 subparagraph (B), a unit that is designated as 

22 an affected unit under this section shall not be 

23 subject to the national emissions standards for 

24 hazardous air pollutants (NESHAP) promul25 gated under section 112(d) for— 
60 

•S 131 IS 

1 ‘‘(i) Industrial, Commercial, and Insti2 tutional Boilers and Process Heaters (Fed. 

3 Reg. 69–55217); 

4 ‘‘(ii) Plywood and Composite Wood 

5 Panel (Fed. Reg. 69–45943); 

6 ‘‘(iii) Reciprocating Internal Combus7 tion Engines (Fed. Reg. 69–33473); or 

8 ‘‘(iv) Stationary Combustion Turbines 

9 (Fed. Reg. 69–10511). 

10 ‘‘(B) EXCEPTION.—Units that are boilers 

11 or process heaters, industrial furnaces, kilns, or 

12 other stationary sources shall be subject on and 

13 after January 1, 2010, to the emissions limita14 tion for mercury or the equivalent mercury allo15 cation under subsection (f)(2), along with asso16 ciated monitoring and compliance requirements, 

17 that would be applicable to such units under 

18 the NESHAP for those sources promulgated 

19 pursuant to section 112(d). 

20 ‘‘(2) REPORTS.— 

21 ‘‘(A) PRELIMINARY REPORT.—Not later 

22 than 18 months after the date of enactment of 

23 this section, the Administrator shall publish and 

24 make available for public comment a peer re25 viewed preliminary report characterizing the 
61 

•S 131 IS 

1 emissions and public health effects that may 

2 reasonably be anticipated to occur from the im3 plementation of subsection (j)(1) and subsection 

4 (f). 

5 ‘‘(B) FINAL REPORT.—Not later than 30 

6 months after the date on which the preliminary 

7 report is published under subparagraph (A), in 

8 accordance with section 112(n)(1)(A), the Ad9 ministrator shall publish a final report, includ10 ing responses to the comments received. 

11 ‘‘(C) REQUIREMENTS.—The requirements 

12 of section 112(n)(1)(A), for purposes of this 

13 paragraph, shall be considered to be modified to 

14 ensure that the final report under subparagraph 

15 (B) includes— 

16 ‘‘(i) an estimate of the numbers and 

17 types of sources that are expected to be 

18 designated under this section; 

19 ‘‘(ii) an estimate of any increase or 

20 decrease in the annual emissions of criteria 

21 pollutants and of those hazardous air pol22 lutants subject to emission limitations 

23 under the NESHAPs identified in sub24 section (j)(1) from such sources that may 
62 

•S 131 IS 

1 reasonably be expected to occur for each 

2 year from 2010 through 2018; 

3 ‘‘(iii) an estimate of any increase or 

4 decrease in the annual emissions of criteria 

5 pollutants and of those hazardous air pol6 lutants subject to emission limitations 

7 under the NESHAPs identified in sub8 section (j)(1) from such sources that might 

9 reasonably be expected to occur for each 

10 year from 2010 through 2018, if such 

11 sources estimated in clause (i) are not des12 ignated under this section; and 

13 ‘‘(iv) a description of the public health 

14 and environmental impacts associated with 

15 the emissions increases and decreases de16 scribed in clauses (ii) and (iii). 

17 ‘‘(D) ADDITIONAL AUTHORITY.— 

18 ‘‘(i) IN GENERAL.—Notwithstanding 

19 subsection (j)(1), the Administrator may 

20 regulate emissions of hazardous air pollut21 ants listed under section 112(b), other 

22 than mercury compounds, from sources 

23 designated under this section in accordance 

24 with section 112(f)(2). 
63 

•S 131 IS 

1 ‘‘(ii) DETERMINATION.—Not later 

2 than 2 years after the date on which the 

3 final report under subparagraph (B) is 

4 published, the Administrator shall make a 

5 determination based on the study and 

6 other information satisfying the criteria of 

7 the Data Quality Act whether to establish 

8 emissions limitations under section 112(f) 

9 for sources designated under this section. 

10 ‘‘(iii) TREATMENT OF DETERMINA11 TION.—The determination shall be a final 

12 agency action subject to judicial review 

13 under section 307 and the Administrative 

14 Procedures Act. 

15 ‘‘(k) EXEMPTION FROM MAJOR SOURCE

16 PRECONSTRUCTION REVIEW REQUIREMENTS AND BEST

17 AVAILABLE RETROFIT CONTROL TECHNOLOGY REQUIRE18 MENTS.— 

19 ‘‘(1) MAJOR SOURCE EXEMPTION.— 

20 ‘‘(A) IN GENERAL.—Subject to subpara21 graph (B), a unit designated as an affected unit 

22 under this section shall not be considered to be 

23 a major source, or a part of a major emitting 

24 facility or major stationary source for purposes 

25 of compliance with the requirements of parts C 
64 

•S 131 IS 

1 and D of title I, for the 20-year period begin2 ning on the date of enactment of the Clear 

3 Skies Act of 2005. 

4 ‘‘(B) APPLICABILITY.—Subparagraph (A) 

5 applies only if, beginning on the date that is 8 

6 years after the date of enactment of this section 

7 or designation of a unit as an affected unit— 

8 ‘‘(i)(I) the designated unit either 

9 achieves in fact, or is subject to a regu10 latory requirement to achieve, a limit on 

11 the emissions of particulate matter from 

12 the affected unit to the level not greater 

13 than the level applicable to the unit either 

14 pursuant to subpart D of part 60 of title 

15 40, Code of Federal Regulations, or the 

16 national emissions standards for hazardous 

17 air pollutants for industrial boilers and 

18 process heaters issued pursuant to section 

19 112; or 

20 ‘‘(II) the owner or operator of the af21 fected unit properly operates, maintains, 

22 and repairs pollution control equipment to 

23 limit emissions of particulate matter; and 

24 ‘‘(ii) the owner or operator of the des25 ignated unit uses good combustion prac-
65 

•S 131 IS 

1 tices to minimize emissions of carbon mon2 oxide. 

3 ‘‘(2) CLASS I AREA PROTECTIONS.—Notwith4 standing the exemption in paragraph (1), an af5 fected unit located within 50 kilometers of a Class 

6 I area on which construction commences after the 

7 date of enactment of this section is subject to those 

8 provisions under part C of title I to the review of a 

9 new or modified major stationary source’s impact on 

10 a Class I area. 

11 ‘‘(l) LIMITATION.— 

12 ‘‘(1) IN GENERAL.—No unit designated under 

13 this section shall transfer or bank allowances pro14 duced as a result of reduced utilization or shutdown, 

15 except that such allowances may be transferred or 

16 carried forward for use in subsequent years to the 

17 extent that— 

18 ‘‘(A) reduced utilization or shutdown re19 sults from the replacement of the unit des20 ignated under this section, with any other unit 

21 or units subject to the requirements of this sub22 part; and 

23 ‘‘(B) the designated unit’s allowances are 

24 transferred or carried forward for use at such 

25 other replacement unit or units. 
66 

•S 131 IS 

1 ‘‘(2) NO GREATER ALLOCATION.—In no case 

2 may the Administrator allocate to a source des3 ignated under this section allowances in an amount 

4 greater than the emissions resulting from operation 

5 of the source in full compliance with the require6 ments of this Act. 

7 ‘‘(3) NO VIOLATION.—No allowances allocated 

8 under this Act shall authorize operation of a unit in 

9 violation of any other requirements of this Act. 

10 ‘‘(m) DEFINITION OF PRODUCT OUTPUT.—In this 

11 section, the term ‘product output’ means the output of a 

12 stationary source that produces a commercial product 

13 other than electricity, heat, or steam which may be used 

14 to determine a baseline for units for which heat input is 

15 not an appropriate baseline.’’. 

16 ‘‘SEC. 408. CLEAN COAL TECHNOLOGY REGULATORY INCEN17 TIVES. 

18 ‘‘(a) DEFINITION.—For purposes of this section, the 

19 term ‘clean coal technology’ means any technology, includ20 ing technologies applied at the precombustion, combus21 tion, or post combustion stage, at a new or existing facility 

22 which will achieve significant reductions in air emissions 

23 of sulfur dioxide or oxides of nitrogen associated with the 

24 utilization of coal in the generation of electricity, process 
67 

•S 131 IS 

1 steam, or industrial products, which is not in widespread 

2 use as of November 15, 1990. 

3 ‘‘(b) REVISED REGULATIONS FOR CLEAN COAL

4 TECHNOLOGY DEMONSTRATIONS.— 

5 ‘‘(1) APPLICABILITY.—This subsection applies 

6 to physical or operational changes to existing facili7 ties for the sole purpose of installation, operation, 

8 cessation, or removal of a temporary or permanent 

9 clean coal technology demonstration project. For the 

10 purposes of this section, a clean coal technology 

11 demonstration project shall mean a project using 

12 funds appropriated under the heading ‘Department 

13 of Energy—Clean Coal Technology’, up to a total 

14 amount of $2,500,000,000 for commercial dem15 onstration of clean coal technology, or similar 

16 projects funded through appropriations for the Envi17 ronmental Protection Agency. The Federal contribu18 tion for qualifying project shall be at least twenty 

19 percent of the total cost of the demonstration 

20 project. 

21 ‘‘(2) TEMPORARY PROJECTS.—Installation, op22 eration, cessation, or removal of a temporary clean 

23 coal technology demonstration project that is oper24 ated for a period of 5 years or less, and which com25 plies with the State implementation plans for the 
68 

•S 131 IS 

1 State in which the project is located and other re2 quirements necessary to attain and maintain the na3 tional ambient air quality standards during and 

4 after the project is terminated, shall not subject 

5 such facility to the requirements of section 111 or 

6 part C or D of title I. 

7 ‘‘(3) PERMANENT PROJECTS.—For permanent 

8 clean coal technology demonstration projects that 

9 constitute repowering as defined in section 411, any 

10 qualifying project shall not be subject to standards 

11 of performance under section 111 or to the review 

12 and permitting requirements of part C for any pol13 lutant the potential emissions of which will not in14 crease as a result of the demonstration project. 

15 ‘‘(4) EPA REGULATIONS.—Not later than 

16 twelve months after November 15, 1990, the Admin17 istrator shall promulgate regulations or interpretive 

18 rulings to revise requirements under section 111 and 

19 parts C and D, as appropriate, to facilitate projects 

20 consistent in this subsection. With respect to parts 

21 C and D, such regulations or rulings shall apply to 

22 all areas in which EPA is the permitting authority. 

23 In those instances in which the State is the permit24 ting authority under part C or D, any State may 

25 adopt and submit to the Administrator for approval 
69 

•S 131 IS 

1 revisions to its implementation plan to apply the reg2 ulations or rulings promulgated under this sub3 section. 

4 ‘‘(c) EXEMPTION FOR REACTIVATION OF VERY

5 CLEAN UNITS.—Physical changes or changes in the meth6 od of operation associated with the commencement of com7 mercial operations by a coal-fired utility unit after a pe8 riod of discontinued operation shall not subject the unit 

9 to the requirements of section 111 or part C of the Act 

10 where the unit— 

11 ‘‘(1) has not been in operation for the two-year 

12 period prior to November 15, 1990, and the emis13 sions from such unit continue to be carried in the 

14 permitting authority’s emissions inventory on No15 vember 15, 1990; 

16 ‘‘(2) was equipped prior to shut-down with a 

17 continuous system of emissions control that achieves 

18 a removal efficiency for sulfur dioxide of no less 

19 than 85 percent and a removal efficiency for particu20 lates of no less than 98 percent; 

21 ‘‘(3) is equipped with low-NOX burners prior to 

22 the time of commencement; and 

23 ‘‘(4) is otherwise in compliance with the re24 quirements of this Act. 
70 

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1 ‘‘SEC. 409. ELECTRICITY RELIABILITY. 

2 ‘‘(a) RELIABILITY.— 

3 ‘‘(1) APPLICABILITY.—At any time prior the 

4 applicability of this Act under sections 422, 432, 

5 452, and 472, in order to ensure the reliability of an 

6 electric utility company or system, including a sys7 tem cooperatively or municipally owned, for a speci8 fied geographic area or service territory, as deter9 mined by the Department of Energy in consultation 

10 with the Administrator, during the installation of 

11 sulfur dioxide pollution control technology or scrub12 bers, nitrogen oxides, mercury or particulate matter 

13 control technology, or any combination thereof, the 

14 owner or operator of an affected unit may meet the 

15 requirements of sections 422, 432, 452, and 472 by 

16 means of the compliance procedures of this sub17 section (a). 

18 ‘‘(2) PETITION.—The owner or operator of an 

19 affected unit that believes it may experience an ad20 verse impact on the reliability of the company or 

21 system as a result, in substantial part, of the need 

22 to construct sulfur dioxide pollution control equip23 ment or scrubbers, nitrogen oxides, mercury or par24 ticulate matter control technology, or any combina25 tion thereof, may petition the Secretary of Energy, 

26 in consultation with the Administrator, for a deter-
71 

•S 131 IS 

1 mination that, to a reasonable degree of certainty, 

2 reliability will likely be threatened. Upon such a de3 termination, the owner or operator may elect to 

4 adopt a compliance method meeting the require5 ments of this subsection, as follows: 

6 ‘‘(A) REGULATIONS.—Within 12 months of 

7 enactment the Secretary of Energy shall pro8 mulgate regulations describing the requirements 

9 for a petition and the petition process, which 

10 will include notice and public comment. The 

11 Secretary of Energy, in consultation with the 

12 Administrator, shall make a final determination 

13 on a petition within 180 days of the submittal 

14 of a reasonably complete petition. Failure to act 

15 within the 180-day period will extend the appli16 cability by 12 months for all units subject to 

17 the petition. 

18 ‘‘(B) CONTENTS OF PETITION.—The peti19 tion must contain— 

20 ‘‘(i) a description of each affected 

21 unit, the estimated outage time and a con22 struction schedule; 

23 ‘‘(ii) an estimate of demand from date 

24 of applicability until 2018; 
72 

•S 131 IS 

1 ‘‘(iii) the impacts on reliability associ2 ated with constructing all of the pollution 

3 control projects, including those for sulfur 

4 dioxide, nitrogen oxides, mercury, or par5 ticulate matter, by the respective deadlines; 

6 and 

7 ‘‘(iv) how the proposed compliance 

8 schedule would alleviate detrimental im9 pacts. 

10 ‘‘(C) FAILURE TO PROMULGATE REGULA11 TIONS.—If the Secretary of Energy fails to pro12 mulgate final regulations or such regulations 

13 are not effective for any reason, within the pre14 scribed time, petitions containing reasonably 

15 sufficient information for a final determination 

16 may be submitted to the Secretary of Energy 

17 and will be deemed complete. 

18 ‘‘(3) FINAL DETERMINATION.—In making a 

19 final determination the Secretary of Energy, in con20 sultation with the Administrator, shall consider the 

21 following factors, provided that not all factors need 

22 be present to make a determination that, to a rea23 sonable degree, reliability will be threatened: 

24 ‘‘(A) SUPPLY.—The ability of vendors to 

25 supply scrubbers; scrubber system equipment, 
73 

•S 131 IS 

1 materials and scrubber affected balance of plant 

2 equipment including fans, pumps, electric mo3 tors, motor drives, dampers, electrical power 

4 supply equipment; at fair prices with meaning5 ful guarantees or warranties as to availability, 

6 delivery dates and meeting contracted pollution 

7 control reduction requirements or emissions 

8 limitations; with similar considerations for ni9 trogen oxides, mercury or particulate matter 

10 control technology, or any combination thereof. 

11 ‘‘(B) DESIGN AND CONSTRUCTION RE12 SOURCES.—The availability and limitations of 

13 key sulfur dioxide, nitrogen oxides or mercury 

14 controls design resources and North American 

15 construction resources. The design resources 

16 shall include Architect Engineering companies 

17 experienced in the design of sulfur dioxide, ni18 trogen oxides, mercury or particulate matter 

19 control technology. The construction resources 

20 shall include construction companies with expe21 rience in the construction of sulfur dioxide, ni22 trogen oxides, mercury, or particulate matter 

23 control technology and trained and experienced 

24 labor resources including but not limited to 
74 

•S 131 IS 

1 boilermakers, iron workers, electricians, me2 chanics; 

3 ‘‘(C) FEASIBILITY OF CONSTRUCTION.— 

4 The feasibility to complete the construction of 

5 all pollution control technology projects by the 

6 relevant applicability compliance deadline; 

7 ‘‘(D) IMPACT.—The impact in terms of 

8 unit outages and construction schedules on a 

9 company or systems reliability and whether 

10 such impact is unreasonable, which term shall 

11 be presumed to be— 

12 ‘‘(i) an increase in the price of pur13 chase power of (10) percent over the esti14 mated cost in cents per kilowatt for the 

15 company, system or State, utilized in the 

16 latest submissions to a relevant State or 

17 Federal agency; 

18 ‘‘(ii) a projected reduction in available 

19 generating capacity such that adequate re20 serve margins for a company, system or 

21 State do not exist, as determined by the 

22 Secretary of Energy in coordination with 

23 the relevant Federal or State utility agency 

24 or reliability council; or 
75 

•S 131 IS 

1 ‘‘(iii) a supply shortage of coal needed 

2 to meet emissions control expectations for 

3 any proposed emissions control device. 

4 ‘‘(E) POSITIVE DETERMINATION.—A com5 pany or system which submits a petition to in6 stall sulfur dioxide, nitrogen oxides, mercury, or 

7 particulate matter control technology, or any 

8 combination thereof, on affected units equaling 

9 25 percent or more of its coal-fired capacity 

10 shall be presumed to meet the requirements of 

11 a positive determination from the Secretary of 

12 Energy. 

13 ‘‘(4) COMPLIANCE.—Upon a positive determina14 tion by the Secretary of Energy in accordance with 

15 paragraph (3)(E), such affected units will be grant16 ed a 1-year extension from the relevant applicability 

17 date under this title. 

18 ‘‘(b) SUBMISSION OF PETITION.—During any year 

19 covered by this title, an affected unit may submit a peti20 tion in accordance with paragraph (a)(2) to allow use of 

21 sulfur dioxide allowances, nitrogen oxides allowances, and 

22 mercury allowances, as the case may be, allocated for the 

23 immediate next year to meet the applicable requirement 

24 to hold such allowances equal to the petitioned year’s 

25 emissions. 
76

•S 131 IS 

1 ‘‘(c) PRESIDENTIAL WAIVER.—Notwithstanding sub2 section (a) or any other provision of this Act, The Presi3 dent of the United States shall have authority to tempo4 rarily grant waivers from emission limitations under sec5 tions 412, 422, 432, 452, and 472, as the case may be, 

6 if the President determines that the reliability of any por7 tion of national electricity supply or national security is 

8 imperiled.

9 ‘‘PART B—SULFUR DIOXIDE EMISSION 

10 REDUCTIONS 

11 ‘‘Subpart 1—Acid Rain Program 

12 ‘‘SEC. 411. DEFINITIONS. 

13 ‘‘For purposes of this subpart and subpart 1 of part 

14 B: 

15 ‘‘(1) ACTUAL 1985 EMISSION RATE.—The term 

16 ‘actual 1985 emission rate’, for electric utility units 

17 means the annual sulfur dioxide or nitrogen oxides 

18 emission rate in pounds per million Btu as reported 

19 in the 1985 National Acid Precipitation Assessment 

20 Program (NAPAP) Emissions Inventory, Version 2, 

21 National Utility Reference File (NURF). For non22 utility units, the term ‘actual 1985 emission rate’ 

23 means the annual sulfur dioxide or nitrogen oxides 

24 emission rate in pounds per million Btu as reported 

25 in the NAPAP Emission Inventory, Version 2. 
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1 ‘‘(2) ALLOWABLE 1985 EMISSIONS RATE.—The 

2 term ‘allowable 1985 emissions rate’ means a feder3 ally enforceable emissions limitation for sulfur diox4 ide or oxides of nitrogen, applicable to the unit in 

5 1985 or the limitation applicable in such other sub6 sequent year as determined by the Administrator if 

7 such a limitation for 1985 does not exist. Where the 

8 emissions limitation for a unit is not expressed in 

9 pounds of emissions per million Btu, or the aver10 aging period of that emissions limitation is not ex11 pressed on an annual basis, the Administrator shall 

12 calculate the annual equivalent of that emissions 

13 limitation. 

14 ‘‘(3) ALTERNATIVE METHOD OF COMPLI15 ANCE.—The term ‘alternative method of compliance’ 

16 means a method of compliance in accordance with 

17 one or more of the following authorities— 

18 ‘‘(A) a substitution plan submitted and ap19 proved in accordance with subsections 413(b) 

20 and (c); or 

21 ‘‘(B) a phase I extension plan approved by 

22 the Administrator under section 413(d), using 

23 qualifying phase I technology as determined by 

24 the Administrator in accordance with that sec25 tion. 
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1 ‘‘(4) BASELINE.—The term ‘baseline’ means 

2 the annual quantity of fossil fuel consumed by an af3 fected unit, measured in millions of British Thermal 

4 Units (‘mmBtu’s’), calculated as follows: 

5 ‘‘(A) For each utility unit that was in com6 mercial operation prior to January 1, 1985, the 

7 baseline shall be the annual average quantity of 

8 mmBtu’s consumed in fuel during calendar 

9 years 1985, 1986, and 1987, as recorded by the 

10 Department of Energy pursuant to Form 767. 

11 For any utility unit for which such form was 

12 not filed, the baseline shall be the level specified 

13 for such unit in the 1985 (NAPAP) Emissions 

14 Inventory, Version 2 (NURF), or in a corrected 

15 data base as established by the Administrator 

16 pursuant to paragraph (3). For nonutility units, 

17 the baseline in the NAPAP Emissions Inven18 tory, Version 2. The Administrator, in the Ad19 ministrator’s sole discretion, may exclude peri20 ods during which a unit is shutdown for a con21 tinuous period of 4 calendar months or longer, 

22 and make appropriate adjustments under this 

23 paragraph. Upon petition of the owner or oper24 ator of any unit, the Administrator may make 

25 appropriate baseline adjustments for accidents, 
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1 strikes, disruptions of fuel supplies, failure of 

2 equipment, other causes beyond the reasonable 

3 control of the owner or operator of the unit that 

4 caused prolonged outages. 

5 ‘‘(B) For any other nonutility unit that is 

6 not included in the NAPAP Emissions Inven7 tory, Version 2, or a corrected data base as es8 tablished by the Administrator pursuant to 

9 paragraph (3), the baseline shall be the annual 

10 average quantity, in mmBtu consumed in fuel 

11 by that unit, as calculated pursuant to a meth12 od which the Administrator shall prescribe by 

13 regulation to be promulgated not later than 18 

14 months after November 15, 1990. 

15 ‘‘(C) The Administrator shall, upon appli16 cation or on his own motion, by December 31, 

17 1991, supplement data needed in support of 

18 this subpart and correct any factual errors in 

19 data from which affected phase II units’ base20 lines or actual 1985 emission rates have been 

21 calculated. Corrected data shall be used for pur22 poses of issuing allowances under this subpart. 

23 Such corrections shall not be subject to judicial 

24 review, nor shall the failure of the Adminis-
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•S 131 IS 

1 trator to correct an alleged factual error in such 

2 reports be subject to judicial review. 

3 ‘‘(5) BASIC PHASE II ALLOWANCE ALLOCA4 TIONS.—The term ‘basic phase II allowance alloca5 tions’ means: 

6 ‘‘(A) For calendar years 2000 through 

7 2009 inclusive, allocations of allowances made 

8 by the Administrator pursuant to section 412 

9 and subsections (b)(1), (3), and (4); (c)(1), (2), 

10 (3), and (5); (d)(1), (2), (4), and (5); (e); (f); 

11 (g)(1), (2), (3), (4), and (5); (h)(1); (i); and (j) 

12 of section 414. 

13 ‘‘(B) For each calendar year beginning in 

14 2010, allocations of allowances made by the Ad15 ministrator pursuant to section 412 and sub16 sections (b)(1), (3), and (4); (c)(1), (2), (3), 

17 and (5); (d)(1), (2), (4), and (5); (e); (f); 

18 (g)(1), (2), (3), (4), and (5); (h)(1) and (3); (i); 

19 and (j) of section 414. 

20 ‘‘(6) CAPACITY FACTOR.—The term ‘capacity 

21 factor’ means the ratio between the actual electric 

22 output from a unit and the potential electric output 

23 from that unit. 

24 ‘‘(7) COMMENCED.—The term ‘commenced’ as 

25 applied to construction of any new electric utility 
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1 unit means that an owner or operator has under2 taken a continuous program of construction or that 

3 an owner or operator has entered into a contractual 

4 obligation to undertake and complete, within a rea5 sonable time, a continuous program of construction. 

6 ‘‘(8) COMMENCED COMMERCIAL OPERATION.—

7 The term ‘commenced commercial operation’ with 

8 regard to a unit means the start up of the unit’s 

9 combustion chamber and commencement of the gen10 eration of electricity for sale. 

11 ‘‘(9) CONSTRUCTION.—The term ‘construction’ 

12 means fabrication, erection, or installation of an af13 fected unit. 

14 ‘‘(10) EXISTING UNIT.—The term ‘existing 

15 unit’ means a unit (including units subject to section 

16 111) that commenced commercial operation before 

17 November 15, 1990. Any unit that commenced com18 mercial operation before November 15, 1990, which 

19 is modified, reconstructed, or repowered after No20 vember 15, 1990, shall continue to be an existing 

21 unit for the purposes of this subpart. For the pur22 poses of this subpart, existing units shall not include 

23 simple combustion turbines, or units which serve a 

24 generator with a nameplate capacity of 25 MWe or 

25 less. 
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1 ‘‘(11) INDEPENDENT POWER PRODUCER.—The 

2 term ‘independent power producer’ means any per3 son who owns or operates, in whole or in part, one 

4 or more new independent power production facilities. 

5 ‘‘(12) NEW INDEPENDENT POWER PRODUCTION

6 FACILITY.—The term ‘new independent power pro7 duction facility’ means a facility that— 

8 ‘‘(A) is used for the generation of electric 

9 energy, 80 percent or more of which is sold at 

10 wholesale; 

11 ‘‘(B) in nonrecourse project-financed (as 

12 such term is defined by the Secretary of Energy 

13 within 3 months of the date of the enactment 

14 of the Clean Air Act Amendments of 1990); 

15 and 

16 ‘‘(C) is a new unit required to hold allow17 ances under this subpart. 

18 ‘‘(13) INDUSTRIAL SOURCE.—The term ‘indus19 trial source’ means a unit that does not serve a gen20 erator that produces electricity, a ‘nonutility unit’ as 

21 defined in this section, or a process source. 

22 ‘‘(14) LIFE-OF-THE-UNIT, FIRM POWER CON23 TRACTUAL ARRANGEMENT.—The term ‘life-of-the24 unit, firm power contractual arrangement’ means a 

25 unit participation power sales agreement under 
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•S 131 IS 

1 which a utility or industrial customer reserves, or is 

2 entitled to receive, a specified amount or percentage 

3 of capacity and associated energy generated by a 

4 specified generating unit (or units) and pays its pro5 portional amount of such unit’s total costs, pursuant 

6 to a contract either— 

7 ‘‘(A) for the life of the unit; 

8 ‘‘(B) for a cumulative term of no less than 

9 30 years, including contracts that permit an 

10 election for early termination; or 

11 ‘‘(C) for a period equal to or greater than 

12 25 years or 70 percent of the economic useful 

13 life of the unit determined as of the time the 

14 unit was built, with option rights to purchase or 

15 release some portion of the capacity and associ16 ated energy generated by the unit (or units) at 

17 the end of the period. 

18 ‘‘(15) NEW UNIT.—The term ‘new unit’ means 

19 a unit that commences commercial operation on or 

20 after November 15, 1990.

21 ‘‘(16) NONUTILITY UNIT.—The term ‘nonutility 

22 unit’ means a unit other than a utility unit. 

23 ‘‘(17) PHASE II BONUS ALLOWANCE ALLOCA24 TIONS.—The term ‘phase II bonus allowance alloca25 tions’ means, for calendar year 2000 through 2009, 
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1 inclusive, and only for such years, allocations made 

2 by the Administrator pursuant to section 412, sub3 sections (a)(2), (b)(2), (c)(4), (d)(3) (except as oth4 erwise provided therein), and (h)(2) of section 414, 

5 and section 415. 

6 ‘‘(18) QUALIFYING PHASE I TECHNOLOGY.—

7 The term ‘qualifying phase I technology’ means a 

8 technological system of continuous emission reduc9 tion which achieves a 90 percent reduction in emis10 sions of sulfur dioxide from the emissions that would 

11 have resulted from the use of fuels which were not 

12 subject to treatment prior to combustion. 

13 ‘‘(19) REPOWERING.—The term ‘repowering’ 

14 means replacement of an existing coal-fired boiler 

15 with one of the following clean coal technologies: at16 mospheric or pressurized fluidized bed combustion, 

17 integrated gasification combined cycle, magneto18 hydrodynamics, direct and indirect coal-fired tur19 bines, integrated gasification fuel cells, or as deter20 mined by the Administrator, in consultation with the 

21 Secretary of Energy, a derivative of one or more of 

22 these technologies, and any other technology capable 

23 of controlling multiple combustion emissions simulta24 neously with improved boiler or generation efficiency 

25 and with significantly greater waste reduction rel-
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1 ative to the performance of technology in widespread 

2 commercial use as of November 15, 1990. 

3 ‘‘(20) RESERVE.—The term ‘reserve’ means 

4 any bank of allowances established by the Adminis5 trator under this subpart. 

6 ‘‘(21) UTILITY UNIT.— 

7 ‘‘(A) IN GENERAL.—The term ‘utility unit’ 

8 means— 

9 ‘‘(i) a unit that serves a generator lo10 cated in any State and that produces elec11 tricity for sale; or 

12 ‘‘(ii) a unit that, during 1985, served 

13 a generator located in any State and that 

14 produced electricity for sale. 

15 ‘‘(B) EXCLUSIONS.— 

16 ‘‘(i) IN GENERAL.—Notwithstanding 

17 subparagraph (A), a unit described in sub18 paragraph (A) that— 

19 ‘‘(I) was in commercial operation 

20 during 1985; but 

21 ‘‘(II) did not during 1985, serve 

22 a generator in any State that pro23 duced electricity for sale 

24 shall not be a utility unit for purposes of 

25 this subpart. 
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•S 131 IS 

1 ‘‘(i) UNITS THAT COGENERATE STEAM

2 AND ELECTRICITY.—A unit that cogen3 erates steam and electricity is not a ‘utility 

4 unit’ for purposes of this subpart unless 

5 the unit is constructed for the purpose of 

6 supplying, or commences construction after 

7 November 15, 1990 and supplies more 

8 than one-third of its potential electric out9 put capacity of more than 25 megawatts 

10 electrical output to any utility power dis11 tribution system for sale. 

12 ‘‘SEC. 412. ALLOWANCE ALLOCATION. 

13 ‘‘(a) IN GENERAL.—Except as provided in sections 

14 414(a)(2), 415(a)(3), and 416, beginning January 1, 

15 2000, the Administrator shall not allocate annual emission 

16 allowances for sulfur dioxide from utility units in excess 

17 of 8.90 million tons except that the Administrator shall 

18 not take into account unused allowances carried forward 

19 by owners and operators of affected units or by other per20 sons holding such allowances, following the year for which 

21 they were allocated. If necessary to meeting the restric22 tions imposed in the preceding sentence, the Adminis23 trator shall reduce, pro rata, the basic phase II allowance 

24 allocations for each unit subject to the requirements of 

25 section 414. Subject to the provisions of section 417, the 
87 

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1 Administrator shall allocate allowances for each affected 

2 until at an affected source annually, as provided in para3 graphs (2) and (3) and section 404. Except as provided 

4 in sections 416, the removal of an existing affected unit 

5 or source from commercial operation at any time after No6 vember 15, 1990 (whether before or after January 1, 

7 1995, or January 1, 2000), shall not terminate or other8 wise affect the allocation of allowances pursuant to section 

9 413 or 414 to which the unit is entitled. Prior to June 

10 1, 1998, the Administrator shall publish a revised final 

11 statement of allowance allocations, subject to the provi12 sions of section 414(a)(2). 

13 ‘‘(b) NEW UTILITY UNITS.— 

14 ‘‘(1) PROHIBITION OF EXCEEDING UNIT AL15 LOWANCES.—After January 1, 2000 and through 

16 December 31, 2007, it shall be unlawful for a new 

17 utility unit to emit an annual tonnage of sulfur diox18 ide in excess of the number of allowances to emit 

19 held for the unit by the unit’s owner or operator. 

20 ‘‘(2) PROHIBITION OF EXCEEDING SOURCE AL21 LOWANCES.—Starting January 1, 2008, a new util22 ity unit shall be subject to the prohibition in sub23 section (c)(3). 

24 ‘‘(3) ELIGIBILITY FOR ALLOCATION OF SULFUR

25 DIOXIDE ALLOWANCES.—New utility units shall not 
88 

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1 be eligible for an allocation of sulfur dioxide allow2 ances under subsection (a)(1), unless the unit is 

3 subject to the provisions of subsection (g)(2) or (3) 

4 of section 414. New utility units may obtain allow5 ances from any person, in accordance with this title. 

6 The owner or operator of any new utility unit in vio7 lation of subsection (b)(1) or subsection(c)(3) shall 

8 be liable for fulfilling the obligations specified in sec9 tion 406. 

10 ‘‘(c) PROHIBITIONS.— 

11 ‘‘(1) IN GENERAL.—It shall be unlawful for any 

12 person to hold, use, or transfer any allowance allo13 cated under this subpart, except in accordance with 

14 regulations promulgated by the Administrator. 

15 ‘‘(2) PROHIBITION OF EXCEEDING UNIT AL16 LOWANCES.—For any year 1995 through 2007, it 

17 shall be unlawful for any affected unit to emit sulfur 

18 dioxide in excess of the number of allowances held 

19 for that unit for that year by the owner or operator 

20 of the unit. 

21 ‘‘(3) PROHIBITION OF EXCEEDING SOURCE AL22 LOWANCES.—Starting January 1, 2008, it shall be 

23 unlawful for the affected units at a source to emit 

24 a total amount of sulfur dioxide during the year in 

25 excess of the number of allowances held for the 
89 

•S 131 IS 

1 source for that year by the owner or operator of the 

2 source. 

3 ‘‘(4) EFFECT ON OTHER EMISSION LIMITA4 TIONS.—Upon the allocation of allowances under 

5 this subpart, the prohibition in paragraphs (2) and 

6 (3) shall supersede any other emission limitation ap7 plicable under this subpart to the units for which 

8 such allowances are allocated. 

9 ‘‘(d) LIMITATION ON REGULATIONS.—In order to en10 sure electricity reliability, regulations establishing a sys11 tem for issuing, recording, and tracking allowances under 

12 section 403(b) and this subpart shall not prohibit or affect 

13 temporary increases and decreases in emissions within 

14 utility systems, power pools, or utilities entering into al15 lowance pool agreements, that result from their oper16 ations, including emergencies and central dispatch, and 

17 such temporary emissions increases and decreases shall 

18 not require transfer of allowances among units nor shall 

19 it require recording. The owners or operators of such units 

20 shall act through a designated representative. Notwith21 standing the preceding sentence, the total tonnage of emis22 sions in any calendar year (calculated at the end thereof) 

23 from all units in such a utility system, power pool, or al24 lowance pool agreements shall not exceed the total allow25 ances for such units for the calendar year concerned, in-
90 

•S 131 IS 

1 cluding for calendar years after 2007, allowances held for 

2 such units by the owner or operator of the sources where 

3 the units are located. 

4 ‘‘(e) INTEREST IN AFFECTED UNITS.—Where there 

5 are multiple holders of a legal or equitable title to, or a 

6 leasehold interest in, an affected unit, or where a utility 

7 or industrial customer purchases power from an affected 

8 unit (or units) under life-of-the-unit, firm power contrac9 tual arrangements, the certificate of representation re10 quired under section 404(f) shall state— 

11 ‘‘(1) that allowances under this subpart and the 

12 proceeds of transactions involving such allowances 

13 will be deemed to be held or distributed in propor14 tion to each holder’s legal, equitable, leasehold, or 

15 contractual reservation or entitlement; or 

16 ‘‘(2) if such multiple holders have expressly pro17 vided for a different distribution of allowances by 

18 contract, that allowances under this subpart and the 

19 proceeds of transactions involving such allowances 

20 will be deemed to be held or distributed in accord21 ance with the contract. 

22 A passive lessor, or a person who has an equitable interest 

23 through such lessor, whose rental payments are not based, 

24 either directly or indirectly, upon the revenues or income 

25 from the affected unit shall not be deemed to be a holder 
91 

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1 of a legal, equitable, leasehold, or contractual interest for 

2 the purpose of holding or distributing allowances as pro3 vided in this subsection, during either the term of such 

4 leasehold or thereafter, unless expressly provided for in the 

5 leasehold agreement. Except as otherwise provided in this 

6 subsection, where all legal or equitable title to or interest 

7 in an affected unit is held by a single person, the certifi8 cation shall state that all allowances under this subpart 

9 received by the unit are deemed to be held for that person. 

10 ‘‘SEC. 413. PHASE I SULFUR DIOXIDE REQUIREMENTS. 

11 ‘‘(a) EMISSION LIMITATIONS.— 

12 ‘‘(1) ALLOCATION.—After January 1, 1995, 

13 each source that includes one or more affected units 

14 listed in table A is an affected source under this sec15 tion. After January 1, 1995, it shall be unlawful for 

16 any affected unit (other than an eligible phase I unit 

17 under section 413(d)(2)) to emit sulfur dioxide in 

18 excess of the tonnage limitation stated as a total 

19 number of allowances in table A for phase 1; un20 less— 

21 ‘‘(A) the emissions reduction requirements 

22 applicable to such unit have been achieved pur23 suant to subsection (b) or (d); or 

24 ‘‘(B) the owner or operator of such unit 

25 holds allowances to emit not less than the unit’s 
92 

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1 total annual emissions, except that, after Janu2 ary 1, 2000, the emissions limitations estab3 lished in this section shall be superseded by 

4 those established in section 414. The owner or 

5 operator of any unit in violation of this section 

6 be fully liable for such violation including, but 

7 not limited to, liability for fulfilling the obliga8 tions specified in section 406. 

9 ‘‘(2) DETERMINATION.—Not later than Decem10 ber 31, 1991, the Administrator shall determine the 

11 total tonnage of reductions in the emissions of sulfur 

12 dioxide from all utility units in calendar year 1995 

13 that will occur as a result of compliance with the 

14 emissions limitation requirements of this section, 

15 and shall establish a reserve of allowances equal in 

16 amount to the number of tons determined thereby 

17 not to exceed a total of 3.50 million tons. In making 

18 such a determination, the Administrator shall com19 pute for each unit subject to the emissions limitation 

20 requirements of this section the difference be21 tween— 

22 ‘‘(A) the product of its baseline multiplied 

23 by the lesser of each unit’s allowable 1985 

24 emissions rate and its actual 1985 emissions 

25 rate, divided by 2,000; and 
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1 ‘‘(B) the product of each unit’s baseline 

2 multiplied by 2.50 lbs/mmBtu divided by 2,000, 

3 and sum the computations. The Administrator 

4 shall adjust the foregoing calculation to reflect 

5 projected calendar year 1995 utilization of the 

6 units subject to the emissions limitations of this 

7 subpart that the Administrator finds would 

8 have occurred in the absence of the imposition 

9 of such requirements. Pursuant to subsection 

10 (d), the Administrator shall allocate allowances 

11 from the reserve established hereunder until the 

12 earlier of such time as all such allowances in 

13 the reserve are allocated or December 31, 1999. 

14 ‘‘(3) ADDITIONAL ALLOCATIONS.—In addition 

15 to allowances allocated pursuant to paragraph (1), 

16 in each calendar year beginning in 1995 and ending 

17 in 1999, inclusive, the Administrator shall allocate 

18 for each unit on table A that is located in the States 

19 of Illinois, Indiana, or Ohio (other than units at 

20 Kyger Creek, Clifty Creek and Joppa Steam), allow21 ances in an amount equal to 200,000 multiplied by 

22 the unit’s pro rata share of the total number of al23 lowances allocated for all units on table A in the 3 

24 States (other than units at Kyger Creek, Clifty 

25 Creek, and Joppa Steam) pursuant to paragraph 
94 

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1 (1). Such allowances shall be excluded from the cal2 culation of the reserve under paragraph (2). 

3 ‘‘(b) SUBSTITUTIONS.—The owner or operator of an 

4 affected unit under subsection (a) may include in its sec5 tion 404 permit application and proposed compliance plan 

6 a proposal to reassign, in whole or in part, the affected 

7 unit’s sulfur dioxide reduction requirements to any other 

8 unit(s) under the control of such owner or operator. Such 

9 proposal shall specify— 

10 ‘‘(1) the designation of the substitute unit or 

11 units to which any part of the reduction obligations 

12 of subsection (a) shall be required, in addition to, or 

13 in lieu of, any original affected units designated 

14 under such subsection; 

15 ‘‘(2) the original affected unit’s baseline, the ac16 tual and allowable 1985 emissions rate for sulfur di17 oxide, and the authorized annual allowance alloca18 tion stated in table A; 

19 ‘‘(3) calculation of the annual average tonnage 

20 for calendar years 1985, 1986, and 1987, emitted by 

21 the substitute unit or units, based on the baseline 

22 for each unit, as defined in section 411(4), multi23 plied by the lesser of the unit’s actual or allowable 

24 1985 emissions rate; 
95 

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1 ‘‘(4) the emissions rates and tonnage limita2 tions that would be applicable to the original and 

3 substitute affected units under the substitution pro4 posal; 

5 ‘‘(5) documentation, to the satisfaction of the 

6 Administrator, that the reassigned tonnage limits 

7 will, in total, achieve the same or greater emissions 

8 reduction than would have been achieved by the 

9 original affected unit and the substitute unit or 

10 units without such substitution; and 

11 ‘‘(6) such other information as the Adminis12 trator may require. 

13 ‘‘(c) ADMINISTRATOR’S ACTION ON SUBSTITUTION

14 PROPOSALS.— 

15 ‘‘(1) IN GENERAL.—The Administrator shall 

16 take final action on such substitution proposal in ac17 cordance with section 404(c) if the substitution pro18 posal fulfills the requirements of this subsection. 

19 The Administrator may approve a substitution pro20 posal in whole or in part and with such modifica21 tions or conditions as may be consistent with the or22 derly functioning of the allowance system and which 

23 will ensure the emissions reductions contemplated by 

24 this title. If a proposal does not meet the require25 ments of subsection (b), the Administrator shall dis-
96 

•S 131 IS 

1 approve it. The owner or operator of a unit listed in 

2 table A shall not substitute another unit or units 

3 without the prior approval of the Administrator. 

4 ‘‘(2) ISSUANCE OF PERMITS.—Upon approval of 

5 a substitution proposal, each substitute unit, and 

6 each source with such unit, shall be deemed affected 

7 under this title, and the Administrator shall issue a 

8 permit to the original and substitute affected source 

9 and unit in accordance with the approved substi10 tution plan and section 404. The Administrator shall 

11 allocate allowances for the original and substitute af12 fected units in accordance with the approved substi13 tution proposal pursuant to section 412. It shall be 

14 unlawful for any source or unit that is allocated al15 lowances pursuant to this section to emit sulfur di16 oxide in excess of the emissions limitation provided 

17 for in the approved substitution permit and plan un18 less the owner or operator of each unit governed by 

19 the permit and approved substitution plan holds al20 lowances to emit not less than the unit’s total an21 nual emissions. The owner or operator of any origi22 nal or substitute affected unit operated in violation 

23 of this subsection shall be fully liable for such viola24 tion, including liability for fulfilling the obligations 

25 specified in section 406. If a substitution proposal is 
97 

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1 disapproved, the Administrator shall allocate allow2 ances to the original affected unit or units in accord3 ance with subsection (a). 

4 ‘‘(d) ELIGIBLE PHASE I EXTENSION UNITS.— 

5 ‘‘(1) IN GENERAL.—The owner or operator of 

6 any affected unit subject to an emissions limitation 

7 requirement under this section may petition the Ad8 ministrator in its permit application under section 

9 404 for an extension of 2 years of the deadline for 

10 meeting such requirement, provided that the owner 

11 or operator of any such unit holds allowances to 

12 emit not less than the unit’s total annual emissions 

13 for each of the 2 years of the period of extension. 

14 To qualify for such an extension, the affected unit 

15 must either employ a qualifying phase I technology, 

16 or transfer its phase I emissions reduction obligation 

17 to a unit employing a qualifying phase I technology. 

18 Such transfer shall be accomplished in accordance 

19 with a compliance plan, submitted and approved 

20 under section 404, that shall govern operations at all 

21 units included in the transfer, and that specifies the 

22 emissions reduction requirements imposed pursuant 

23 to this title. 

24 ‘‘(2) REQUIREMENTS FOR EXTENSION PRO25 POSALS.—Such extension proposal shall— 
98 

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1 ‘‘(A) specify the unit or units proposed for 

2 designation as an eligible phase I extension 

3 unit; 

4 ‘‘(B) provide a copy of an executed con5 tract, which may be contingent upon the Ad6 ministrator approving the proposal, for the de7 sign engineering, and construction of the quali8 fying phase I technology for the extension unit, 

9 or for the unit or units to which the extension 

10 unit’s emission reduction obligation is to be 

11 transferred; 

12 ‘‘(C) specify the unit’s or units’ baselines, 

13 actual 1985 emissions rates, allowable 1985 

14 emissions rates, and projected utilizations for 

15 calendar years 1995 through 1999; 

16 ‘‘(D) require CEMS on both the eligible 

17 phase I extension unit or units and the transfer 

18 unit or units beginning no later than January 

19 1, 1995; and 

20 ‘‘(E) specify the emission limitation and 

21 number of allowances expected to be necessary 

22 for annual operation after the qualifying phase 

23 I technology has been installed. 

24 ‘‘(3) APPROVAL OR DISAPPROVAL.—The Ad25 ministrator shall review and take final action on 
99 

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1 each extension proposal in order of receipt, con2 sistent with section 404, and for an approved pro3 posal shall designate the unit or units as an eligible 

4 phase I extension unit. The Administrator may ap5 prove an extension proposal in whole or in part, and 

6 with such modifications or conditions as may be nec7 essary, consistent with the orderly functioning of the 

8 allowance system, and to ensure the emissions reduc9 tions contemplated by the subpart. 

10 ‘‘(4) DETERMINING THE AVAILABILITY OF AL11 LOCATIONS.—In order to determine the number of 

12 proposals eligible for allocations from the reserve 

13 under subsection (a)(2) and the number of the al14 lowances remaining available after each proposal is 

15 acted upon, the Administrator shall reduce the total 

16 number of allowances remaining available in the re17 serve by the number of allowances calculated accord18 ing to subparagraph (A), (B), and (C) until either 

19 no allowances remain available in the reserve for fur20 ther allocation or all approved proposals have been 

21 acted upon. If no allowances remain available in the 

22 reserve for further allocation before all proposals 

23 have been acted upon by the Administrator, any 

24 pending proposals shall be disapproved. The Admin25 istrator shall calculate allowances equal to— 
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1 ‘‘(A) the difference between the lesser of 

2 the average annual emissions in calendar years 

3 1988 and 1989 or the projected emissions ton4 nage for calendar year 1995 of each eligible 

5 phase I extension unit, as designated under 

6 paragraph (3), and the product of the unit’s 

7 baseline multiplied by an emission rate of 2.50 

8 lbs/mmBtu, divided by 2,000; 

9 ‘‘(B) the difference between the lesser of 

10 the average annual emissions in calendar years 

11 1988 and 1989 or the projected emissions ton12 nage for calendar year 1996 of each eligible 

13 phase I extension unit, as designated under 

14 paragraph (3), and the product of the unit’s 

15 baseline multiplied by an emission rate of 2.50 

16 lbs/mmBtu, divided by 2,000; and 

17 ‘‘(C) the amount by which (i) the product 

18 of each unit’s baseline multiplied by an emis19 sion rate of 1.20 lbs/mmBtu, divided by 2,000, 

20 exceeds (ii) the tonnage level specified under 

21 subparagraph (E) of paragraph (2) of this sub22 section multiplied by a factor of 3. 

23 ‘‘(5) ALLOCATION OF INITIAL ALLOWANCES.— 

24 Each eligible phase I extension unit shall receive al25 lowances determined under subsection (a)(1) or (c) 
101 

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1 of this section. In addition, for calendar year 1995, 

2 the Administrator shall allocate to each eligible 

3 phase I extension unit, from the allowance reserve 

4 created pursuant to subsection (a)(2), allowances 

5 equal to the difference between the lesser of the av6 erage annual emissions in calendar years 1988 and 

7 1989 or its projected emission tonnage for calendar 

8 year 1995 and the product of the unit’s baseline 

9 multiplied by an emission rate of 2.50 lbs/mmBtu, 

10 divided by 2,000. In calendar year 1996, the Admin11 istrator shall allocate for each eligible unit, from the 

12 allowance reserve created pursuant to subsection 

13 (a)(2), allowances equal to the difference between 

14 the lesser of the average annual emissions in cal15 endar years 1988 and 1989 or its projected emis16 sions tonnage for calendar year 1996 and the prod17 uct of the unit’s baseline multiplied by an emission 

18 rate of 2.50 lbs/mmBtu, divided by 2,000. It shall 

19 be unlawful for any source or unit subject to an ap20 proved extension plan under this subsection to emit 

21 sulfur dioxide in excess of the emissions limitations 

22 provided for in the permit and approved extension 

23 plan, unless the owner or operator of each unit gov24 erned by the permit and approved plan holds allow-
102 

•S 131 IS 

1 ances to emit not less than the unit’s total annual 

2 emissions. 

3 ‘‘(6) ALLOCATION OF ADDITIONAL ALLOW4 ANCES.—In addition to allowances specified in para5 graph (4), the Administrator shall allocate for each 

6 eligible phase I extension unit employing qualifying 

7 phase I technology, for calendar years 1997, 1998, 

8 and 1999, additional allowances, from any remaining 

9 allowances in the reserve created pursuant to sub10 section (a)(2), following the reduction in the reserve 

11 provided for in paragraph (4), not to exceed the 

12 amount by which (A) the product of each eligible 

13 unit’s baseline times an emission rate of 1.20 lbs/ 

14 mmBtu, divided by 2,000 exceeds (B) the tonnage 

15 level specified under subparagraph (E) of paragraph 

16 (2) of this subsection. 

17 ‘‘(7) DEDUCTION FROM ANNUAL ALLOWANCE

18 ALLOCATIONS.—After January 1, 1997, in addition 

19 to any liability under this Act, including under sec20 tion 406, if any eligible phase I extension unit em21 ploying qualifying phase I technology or any transfer 

22 unit under this subsection emits sulfur dioxide in ex23 cess of the annual tonnage limitation specified in the 

24 extension plan, as approved in paragraph (2) of this 

25 subsection, the Administrator shall, in the calendar 
103 

•S 131 IS 

1 year following such excess, deduct allowances equal 

2 to the amount of such excess from such unit’s an3 nual allowance allocation. 

4 ‘‘(e) EARLY REDUCTIONS.— 

5 ‘‘(1) IN GENERAL.—In the case of a unit that 

6 receives authorization from the Governor of the 

7 State in which such unit is located to make reduc8 tions in the emissions of sulfur dioxide prior to cal9 endar year 1995 and that is part of a utility system 

10 that meets the following requirements— 

11 ‘‘(A) the total coal-fired generation within 

12 the utility system as a percentage of total sys13 tem generation decreased by more than 20 per14 cent between January 1, 1980, and December 

15 31, 1985; and 

16 ‘‘(B) the weighted capacity factor of all 

17 coal-fired units within the utility system aver18 aged over the period from January 1, 1985, 

19 through December 31, 1987, was below 50 per20 cent, the Administrator shall allocate allowances 

21 under this paragraph for the unit pursuant to 

22 this subsection. The Administrator shall allo23 cate allowances for a unit that is an affected 

24 unit pursuant to section 414 (but is not also an 

25 affected unit under this section) and part of a 
104 

•S 131 IS 

1 utility system that includes one or more af2 fected units under section 414 for reductions in 

3 the emissions of sulfur dioxide made during the 

4 period 1995–1999 if the unit meets the require5 ments of this subsection and the requirements 

6 of the preceding sentence, except that for the 

7 purposes of applying this subsection to any 

8 such unit, the prior year concerned as specified 

9 below, shall be any year after January 1, 1995 

10 but prior to January 1, 2000. 

11 ‘‘(2) LIMITATIONS.—In the case of an affected 

12 unit under this section described in subparagraph 

13 (A), the allowances allocated under this subsection 

14 for early reductions in any prior year may not ex15 ceed the amount which (A) the product of the unit’s 

16 baseline multiplied by the unit’s 1985 actual sulfur 

17 dioxide emission rate (in lbs per mmBtu), divided by 

18 2,000 exceeds (B) the allowances specified for such 

19 unit in table A. In the case of an affected unit under 

20 section 414, the allowances awarded under this sub21 section for early reductions in any prior year may 

22 not exceed the amount by which— 

23 ‘‘(A) the product of— 
105 

•S 131 IS 

1 ‘‘(i) the quantity of fossil fuel con2 sumed by the unit (in mmBtu) in the prior 

3 year multiplied by— 

4 ‘‘(ii) the lesser of— 

5 ‘‘(I) 2.50, or 

6 ‘‘(II) the most stringent emission 

7 rate (in lbs per mmBtu) applicable to 

8 the unit under the applicable imple9 mentation plan— 

10 divided by 2,000 exceeds 

11 ‘‘(B) the unit’s actual tonnage of sulfur di12 oxide emission for the prior year concerned. 

13 Allowances allocated under this subsection for units 

14 may be allocated only for emission reductions 

15 achieved as a result of physical changes or changes 

16 in the method of operation made after November 15, 

17 1990, including changes in the type or quantity of 

18 fossil fuel consumed. 

19 ‘‘(3) NO BASIS FOR EXCUSED NONPERFORM20 ANCE.—In no event shall the provisions of this para21 graph be interpreted as an event of force majeure or 

22 a commercial impracticability or in any other way as 

23 a basis for excused nonperformance by a utility sys24 tem under a coal sales contract in effect before No25 vember 15, 1990. 
106 

•S 131 IS 

‘‘TABLE A—AFFECTED SOURCES AND UNITS IN PHASE 

I AND THEIR SULFUR DIOXIDE ALLOWANCES (TONS) 

State Plant name Generator Phase I 

allowances 

Alabama ......................... Colbert ........................... 1 13,570 

2 15,310 

3 15,400 

4 15,410 

5 37,180 

E.C. Gaston ................... 1 18,100 

2 18,540 

3 18,310 

4 19,280 

5 59,840 

Florida ............................ Big Bend ....................... 1 28,410 

2 27,100 

3 26,740 

Crist ............................... 6 19,200 

7 31,680 

Georgia ........................... Bowen ............................ 1 56,320 

2 54,770 

3 71,750 

4 71,740 

Hammond ...................... 1 8,780 

2 9,220 

3 8,910 

4 37,640 

J. McDonough ............... 1 19,910 

2 20,600 

Wansley ......................... 1 70,770 

2 65,430 

Yates .............................. 1 7,210 

2 7,040 

3 6,950 

4 8,910 

5 9,410 

6 24,760 

7 21,480 

Illinois ............................. Baldwin ......................... 1 42,010 

2 44,420 

3 42,550 

Coffeen .......................... 1 11,790 

2 35,670 

Grand Tower ................. 4 5,910 

Hennepin ....................... 2 18,410 

Joppa Steam ................. 1 12,590 

2 10,770 

3 12,270 

4 11,360 

5 11,420 

6 10,620 

Kincaid .......................... 1 31,530 

2 33,810 

Meredosia ...................... 3 13,890 
107 

•S 131 IS 

‘‘TABLE A—AFFECTED SOURCES AND UNITS IN PHASE 

I AND THEIR SULFUR DIOXIDE ALLOWANCES 

(TONS)—Continued 

State Plant name Generator Phase I 

allowances 

Vermilion ....................... 2 8,880 

Indiana ........................... Bailly ............................. 7 11,180 

8 15,630 

Breed ............................. 1 18,500 

Cayuga ........................... 1 33,370 

2 34,130 

Clifty Creek ................... 1 20,150 

2 19,810 

3 20,410 

4 20,080 

5 19,360 

6 20,380 

E.W. Stout .................... 5 3,880 

6 4,770 

7 23,610 

F.B. Culley .................... 2 4,290 

3 16,970 

F.E. Ratts ..................... 1 8,330 

2 8,480 

Gibson ........................... 1 40,400 

2 41,010 

3 41,080 

4 40,320 

H.T. Pritchard .............. 6 5,770 

Michigan City ................ 12 23,310 

Petersburg..................... 1 16,430 

2 32,380 

R. Gallagher .................. 1 6,490 

2 7,280 

3 6,530 

4 7,650 

Tanners Creek ............... 4 24,820 

Wabash River ................ 1 4,000 

2 2,860 

3 3,750 

5 3,670 

6 12,280 

Warrick .......................... 4 26,980 

Iowa ................................ Burlington ..................... 1 10,710 

Des Moines .................... 7 2,320 

George Neal ................... 1 1,290 

M.L. Kapp ..................... 2 13,800 

Prairie Creek ................. 4 8,180 

Riverside ........................ 5 3,990 

Kansas ............................ Quindaro ........................ 2 4,220 

Kentucky ........................ Coleman ......................... 1 11,250 

2 12,840 

3 12,340 

Cooper ........................... 1 7,450 
108 

•S 131 IS 

‘‘TABLE A—AFFECTED SOURCES AND UNITS IN PHASE 

I AND THEIR SULFUR DIOXIDE ALLOWANCES 

(TONS)—Continued 

State Plant name Generator Phase I 

allowances 

2 15,320 

E.W. Brown .................. 1 7,110 

2 10,910 

3 26,100 

Elmer Smith .................. 1 6,520 

2 14,410 

Ghent ............................. 1 28,410 

Green River ................... 4 7,820 

H.L. Spurlock ............... 1 22,780 

Henderson II ................. 1 13,340 

2 12,310 

Paradise ......................... 3 59,170 

Shawnee ......................... 10 10,170 

Maryland ........................ Chalk Point ................... 1 21,910 

2 24,330 

C.P. Crane ..................... 1 10,330 

2 9,230 

Morgantown ................... 1 35,260 

2 38,480 

Michigan ......................... J.H. Campbell ............... 1 19,280 

2 23,060 

Minnesota ....................... High Bridge .................. 6 4,270 

Mississippi ...................... Jack Watson .................. 4 17,910 

5 36,700 

Missouri .......................... Asbury ........................... 1 16,190 

James River .................. 5 4,850 

Labadie .......................... 1 40,110 

2 37,710 

3 40,310 

4 35,940 

Montrose ........................ 1 7,390 

2 8,200 

3 10,090 

New Madrid ................... 1 28,240 

2 32,480 

Sibley ............................. 3 15,580 

Sioux .............................. 1 22,570 

2 23,690 

Thomas Hill .................. 1 10,250 

2 19,390 

New Hampshire .............. Merrimack ..................... 1 10,190 

2 22,000 

New Jersey ..................... B.L. England ................ 1 9,060 

2 11,720 

New York ....................... Dunkirk ......................... 3 12,600 

4 14,060 

Greenidge ...................... 4 7,540 

Milliken .......................... 1 11,170 

2 12,410 
109 

•S 131 IS 

‘‘TABLE A—AFFECTED SOURCES AND UNITS IN PHASE 

I AND THEIR SULFUR DIOXIDE ALLOWANCES 

(TONS)—Continued 

State Plant name Generator Phase I 

allowances 

Northport ...................... 1 19,810 

2 24,110 

3 26,480 

Port Jefferson ............... 3 10,470 

4 12,330 

Ohio ................................ Ashtabula ...................... 5 16,740 

Avon Lake ..................... 8 11,650 

9 30,480 

Cardinal ......................... 1 34,270 

2 38,320 

Conesville ....................... 1 4,210 

2 4,890 

3 5,500 

4 48,770 

Eastlake ......................... 1 7,800 

2 8,640 

3 10,020 

4 14,510 

5 34,070 

Edgewater ..................... 4 5,050 

Gen. J.M. Gavin ............ 1 79,080 

2 80,560 

Kyger Creek .................. 1 19,280 

2 18,560 

3 17,910 

4 18,710 

5 18,740 

Miami Fort .................... 5 760 

6 11,380 

7 38,510 

Muskingum River .......... 1 14,880 

2 14,170 

3 13,950 

4 11,780 

5 40,470 

Niles .............................. 1 6,940 

2 9,100 

Picway ........................... 5 4,930 

R.E. Burger .................. 3 6,150 

4 10,780 

5 12,430 

W.H. Sammis ................ 5 24,170 

6 39,930 

7 43,220 

W.C. Beckjord ............... 5 8,950 

6 23,020 

Pennsylvania ................... Armstrong..................... 1 14,410 

2 15,430 

Brunner Island .............. 1 27,760 
110 

•S 131 IS 

‘‘TABLE A—AFFECTED SOURCES AND UNITS IN PHASE 

I AND THEIR SULFUR DIOXIDE ALLOWANCES 

(TONS)—Continued 

State Plant name Generator Phase I 

allowances 

2 31,100 

3 53,820 

Cheswick ........................ 1 39,170 

Conemaugh .................... 1 59,790 

2 66,450 

Hatfield’s Ferry ............ 1 37,830 

2 37,320 

3 40,270 

Martins Creek ............... 1 12,660 

2 12,820 

Portland ........................ 1 5,940 

2 10,230 

Shawville ........................ 1 10,320 

2 10,320 

3 14,220 

4 14,070 

Sunbury ......................... 3 8,760 

4 11,450 

Tennessee ....................... Allen .............................. 1 15,320 

2 16,770 

3 15,670 

Cumberland ................... 1 86,700 

2 94,840 

Gallatin .......................... 1 17,870 

2 17,310 

3 20,020 

4 21,260 

Johnsonville ................... 1 7,790 

2 8,040 

3 8,410 

4 7,990 

5 8,240 

6 7,890 

7 8,980 

8 8,700 

9 7,080 

10 7,550 

West Virginia ................. Albright ......................... 3 12,000 

Fort Martin ................... 1 41,590 

2 41,200 

Harrison ........................ 1 48,620 

2 46,150 

3 41,500 

Kammer ......................... 1 18,740 

2 19,460 

3 17,390 

Mitchell .......................... 1 43,980 

2 45,510 

Mount Storm ................. 1 43,720 
111 

•S 131 IS 

‘‘TABLE A—AFFECTED SOURCES AND UNITS IN PHASE 

I AND THEIR SULFUR DIOXIDE ALLOWANCES 

(TONS)—Continued 

State Plant name Generator Phase I 

allowances 

2 35,580 

3 42,430 

Wisconsin ....................... Edgewater ..................... 4 24,750 

La Crosse/Genoa ........... 3 22,700 

Nelson Dewey ................ 1 6,010 

2 6,680 

N. Oak Creek ................ 1 5,220 

2 5,140 

3 5,370 

4 6,320 

Pulliam .......................... 8 7,510 

S. Oak Creek ................. 5 9,670 

6 12,040 

7 16,180 

8 15,790 

1 ‘‘(f) ENERGY CONSERVATION AND RENEWABLE EN2 ERGY.— 

3 ‘‘(1) DEFINITIONS.—As used in this subsection: 

4 ‘‘(A) QUALIFIED ENERGY CONSERVATION

5 MEASURE.—The term ‘qualified energy con6 servation measure’ means a cost effective meas7 ure, as identified by the Administrator in con8 sultation with the Secretary of Energy, that in9 creases the efficiency of the use of electricity 

10 provided by an electric utility to its customers. 

11 ‘‘(B) QUALIFIED RENEWABLE ENERGY.— 

12 The term ‘qualified renewable energy’ means 

13 energy derived from biomass, solar, geothermal, 

14 or wind as identified by the Administrator in 

15 consultation with the Secretary of Energy. 
112 

•S 131 IS 

1 ‘‘(C) ELECTRIC UTILITY.—The term ‘elec2 tric utility’ means any person, State agency, or 

3 Federal agency, which sells electric energy. 

4 ‘‘(2) ALLOWANCES FOR EMISSIONS AVOIDED

5 THROUGH ENERGY CONSERVATION AND RENEWABLE

6 ENERGY.— 

7 ‘‘(A) IN GENERAL.—The regulations under 

8 paragraph (4) of this subsection shall provide 

9 that for each ton of sulfur dioxide emissions 

10 avoided by an electric utility, during the appli11 cable period, through the use of qualified en12 ergy conservation measures or qualified renew13 able energy, the Administrator shall allocate a 

14 single allowance to such electric utility, on a 

15 first-come-first-served basis from the Conserva16 tion and Renewable Energy Reserve established 

17 under subsection (g), up to a total of 300,000 

18 allowances for allocation from such Reserve. 

19 ‘‘(B) REQUIREMENTS FOR ISSUANCE.— 

20 The Administrator shall allocate allowances to 

21 an electric utility under this subsection only if 

22 all of the following requirements are met: 

23 ‘‘(i) Such electric utility is paying for 

24 or participating in the qualified energy 
113 

•S 131 IS 

1 conservation measures or qualified renew2 able energy. 

3 ‘‘(ii) The emissions of sulfur dioxide 

4 avoided through the use of qualified energy 

5 conservation measures or qualified renew6 able energy are quantified in accordance 

7 with regulations promulgated by the Ad8 ministrator under this subsection. 

9 ‘‘(iii)(I) Such electric utility has 

10 adopted and is implementing a least cost 

11 energy conservation and electric power 

12 plan which evaluates a range of resources, 

13 including new power supplies, energy con14 servation, and renewable energy resources, 

15 in order to meet expected future demand 

16 at the lowest system cost. 

17 ‘‘(II) The qualified energy conserva18 tion measures or qualified renewable en19 ergy, or both, are consistent with that 

20 plan. 

21 ‘‘(III) In the case of electric utilities 

22 subject to the jurisdiction of a State regu23 latory authority such plan shall have been 

24 approved by such authority. For electric 

25 utilities not subject to the jurisdiction of a 
114 

•S 131 IS 

1 State regulatory authority such plan shall 

2 have been approved by the Administrator. 

3 ‘‘(iv) In the case of qualified energy 

4 conservation measures undertaken by a 

5 State regulated electric utility, the Sec6 retary of Energy has certified that the 

7 State regulatory authority with jurisdiction 

8 over the electric rates of such electric util9 ity has established rates and charges which 

10 ensure that the net income of such electric 

11 utility after implementation of specific cost 

12 effective energy conservation measures is 

13 at least as high as such net income would 

14 have been if the energy conservation meas15 ures had not been implemented. Upon the 

16 date of any such certification by the Sec17 retary of Energy, all allowances which, but 

18 for this paragraph, would have been allo19 cated under subparagraph (B) before such 

20 date, shall be allocated to the electric util21 ity. This clause is not a requirement for 

22 qualified renewable energy. 

23 ‘‘(v) Such utility or any subsidiary of 

24 the utility’s holding company owns or oper25 ates at least one affected unit. 
115 

•S 131 IS 

1 ‘‘(C) PERIOD OF APPLICABILITY.—Allow2 ances under this subsection shall be allocated 

3 only with respect to kilowatt hours of electric 

4 energy saved by qualified energy conservation 

5 measures or generated by qualified renewable 

6 energy after January 1, 1992, and before the 

7 earlier of (i) December 31, 2000, or (ii) the 

8 date on which any electric utility steam gener9 ating unit owned or operated by the electric 

10 utility to which the allowances are allocated be11 comes subject to this subpart (including those 

12 sources that elect to become affected by this 

13 title, pursuant to section 417). 

14 ‘‘(D) DETERMINATION OF AVOIDED EMIS15 SIONS.— 

16 ‘‘(i) APPLICATION.—In order to re17 ceive allowances under this subsection, an 

18 electric utility shall make an application 

19 which— 

20 ‘‘(I) designates the qualified en21 ergy conservation measures imple22 mented and the qualified renewable 

23 energy sources used for purposes of 

24 avoiding emissions; 
116 

•S 131 IS 

1 ‘‘(II) calculates, in accordance 

2 with subparagraphs (F) and (G), the 

3 number of tons of emissions avoided 

4 by reason of the implementation of 

5 such measures or the use of such re6 newable energy sources; and 

7 ‘‘(III) demonstrates that the re8 quirements of subparagraph (B) have 

9 been met. 

10 ‘‘(ii) APPROVAL.—Such application 

11 for allowances by a State-regulated electric 

12 utility shall require approval by the State 

13 regulatory authority with jurisdiction over 

14 such electric utility. The authority shall re15 view the application for accuracy and com16 pliance with this subsection and the rules 

17 under this subsection. Electric utilities 

18 whose retail rates are not subject to the ju19 risdiction of a State regulatory authority 

20 shall apply directly to the Administrator 

21 for such approval. 

22 ‘‘(E) AVOIDED EMISSIONS FROM QUALI23 FIED ENERGY CONSERVATION MEASURES.—For 

24 the purposes of this subsection, the emission 

25 tonnage deemed avoided by reason of the imple-
117 

•S 131 IS 

1 mentation of qualified energy conservation 

2 measures for any calendar year shall be a ton3 nage equal to the product of multiplying— 

4 ‘‘(i) the kilowatt hours that would 

5 otherwise have been supplied by the utility 

6 during such year in the absence of such 

7 qualified energy conservation measures; by 

8 ‘‘(ii) 0.004, and dividing the product 

9 so derived by 2,000. 

10 ‘‘(F) AVOIDED EMISSIONS FROM THE USE

11 OF QUALIFIED RENEWABLE ENERGY.—The 

12 emissions tonnage deemed avoided by reason of 

13 the use of qualified renewable energy by an 

14 electric utility for any calendar year shall be a 

15 tonnage equal to the product of multiplying— 

16 ‘‘(i) the actual kilowatt hours gen17 erated by, or purchased from, qualified re18 newable energy; by 

19 ‘‘(ii) 0.004, and dividing the product 

20 so derived by 2,000. 

21 ‘‘(G) PROHIBITIONS.— 

22 ‘‘(i) No allowances shall be allocated 

23 under this subsection for the implementa24 tion of programs that are exclusively infor25 mational or educational in nature. 
118 

•S 131 IS 

1 ‘‘(ii) No allowances shall be allocated 

2 for energy conservation measures or renew3 able energy that were operational before 

4 January 1, 1992. 

5 ‘‘(3) SAVINGS PROVISION.—Nothing in this sub6 section precludes a State or State regulatory author7 ity from providing additional incentives to utilities to 

8 encourage investment in demand-side resources. 

9 ‘‘(4) REGULATIONS.—The Administrator shall 

10 implement this subsection under 40 CFR part 73 

11 (2002), amended as appropriate by the Adminis12 trator. Such regulations shall list energy conserva13 tion measures and renewable energy sources which 

14 may be treated as qualified energy conservation 

15 measures and qualified renewable energy for pur16 poses of this subsection. Allowances shall only be al17 located if all requirements of this subsection and the 

18 rules promulgated to implement this subsection are 

19 complied with. The Administrator shall review the 

20 determinations of each State regulatory authority 

21 under this subsection to encourage consistency from 

22 electric utility and from State-to-State in accordance 

23 with the Administrator’s rules. The Administrator 

24 shall publish and make available to the public the 

25 findings of this review no less than annually. 
119 

•S 131 IS 

1 ‘‘(g) CONSERVATION AND RENEWABLE ENERGY RE2 SERVE.—The Administrator shall establish a Conservation 

3 and Renewable Energy Reserve under this subsection. Be4 ginning on January 1, 1995, the Administrator may allo5 cate from the Conservation and Renewable Energy Re6 serve an amount equal to a total of 300,000 allowances 

7 for emissions of sulfur dioxide pursuant to section 411. 

8 In order to provide 300,000 allowances for such reserve, 

9 in each year beginning in calendar year 2000 and until 

10 calendar year 2009, inclusive, the Administrator shall re11 duce each unit’s basic phase II allowance allocation on the 

12 basis of its pro rata share of 30,000 allowances. Notwith13 standing the prior sentence, if allowances remain in the 

14 reserve on January 1, 2010, the Administrator shall allo15 cate such allowances for affected units under section 414 

16 on a pro rata basis. For purposes of this subsection, for 

17 any unit subject to the emissions limitation requirements 

18 of section 414, the term ‘pro rata basis’ refers to the ratio 

19 which the reductions made in such unit’s allowances in 

20 order to establish the reserve under this subsection bears 

21 to the total of such reductions for all such units. 

22 ‘‘(h) ALTERNATIVE ALLOWANCE ALLOCATION FOR

23 UNITS IN CERTAIN UTILITY SYSTEMS WITH OPTIONAL

24 BASELINE.— 
120 

•S 131 IS 

1 ‘‘(1) OPTIONAL BASELINE FOR UNITS IN CER2 TAIN SYSTEMS.—In the case of a unit subject to the 

3 emissions limitation requirements of this section 

4 which (as of November 15, 1990)— 

5 ‘‘(A) has an emission rate below 1.0 lbs/ 

6 mmBtu, 

7 ‘‘(B) has decreased its sulfur dioxide emis8 sions rate by 60 percent or greater since 1980, 

9 and 

10 ‘‘(C) is part of a utility system which has 

11 a weighted average sulfur dioxide emissions rate 

12 for all fossil fueled-fired units below 1.0 lbs/ 

13 mmBtu, at the election to the owner or oper14 ator of such unit, the unit’s baseline may be 

15 calculated— 

16 ‘‘(i) as provided under section 411, or 

17 ‘‘(ii) by utilizing the unit’s average 

18 annual fuel consumption at a 60 percent 

19 capacity factor. Such election shall be 

20 made no later than March 1, 1991. 

21 ‘‘(2) ALLOWANCE ALLOCATION.—Whenever a 

22 unit referred to in paragraph (1) elects to calculate 

23 its baseline as provided in clause (ii) of paragraph 

24 (1), the Administrator shall allocate allowances for 

25 the unit pursuant to section 412(a), this section, 
121 

•S 131 IS 

1 and section 414 (as basic phase II allowance alloca2 tions) in an amount equal to the baseline selected 

3 multiplied by the lower of the average annual emis4 sion rate for such unit in 1989, or 1.0 lbs/mmBtu. 

5 Such allowance allocation shall be in lieu of any allo6 cation of allowances under this section and section 

7 414. 

8 ‘‘SEC. 414. PHASE II SULFUR DIOXIDE REQUIREMENTS. 

9 ‘‘(a) APPLICABILITY.— 

10 ‘‘(1) BASIC PHASE II ALLOWANCE ALLOCA11 TIONS.—After January l, 2000, each existing utility 

12 unit as provided below is subject to the limitations 

13 or requirements of this section. Each utility unit 

14 subject to an annual sulfur dioxide tonnage emission 

15 limitation under this section is an affected unit 

16 under this subpart. Each source that includes one or 

17 more affected units is an affected source. In the case 

18 of an existing unit that was not in operation during 

19 calendar year 1985, the emission rate for a calendar 

20 year after 1985, as determined by the Adminis21 trator, shall be used in lieu of the 1985 rate. 

22 ‘‘(2) BASIC PHASE II BONUS ALLOWANCE ALLO23 CATIONS.—In addition to basic phase II allowance 

24 allocations, in each year beginning in calendar year 

25 2000 and ending in calendar year 2009, inclusive, 
122 

•S 131 IS 

1 the Administrator shall allocate up to 530,000 phase 

2 II bonus allowances pursuant to subsections (b)(2), 

3 (c)(4), (d)(3) (A) and (B), and (h)(2) of this section 

4 and section 415. 

5 ‘‘(3) ADDITIONAL ALLOWANCE ALLOCATIONS

6 FOR CERTAIN AFFECTED SOURCES AND UNITS.—In 

7 addition to basic phase II allowances allocations and 

8 phase II bonus allowance allocations, beginning Jan9 uary 1, 2000, the Administrator shall allocate for 

10 each unit listed on table A in section 413 (other 

11 than units at Kyger Creek, Clifty Creek, and Joppa 

12 Stream) and located in the States of Illinois, Indi13 ana, Ohio, Georgia, Alabama, Missouri, Pennsyl14 vania, West Virginia, Kentucky, or Tennessee allow15 ances in an amount equal to 50,000 multiplied by 

16 the unit’s pro rata share of the total number of 

17 basic allowances allocated for all units listed on table 

18 A (other than units at Kyger Creek, Clifty Creek, 

19 and Joppa Stream). Allowances allocated pursuant 

20 to this paragraph shall not be subject to the 

21 8,900,000 ton limitation in section 412(a). 

22 ‘‘(b) UNITS EQUAL TO, OR ABOVE, 75 MWE AND

23 1.20 LBS/MMBTU.— 

24 ‘‘(1) BASIC PHASE II ALLOWANCE ALLOCA25 TIONS.—Except as otherwise provided in paragraph 
123 

•S 131 IS 

1 (3), after January 1, 2000, it shall be unlawful for 

2 any existing utility unit that serves a generator with 

3 nameplate capacity equal to, or greater, than 75 

4 MWe and an actual 1985 emission rate equal to or 

5 greater than 1.20 lbs/mmBtu to exceed an annual 

6 sulfur dioxide tonnage emission limitation equal to 

7 the product of the unit’s baseline multiplied by an 

8 emission rate equal to 1.20 lbs/mmBtu, divided by 

9 2,000, unless the owner or operator of such unit 

10 holds allowances to emit not less than the unit’s 

11 total annual emissions or, for a year after 2007, un12 less the owner or operator of the source that in13 cludes such unit holds allowances to emit not less 

14 than the total annual emissions of all affected units 

15 at the source. 

16 ‘‘(2) RESERVE ALLOWANCES.—In addition to 

17 allowances allocated pursuant to paragraph (1) and 

18 section 412(a) as basic phase II allowance alloca19 tions, beginning January 1, 2000, and for each cal20 endar year thereafter until and including 2009, the 

21 Administrator shall allocate annually for each unit 

22 subject to the emissions limitation requirements of 

23 paragraph (1) with an actual 1985 emissions rate 

24 greater than 1.20 lbs/mmBtu and less than 2.50 lbs/ 

25 mmBtu and a baseline capacity factor of less than 
124 

•S 131 IS 

1 60 percent, allowances from the reserve created pur2 suant to subsection (a)(2) in an amount equal to 

3 1.20 lbs/mmBtu multiplied by 50 percent of the dif4 ference, on a Btu basis, between the unit’s baseline 

5 and the unit’s fuel consumption at a 60 percent ca6 pacity factor. 

7 ‘‘(3) PROHIBITION.—After January 1, 2000, it 

8 shall be unlawful for any existing utility unit with an 

9 actual 1985 emissions rate equal to or greater than 

10 1.20 lbs/mmBtu whose annual average fuel con11 sumption during 1985, 1986, and 1987 on a Btu 

12 basis exceeded 90 percent in the form of lignite coal 

13 which is located in a State in which, as of July 1, 

14 1989, no county or portion of a county was des15 ignated nonattainment under section 107 of this Act 

16 for any pollutant subject to the requirements of sec17 tion 109 of this Act to exceed an annual sulfur diox18 ide tonnage limitation equal to the product of the 

19 unit’s baseline multiplied by the lesser of the unit’s 

20 actual 1985 emissions rate or its allowable 1985 

21 emissions rate, divided by 2,000, unless the owner or 

22 operator of such unit holds allowances to emit not 

23 less than the unit’s total annual emissions or, for a 

24 year after 2007, unless the owner or operator of the 

25 source that includes such unit holds allowances to 
125 

•S 131 IS 

1 emit not less than the total annual emissions of all 

2 affected units at the source. 

3 ‘‘(4) ANNUAL ALLOWANCE ALLOCATIONS.— 

4 After January 1, 2000, the Administrator shall allo5 cate annually for each unit, subject to the emissions 

6 limitation requirements of paragraph (1), which is 

7 located in a State with an installed electrical gener8 ating capacity of more than 30,000,000 kw in 1988 

9 and for which was issued a prohibition order or a 

10 proposed prohibition order (from burning oil), which 

11 unit subsequently converted to coal between January 

12 1, 1980, and December 31, 1985, allowances equal 

13 to the difference between (A) the product of the 

14 unit’s annual fuel consumption, on a Btu basis, at 

15 a 65 percent capacity factor multiplied by the lesser 

16 of its actual or allowable emissions rate during the 

17 first full calendar year after conversion, divided by 

18 2,000, and (B) the number of allowances allocated 

19 for the unit pursuant to paragraph (1): Provided, 

20 That the number of allowances allocated pursuant to 

21 this paragraph shall not exceed an annual total of 

22 five thousand. If necessary to meeting the restriction 

23 imposed in the preceding sentence the Administrator 

24 shall reduce, pro rata, the annual allowances allo25 cated for each unit under this paragraph. 
126

•S 131 IS 

1 ‘‘(c) COAL OR OIL-FIRED UNITS BELOW 75 MWE

2 AND ABOVE 1.20 LBS/MMBTU.— 

3 ‘‘(1) STEAM-ELECTRIC CAPACITY EQUAL TO OR

4 GREATER THAN 250 MWE.—Except as otherwise pro5 vided in paragraph (3), after January 1, 2000, it 

6 shall be unlawful for a coal or oil-fired existing util7 ity unit that serves a generator with nameplate ca8 pacity of less than 75 MWe and an actual 1985 

9 emission rate equal to, or greater than, 1.20 lbs/

10 mmBtu and which is a unit owned by a utility oper11 ating company whose aggregate nameplate fossil fuel 

12 steam-electric capacity is, as of December 31, 1989, 

13 equal to, or greater than, 250 MWe to exceed an an14 nual sulfur dioxide emissions limitation equal to the 

15 product of the unit’s baseline multiplied by an emis16 sion rate equal to 1.20 lbs/mmBtu, divided by 2,000 

17 unless the owner or operator of such unit holds al18 lowances to emit not less than the unit’s total an19 nual emissions for a year after 2007, or the owner 

20 or operator of the source that includes such unit 

21 holds allowances to emit not less than the total an22 nual emissions of all affected units at the source. 

23 ‘‘(2) STEAM-ELECTRIC CAPACITY LESS THAN

24 250 MWE.—After January 1, 2000, it shall be unlaw25 ful for a coal or oil-fired existing utility unit that 
127 

•S 131 IS 

1 serves a generator with nameplate capacity of less 

2 than 75 MWe and an actual 1985 emission rate 

3 equal to, or greater than, 1.20 lbs/mmBtu (excluding 

4 units subject to section 111 of the Act or to a feder5 ally enforceable emissions limitation for sulfur diox6 ide equivalent to an annual rate of less than 1.20 

7 lbs/mmBtu) and which is a unit owned by a utility 

8 operating company whose aggregate nameplate fossil 

9 fuel steam-electric capacity is, as of December 31, 

10 1989, less than 250 MWe, to exceed an annual sul11 fur dioxide tonnage emissions limitation equal to the 

12 product of the unit’s baseline multiplied by the less13 er of its actual 1985 emissions rate or its allowable 

14 1985 emissions rate, divided by 2,000, unless the 

15 owner or operator of such unit holds allowances to 

16 emit not less than the unit’s total annual emissions, 

17 for a year after 2007, or the owner or operator of 

18 the source that includes such unit holds allowances 

19 to emit not less than the total annual emissions of 

20 all affected units at the source. 

21 ‘‘(3) STEAM-ELECTRIC CAPACITY BETWEEN 250

22 AND 450 MWE.—After January 1, 2000 it shall be 

23 unlawful for any existing utility unit with a name24 plate capacity below 75 MWe and an actual 1985 

25 emissions rate equal to, or greater than, 1.20 lbs/ 
128 

•S 131 IS 

1 mmBtu which became operational on or before De2 cember 31, 1965, which is owned by a utility oper3 ating company with, as of December 31, 1989, a 

4 total fossil fuel steam-electric generating capacity 

5 greater than 250 MWe, and less than 450 MWe 

6 which serves fewer than 78,000 electrical customers 

7 as of November 15, 1990, to exceed an annual sul8 fur dioxide emissions tonnage limitation equal to the 

9 product of its baseline multiplied by the lesser of its 

10 actual or allowable 1985 emission rate, divided by 

11 2,000, unless the owner or operator holds allowances 

12 to emit not less than the units total annual emis13 sions or, for a year after 2007, unless the owner or 

14 operator of the source that includes such unit holds 

15 allowances to emit not less than the total annual 

16 emissions of all affected units at the source. After 

17 January 1, 2010, it shall be unlawful for each unit 

18 subject to the emissions limitation requirements of 

19 this paragraph to exceed an annual emissions ton20 nage limitation equal to the product of its baseline 

21 multiplied by an emissions rate of 1.20 lbs/mmBtu, 

22 divided by 2,000, unless the owner or operator holds 

23 allowances to emit not less than the unit’s total an24 nual emissions for a year after 2007, or the owner 

25 or operator of the source that includes such unit 
129 

•S 131 IS 

1 holds allowances to emit not less than the total an2 nual emissions of all affected units at the source. 

3 ‘‘(4) RESERVE ALLOWANCES.—In addition to 

4 allowances allocated pursuant to paragraph (1) and 

5 section 412(a) as basic phase II allowance alloca6 tions, beginning January 1, 2000, and for each cal7 endar year thereafter until and including 2009, in8 clusive, the Administrator shall allocate annually for 

9 each unit subject to the emissions limitation require10 ments of paragraph (1) with an actual 1985 emis11 sions rate equal to, or greater than, 1.20 lbs/mmBtu 

12 and less than 2.50 lbs/mmBtu and a baseline capac13 ity factor of less than 60 percent, allowances from 

14 the reserve created pursuant to subsection (a)(2) in 

15 an amount equal to 1.20 lbs/mmBtu multiplied by 

16 50 percent of the difference, on a Btu basis, between 

17 the unit’s baseline and the unit’s fuel consumption 

18 at a 60 percent capacity factor. 

19 ‘‘(5) CERTAIN ELECTRIC UTILITY SYSTEMS.— 

20 After January 1, 2000, it shall be unlawful for any 

21 existing unit with a nameplate capacity below 75 

22 MWe and an actual 1985 emissions rate equal to, or 

23 greater than, 1.20 lbs/mmBtu which is part of an 

24 electric utility system which, as of November 15, 

25 1990— 
130 

•S 131 IS 

1 ‘‘(A) has at least 20 percent of its fossil2 fuel capacity controlled by flue gas 

3 desulfurization devices; 

4 ‘‘(B) has more than 10 percent of its fos5 sil-fuel capacity consisting of coal-fired units of 

6 less than 75 MWe; and 

7 ‘‘(C) has large units (greater than 400 

8 MWe) all of which have difficult or very dif9 ficult FGD Retrofit Cost Factors (according to 

10 the Emissions and the FGD Retrofit Feasibility 

11 at the 200 Top Emitting Generating Stations, 

12 prepared for the United States Environmental 

13 Protection Agency on January 10, 1986) to ex14 ceed an annual sulfur dioxide emissions tonnage 

15 limitation equal to the product of its baseline 

16 multiplied by an emissions rate of 2.5 lbs/ 

17 mmBtu, divided by 2,000, unless the owner or 

18 operator holds allowances to emit not less than 

19 the unit’s total annual emissions, for a year 

20 after 2007, or the owner or operator of the 

21 source that includes such unit holds allowances 

22 to emit not less than the total annual emissions 

23 of all affected units at the source. After Janu24 ary 1, 2010, it shall be unlawful for each unit 

25 subject to the emissions limitation requirements 
131 

•S 131 IS 

1 of this paragraph to exceed an annual emissions 

2 tonnage limitation equal to the project of its 

3 baseline multiplied by an emissions rate of 1.20 

4 lbs/mmBtu, divided by 2,000, unless the owner 

5 or operator holds for use allowances to emit not 

6 less than the unit’s total annual emissions for 

7 a year after 2007, or the owner or operator of 

8 the source that includes such unit holds allow9 ances to emit not less than the total annual 

10 emissions of all affected units at the source. 

11 ‘‘(d) COAL-FIRED UNITS BELOW 1.20 LBS/ 

12 MMBTU.— 

13 ‘‘(1) RATE LESS THAN 0.60 LBS/MMBTU.—After 

14 January 1, 2000, it shall be unlawful for any exist15 ing coal-fired utility unit the lesser of whose actual 

16 or allowable 1985 sulfur dioxide emissions rate is 

17 less than 0.60 lbs/mmBtu to exceed an annual sulfur 

18 dioxide tonnage emission limitation equal to the 

19 product of the unit’s baseline multiplied by— 

20 ‘‘(A) the lesser of 0.60 lbs/mmBtu or the 

21 unit’s allowable 1985 emissions rate; and 

22 ‘‘(B) a numerical factor of 120 percent, di23 vided by 2,000, unless the owner or operator of 

24 such unit holds allowances to emit not less than 

25 the unit’s total annual emissions for a year 
132 

•S 131 IS 

1 after 2007, or the owner or operator of the 

2 source that includes such unit holds allowances 

3 to emit not less than the total annual emissions 

4 of all affected units at the source. 

5 ‘‘(2) RATE BETWEEN 0.60 AND 1.20 LBS/ 

6 MMBTU.—After January 1, 2000, it shall be unlaw7 ful for any existing coal-fired utility unit the lesser 

8 of whose actual or allowable 1985 sulfur dioxide 

9 emissions rate is equal to, or greater than, 0.60 lbs/ 

10 mmBtu and less than 1.20 lbs/mmBtu to exceed an 

11 annual sulfur dioxide tonnage emissions limitation 

12 equal to the product of the unit’s baseline multiplied 

13 by (A) the lesser of its actual 1985 emissions rate 

14 or its allowable 1985 emissions rate, and (B) a nu15 merical factor of 120 percent, divided by 2,000, un16 less the owner or operator of such unit holds allow17 ances to emit not less than the unit’s total annual 

18 emissions for a year after 2007, or the owner or op19 erator of the source that includes such unit holds al20 lowances to emit not less than the total annual emis21 sions of all affected units at the source. 

22 ‘‘(3) RESERVE ALLOWANCE.— 

23 ‘‘(A) IN GENERAL.—In addition to allow24 ances allocated pursuant to paragraph (1) and 

25 section 412(a) as basic phase II allowance allo-
133 

•S 131 IS 

1 cations, at the election of the designated rep2 resentative of the operating company, beginning 

3 January 1, 2000, and for each calendar year 

4 thereafter until and including 2009, the Admin5 istrator shall allocate annually for each unit 

6 subject to the emissions limitation requirements 

7 of paragraph (1) allowances from the reserve 

8 created pursuant to subsection (a)(2) in an 

9 amount equal to the amount by which— 

10 ‘‘(i) the product of the lesser of 0.60 lbs/ 

11 mmBtu or the unit’s allowable 1985 emissions 

12 rate multiplied by the unit’s baseline adjusted 

13 to reflect operation at a 60 percent capacity 

14 factor, divided by 2,000, exceeds 

15 ‘‘(ii) the number of allowances allocated 

16 for the unit pursuant to paragraph (1) and sec17 tion 403(a)(1) as basic phase II allowance allo18 cations. 

19 ‘‘(B) UNITS SUBJECT TO CERTAIN LIMITA20 TIONS.—In addition to allowances allocated pursu21 ant to paragraph (2) and section 412(a) as basic 

22 phase II allowance allocations, at the election of the 

23 designated representative of the operating company, 

24 beginning January 1, 2000, and for each calendar 

25 year thereafter until and including 2009, the Admin-
134 

•S 131 IS 

1 istrator shall allocate annually for each unit subject 

2 to the emissions limitation requirements of para3 graph (2) allowances from the reserve created pursu4 ant to subsection (a)(2) in an amount equal to the 

5 amount by which— 

6 ‘‘(i) the product of the lesser of the unit’s 

7 actual 1985 emissions rate or its allowable 

8 1985 emissions rate multiplied by the unit’s 

9 baseline adjusted to reflect operation at a 60 

10 percent capacity factor, divided by 2,000; ex11 ceeds 

12 ‘‘(ii) the number of allowances allocated 

13 for the unit pursuant to paragraph (2) and sec14 tion 412(a) as basic phase II allowance alloca15 tions. 

16 ‘‘(C) ELECTION BY OPERATING COMPANY.—An 

17 operating company with units subject to the emis18 sions limitation requirements of this subsection may 

19 elect the allocation of allowances as provided under 

20 subparagraphs (A) and (B). Such election shall 

21 apply to the annual allowance allocation for each 

22 and every unit in the operating company subject to 

23 the emissions limitation requirements of this sub24 section. The Administrator shall allocate allowances 
135 

•S 131 IS 

1 pursuant to subparagraphs (A) and (B) only in ac2 cordance with this subparagraph. 

3 ‘‘(4) ALTERNATIVE ALLOCATION.—Notwith4 standing any other provision of this section, at the 

5 election of the owner or operator, after January l, 

6 2000, the Administrator shall allocate in lieu of allo7 cation, pursuant to paragraph (1), (2), (3), (5), or 

8 (6), allowances for a unit subject to the emissions 

9 limitation requirements of this subsection which 

10 commenced commercial operation on or after Janu11 ary 1, 1981 and before December 31, 1985, which 

12 was subject to, and in compliance with, section 111 

13 of the Act in an amount equal to the unit’s annual 

14 fuel consumption, on a Btu basis, at a 65-percent15 capacity factor multiplied by the unit’s allowable 

16 1985 emissions rate, divided by 2,000. 

17 ‘‘(5) CLEAN COAL TECHNOLOGY DEMONSTRA18 TION GRANT.—For the purposes of this section, in 

19 the case of an oil- and gas-fired unit which has been 

20 awarded a clean coal technology demonstration grant 

21 as of January 1, 1991, by the United States Depart22 ment of Energy, beginning January 1, 2002, the Ad23 ministrator shall allocate for the unit allowances in 

24 an amount equal to the unit’s baseline multiplied by 

25 1.20 lbs/mmBtu, divided by 2,000. 
136 

•S 131 IS 

1 ‘‘(e) OIL AND GAS-FIRED UNITS EQUAL TO OR

2 GREATER THAN 0.60 LBS/MMBTU AND LESS THAN 1.20 

3 LBS/MMBTU.—After January 1, 2000, it shall be unlawful 

4 for any existing oil and gas-fired utility unit the lesser of 

5 whose actual or allowable 1985 sulfur dioxide emission 

6 rate is equal to, or greater than, 0.60 lbs/mmBtu, but less 

7 than 1.20 lbs/mmBtu to exceed an annual sulfur dioxide 

8 tonnage limitation equal to the product of the unit’s base9 line multiplied by (A) the lesser of the unit’s allowable 

10 1985 emissions rate or its actual 1985 emissions rate and 

11 (B) a numerical factor of 120 percent divided by 2,000, 

12 unless the owner or operator of such unit holds allowances 

13 to emit not less than the unit’s total annual emissions for 

14 a year after 2007, or the owner or operator of the source 

15 that includes such unit holds allowances to emit not less 

16 than the total annual emissions of all affected units at 

17 the source. 

18 ‘‘(f) OIL AND GAS-FIRED UNITS LESS THAN 0.60 

19 LBS/MMBTU.— 

20 ‘‘(1) IN GENERAL.—After January 1, 2000, it 

21 shall be unlawful for any oil and gas-fired existing 

22 utility unit the lesser of whose actual or allowance 

23 1985 emission rate is less than 0.60 lbs/mmBtu and 

24 whose average annual fuel consumption during the 

25 period 1980 through 1989 on a Btu basis was 90 
137 

•S 131 IS 

1 percent or less in the form of natural gas to exceed 

2 an annual sulfur dioxide tonnage emissions limita3 tion equal to the product of the unit’s baseline mul4 tiplied by— 

5 ‘‘(A) the lesser of 0.60 lbs/mmBtu or the 

6 unit’s allowance 1985 emissions, and 

7 ‘‘(B) a numerical factor of 120 percent, di8 vided by 2,000, unless the owner or operator of 

9 such unit holds allowances to emit not less than 

10 the unit’s total annual emissions, for a year 

11 after 2007, or the owner or operator of the 

12 source that includes such unit holds allowances 

13 to emit not less than the total annual emissions 

14 of all affected units at the source. 

15 ‘‘(2) ADDITIONAL ALLOCATION.—In addition to 

16 allowances allocated pursuant to paragraph (1) as 

17 basic phase II allowance allocations and section 

18 412(a), beginning January 1, 2000, the Adminis19 trator shall, in the case of any unit operated by a 

20 utility that furnishes electricity, electric energy, 

21 steam, and natural gas within an area consisting of 

22 a city and 1 contiguous county, and in the case of 

23 any unit owned by a State authority, the output of 

24 which unit is furnished within that same area con25 sisting of a city and 1 contiguous county, the Ad-
138 

•S 131 IS 

1 ministrator shall allocate for each unit in the utility 

2 its pro rata share of 7,000 allowances and for each 

3 unit in the State authority its pro rata share of 

4 2,000 allowances. 

5 ‘‘(g) UNITS THAT COMMENCE COMMERCIAL OPER6 ATION BETWEEN 1986 AND DECEMBER 31, 1995.— 

7 ‘‘(1) IN GENERAL.—After January 1, 2000, it 

8 shall be unlawful for any utility unit that has com9 menced commercial operation on or after January 1, 

10 1986, but not later than September 30, 1990 to ex11 ceed an annual tonnage emission limitation equal to 

12 the product of the unit’s annual fuel consumption, 

13 on a Btu basis, at a 65-percent-capacity factor mul14 tiplied by the unit’s allowance 1985 sulfur dioxide 

15 emission rate (converted, if necessary, to pounds per 

16 mmBtu), divided by 2,000 unless the owner or oper17 ator of such unit holds allowances to emit not less 

18 than the unit’s total annual emissions for a year 

19 after 2007, or the owner or operator of the source 

20 that includes such unit holds allowances to emit not 

21 less than the total annual emissions of all affected 

22 units at the source. 

23 ‘‘(2) UNIT ALLOWANCES.—After January 1, 

24 2000, the Administrator shall allocate allowances 

25 pursuant to section 411 to each unit which is listed 
139 

•S 131 IS 

1 in table B of this paragraph in an annual amount 

2 equal to the amount specified in table B. 

‘‘TABLE B 

Unit Allowances 

Brandon Shores .............................................................................. 8,907 

Miller 4 ........................................................................................... 9,197 

TNP One 2 ..................................................................................... 4,000 

Zimmer 1 ........................................................................................ 18,458 

Spruce 1 ......................................................................................... 7,647 

Clover 1 .......................................................................................... 2,796 

Clover 2 .......................................................................................... 2,796 

Twin Oak 2 ..................................................................................... 1,760 

Twin Oak 1 ..................................................................................... 9,158 

Cross 1 ............................................................................................ 6,401 

Malakoff 1 ...................................................................................... 1,759 

3 Notwithstanding any other paragraph of this subsection, 

4 for units subject to this paragraph, the Administrator 

5 shall not allocate allowances pursuant to any other para6 graph of this subsection, provided that the owner or oper7 ator of a unit listed on table B may elect an allocation 

8 of allowances under another paragraph of this subsection 

9 in lieu of an allocation under this paragraph. 

10 ‘‘(3) UNITS THAT COMMENCED COMMERCIAL

11 OPERATION BETWEEN OCTOBER 1, 1990, AND DE12 CEMBER 31, 1992.—Beginning January 1, 2000, the 

13 Administrator shall allocate to the owner or operator 

14 of any utility unit that commences commercial oper15 ation, or has commenced commercial operation, on 

16 or after October 1, 1990, but not later than Decem17 ber 31, 1992, allowances in an amount equal to the 

18 product of the unit’s annual fuel consumption, on a 
140 

•S 131 IS 

1 Btu basis, at a 65 percent capacity factor multiplied 

2 by the lesser of 0.30 lbs/mmBtu or the unit’s allow3 able sulfur dioxide emission rate (converted, if nec4 essary, to pounds per mmBtu), divided by 2,000. 

5 ‘‘(4) UNITS THAT COMMENCED COMMERCIAL

6 OPERATION BETWEEN JANUARY 1, 1993, AND DE7 CEMBER 31, 1995.—Beginning January 1, 2000, the 

8 Administrator shall allocate to the owner or operator 

9 of any utility unit that has commenced construction 

10 before December 31, 1990 and that commences com11 mercial operation between January 1, 1993, and De12 cember 31, 1995, allowances in an amount equal to 

13 the product of the unit’s annual fuel consumption, 

14 on a Btu basis, at a 65 percent capacity factor mul15 tiplied by the lesser of 0.30 lbs/mmBtu or the unit’s 

16 allowable sulfur dioxide emission rate (converted, if 

17 necessary, to pounds per mmBtu), divided by 2,000. 

18 ‘‘(5) UNITS THAT CONVERTED TO COAL FIRED

19 OPERATION BETWEEN JANUARY 1, 1985, AND DE20 CEMBER 31, 1987.—After January 1, 2000, it shall 

21 be unlawful for any existing utility unit that has 

22 completed conversion from predominantly gas fired 

23 existing operation to coal fired operation between 

24 January 1, 1985, and December 31, 1987, for which 

25 there has been allocated a proposed or final prohibi-
141 

•S 131 IS 

1 tion order pursuant to section 301(b) of the Power2 plant and Industrial Fuel Use Act of 1978 (42 

3 U.S.C. 8301 et seq., repealed 1987) to exceed an an4 nual sulfur dioxide tonnage emissions limitation 

5 equal to the product of the unit’s annual fuel con6 sumption, on a Btu basis, at a 65 percent capacity 

7 factor multiplied by the lesser of 1.20 lbs/mmBtu or 

8 the unit’s allowable 1987 sulfur dioxide emissions 

9 rate, divided by 2,000, unless the owner or operator 

10 of such unit has obtained allowances equal to its ac11 tual emissions for a year after 2007, or the owner 

12 or operator of the source that includes such unit 

13 holds allowances to emit not less than the total an14 nual emissions of all affected units at the source. 

15 ‘‘(6) APPLICABILITY TO QUALIFYING SMALL

16 POWER PRODUCTION FACILITIES, QUALIFYING CO17 GENERATION FACILITIES, AND NEW INDEPENDENT

18 POWER PRODUCTION FACILITIES.—Unless the Ad19 ministrator has approved a designation of such facil20 ity under section 417, the provisions of this subpart 

21 shall not apply to a ‘qualifying small power produc22 tion facility’ or ‘qualifying cogeneration facility’ 

23 (within the meaning of section 3(17)(C) or 3(18)(B) 

24 of the Federal Power Act) or to a ‘new independent 
142 

•S 131 IS 

1 power production facility’ if, as of November 15, 

2 1990— 

3 ‘‘(A) an applicable power sales agreement 

4 has been executed; 

5 ‘‘(B) the facility is the subject of a State 

6 regulatory authority order requiring an electric 

7 utility to enter into a power sales agreement 

8 with, purchase capacity from, or (for purposes 

9 of establishing terms and conditions of the elec10 tric utility’s purchase of power) enter into arbi11 tration concerning, the facility; 

12 ‘‘(C) an electric utility has issued a letter 

13 of intent or similar instrument committing to 

14 purchase power from the facility at a previously 

15 offered or lower price and a power sales agree16 ment is executed within a reasonable period of 

17 time; or 

18 ‘‘(D) the facility has been selected as a 

19 winning bidder in a utility competitive bid solic20 itation. 

21 ‘‘(h) OIL- AND GAS-FIRED UNITS LESS THAN 10 

22 PERCENT OIL CONSUMED.— 

23 ‘‘(1) IN GENERAL.—After January 1, 2000, it 

24 shall be unlawful for any oil- and gas-fired utility 

25 unit whose average annual fuel consumption during 
143 

•S 131 IS 

1 the period 1980 through 1989 on a Btu basis ex2 ceeded 90 percent in the form of natural gas to ex3 ceed an annual sulfur dioxide tonnage limitation 

4 equal to the product of the unit’s baseline multiplied 

5 by the unit’s actual 1985 emissions rate divided by 

6 2,000 unless the owner or operator of such unit 

7 holds allowances to emit not less than the unit’s 

8 total annual emissions for a year after 2007, or the 

9 owner or operator of the source that includes such 

10 unit holds allowances to emit not less than the total 

11 annual emissions of all affected units at the source. 

12 ‘‘(2) RESERVE ALLOWANCES.—In addition to 

13 allowances allocated pursuant to paragraph (1) and 

14 section 412(a) as basic phase II allowance alloca15 tions, beginning January 1, 2000, and for each cal16 endar year thereafter until and including 2009, the 

17 Administrator shall allocate annually for each unit 

18 subject to the emissions limitation requirements of 

19 paragraph (1) allowances from the reserve created 

20 pursuant to subsection (a)(2) in an amount equal to 

21 the unit’s baseline multiplied by 0.050 lbs/mmBtu, 

22 divided by 2,000. 

23 ‘‘(3) ADDITIONAL ALLOWANCES.—In addition 

24 to allowances allocated pursuant to paragraph (1) 

25 and section 412(a), beginning January 1, 2010, the 
144 

•S 131 IS 

1 Administrator shall allocate annually for each unit 

2 subject to the emissions limitation requirements of 

3 paragraph (1) allowances in an amount equal to the 

4 unit’s baseline multiplied by 0.050 lbs/mmBtu, di5 vided by 2,000. 

6 ‘‘(i) UNITS IN HIGH GROWTH STATES.— 

7 ‘‘(1) ANNUAL ALLOCATIONS.—In addition to al8 lowances allocated pursuant to this section and sec9 tion 412(a) as basic phase II allowance allocations, 

10 beginning January 1, 2000, the Administrator shall 

11 allocate annually allowances for each unit, subject to 

12 an emissions limitation requirement under this sec13 tion, and located in a State that— 

14 ‘‘(A) has experienced a growth in popu15 lation in excess of 25 percent between 1980 and 

16 1988 according to State Population and House17 hold Estimates, With Age, Sex, and Compo18 nents of Change: 1981–1988 allocated by the 

19 United States Department of Commerce, and 

20 ‘‘(B) had an installed electrical generating 

21 capacity of more than 30,000,000 kw in 1988, 

22 in an amount equal to the difference between— 

23 ‘‘(i) the number of allowances that 

24 would be allocated for the unit pursuant to 

25 the emissions limitation requirements of 
145 

•S 131 IS 

1 this section applicable to the unit adjusted 

2 to reflect the unit’s annual average fuel 

3 consumption on a Btu basis of any three 

4 consecutive calendar years between 1980 

5 and 1989 (inclusive) as elected by the 

6 owner or operator; and 

7 ‘‘(ii) the number of allowances allo8 cated for the unit pursuant to the emis9 sions limitation requirements of this sec10 tion: 

11 Provided, That the number of allowances allo12 cated pursuant to this subsection shall not ex13 ceed an annual total of 40,000. If necessary to 

14 meeting the 40,000 allowance restriction im15 posed under this subsection the Administrator 

16 shall reduce, pro rata, the additional annual al17 lowances allocated to each unit under this sub18 section. 

19 ‘‘(2) ADDITIONAL ALLOCATIONS.—Beginning 

20 January 1, 2000, in addition to allowances allocated 

21 pursuant to this section and section 403(a)(1) as 

22 basic phase II allowance allocations, the Adminis23 trator shall allocate annually for each unit subject to 

24 the emissions limitation requirements of subsection 

25 (b)(1)— 
146 

•S 131 IS 

1 ‘‘(A) the lesser of whose actual or allow2 able 1980 emissions rate has declined by 50 

3 percent or more as of November 15, 1990; 

4 ‘‘(B) whose actual emissions rate is less 

5 than 1.2 lbs/mmBtu as of January 1, 2000; 

6 ‘‘(C) which commenced operation after 

7 January 1, 1970; 

8 ‘‘(D) which is owned by a utility company 

9 whose combined commercial and industrial kilo10 watt-hour sales have increased by more than 20 

11 percent between calendar year 1980 and No12 vember 15, 1990; and 

13 ‘‘(E) whose company-wide fossil-fuel sulfur 

14 dioxide emissions rate has declined 40 percent 

15 or more from 1980 to 1988, allowances in an 

16 amount equal to the difference between— 

17 ‘‘(i) the number of allowances that 

18 would be allocated for the unit pursuant to 

19 the emissions limitation requirements of 

20 subsection (b)(1) adjusted to reflect the 

21 unit’s annual average fuel consumption on 

22 a Btu basis for any three consecutive years 

23 between 1980 and 1989 (inclusive) as 

24 elected by the owner or operator; and 
147 

•S 131 IS 

1 ‘‘(ii) the number of allowances allo2 cated for the unit pursuant to the emis3 sions limitation requirements of subsection 

4 (b)(1): 

5 Provided, That the number of allowances allo6 cated pursuant to this paragraph shall not ex7 ceed an annual total of 5,000. If necessary to 

8 meeting the 5,000 allowance restriction imposed 

9 in the last clause of the preceding sentence the 

10 Administrator shall reduce, pro rata, the addi11 tional allowances allocated to each unit pursu12 ant to this paragraph. 

13 ‘‘(j) CERTAIN MUNICIPALLY OWNED POWER

14 PLANTS.—Beginning January 1, 2000, in addition to al15 lowances allocated pursuant to this section and section 

16 412(a) as basic phase II allowance allocations, the Admin17 istrator shall allocate annually for each existing munici18 pally owned oil and gas-fired utility unit with nameplate 

19 capacity equal to, or less than, 40 MWe, the lesser of 

20 whose actual or allowable 1985 sulfur dioxide emission 

21 rate is less than 1.20 lbs/mmBtu, allowances in an amount 

22 equal to the product of the unit’s annual fuel consumption 

23 on a Btu basis at a 60 percent capacity factor multiplied 

24 by the lesser of its allowable 1985 emission rate or its 

25 actual 1985 emission rate, divided by 2,000. 
148 

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1 ‘‘SEC. 415. ALLOWANCES FOR STATES WITH EMISSIONS 

2 RATES AT OR BELOW 0.80 LBS/MMBTU. 

3 ‘‘(a) ELECTION OF GOVERNOR.—In addition to basic 

4 phase II allowance allocations, upon the election of the 

5 Governor of any State, with a 1985 statewide annual sul6 fur dioxide emissions rate equal to or less than, 0.80 lbs/ 

7 mmBtu, averaged over all fossil fuel-fired utility steam 

8 generating units, beginning January 1, 2000, and for each 

9 calendar year thereafter until and including 2009, the Ad10 ministrator shall allocate, in lieu of other phase 11 bonus 

11 allowance allocations, allowances from the reserve created 

12 pursuant to section 414(a)(2) to all such units in the State 

13 in an amount equal to 125,000 multiplied by the unit’s 

14 pro rata share of electricity generated in calendar year 

15 1985 at fossil fuel-fired utility steam units in all States 

16 eligible for the election. 

17 ‘‘(b) NOTIFICATION OF ADMINISTRATOR.—Pursuant 

18 to section 412(a), each Governor of a State eligible to 

19 make an election under paragraph (a) shall notify the Ad20 ministrator of such election. In the event that the Gov21 ernor of any such State fails to notify the Administrator 

22 of the Governor’s elections, the Administrator shall allo23 cate allowances pursuant to section 414. 

24 ‘‘(c) ALLOWANCES AFTER JANUARY 1, 2010.—After 

25 January 1, 2010, the Administrator shall allocate allow-
149

•S 131 IS 

1 ances to units subject to the provisions of this section pur2 suant to section 414. 

3 ‘‘SEC. 416. ELECTION FOR ADDITIONAL SOURCES. 

4 ‘‘(a) APPLICABILITY.—The owner or operator of any 

5 unit that is not, nor will become, an affected unit under 

6 section 412(b), 413, or 414, that emits sulfur dioxide, may 

7 elect to designate that unit or source to become an af8 fected unit and to receive allowances under this subpart. 

9 An election shall be submitted to the Administrator for 

10 approval, along with a permit application and proposed 

11 compliance plan in accordance with section 404. The Ad12 ministrator shall approve a designation that meets the re13 quirements of this section, and such designated unit shall 

14 be allocated allowances, and be an affected unit for pur15 poses of this subpart. 

16 ‘‘(b) ESTABLISHMENT OF BASELINE.—The baseline 

17 for a unit designated under this section shall be estab18 lished by the Administrator by regulation, based on fuel 

19 consumption and operating data for the unit for calendar 

20 years 1985, 1986, and 1987, or if such data is not avail21 able, the Administrator may prescribe a baseline based on 

22 alternative representative data. 

23 ‘‘(c) EMISSION LIMITATIONS.—

24 ‘‘(1) ELECTIONS SUBMITTED BEFORE JANUARY

25 1, 2002.—For a unit for which an election, along 
150

•S 131 IS 

1 with a permit application and compliance plan, is 

2 submitted to the Administrator under paragraph (a) 

3 before January 1, 2002, annual emissions limita4 tions for sulfur dioxide shall be equal to the product 

5 of the baseline multiplied by the lesser of the unit’s 

6 1985 actual or allowable emission rate in lbs/

7 mmBtu, or, if the unit did not operate in 1985, by 

8 the lesser of the unit’s actual or allowable emission 

9 rate for a calendar year after 1985 (as determined 

10 by the Administrator); divided by 2,000. 

11 ‘‘(2) ELECTIONS SUBMITTED AFTER JANUARY

12 1, 2002.—For a unit for which an election, along 

13 with a permit application and compliance plan, is 

14 submitted to the Administrator under paragraph (a) 

15 on or after January 1, 2002, annual emissions limi16 tations for sulfur dioxide shall be equal to the prod17 uct of the baseline multiplied by the lesser of the 

18 unit’s 1985 actual or allowable emission rate in lbs/

19 mmBtu, or, if the unit did not operate in 1985, by 

20 the lesser of the unit’s actual or allowable emission 

21 rate for a calendar year after 1985 (as determined 

22 by the Administrator); divided by 4,000. 

23 ‘‘(d) ALLOWANCES AND PERMITS.—The Adminis24 trator shall issue allowances to an affected unit under this 

25 section in an amount equal to the emissions limitation cal-
151

•S 131 IS 

1 culated under subsection (c), in accordance with section 

2 412. Such allowance may be used in accordance with, and 

3 shall be subject to, the provisions of section 412. Affected 

4 sources under this section shall be subject to the require5 ments of sections 404, 405, 406, and 412. 

6 ‘‘(e) LIMITATION.—Any unit designated under this 

7 section shall not transfer or bank allowances produced as 

8 a result of reduced utilization or shutdown, except that, 

9 such allowances may be transferred or carried forward for 

10 use in subsequent years to the extent that the reduced 

11 utilization or shutdown results from the replacement of 

12 thermal energy from the unit designated under this sec13 tion, with thermal energy generated by any other unit or 

14 units subject to the requirements of this subpart, and the 

15 designated unit’s allowances are transferred or carried for16 ward for use at such other replacement unit or units. In 

17 no case may the Administrator allocate to a source des18 ignated under this section allowances in an amount great19 er than the emissions resulting from operation of the 

20 source in full compliance with the requirements of this 

21 Act. No such allowances shall authorize operation of a unit 

22 in violation of any other requirements of this Act. 

23 ‘‘(f) IMPLEMENTATION.—The Administrator shall 

24 implement this section under 40 CFR part 74 (2002), 

25 amended as appropriate by the Administrator. 
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1 ‘‘SEC. 417. AUCTIONS, RESERVE. 

2 ‘‘(a) SPECIAL RESERVE OF ALLOWANCES.—For pur3 poses of establishing the Special Allowance Reserve, the 

4 Administrator shall withhold—

5 ‘‘(1) 2.8 percent of the allocation of allowances 

6 for each year from 1995 through 1999 inclusive; and 

7 ‘‘(2) 2.8 percent of the basic phase 11 allow8 ance allocation of allowances for each year beginning 

9 in the year 2000; 

10 which would (but for this subsection) be issued for each 

11 affected unit at an affected source. The Administrator 

12 shall record such withholding for purposes of transferring 

13 the proceeds of the allowance sales under this subsection. 

14 The allowances so withheld shall be deposited in the Re15 serve under this section. 

16 ‘‘(b) AUCTION SALES.—

17 ‘‘(1) SUBACCOUNT FOR AUCTIONS.—The Ad18 ministrator shall establish an Auction Subaccount in 

19 the Special Reserve established under this section. 

20 The Auction Subaccount shall contain allowances to 

21 be sold at auction under this section in the amount 

22 of 150,000 tons per year for each year from 1995 

23 through 1999, inclusive and 250,000 tons per year 

24 for each year from 2000 through 2009, inclusive. 

25 ‘‘(2) ANNUAL AUCTIONS.—Commencing in 

26 1993 and in each year thereafter until 2010, the Ad-
153

•S 131 IS 

1 ministrator shall conduct auctions at which the al2 lowances referred to in paragraph (1) shall be of3 fered for sale in accordance with regulations promul4 gated by the Administrator. The allowances referred 

5 to in paragraph (1) shall be offered for sale at auc6 tion in the amounts specified in table C. The auction 

7 shall be open to any person. A person wishing to bid 

8 for such allowances shall submit (by a date set by 

9 the Administrator) to the Administrator (on a sealed 

10 bid schedule provided by the Administrator) offers to 

11 purchase specified numbers of allowances at speci12 fied prices. Such regulations shall specify that the 

13 auctioned allowances shall be allocated and sold on 

14 the basis of bid price, starting with the highest15 priced bid and continuing until all allowances for 

16 sale at such auction have been allocated. The regula17 tions shall not permit that a minimum price be set 

18 for the purchase of withheld allowances. Allowances 

19 purchased at the auction may be used for any pur20 pose and at any time after the auction, subject to 

21 the provisions of this subpart and subpart 2.

TABLE C—NUMBER OF ALLOWANCES AVAILABLE FOR 

AUCTION 

Year of sale Spot auction 

(same year) 

Advance 

auction 

1993 ........................................................................ 50,000 100,000 

1994 ........................................................................ 50,000 100,000 

1995 ........................................................................ 50,000 100,000 

1996 ........................................................................ 150,000 100,000 
154

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TABLE C—NUMBER OF ALLOWANCES AVAILABLE FOR 

AUCTION—Continued

Year of sale Spot auction 

(same year) 

Advance 

auction 

1997 ........................................................................ 150,000 100,000 

1998 ........................................................................ 150,000 100,000 

1999 ........................................................................ 150,000 100,000 

2000 ........................................................................ 125,000 125,000 

2001 ........................................................................ 125,000 125,000 

2002 ........................................................................ 125,000 125,000 

2003 ........................................................................ 125,000 0

2004–2009 .............................................................. 125,000 0 

1 ‘‘(3) PROCEEDS.—

2 ‘‘(A) TRANSFER.—Notwithstanding section 

3 3302 of title 31 of the United States Code or 

4 any other provision of law, within 90 days of re5 ceipt, the Administrator shall transfer the pro6 ceeds from the auction under this section, on a 

7 pro rata basis, to the owners or operators of the 

8 affected units at an affected source from whom 

9 allowances were withheld under subsection (b). 

10 No funds transferred from a purchaser to a 

11 seller of allowances under this paragraph shall 

12 be held by any officer or employee of the United 

13 States or treated for any purpose as revenue to 

14 the United States or the Administrator. 

15 ‘‘(B) RETURN.—At the end of each year, 

16 any allowances offered for sale but not sold at 

17 the auction shall be returned without charge, on 

18 a pro rata basis, to the owner or operator of the 
155

•S 131 IS 

1 affected units from whose allocation the allow2 ances were withheld. With 170 days after the 

3 date of enactment of the Clear Skies Act of 

4 2005, any allowance withheld under paragraph 

5 (a)(2) but not offered for sale at an auction 

6 shall be returned without charge, on a pro rata 

7 basis, to the owner or operator of the affected 

8 units from whose allocation the allowances were 

9 withheld. 

10 ‘‘(4) RECORDING BY EPA.—The Administrator 

11 shall record and publicly report the nature, prices 

12 and results of each auction under this subsection, in13 cluding the prices of successful bids, and shall 

14 record the transfers of allowances as a result of each 

15 auction in accordance with the requirements of this 

16 section. The transfer of allowances at such auction 

17 shall be recorded in accordance with the regulations 

18 promulgated by the Administrator under this sub19 part. 

20 ‘‘(c) CHANGES IN AUCTIONS AND WITHHOLDING.—

21 Pursuant to rulemaking after public notice and comment 

22 the Administrator may at any time after the year 1998 

23 (in the case of advance auctions) and 2005 (in the case 

24 of spot auctions) decrease the number of allowances with25 held and sold under this section. 
156

•S 131 IS 

1 ‘‘(d) TERMINATION OF AUCTIONS.—Not later than 

2 the commencement date of the sulfur dioxide allowance re3 quirement under section 422, the Administrator shall ter4 minate the withholding of allowances and the auction sales 

5 under this section. Pursuant to regulations under this sec6 tion, the Administrator may by delegation or contract pro7 vide for the conduct of sales or auctions under the Admin8 istrator’s supervision by other departments or agencies of 

9 the United States Government or by nongovernmental 

10 agencies, groups, or organizations. 

11 ‘‘(e) APPLICABLE LAW.—The Administrator shall 

12 implement this section under 40 CFR part 73 (2002), 

13 amended as appropriate by the Administrator. 

14 ‘‘SEC. 418. INDUSTRIAL SULFUR DIOXIDE EMISSIONS. 

15 ‘‘(a) REPORT.—Not later than January 1, 1995 and 

16 every 5 years thereafter, the Administrator shall transmit 

17 to the Congress a report containing an inventory of na18 tional annual sulfur dioxide emissions from industrial 

19 sources (as defined in section 411(11)), including units 

20 subject to section 414(g)(2), for all years for which data 

21 are available, as well as the likely trend in such emission 

22 over the following twenty-year period. The reports shall 

23 also contain estimates of the actual emission reduction in 

24 each year resulting from promulgation of the diesel fuel 

25 desulfurization regulations under section 214. 
157

•S 131 IS 

1 ‘‘(b) 5.60 MILLION TON CAP.—Whenever the inven2 tory required by this section indicates that sulfur dioxide 

3 emissions from industrial sources, including units subject 

4 to section 414(g)(2), and may reasonably be expected to 

5 reach levels greater than 5.60 million tons per year, the 

6 Administrator shall take such actions under the Act as 

7 may be appropriate to ensure that such emissions do not 

8 exceed 5.60 million tons per year. Such actions may in9 clude the promulgation of new and revised standards of 

10 performance for new sources, including units subject to 

11 section 414(g)(2), under section 111(b), as well as pro12 mulgation of standards of performance for existing 

13 sources, including units subject to section 414(g)(2), 

14 under authority of this section. For an existing source reg15 ulated under this section, ‘standard of performance’ 

16 means a standard which the Administrator determines is 

17 applicable to that source and which reflects the degree of 

18 emission reduction achievable through the application of 

19 the best system of continuous emission reduction which 

20 (taking into consideration the cost of achieving such emis21 sion reduction, and any nonair quality health and environ22 mental impact and energy requirements) the Adminis23 trator determines has been adequately demonstrated for 

24 that category of sources. 
158

•S 131 IS 

1 ‘‘(c) ELECTION.—Regulations promulgated under 

2 section 414(b) shall not prohibit a source from electing 

3 to become an affected unit under section 417. 

4 ‘‘SEC. 419. TERMINATION. 

5 ‘‘Starting January l, 2010, the owners or operators 

6 of affected units and affected facilities under sections 

7 412(b) and (c) and 416 and shall no longer be subject 

8 to the requirements of sections 412 through 417. 

9 ‘‘Subpart 2—Clear Skies Sulfur Dioxide Allowance 

10 Program 

11 ‘‘SEC. 421. DEFINITIONS. 

12 ‘‘For purposes of this subpart— 

13 ‘‘(1) AFFECTED EGU.—The term ‘affected 

14 EGU’ means— 

15 ‘‘(A) for a unit serving a generator before 

16 the date of enactment of the Clear Skies Act of 

17 2005, a unit in a State serving a generator with 

18 a nameplate capacity of greater than twenty19 five megawatts that produced or produces elec20 tricity for sale during 2002 or any year there21 after, except for a cogeneration unit that meets 

22 the criteria for qualifying cogeneration facilities 

23 codified in section 292.205 of title 18 of the 

24 Code of Federal Regulations as issued on April 
159 

•S 131 IS 

1 1, 2002 during 2002 and each year thereafter; 

2 and 

3 ‘‘(B) for a unit commencing service of a 

4 generator on or after the date of enactment of 

5 the Clear Skies Act of 2005, a unit in a State 

6 serving a generator that produces electricity for 

7 sale during any year starting with the year the 

8 unit commences service of a generator, except 

9 for a unit serving one or more generators with 

10 total nameplate capacity of twenty-five 

11 megawatts or less, or a cogeneration unit that 

12 meets the criteria for qualifying cogeneration 

13 facilities codified in section 292.205 of title 18 

14 of the Code of Federal Regulations as issued on 

15 April 1, 2002, during each year starting with 

16 the year the unit commences services of a gen17 erator. 

18 Notwithstanding paragraphs (A) and (B), the term 

19 ‘affected EGU’ does not include a solid waste incin20 eration unit subject to section 129 or a unit for the 

21 treatment, storage, or disposal of hazardous waste 

22 subject to section 3005 of the Solid Waste Disposal 

23 Act. 

24 ‘‘(2) COAL-FIRED.—The term ‘coal-fired’ with 

25 regard to a unit means, for purposes of section 424, 
160 

•S 131 IS 

1 combusting coal or any coal-derived fuel alone or in 

2 combination with any amount of any other fuel in 

3 any year during 1998 through 2002 or, for a unit 

4 that commenced operation on or after January 1, 

5 2003, a unit designed to combust coal or any coal 

6 derived fuel alone or in combination with any other 

7 fuel. 

8 ‘‘(3) EASTERN BITUMINOUS.—The term ‘East9 ern bituminous’ means bituminous that is from a 

10 mine located in a State east of the Mississippi River. 

11 ‘‘(4) GENERAL ACCOUNT.—The term ‘general 

12 account’ means an account in the Allowance Track13 ing System under section 403(c) established by the 

14 Administrator for any person under 40 CFR part 

15 73.31(c) (2002), amended as appropriate by the Ad16 ministrator. 

17 ‘‘(5) OIL-FIRED.—The term ‘oil-fired’ with re18 gard to a unit means, for purposes of section 424, 

19 combusting fuel oil for more than 10 percent of the 

20 unit’s total heat input, and combusting no coal or 

21 coal-derived fuel, in any year during 1998 through 

22 2002 or, for a unit that commenced operation on or 

23 after January 1, 2003, a unit designed to combust 

24 oil for more than 10 percent of the unit’s total heat 
161 

•S 131 IS 

1 input and not to combust any coal or coal-derived 

2 fuel. 

3 ‘‘(6) UNIT ACCOUNT.—The term ‘unit account’ 

4 means an account in the Allowance Tracking System 

5 under section 403(c) established by the Adminis6 trator for any unit under 40 CFR section 73.31 (a) 

7 and (b) (2002), amended as appropriate by the Ad8 ministrator. 

9 ‘‘SEC. 422. APPLICABILITY. 

10 ‘‘(a) PROHIBITION.—Starting January 1, 2010, it 

11 shall be unlawful for the affected EGUs at a facility to 

12 emit a total amount of sulfur dioxide during the year in 

13 excess of the number of sulfur dioxide allowances held for 

14 such facility for that year by the owner or operator of the 

15 facility. 

16 ‘‘(b) ALLOWANCES HELD.—Only sulfur dioxide al17 lowances under section 423 shall be held in order to meet 

18 the requirements of subsection (a). 

19 ‘‘SEC. 423. LIMITATIONS ON TOTAL EMISSIONS. 

20 ‘‘For affected EGUs for 2010 and each year there21 after, the Administrator shall allocate sulfur dioxide allow22 ances under section 424. 

‘‘TABLE A—TOTAL SO2 ALLOWANCES ALLOCATED FOR EGUS

Year SO2 allowances allocated 

2010 ............................................................................................. 4,416,666

2011–2012 ................................................................................... 4,416,667

2013–2017 ................................................................................... 4,500,000

2018 and thereafter ..................................................................... 3,000,000. 
162 

•S 131 IS 

1 ‘‘SEC. 424. EGU ALLOCATIONS. 

2 ‘‘(a) IN GENERAL.—Not later than 3 years before the 

3 commencement date of the sulfur dioxide allowance re4 quirement of section 422, the Administrator shall promul5 gate regulations determining allocations of sulfur dioxide 

6 allowances for affected EGUs for each year during 2010 

7 and thereafter. The regulations shall provide that: 

8 ‘‘(1) 93 percent of the total amount of sulfur 

9 dioxide allowances shall be allocated to fossil-fuel10 fired affected EGUs under section 424 shall be allo11 cated by the Administrator to individual EGUs as 

12 follows: 

13 ‘‘(A) For each unit account and each gen14 eral account in the Allowance Tracking System, 

15 the Administrator shall determine the total 

16 amount of sulfur dioxide allowances allocated 

17 under subpart 1 for 2010 and thereafter that 

18 are recorded, as of 12:00 noon, Eastern Stand19 ard time, on the date 180 days after enactment 

20 of the Clear Skies Act of 2005. The Adminis21 trator shall determine this amount in accord22 ance with 40 CFR part 73 (2002), amended as 

23 appropriate by the Administrator, except that 

24 the Administrator shall apply a discount rate of 

25 7 percent for each year after 2010 to the 
163 

•S 131 IS 

1 amounts of sulfur dioxide allowances allocated 

2 for 2011 or later. 

3 ‘‘(B) For each unit account and each gen4 eral account in the Allowance Tracking System, 

5 the Administrator shall determine an amount of 

6 sulfur dioxide allowances equal to the allocation 

7 amount under subparagraph (A) multiplied by 

8 the ratio of the amount of sulfur dioxide allow9 ances determined to be recorded in that account 

10 under clause (i) to the total amount of sulfur 

11 dioxide allowances determined to be recorded in 

12 all unit accounts and general accounts in the 

13 Allowance Tracking System under clause (i). 

14 ‘‘(C) The Administrator shall allocate to 

15 each facility’s account in the Allowance Track16 ing System an amount of sulfur dioxide allow17 ances equal to the total amount of sulfur diox18 ide allowances determined under clause (ii) for 

19 the unit accounts of the units at the facility and 

20 shall allocate to each general account in the Al21 lowance Tracking System the amount of sulfur 

22 dioxide allowances determined under clause (ii) 

23 for that general account. 

24 ‘‘(2)(A) 7 percent of the total amount of sulfur 

25 dioxide allowances allocated each year under section 
164 

•S 131 IS 

1 423 shall be allocated for units at a facility that are 

2 affected EGUs, but did not receive sulfur dioxide al3 locations under subpart 1 of this title. 

4 ‘‘(B) The Administrator shall allocate each year 

5 for the units under subparagraph (A) that com6 menced operation before January 1, 2001, an 

7 amount of sulfur dioxide allowances determined by: 

8 ‘‘(i) For such units at the facility that are 

9 coal-fired, multiplying 0.40 lb/mmBtu by the 

10 total baseline heat input of such units and con11 verting to tons. 

12 ‘‘(ii) For such units at the facility that are 

13 oil-fired, multiplying 0.20 lb/mmBtu by the 

14 total baseline heat input of such units and con15 verting to tons. 

16 ‘‘(iii) For all such other units at the facil17 ity that are not covered by clause (i) or (ii), 

18 multiplying 0.05 lb/mmBtu by the total baseline 

19 heat input of such units and converting to tons. 

20 ‘‘(iv) If the total of the amounts for all fa21 cilities under clauses (i), (ii), and (iii) exceeds 

22 the allocation amount under subparagraph (A), 

23 multiplying the allocation amount under sub24 paragraph (A) by the ratio of the total of the 

25 amounts for the facility under clauses (i), (ii), 
165 

•S 131 IS 

1 and (iii) to the total of the amounts for all fa2 cilities under clause (i), (ii), and (iii). 

3 ‘‘(v) Allocating to each facility the lesser of 

4 the total of the amounts for the facility under 

5 clauses (i), (ii), and (iii) or, if the total of the 

6 amounts for all facilities under clauses (i), (ii), 

7 and (iii) exceeds the allocation amount under 

8 subparagraph (A), the amount under clause 

9 (iv). 

10 ‘‘(C) The Administrator shall allocate each year 

11 for units under subparagraph (A) that commence 

12 commercial operation on or after January l, 2001 

13 and before January 1, 2005, an amount of sulfur di14 oxide allowances determined by: 

15 ‘‘(i) For such units at the facility that are 

16 coal-fired or oil-fired, multiplying 0.19 lb/ 

17 mmBtu by the total baseline heat input of such 

18 units and converting to tons. 

19 ‘‘(ii) For all such other units at the facility 

20 that are not covered by clause (i), multiplying 

21 .005 lb/mmBtu by the total baseline heat input 

22 of such units and converting to tons. 

23 ‘‘(iii) If the total of the amounts for all fa24 cilities under clauses (i) and (ii) exceeds the al25 location amount under subparagraph (A), mul-
166 

•S 131 IS 

1 tiplying the allocation amount under subpara2 graph (A) by the ratio of the total of the 

3 amounts for the facility under clauses (i) and 

4 (ii) to the total of the amounts for all facilities 

5 under clauses (i) and (ii). 

6 ‘‘(iv) Allocating to each facility the lesser 

7 of the total of the amounts for the facility 

8 under clauses (i) and (ii) or, if the total of the 

9 amounts for all facilities under clauses (i) and 

10 (ii) exceeds the allocation amount under sub11 paragraph (A), the amount under clause (iv). 

12 The Administrator shall allocate to the facilities 

13 under paragraph (1) and this paragraph on a 

14 pro rata basis (based on the allocations under 

15 those paragraphs) any allowances not allocated 

16 under this paragraph. 

17 ‘‘(D) The Administrator shall allocate each year 

18 for units under subparagraph (A) that commence 

19 commercial operation on or after January 1, 2005, 

20 an amount of sulfur dioxide allowances determined 

21 for each such unit at the facility by multiplying the 

22 applicable National Emissions Standard under sec23 tion 481 by the applicable ‘‘baseline heat input,’’ 

24 considering fuel and combustion type, as defined in 

25 section 402(5)(B) and converting to tons. 
167 

•S 131 IS 

1 ‘‘(E) In the event that allocation demand ex2 ceeds supply, the Administrator shall allocate allow3 ances under subparagraph (A) giving first priority to 

4 units qualifying under subparagraph (B), second pri5 ority to units qualifying under subparagraph (C), 

6 and third priority to units qualifying under subpara7 graph (D). Allowances allocated under subparagraph 

8 (D) shall be allocated to units on a first come basis 

9 determined by date of unit commencement of con10 struction, provided that such unit actually com11 mences operation. As such, allocations to units 

12 under sub-paragraph (D) will not be reduced as a 

13 result of new units commencing commercial oper14 ation. 

15 ‘‘(b) FAILURE TO PROMULGATE.— 

16 ‘‘(1) ANNUAL NOTICE.—For each year 2010 

17 and thereafter, if the Administrator has not promul18 gated regulations, determining allocations under 

19 subsection (a), each affected EGU shall comply with 

20 section 422 by providing annual notice to the per21 mitting authority. Such notice shall indicate the 

22 amount of allowances the affected EGU believes it 

23 has for the relevant year and the amount of sulfur 

24 dioxide emissions for such year. The amount of sul25 fur dioxide emissions shall be determined using rea-
168 

•S 131 IS 

1 sonable industry accepted methods unless the Ad2 ministrator has promulgated applicable monitoring 

3 and alternative monitoring requirements. 

4 ‘‘(2) RECONCILIATION.—Upon promulgation of regu5 lations under subsection (a) determining the allocations 

6 for 2010 and thereafter, and promulgating regulations 

7 under section 403(b) providing for the transfer of sulfur 

8 dioxides and section 403(c) establishing an Allowance 

9 Transfer System for sulfur dioxide allowances, each unit’s 

10 emissions shall be compared to and reconciled to its actual 

11 allocations under the promulgated regulations. Each unit 

12 will have nine (9) months to purchase any allowance short13 fall through allowances purchased from other allowance 

14 holders or through direct sale. 

15 ‘‘SEC. 425. DISPOSITION OF SULFUR DIOXIDE ALLOWANCES 

16 ALLOCATED UNDER SUBPART 1. 

17 ‘‘(a) REMOVAL FROM ACCOUNTS.—After allocating 

18 allowances under section 424(a)(1), the Administrator 

19 shall remove from the unit accounts and general accounts 

20 in the Allowance Tracking System under section 403(c) 

21 and from the Special Allowances Reserve under section 

22 418 all sulfur dioxide allowances allocated or deposited 

23 under subpart 1 for 2010 or later. 

24 ‘‘(b) REGULATIONS.—The Administrator shall pro25 mulgate regulations as necessary to assure that the re-
169 

•S 131 IS 

1 quirement to hold allowances under section 422 may be 

2 met using sulfur dioxide allowances allocated under sub3 part 1 for 1995 through 2009. No part of this Act shall 

4 be construed to prevent use of unused pre-2010 allowances 

5 to meet the requirements of section 422. 

6 ‘‘SEC. 426. INCENTIVES FOR SULFUR DIOXIDE EMISSION 

7 CONTROL TECHNOLOGY. 

8 ‘‘(a) RESERVE.—The Administrator shall establish a 

9 reserve of 250,000 sulfur dioxide allowances comprising 

10 83,334 sulfur dioxide allowances for 2010, 83,333 sulfur 

11 dioxide allowances for 2011, and 83,333 sulfur dioxide al12 lowances for 2012. 

13 ‘‘(b) APPLICATION.—Not later than 18 months after 

14 the enactment of the Clear Skies Act of 2005, an owner 

15 or operator of an affected EGU that commenced operation 

16 before 2001 and that during 2001 combusted Eastern bi17 tuminous may submit an application to the Administrator 

18 for sulfur dioxide allowances from the reserve under sub19 section (a). The application shall include each of the fol20 lowing: 

21 ‘‘(1) A statement that the owner or operator 

22 will install and commence commercial operation of 

23 specified sulfur dioxide control technology at the 

24 unit within 24 months after approval of the applica25 tion under subsection (c) if the unit is allocated the 
170 

•S 131 IS 

1 sulfur dioxide allowances requested under paragraph 

2 (4). The owner or operator shall provide description 

3 of the control technology. 

4 ‘‘(2) A statement that, during the period start5 ing with the commencement of operation of sulfur 

6 dioxide technology under paragraph (1) through 

7 2009, the unit will combust Eastern bituminous at 

8 a percentage of the unit’s total heat input equal to 

9 or exceeding the percentage of total heat input com10 busted by the unit in 2001 if the unit is allocated 

11 the sulfur dioxide allowances requested under para12 graph (4). 

13 ‘‘(3) A demonstration that the unit will achieve, 

14 while combusting fuel in accordance with paragraph 

15 (2) and operating the sulfur dioxide control tech16 nology specified in paragraph (1), a specified ton17 nage of sulfur dioxide emission reductions during the 

18 period starting with the commencement of operation 

19 of sulfur dioxide control technology under subpara20 graph (1) through 2009. The tonnage of emission 

21 reductions shall be the difference between emissions 

22 monitored at a location at the unit upstream of the 

23 control technology described in paragraph (1) and 

24 emissions monitored at a location at the unit down-
171 

•S 131 IS 

1 stream of such control technology, while the unit is 

2 combusting fuel in accordance with paragraph (2). 

3 ‘‘(4) A request that the Administrator allocate 

4 for the unit a specified number of sulfur dioxide al5 lowances from the reserve under subsection (a) for 

6 the period starting with the commencement of oper7 ation of the sulfur dioxide technology under para8 graph (1) through 2009. 

9 ‘‘(5) A statement of the ratio of the number of 

10 sulfur dioxide allowances requested under paragraph 

11 (4) to the tonnage of sulfur dioxide emissions reduc12 tions under paragraph (3). 

13 ‘‘(c) APPROVAL OR DISAPPROVAL.—By order subject 

14 to notice and opportunity for comment, the Administrator 

15 shall— 

16 ‘‘(1) determine whether each application meets 

17 the requirements of subsection (b); 

18 ‘‘(2) list the applications meeting the require19 ments of subsection (b) and their respective allow20 ance-to-emission-reduction ratios under paragraph 

21 (b)(5) in order, from lowest to highest, of such ra22 tios; 

23 ‘‘(3) for each application listed under paragraph 

24 (2), multiply the amount of sulfur dioxide emission 

25 reductions requested by each allowance-to-emission- 
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1 reduction ratio on the list that equals or is less than 

2 the ratio for the application; 

3 ‘‘(4) sum, for each allowance-to-emission-reduc4 tion ratio in the list under paragraph (2), the 

5 amounts of sulfur dioxide allowances determined 

6 under paragraph (3); 

7 ‘‘(5) based on the calculations in paragraph (4), 

8 determine which allowance-to-emission-reduction 

9 ratio on the list under paragraph (2) results in the 

10 highest total amount of allowances that does not ex11 ceed 250,000 allowances; and 

12 ‘‘(6) approve each application listed under para13 graph (2) with a ratio equal to or less than the al14 lowance-to-emission-reduction ratio determined 

15 under paragraph (5) and disapprove all the other 

16 applications. 

17 ‘‘(d) MONITORING.—An owner or operator whose ap18 plication is approved under subsection (c) shall install and 

19 operate a CEMS for monitoring sulfur dioxide and to 

20 quality assure the data. The installation of the CEMS and 

21 the quality assurance of data shall be in accordance with 

22 subparagraph (a)(2)(B) and subsections (c) through (e) 

23 of section 405, except that, where two or more units utilize 

24 a single stack, and one or more units are not subject to 
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1 such standards, separate monitoring shall be required for 

2 each unit. 

3 ‘‘(e) ALLOCATIONS.—Not later than 6 months after 

4 the commencement date of the sulfur dioxide allowance re5 quirement of section 422, for the units for which applica6 tions are approved under subsection (c), the Administrator 

7 shall allocate sulfur dioxide allowances as follows: 

8 ‘‘(1) For each unit, the Administrator shall 

9 multiply the allowance-to-emission-reduction ratio of 

10 the last application that the Administrator approved 

11 under subsection (c) by the lesser of— 

12 ‘‘(A) the total tonnage of sulfur dioxide 

13 emissions reductions achieved by the unit, dur14 ing the period starting with the commencement 

15 of operation of the sulfur dioxide control tech16 nology under subparagraph (b)(1) through 

17 2009, through use of such control technology; 

18 or 

19 ‘‘(B) the tonnage of sulfur dioxide emission 

20 reductions under paragraph (b)(3). 

21 ‘‘(2) If the total amount of sulfur dioxide allow22 ances determined for all units under paragraph (1) 

23 exceeds 250,000 sulfur dioxide allowances, the Ad24 ministrator shall multiply 250,000 sulfur dioxide al25 lowances by the ratio of the amount of sulfur dioxide 
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1 allowances determined for each unit under para2 graph (1) to the total amount of sulfur dioxide al3 lowances determined for all units under paragraph 

4 (1). 

5 ‘‘(3) The Administrator shall allocate to each 

6 unit the lesser of the amount determined for that 

7 unit under paragraph (1) or, if the total amount of 

8 sulfur dioxide allowances determined for all units 

9 under paragraph (1) exceeds 250,000 sulfur dioxide 

10 allowances, under paragraph (2). The Administrator 

11 shall allocate to the facilities under section 424 

12 paragraphs (1) and (2) on a pro rata basis (based 

13 on the allocations under those paragraphs) any 

14 unallocated allowances under this paragraph. 

15 ‘‘Subpart 3—Western Regional Air Partnership 

16 ‘‘SEC. 431. DEFINITIONS. 

17 ‘‘For purposes of this subpart— 

18 ‘‘(1) ADJUSTED BASELINE HEAT INPUT.—The 

19 term ‘adjusted baseline heat input’ means the aver20 age annual heat input used by a unit during the 

21 three years in which the unit had the highest heat 

22 input for the period from the eighth through the 

23 fourth year before the first covered year. 
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1 ‘‘(A) Notwithstanding paragraph (1), if a 

2 unit commences operation during such period 

3 and— 

4 ‘‘(i) on or after January 1 of the fifth 

5 year before the first covered year, then ‘ad6 justed baseline heat input’ shall mean the 

7 average annual heat input used by the unit 

8 during the fifth and fourth years before 

9 the first covered year; and 

10 ‘‘(ii) on or after January 1 of the 

11 fourth year before the first covered year, 

12 then ‘adjusted baseline heat input’ shall 

13 mean the annual heat input used by the 

14 unit during the fourth year before the first 

15 covered year. 

16 ‘‘(B) A unit’s heat input for a year shall 

17 be the heat input— 

18 ‘‘(i) required to be reported under sec19 tion 405 for the unit, if the unit was re20 quired to report heat input during the year 

21 under that section; 

22 ‘‘(ii) reported to the Energy Informa23 tion Administrator for the unit, if the unit 

24 was not required to report heat input 

25 under section 405; 
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1 ‘‘(iii) based on data for the unit re2 ported to the WRAP State where the unit 

3 is located as required by State law, if the 

4 unit was not required to report heat input 

5 during the year under section 405 and did 

6 not report to the Energy Information Ad7 ministration; or 

8 ‘‘(iv) based on fuel use and fuel heat 

9 content data for the unit from fuel pur10 chase or use records, if the unit was not 

11 required to report heat input during the 

12 year under section 405 and did not report 

13 to the Energy Information Administration 

14 and the WRAP State. 

15 ‘‘(2) AFFECTED EGU.—The term ‘affected 

16 EGU’ means an affected EGU under subpart 2 that 

17 is in a WRAP State and that— 

18 ‘‘(A) in 2000, emitted 100 tons or more of 

19 sulfur dioxide and was used to produce elec20 tricity for sale; or 

21 ‘‘(B) in any year after 2000, emits 100 

22 tons or more of sulfur dioxide and is used to 

23 produce electricity for sale. 

24 ‘‘(3) COAL-FIRED.—The term ‘coal-fired’ with 

25 regard to a unit means, for purposes of section 434, 
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1 a unit combusting coal or any coal-derived fuel alone 

2 or in combination with any amount of any other fuel 

3 in any year during the period from the eighth 

4 through the fourth year before the first covered 

5 year. 

6 ‘‘(4) COVERED YEAR.—The term ‘covered year’ 

7 means— 

8 ‘‘(A)(i) the third year after the year 2018 

9 or later when the total annual sulfur dioxide 

10 emissions of all affected EGUs in the WRAP 

11 States first exceed 271,000 tons; or 

12 ‘‘(ii) the third year after the year 2013 or 

13 later when the Administrator determines by 

14 regulation that the total annual sulfur dioxide 

15 emissions of all affected EGUs in the WRAP 

16 States are reasonably projected to exceed 

17 271,000 tons in 2018 or any year thereafter. 

18 The Administrator may make such determina19 tion only if all the WRAP States submit to the 

20 Administrator a petition requesting that the 

21 Administrator issue such determination and 

22 make all affected EGUs in the WRAP States 

23 subject to the requirements of sections 432 

24 through 434; and 
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1 ‘‘(B) each year after the ‘covered year’ 

2 under subparagraph (A). 

3 ‘‘(5) OIL-FIRED.—The term ‘oil-fired’ with re4 gard to a unit means, for purposes of section 434, 

5 a unit combusting fuel oil for more than 10 percent 

6 of the unit’s total heat input, and combusting no 

7 coal or coal-derived fuel, and any year during the pe8 riod from the eighth through the fourth year before 

9 the first covered year. 

10 ‘‘(6) WRAP STATE.—The term ‘WRAP State’ 

11 means Arizona, California, Colorado, Idaho, Nevada, 

12 New Mexico, Oregon, Utah, and Wyoming. 

13 ‘‘SEC. 432. APPLICABILITY. 

14 ‘‘(a) PROHIBITION.—Starting January 1 of the first 

15 covered year, it shall be unlawful for the affected EGUs 

16 at a facility to emit a total amount of sulfur dioxide during 

17 the year in excess of the number of sulfur dioxide allow18 ances held for such facility for that year by the owner or 

19 operator of the facility. 

20 ‘‘(b) ALLOWANCES HELD.—Only sulfur dioxide al21 lowances under section 433 shall be held in order to meet 

22 the requirements of subsection (a). 

23 ‘‘SEC. 433. LIMITATIONS ON TOTAL EMISSIONS. 

24 For affected EGUs, the total amount of sulfur diox25 ide allowances that the Administrator shall allocate for 
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1 each covered year under section 434 shall equal 271,000 

2 tons. 

3 ‘‘SEC. 434. EGU ALLOCATIONS. 

4 ‘‘(a) IN GENERAL.—By January 1 of the year before 

5 the first covered year, the Administrator shall promulgate 

6 regulations determining, for each covered year, the alloca7 tions of sulfur dioxide allowances for the units at a facility 

8 that are affected EGUs as of December 31 of the fourth 

9 year before the covered year by— 

10 ‘‘(1) for such units at the facility that are coal11 fired, multiplying 0.40 lb/mmBtu by the total ad12 justed baseline heat input of such units and con13 verting to tons; 

14 ‘‘(2) for such units at the facility that are oil15 fired, multiplying 0.20 lb/mmBtu by the total ad16 justed baseline heat input of such units and con17 verting to tons; 

18 ‘‘(3) for all such other units at the facility that 

19 are not covered by paragraph (1) or (2) multiplying 

20 0.05 lb/mmBtu by the total adjusted baseline heat 

21 input of such units and converting to tons; and 

22 ‘‘(4) multiplying by 0.95 the allocation amount 

23 under section 433 by the ratio of the total of the 

24 amounts for the facility under paragraphs (1), (2), 
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1 and (3) to the total of the amounts for all facilities 

2 under paragraphs (1), (2), and (3); and 

3 ‘‘(5)(A) 5 percent of the total amount of sulfur 

4 dioxide allowances allocated each year under section 

5 433 shall be allocated for units at a facility that are 

6 affected EGUs, but did not receive sulfur dioxide al7 locations under paragraph (4). These units shall be 

8 allocated allowances in accordance with paragraphs 

9 (1), (2), and (3). 

10 ‘‘(B) Allowances allocated under subparagraph 

11 (A) shall be allocated to units on a first come basis 

12 determined by date of unit commencement of con13 struction, provided that such unit actually com14 mences operation. As such, allocations to units 

15 under paragraph (A) will not be reduced as a result 

16 of new units commencing commercial operation. 

17 ‘‘(C) Allowances not allocated under subpara18 graph (B) shall be allocated to units in paragraphs 

19 (A) and (B) on a pro rata basis. 

20 ‘‘(b) FAILURE TO PROMULGATE.— 

21 ‘‘(1) IN GENERAL.—For each year 2010 and 

22 thereafter, if the Administrator has not promulgated 

23 regulations, determining allocations under paragraph 

24 (a), each affected EGU shall comply with section 

25 422 by provided annual notice to the permitting au-
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1 thority. Such notice shall indicate the amount of al2 lowances the affected EGU believes it has for the 

3 relevant year and the amount of sulfur dioxide emis4 sions for such year. The amount of sulfur dioxide 

5 emissions shall be determined using reasonable in6 dustry accepted methods unless the Administrator 

7 has promulgated applicable monitoring and alter8 native monitoring requirements. 

9 ‘‘(2) RECONCILIATION.—Upon promulgation of 

10 regulations under subsection (a) determining the al11 locations for 2010 and thereafter, and promulgating 

12 regulations under section 403(b) providing for the 

13 transfer of sulfur dioxides and section 403(c) estab14 lishing an Allowance Transfer System for sulfur di15 oxide allowances, each unit’s emissions shall be com16 pared to and reconciled to its actual allocations 

17 under the promulgated regulations. Each unit will 

18 have nine (9) months to purchase any allowance 

19 shortfall through allowances purchased from other 

20 allowance holders or through direct sale. 
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1 ‘‘PART C—NITROGEN OXIDES CLEAR SKIES 

2 EMISSION REDUCTIONS 

3 ‘‘Subpart 1—Acid Rain Program 

4 ‘‘SEC. 441. NITROGEN OXIDES EMISSION REDUCTION PRO5 GRAM. 

6 ‘‘(a) APPLICABILITY.—On the date that a coal-fired 

7 utility unit becomes an affected unit pursuant to sections 

8 413 or 414, or on the date a unit subject to the provisions 

9 of section 413(d), must meet the NOX reduction require10 ments, each such unit shall become an affected unit for 

11 purposes of this section and shall be subject to the emis12 sion limitations for nitrogen oxides set forth herein. 

13 ‘‘(b) EMISSION LIMITATIONS.— 

14 (1) IN GENERAL.—The Administrator shall by 

15 regulation establish annual allowable emission limi16 tations for nitrogen oxides for the types of utility 

17 boilers listed below, which limitations shall not ex18 ceed the rates listed below: Provided, That the Ad19 ministrator may set a rate higher than that listed 

20 for any type of utility boiler if the Administrator 

21 finds that the maximum listed rate for that boiler 

22 type cannot be achieved using low NOX burner tech23 nology. The Administrator shall implement this 

24 paragraph under 40 CFR part 76.5 (2002). The 

25 maximum allowable emission rates are as follows: 
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1 ‘‘(A) for tangentially fired boilers, 0.45 lb/ 

2 mmBtu; and 

3 ‘‘(B) for dry bottom wall-fired boilers 

4 (other than units applying cell burner tech5 nology), 0.50 lb/mmBtu. After January 1, 

6 1995, it shall be unlawful for any unit that is 

7 an affected unit on that date and is of the type 

8 listed in this paragraph to emit nitrogen oxides 

9 in excess of the emission rates set by the Ad10 ministrator pursuant to this paragraph. 

11 ‘‘(2) UTILITY BOILERS.—The Administrator 

12 shall, by regulation, establish allowable emission lim13 itations on a lb/mmBtu, annual average basis, for 

14 nitrogen oxides for the following types of utility boil15 ers: 

16 ‘‘(A) wet bottom wall-fired boilers; 

17 ‘‘(B) cyclones; 

18 ‘‘(C) units applying cell burner technology; 

19 and 

20 ‘‘(D) all other types of utility boilers. 

21 ‘‘(3) BASIS OF RATES.—The Administrator 

22 shall base such rates on the degree of reduction 

23 achievable through the retrofit application of the 

24 best system of continuous emission reduction, taking 

25 into account available technology, costs and energy 
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1 and environmental impacts; and which is comparable 

2 to the costs of nitrogen oxides controls set pursuant 

3 to subsection (b)(1). The Administrator may revise 

4 the applicable emission limitations for tangentially 

5 fired and dry bottom, wall-fired boilers (other than 

6 cell burners) to be more stringent if the Adminis7 trator determines that more effective low NOX

8 burned technology is available: Provided, That, no 

9 unit that is an affected unit pursuant to section 413 

10 and that is subject to the requirements of subsection 

11 (b)(1), shall be subject to the revised emission limi12 tations, if any. The Administrator shall implement 

13 that paragraph under 40 CFR parts 76.6 and 76.7 

14 (2002). 

15 ‘‘(c) ALTERNATIVE EMISSION LIMITATIONS.—(1) 

16 The permitting authority shall, upon request of an owner 

17 or operator of a unit subject to this section, authorize an 

18 emission limitation less stringent than the applicable limi19 tation established under subsection (b)(1) or (b)(2) upon 

20 a determination that— 

21 ‘‘(A) a unit subject to subsection (b)(1) cannot 

22 meet the applicable limitation using low NOX burner 

23 technology; or 

24 ‘‘(B) a unit subject to subsection (b)(2) cannot 

25 meet the applicable rate using the technology on 
185 

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1 which the Administrator based the applicable emis2 sion limitation. 

3 ‘‘(2) ELIGIBILITY FOR ALTERNATIVE EMISSION LIMI4 TATIONS.—The permitting authority shall base such de5 termination upon a reasonable showing satisfactory to the 

6 permitting authority, in accordance with regulations es7 tablished by the Administrator, that the owner or oper8 ator— 

9 ‘‘(A) has properly installed appropriate control 

10 equipment designed to meet the applicable emission 

11 rate; 

12 ‘‘(B) has properly operated such equipment for 

13 a period of 15 months (or such other period of time 

14 as the Administrator determines through the regula15 tions), and provides operating and monitoring data 

16 for such period demonstrating that the unit cannot 

17 meet the applicable emission rate; and 

18 ‘‘(C) has specified an emission rate that such 

19 unit can meet on an annual average basis. The per20 mitting authority shall issue an operating permit for 

21 the unit in question, in accordance with section 404 

22 and title V— 

23 ‘‘(i) that permits the unit during the dem24 onstration period referred to in subparagraph 
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1 (B), to emit at a rate in excess of the applicable 

2 emission rate; 

3 ‘‘(ii) at the conclusion of the demonstra4 tion period to revise the operating permit to re5 flect the alternative emission rate demonstrated 

6 in subparagraphs (B) and (C). 

7 ‘‘(3) ADDITIONAL CONTROL TECHNOLOGY.—Units 

8 subject to subsection (b)(1) for which an alternative emis9 sion limitation is established shall not be required to in10 stall any additional control technology beyond low NOX

11 burners. Nothing in this section shall preclude an owner 

12 or operator from installing and operating an alternative 

13 NOX control technology capable of achieving the applica14 ble emission limitation. The Administrator shall imple15 ment this subsection under 40 CFR part 76 (2002), 

16 amended as appropriate by the Administrator. 

17 ‘‘(d) EMISSIONS AVERAGING.— 

18 ‘‘(1) ALERNATIVE CONTEMPORANEOUS EMIS19 SION LIMITATIONS.—In lieu of complying with the 

20 applicable emission limitations under subsection 

21 (b)(1), (2), or (c), the owner or operator of two or 

22 more units subject to one or more of the applicable 

23 emission limitations set pursuant to these sections, 

24 may petition the permitting authority for alternative 
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1 contemporaneous annual emission limitations for 

2 such units that ensure that— 

3 ‘‘(A) the actual annual emission rate in 

4 pounds of nitrogen oxides per million Btu aver5 aged over the units in question is a rate that 

6 is less than; or equal to 

7 ‘‘(B) the Btu-weighted average annual 

8 emission rate for the same units if they had 

9 been operated, during the same period of time, 

10 in compliance with limitations set in accordance 

11 with the applicable emission rates set pursuant 

12 to subsections (b)(1) and (2). 

13 ‘‘(2) OPERATING PERMITS.—If the permitting 

14 authority determines, in accordance with regulations 

15 issued by the Administrator that the conditions in 

16 paragraph (1) can be met, the permitting authority 

17 shall issue operating permits for such units, in ac18 cordance with section 404 and title V, that allow al19 ternative contemporaneous annual emission limita20 tions. Such emission limitations shall only remain in 

21 effect while both units continue operation under the 

22 conditions specified in their respective operating per23 mits. The Administrator shall implement this sub24 section under 40 CFR part 76 (2002), amended as 

25 appropriate by the Administrator. 
188 

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1 ‘‘SEC. 442. TERMINATION. 

2 ‘‘Starting January 1, 2008, the owner or operator of 

3 affected units and affected facilities under section 441 

4 shall no longer be subject to the requirements of that sec5 tion. 

6 ‘‘Subpart 2—Clear Skies Nitrogen Oxides Allowance 

7 Program 

8 ‘‘SEC. 451. DEFINITIONS. 

9 ‘‘For purposes of this subpart: 

10 ‘‘(1) AFFECTED EGU.—The term ‘affected 

11 EGU’ means— 

12 ‘‘(A) for a unit serving a generator before 

13 the date of enactment of the Clear Skies Act of 

14 2005, a unit in a State serving a generator with 

15 a nameplate capacity of greater than 25 

16 megawatts that produced or produces electricity 

17 for sale during 2002 or any year thereafter, ex18 cept for a cogeneration unit that meets the cri19 teria for qualifying for a cogeneration facilities 

20 codified in section 292.205 of title 18 of the 

21 Code of Federal Regulations as issued on April 

22 1, 2002 during 2002 and each year thereafter; 

23 and 

24 ‘‘(B) for a unit commencing service of a 

25 generator on or after the date of enactment of 

26 the Clear Skies Act of 2005, a unit in a State 
189 

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1 serving a generator that produces electricity for 

2 sale during any year starting with the year the 

3 unit commences service of a generator, except 

4 for a gas-fired unit serving one or more genera5 tors with total nameplate capacity of 25 

6 megawatts or less, or a cogeneration unit that 

7 meets the criteria for qualifying for a cogenera8 tion facilities codified in section 292.205 of title 

9 18 of the Code of Federal Regulations as issued 

10 on April 1, 2002, during each year starting 

11 with the unit commences service of a generator. 

12 ‘‘(C) EXCLUSION.—Notwithstanding para13 graphs (A) and (B), the term ‘affected EGU’ 

14 does not include a solid waste incineration unit 

15 subject to section 129 or a unit for the treat16 ment, storage, or disposal of hazardous waste 

17 subject to section 3005 of the Solid Waste Dis18 posal Act. 

19 ‘‘(2) ADJUSTED BASELINE HEAT INPUT.—The 

20 term ‘adjusted baseline heat input’ with regard to a 

21 unit means, for purposes of allocating nitrogen ox22 ides allowances in a particular year under this sub23 part, the units baseline multiplied by— 

24 ‘‘(A) 1.0 for affected coal-fired units for 

25 2008 and each year thereafter; 
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1 ‘‘(B) 0.55 for affected oil- and gas-fired 

2 units located in a Zone 1 State for years 2008 

3 through 2017 inclusive; 

4 ‘‘(C) 0.8 for affected oil- and gas-fired 

5 units located in a Zone 1 State for 2018 and 

6 each year thereafter; and 

7 ‘‘(D) 0.4 for affected oil- and gas-fired 

8 units located in a Zone 2 State for 2008 and 

9 each year thereafter. 

10 ‘‘(3) ALLOWABLE NITROGEN OXIDES EMISSIONS

11 RATE.—The term ‘allowable nitrogen oxides emis12 sions rate’ means the most stringent Federal or 

13 State emissions limitation for nitrogen oxides that 

14 applies to the unit as of date of enactment of this 

15 subpart. If the emissions limitation for a unit is not 

16 expressed in pounds of emissions per million Btu, or 

17 the averaging period of that emissions limitation is 

18 not expressed on an annual basis, the Administrator 

19 shall calculate the annual equivalent of that emis20 sions limitation to establish the allowable rate. Such 

21 limitation shall not include any requirement to hold 

22 nitrogen oxides allowances under the Federal NOX

23 Budget Trading Program as codified at 40 CFR 

24 part 97 (2002), or any State program adopted to 
191 

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1 meet the requirements of the NOX SIP Call as codi2 fied at 40 CFR 51.121 (2002). 

3 ‘‘(4) ZONE 1 STATE.—The term ‘Zone 1 State’ 

4 means Alabama, Arkansas, Connecticut, Delaware, 

5 the District of Columbia, Florida, Georgia, Illinois, 

6 Indiana, Iowa, Kentucky, Louisiana, Maine, Mary7 land, Massachusetts, Michigan, Mississippi, the fine 

8 grid portion (as defined in section 51.121 of title 40, 

9 Code of Federal Regulations (as in effect for 2002)) 

10 of Missouri, New Hampshire, New Jersey, New 

11 York, North Carolina, Ohio, Pennsylvania, Rhode Is12 land, South Carolina, Tennessee, Texas east of 

13 Interstate 35, Vermont, Virginia, West Virginia, and 

14 Wisconsin. 

15 ‘‘(5) ZONE 2 STATE.—The term ‘Zone 2 State’ 

16 means Alaska, American Samoa, Arizona, California, 

17 Colorado, the Commonwealth of the Northern Mar18 iana Islands, the Commonwealth of Puerto Rico, 

19 Guam, Hawaii, Idaho, Kansas, Minnesota, the 

20 coarse grid portion (as defined in section 51.121 of 

21 title 40, Code of Federal Regulations (as in effect 

22 for 2002)) of Missouri, Montana, Nebraska, North 

23 Dakota, New Mexico, Nevada, Oklahoma, Oregon, 

24 South Dakota, Texas west of Interstate 35, Utah, 

25 the Virgin Islands, Washington, and Wyoming. 
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1 ‘‘SEC. 452. APPLICABILITY. 

2 ‘‘(a) ZONE 1 PROHIBITION.— 

3 (1) IN GENERAL.—Starting January 1, 2008, it 

4 shall be unlawful for the affected EGUs at a facility 

5 in a Zone 1 State to emit a total amount of nitrogen 

6 oxides during a year in excess of the number of ni7 trogen oxides allowances held for such facility for 

8 that year by the owner or operator of the facility. 

9 ‘‘(2) LIMITATION.—Only nitrogen oxides allow10 ances under section 453(a) shall be held in order to 

11 meet the requirements of paragraph (1), except as 

12 provided under section 465. 

13 ‘‘(b) ZONE 2 PROHIBITION.— 

14 (1) IN GENERAL.—Starting January 1, 2008, it 

15 shall be unlawful for the affected EGUs at a facility 

16 in a Zone 2 State to emit a total amount of nitrogen 

17 oxides during a year in excess of the number of ni18 trogen oxides allowances held for such facility for 

19 that year by the owner or operator of the facility. 

20 ‘‘(2) LIMITATION.—Only nitrogen oxides allowances 

21 under section 453(b) shall be held in order to meet the 

22 requirements of paragraph (1). 

23 ‘‘SEC. 453. LIMITATIONS ON TOTAL EMISSIONS. 

24 ‘‘(a) ZONE 1 ALLOCATIONS.—For affected EGUs in 

25 the Zone 1 States for 2008 and each year thereafter, the 
193 

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1 Administrator shall allocate nitrogen oxides allowances 

2 under section 454(a) as specified in table A. 

‘‘TABLE A—TOTAL NOX ALLOWANCES ALLOCATED FOR EGUS IN 

ZONE 1 

Year NOX allowances allocated 

2008–2017 ................................................................................... 1,473,603 

2018 and thereafter ..................................................................... 1,073,603 

3 ‘‘(b) ZONE 2 ALLOCATIONS.—For affected EGUs in 

4 the Zone 2 States for 2008 and each year thereafter, the 

5 Administrator shall allocate nitrogen oxides allowances 

6 under section 454(b) as specified in table B. 

‘‘TABLE B—TOTAL NOX ALLOWANCES ALLOCATED FOR EGUS IN 

ZONE 2 

Year NOX allowance allocated 

2008 and thereafter ..................................................................... 714,794 

7 ‘‘SEC. 454. EGU ALLOCATIONS. 

8 ‘‘(a) EGU ALLOCATIONS IN THE ZONE 1 STATES.— 

9 ‘‘(1) EPA REGULATIONS.—Not later than 18 

10 months before the date on which the nitrogen oxides 

11 allowance requirement under section 452 takes ef12 fect, the Administrator shall promulgate regulations 

13 determining the allocation of nitrogen oxide allow14 ances for 2008 and each subsequent year for units 

15 at a facility in a Zone 1 State that are affected 

16 EGUs as of the date of enactment of this section. 

17 ‘‘(2) FORMULA FOR ALLOCATION.— 

18 ‘‘(A) IN GENERAL.—Subject to subpara19 graph (B) and paragraph (3), the regulations 
194 

•S 131 IS 

1 shall specify that the allocation of nitrogen 

2 oxide allowances for each unit referred to in 

3 paragraph (1) for each year shall be the prod4 uct obtained by multiplying— 

5 ‘‘(i) the product of 0.95 and the allo6 cation amount under section 453(a); and 

7 ‘‘(ii) the ratio that— 

8 ‘‘(I) the total quantity of the ad9 justed baseline heat input of the units 

10 at the facility; bears to 

11 ‘‘(II) the total quantity of ad12 justed baseline heat input to all af13 fected EGUs in the Zone 1 States; 

14 and 

15 ‘‘(B) MAXIMUM ALLOCATION.—Notwith16 standing subparagraph (A) and paragraph (3), 

17 no unit shall receive an allocation in excess of 

18 the product obtained by multiplying— 

19 ‘‘(i) the baseline heat input of the 

20 unit; and 

21 ‘‘(ii) the quotient obtained by dividing 

22 the allowable nitrogen oxides emissions 

23 rate of the unit by 2000. 

24 ‘‘(3) DISTRIBUTION OF REMAINING ALLOW25 ANCES.— 
195 

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1 ‘‘(A) IN GENERAL.—Subject to paragraph 

2 (2)(B), any nitrogen oxide allowances remaining 

3 after the allocation of allowances under para4 graph (2) shall be distributed on a pro rata 

5 basis among the units that received nitrogen 

6 oxide allowances under that paragraph. 

7 ‘‘(B) ADDITIONAL REMAINING ALLOW8 ANCES.—Allowances remaining after each 

9 iteration of the calculation under subparagraph 

10 (A) as a result of the limitation under para11 graph (2)(B) shall be allocated in accordance 

12 with subparagraph (A). 

13 ‘‘(4) SET-ASIDE FOR NEW UNITS.— 

14 ‘‘(A) IN GENERAL.—5 percent of the total 

15 amount of nitrogen oxide allowances allocated 

16 each year under section 453 shall be allocated 

17 for units at a facility that are affected EGUs, 

18 but did not receive nitrogen oxide allocations 

19 under paragraph (2). 

20 ‘‘(B) FORMULA FOR ALLOCATION.— 

21 ‘‘(i) IN GENERAL.—Subject to clause 

22 (ii) and subparagraph (E), the regulations 

23 promulgated under paragraph (1) shall 

24 specify that the allocation of nitrogen oxide 

25 allowances for each unit referred to in sub-
196 

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1 paragraph (A) for each year shall be the 

2 product obtained by multiplying— 

3 ‘‘(I) the product of 0.05 and the 

4 allocation amount under section 

5 453(a); and 

6 ‘‘(II) the ratio that— 

7 ‘‘(aa) the total quantity of 

8 the adjusted baseline heat input 

9 of the units at the facility; bears 

10 to 

11 ‘‘(bb) the total quantity of 

12 adjusted baseline heat input to 

13 all affected EGUs in the Zone 1 

14 States, including those affected 

15 EGUs that receive allowances 

16 under paragraph (2). 

17 ‘‘(ii) ADDITIONAL ALLOWANCES.— 

18 Notwithstanding clause (i) and subpara19 graph (E), no unit shall receive an alloca20 tion under this paragraph in excess of the 

21 product obtained by multiplying— 

22 ‘‘(I) the baseline heat input of 

23 the unit; and 
197 

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1 ‘‘(II) the quotient obtained by di2 viding the allowable nitrogen oxides 

3 emissions rate of the unit by 2000. 

4 ‘‘(C) METHOD OF ALLOCATION.—Allow5 ances allocated under this paragraph shall be 

6 allocated to each unit on a first-come basis de7 termined by the date on which the unit com8 mences operation. 

9 ‘‘(D) NO REDUCTION IN ALLOCATIONS.— 

10 Allocations to units under this paragraph shall 

11 not be reduced as a result of new units com12 mencing commercial operation. 

13 ‘‘(E) DISTRIBUTION OF REMAINING AL14 LOWANCES.—Any nitrogen oxide allowances re15 maining after the allocation of allowances under 

16 subparagraph (B) shall be distributed on a pro 

17 rata basis among the units that received nitro18 gen oxide allowances under that subparagraph 

19 and paragraphs (2) and (3). 

20 ‘‘(5) FAILURE TO PROMULGATE REGULA21 TIONS.—For calendar year 2008 and each calendar 

22 year thereafter, if the Administrator has not promul23 gated the regulations determining the allocations 

24 under this subsection— 
198 

•S 131 IS 

1 ‘‘(A) each affected unit shall comply with 

2 section 452 by providing an annual notice to 

3 the permitting authority that indicates the 

4 amount of allowances the affected unit believes 

5 the affected unit has for the relevant year (in6 cluding the quantity of nitrogen oxide emissions 

7 of the affected unit for that year); 

8 ‘‘(B) the amount of nitrogen oxide emis9 sions of an affected unit described in subpara10 graph (A) shall be determined using reasonable 

11 industry accepted methods unless the Adminis12 trator has promulgated applicable monitoring 

13 and alternative monitoring requirements; and 

14 ‘‘(C) upon promulgation of regulations 

15 under this subsection for Zone 1 determining 

16 the allocations for 2008 and each year there17 after, and promulgation of regulations under 

18 section 403(b) providing for the transfer of ni19 trogen oxides and regulations under section 

20 403(c) establishing an Allowance Transfer Sys21 tem for nitrogen oxide allowances— 

22 ‘‘(i) the emissions of each unit shall 

23 be compared to and reconciled with actual 

24 allocations to the unit under the regula25 tions; and 
199 

•S 131 IS 

1 ‘‘(ii) each unit shall have not more 

2 than 270 days to submit allowances to the 

3 Administrator, without recompense, for 

4 any allowance shortfall (including sub5 mitted allowances obtained and held by 

6 any mechanism consistent with this Act, 

7 including direct sale). 

8 ‘‘(b) EGU ALLOCATIONS IN THE ZONE 2 STATES.— 

9 ‘‘(1) EPA REGULATIONS.—Not later than 18 

10 months before the date on which the nitrogen oxides 

11 allowance requirement under section 452 takes ef12 fect, the Administrator shall promulgate regulations 

13 determining the allocation of nitrogen oxide allow14 ances for 2008 and each subsequent year for units 

15 at a facility in a Zone 2 State that are affected 

16 EGUs as of the date of enactment of this section. 

17 ‘‘(2) FORMULA FOR ALLOCATION.— 

18 ‘‘(A) IN GENERAL.—Subject to subpara19 graph (B) and paragraph (3), the regulations 

20 shall specify that the allocation of nitrogen 

21 oxide allowances for each unit referred to in 

22 paragraph (1) for each year shall be the prod23 uct obtained by multiplying— 

24 ‘‘(i) the product of 0.95 and the allo25 cation amount under section 453(b); and 
200 

•S 131 IS 

1 ‘‘(ii) the ratio that— 

2 ‘‘(I) the total quantity of the ad3 justed baseline heat input of the units 

4 at the facility; bears to 

5 ‘‘(II) the total quantity of ad6 justed baseline heat input to all af7 fected EGUs in the Zone 2 States. 

8 ‘‘(B) MAXIMUM ALLOCATION.—Notwith9 standing subparagraph (A) and paragraph (3), 

10 no unit shall receive an allocation in excess of 

11 the product obtained by multiplying— 

12 ‘‘(i) the baseline heat input of the 

13 unit; and 

14 ‘‘(ii) the quotient obtained by dividing 

15 the allowable nitrogen oxides emissions 

16 rate of the unit by 2000. 

17 ‘‘(3) DISTRIBUTION OF REMAINING ALLOW18 ANCES.— 

19 ‘‘(A) IN GENERAL.—Subject to paragraph 

20 (2)(B), any nitrogen oxide allowances remaining 

21 after the allocation of allowances under para22 graph (2) shall be distributed on a pro rata 

23 basis among the units that received nitrogen 

24 oxide allowances under that paragraph. 
201 

•S 131 IS 

1 ‘‘(B) ADDITIONAL REMAINING ALLOW2 ANCES.—Allowances remaining after each 

3 iteration of the calculation under subparagraph 

4 (A) as a result of the limitation under para5 graph (2)(B) shall be allocated in accordance 

6 with subparagraph (A). 

7 ‘‘(4) SET-ASIDE FOR NEW UNITS.— 

8 ‘‘(A) IN GENERAL.—5 percent of the total 

9 amount of nitrogen oxide allowances allocated 

10 each year under section 453 shall be allocated 

11 for units at a facility that are affected EGUs, 

12 but did not receive nitrogen oxide allocations 

13 under paragraph (2). 

14 ‘‘(B) FORMULA FOR ALLOCATION.— 

15 ‘‘(i) IN GENERAL.—Subject to clause 

16 (ii) and subparagraph (E), the regulations 

17 promulgated under paragraph (1) shall 

18 specify that the allocation of nitrogen oxide 

19 allowances for each unit referred to in sub20 paragraph (A) for each year shall be the 

21 product obtained by multiplying— 

22 ‘‘(I) the product of 0.05 and the 

23 allocation amount under section 

24 453(a); and 

25 ‘‘(II) the ratio that— 
202 

•S 131 IS 

1 ‘‘(aa) the total quantity of 

2 the adjusted baseline heat input 

3 of the units at the facility; bears 

4 to 

5 ‘‘(bb) the total quantity of 

6 adjusted baseline heat input to 

7 all affected EGUs in the Zone 2 

8 States, including those affected 

9 EGUs that receive allowances 

10 under paragraph (2). 

11 ‘‘(ii) ADDITIONAL ALLOWANCES.— 

12 Notwithstanding clause (i) and subpara13 graph (E), no unit shall receive an alloca14 tion under this paragraph in excess of the 

15 product obtained by multiplying— 

16 ‘‘(I) the baseline heat input of 

17 the unit; and 

18 ‘‘(II) the quotient obtained by di19 viding the allowable nitrogen oxides 

20 emissions rate of the unit by 2000. 

21 ‘‘(C) METHOD OF ALLOCATION.—Allow22 ances allocated under this paragraph shall be 

23 allocated to each unit on a first-come basis de24 termined by the date on which the unit com25 mences operation. 
203 

•S 131 IS 

1 ‘‘(D) NO REDUCTION IN ALLOCATIONS.— 

2 Allocations to units under this paragraph shall 

3 not be reduced as a result of new units com4 mencing commercial operation. 

5 ‘‘(E) DISTRIBUTION OF REMAINING AL6 LOWANCES.—Any nitrogen oxide allowances re7 maining after the allocation of allowances under 

8 subparagraph (B) shall be distributed on a pro 

9 rata basis among the units that received nitro10 gen oxide allowances under that subparagraph 

11 and paragraphs (2) and (3). 

12 ‘‘(5) FAILURE TO PROMULGATE REGULA13 TIONS.—For calendar year 2008 and each calendar 

14 year thereafter, if the Administrator has not promul15 gated the regulations determining the allocations 

16 under this subsection— 

17 ‘‘(A) each affected unit shall comply with 

18 section 452 by providing an annual notice to 

19 the permitting authority that indicates the 

20 amount of allowances the affected unit believes 

21 the affected unit has for the relevant year (in22 cluding the quantity of nitrogen oxide emissions 

23 of the affected unit for that year); 

24 ‘‘(B) the amount of nitrogen oxide emis25 sions of an affected unit described in subpara-
204 

•S 131 IS 

1 graph (A) shall be determined using reasonable 

2 industry accepted methods unless the Adminis3 trator has promulgated applicable monitoring 

4 and alternative monitoring requirements; and 

5 ‘‘(C) upon promulgation of regulations 

6 under this subsection for Zone 2 determining 

7 the allocations for 2008 and each year there8 after, and promulgation of regulations under 

9 section 403(b) providing for the transfer of ni10 trogen oxides and regulations under section 

11 403(c) establishing an Allowance Transfer Sys12 tem for nitrogen oxide allowances— 

13 ‘‘(i) the emissions of each unit shall 

14 be compared to and reconciled with actual 

15 allocations to the unit under the regula16 tions; and 

17 ‘‘(ii) each unit shall have not more 

18 than 270 days to submit allowances to the 

19 Administrator, without recompense, for 

20 any allowance shortfall (including sub21 mitted allowances obtained and held by 

22 any mechanism consistent with this Act, 

23 including direct sale). 
205 

•S 131 IS 

1 ‘‘SEC. 455 NITROGEN OXIDES EARLY ACTION REDUCTION 

2 CREDITS. 

3 ‘‘(a) CREDITS.—Except as provided in subsection (e), 

4 the Administrator shall promulgate regulations within 18 

5 months authorizing the allocation of nitrogen oxides allow6 ances to units designated under this section that install 

7 or modify pollution control equipment or combustion tech8 nology improvements identified in such regulations after 

9 the date of enactment of this section and prior to January 

10 1, 2008. 

11 ‘‘(b) EMISSIONS REDUCTIONS.—No allowances shall 

12 be allocated under this section for emissions reductions 

13 that are— 

14 ‘‘(1) attributable to pollution control equipment 

15 or combustion technology improvements that were 

16 operational at any time prior to the date of enact17 ment of this section; 

18 ‘‘(2) attributable to fuel switching; 

19 ‘‘(3) required under any Federal or State regu20 lation for the applicable year; or 

21 ‘‘(4) made by a unit, subject to— 

22 ‘‘(A) subpart 1 of part C, that are nec23 essary for compliance with the limitation on the 

24 Btu-weighted average annual emission rate of 

25 the unit and 1 or more other units under sec26 tion 441(d); or 
206 

•S 131 IS 

1 ‘‘(B) the requirements in the applicable 

2 implementation plan of a NOX SIP Call State 

3 (as defined in section 461(3)) that meet the re4 quirements under sections 51.121 and 51.122 

5 of title 40, Code of Federal Regulations (as in 

6 effect for calendar year 2004) during the period 

7 beginning on May 1 and ending on September 

8 30. 

9 ‘‘(c) ALLOCATION.—The allowances allocated to any 

10 unit under this section shall be in addition to the allow11 ances allocated under section 454 and shall be allocated 

12 in an amount equal to one allowance of nitrogen oxides 

13 for each 1.05 tons of reduction in emissions of nitrogen 

14 oxides achieved by the pollution control equipment or com15 bustion technology improvements starting with the year 

16 in which the equipment or improvement is implemented. 

17 The early compliance reduction allowances available under 

18 this section shall be used and tradable in the same manner 

19 as allowances under section 454. 

20 ‘‘(d) EARLY COMPLIANCE ALLOWANCE CREDIT.— 

21 The Administrator shall promulgate regulations as nec22 essary to ensure affected units receive early compliance 

23 allowance credit. Early compliance allowances shall be al24 located at the end of an early compliance year. Should the 

25 Administrator fail to promulgate allocation regulations by 
207 

•S 131 IS 

1 the end of a given year, early compliance allowances for 

2 each year shall be allocated at the earliest possible time 

3 after allocation regulations are promulgated. 

4 ‘‘(e) EXCEPTION.—This section shall not apply to re5 ductions that are— 

6 ‘‘(1) made during the period beginning on May 

7 1 and ending on September 30 of a year by units 

8 that are subject to an applicable implementation 

9 plan for a NOX SIP Call State (as defined in section 

10 461(3)) required under section 51.121 of title 40, 

11 Code of Federal Regulations (as in effect for cal12 endar year 2004); or 

13 ‘‘(2) necessary to comply with subpart 1 of part 

14 C for the applicable year. 

15 ‘‘Subpart 3—Ozone Season NOX Budget Program 

16 ‘‘SEC. 461. DEFINITIONS. 

17 ‘‘For purposes of this subpart: 

18 ‘‘(1) OZONE SEASON.—The term ‘ozone season’ 

19 means— 

20 ‘‘(A) with regard to Connecticut, Delaware, 

21 the District of Columbia, Maryland, Massachu22 setts, New Jersey, New York, Pennsylvania, 

23 and Rhode Island, the period May 1 through 

24 September 30 for each year starting in 2003; 

25 and 
208

•S 131 IS 

1 ‘‘(B) with regard to all other States, the 

2 period May 1 through September 30, for each 

3 year starting in 2004 and thereafter. 

4 ‘‘(2) NON-OZONE SEASON.—The term ‘non5 ozone season’ means—

6 ‘‘(A) with regard to Connecticut, Delaware, 

7 the District of Columbia, Maryland, Massachu8 setts, New Jersey, New York, Pennsylvania, 

9 and Rhode Island, the period October 1 through 

10 April 30; and 

11 ‘‘(B) with regard to all other States, the 

12 period October 1, 2003, through May 29, 2004 

13 and the period October 1 through April 30 be14 ginning in the year 2004 and for each year 

15 thereafter. 

16 ‘‘(3) NOX SIP CALL STATE.—The term ‘NOX

17 SIP Call State’ means Connecticut, Delaware, the 

18 District of Columbia, Illinois, Indiana, Kentucky, 

19 Maryland, Massachusetts, New Jersey, New York, 

20 North Carolina, Ohio, Pennsylvania, Rhode Island, 

21 South Carolina, Tennessee, Virginia, and West Vir22 ginia and the fine grid portions of Alabama, Geor23 gia, Michigan, and Missouri. 

24 ‘‘(4) FINE GRID PORTIONS OF ALABAMA, GEOR25 GIA, MICHIGAN, AND MISSOURI.—The term ‘fine grid 
209 

•S 131 IS 

1 portions of Alabama, Georgia, Michigan, and Mis2 souri’ means the areas in Alabama, Georgia, Michi3 gan, and Missouri subject to 40 CFR part 51.121 

4 (2001). 

5 ‘‘SEC. 462. GENERAL PROVISIONS. 

6 ‘‘The provisions of sections 402 through 406 shall not 

7 apply to this subpart. 

8 ‘‘SEC. 463. APPLICABLE IMPLEMENTATION PLAN. 

9 ‘‘(a) SIPS.—Except as provided in subsection (b), 

10 the applicable implementation plan for each NOX SIP Call 

11 State shall be consistent with the requirements, including 

12 the NOX SIP Call State’s nitrogen oxides budget and com13 pliance supplement pool, in sections 51.121 and 51.122 

14 of title 40, Code of Federal Regulations (as in effect for 

15 calendar year 2004). 

16 ‘‘(b) REQUIREMENTS.—Notwithstanding any provi17 sion to the contrary in section 51.121 or 51.122 of title 

18 40, Code of Federal Regulations (as in effect for calendar 

19 year 2004): 

20 ‘‘(1) IMPLEMENTATION PLAN.—The applicable 

21 implementation plan for each NOX SIP Call State 

22 shall require full implementation of the required 

23 emission control measures starting no later than the 

24 first ozone season. 
210 

•S 131 IS 

1 ‘‘(2) EXEMPTION.—Starting January 1, 

2 2008— 

3 ‘‘(A) the owners and operators of a boiler, 

4 combustion turbine, or integrated gasification 

5 combined cycle plant subject to emission reduc6 tion requirements or limitations under part B, 

7 C, or D shall no longer be subject to the re8 quirements in a NOX SIP Call State’s applica9 ble implementation plan that meet the require10 ments of subsection (a) and paragraph (1); and 

11 ‘‘(B) notwithstanding subparagraph (A), if 

12 the Administrator determines, by December 31, 

13 2007, that a NOX SIP Call State’s applicable 

14 implementation plan meets the requirements of 

15 subsection (a) and paragraph (1), such applica16 ble implementation plan shall be deemed to con17 tinue to meet such requirements. 

18 ‘‘(c) SAVINGS PROVISION.—Nothing in this section or 

19 section 464 shall preclude or deny the right of any State 

20 or political subdivision thereof to adopt or enforce any reg21 ulation, requirement, limitation, or standard, relating to 

22 a boiler, combustion turbine, or integrated gasification 

23 combined cycle plant subject to emission reduction re24 quirements or limitations under part B, C, or D, that is 

25 more stringent than a regulation, requirement, limitation, 
211 

•S 131 IS 

1 or standard in effect under this section or under any other 

2 provision of this Act. 

3 ‘‘SEC. 464. TERMINATION OF FEDERAL ADMINISTRATION 

4 OF NOX TRADING PROGRAM FOR EGUS. 

5 ‘‘Starting January 1, 2008, with regard to any boiler, 

6 combustion turbine, or integrated gasification combined 

7 cycle plant subject to emission reduction requirements or 

8 limitations under part B, C, or D, the Administrator shall 

9 not administer any nitrogen oxides trading program in10 cluded in any NOX SIP Call State’s applicable implemen11 tation plan and meeting the requirements of section 

12 463(a) and (b)(1). 

13 ‘‘SEC. 465. CARRYFORWARD OF PRE-2008 NITROGEN OXIDES 

14 ALLOWANCES. 

15 ‘‘The Administrator shall promulgate regulations as 

16 necessary to assure that the requirement to hold allow17 ances under section 452(a)(1) may be met using nitrogen 

18 oxides allowances allocated for an ozone season before 

19 2008 under a nitrogen oxides trading program that the 

20 Administrator administers, is included in a NOX SIP Call 

21 State’s applicable implementation plan, and meets the re22 quirements of section 463 (a) and (b)(1). 
212 

•S 131 IS 

1 ‘‘SEC. 466. NON-OZONE SEASON VOLUNTARY ACTION CRED2 ITS. 

3 ‘‘An affected facility that voluntarily elects to operate 

4 selective catalytic reduction (SCR) units, installed prior to 

5 enactment of this title, during the non-ozone season under 

6 section 461(2) shall be credited 0.5 allowances per ton of 

7 NOX emissions avoided as a result of operating these con8 trols. The amount avoided will equal every ton of nitrogen 

9 oxides reduction below the allowable emission rate. The 

10 Administrator shall determine if any other existing NOX

11 emission control devices are generally uneconomic to oper12 ate unless EGUs are provided incentives to control NOX

13 emissions during the non-ozone season. If the Adminis14 trator finds that incentives using different control equip15 ment are necessary to make the operation of these devices 

16 economic, the Administrator shall specify these types of 

17 control devices and, for an affected facility with these 

18 specified devices, installed prior to enactment of this title, 

19 that voluntarily elects to operate these devices during the 

20 nonozone season under section 461(2) shall be credited 0.5 

21 allowances per ton of emissions avoided as a result of oper22 ating these controls. The Administrator shall promulgate 

23 regulations as necessary to establish this NOX allowance 

24 credit program. Failure of the Administrator to promul25 gate implementing regulations prior to voluntary reduc26 tions being undertaken by affected facilities shall not in 
213 

•S 131 IS 

1 any manner reduce the number of allowances an otherwise 

2 qualifying facility shall be credited upon promulgation of 

3 the regulations. 

4 ‘‘PART D—MERCURY EMISSIONS REDUCTIONS 

5 ‘‘SEC. 471. DEFINITIONS. 

6 ‘‘For purposes of this part: 

7 ‘‘(1) ADJUSTED BASELINE HEAT INPUT.—The 

8 term ‘adjusted baseline heat input’ with regard to a 

9 unit means the unit’s baseline heat input multiplied 

10 by— 

11 ‘‘(A) 1.0, for the portion of the baseline 

12 heat input that is the unit’s average annual 

13 combustion of bituminous during the years on 

14 which the unit’s baseline heat input is based; 

15 ‘‘(B) 3.0, for the portion of the baseline 

16 heat input that is the unit’s average annual 

17 combustion of lignite during the years on which 

18 the unit’s baseline heat input is based; 

19 ‘‘(C) 1.25, for the portion of the baseline 

20 heat input that is the unit’s average annual 

21 combustion of subbituminous during the years 

22 on which the unit’s baseline heat input is based; 

23 and 

24 ‘‘(D) 1.0, for the portion of the baseline 

25 heat input that is not covered by subparagraph 
214 

•S 131 IS 

1 (A), (B), or (C) or for the entire baseline heat 

2 input if such baseline heat input is not based 

3 on the unit’s heat input in specified years. 

4 ‘‘(2) AFFECTED EGU.—The term ‘affected 

5 EGU’ means— 

6 ‘‘(A) for a unit serving a generator before 

7 the date of enactment of the Clear Skies Act of 

8 2005, a coal-fired unit in a State serving a gen9 erator with a nameplate capacity of greater 

10 than 25 megawatts that produced or produces 

11 electricity for sale during 2002 or any year 

12 thereafter, except for a cogeneration unit meets 

13 the criteria for qualifying for a cogeneration fa14 cilities codified in section 292.205 of title 18 of 

15 the Code of Federal Regulations as issued on 

16 April 1, 2002, during 2002 and each year 

17 thereafter; and 

18 ‘‘(B) for a unit commencing service of a 

19 generator on or after the date of enactment of 

20 the Clear Skies Act of 2005, a coal-fired unit 

21 in a State serving a generator that produces 

22 electricity for sale during any year starting with 

23 the year the unit commences service of a gener24 ator, except for a cogeneration unit that meets 

25 the criteria for qualifying for a cogeneration fa-
215 

•S 131 IS 

1 cilities codified in section 292.205 of title 18 of 

2 the Code of Federal Regulations as issued on 

3 April 1, 2002, during each year starting with 

4 the year the unit commences service of a gener5 ator. 

6 ‘‘(C) EXCLUSION.—Notwithstanding para7 graphs (A) and (B), the term ‘affected EGU’ 

8 does not include— 

9 ‘‘(i) a solid waste incineration unit 

10 subject to section 129; 

11 ‘‘(ii) a unit for the treatment, storage, 

12 or disposal of hazardous waste subject to 

13 section 3005 of the Solid Waste Disposal 

14 Act; or 

15 ‘‘(iii) a unit with de minimis emissions 

16 equal to or less than 50 pounds on an av17 erage annual basis, as calculated by the 

18 Administrator for a 3-year period using— 

19 ‘‘(I) for calendar year 2010, the 

20 emissions data for a facility for cal21 endar years 2006 through 2009; and 

22 ‘‘(II) for calendar year 2011 and 

23 subsequent calendar years, the 3 most 

24 recent calendar years for which emis25 sions data are available. 
216 

•S 131 IS 

1 ‘‘SEC. 472. APPLICABILITY. 

2 ‘‘Starting January 1, 2010, it shall be unlawful for 

3 the affected EGUs at a facility in a State to emit a total 

4 amount of mercury during the year in excess of the num5 ber of mercury allowances held for such facility for that 

6 year by the owner or operator of the facility. 

7 ‘‘SEC. 473. LIMITATIONS ON TOTAL EMISSIONS. 

8 ‘‘For affected EGUs for 2010 and each year there9 after, the Administrator shall allocate mercury allowances 

10 pursuant to section 474. 

TABLE A.—TOTAL MERCURY ALLOWANCES ALLOCATED 

FOR EGUS 

Year 

Mercury allowances allocated 

2010–2017 ..................................................................................... 1,088,000 

2018 and thereafter ....................................................................... 480,000 

11 ‘‘SEC. 474. EGU ALLOCATIONS. 

12 ‘‘(a) IN GENERAL.—Not later than 24 months before 

13 the commencement date of the mercury allowance require14 ment of section 472, the Administrator shall promulgate 

15 regulations determining allocations of mercury allowances 

16 for 2010 and thereafter for units at a facility that com17 mence commercial operation by and are affected EGUs as 

18 of date of enactment. The regulations shall provide that 

19 the Administrator shall allocate each year for such units 

20 an amount determined by multiplying by 0.95 the alloca21 tion amount in section 473 by the ratio of the total 
217 

•S 131 IS 

1 amount of the adjusted baseline heat input of such units 

2 at the facility to the total amount of adjusted baseline heat 

3 input of all affected EGUs. 

4 ‘‘(b) NEW FACILITIES.—5 percent of the total 

5 amount of nitrogen oxides allowances allocated each year 

6 under section 473 shall be allocated for units at a facility 

7 that commence commercial operation and are affected 

8 EGUs after the date of enactment. These units shall be 

9 allocated allowances for each year by multiplying the allo10 cation amount under section 473 by the ratio of the total 

11 amount of the adjusted baseline heat input of such units 

12 at the facility to the total amount of adjusted baseline heat 

13 input to all affected EGUs, including those covered in sub14 section (a). However, the regulations shall not allocate al15 lowances to any affected unit in excess of the product of 

16 the unit’s baseline heat input multiplied by the unit’s al17 lowable mercury emissions rate, divided by 2000. 

18 ‘‘(c) ALLOCATION.—Allowances allocated under sub19 section (b) shall be allocated to units on a first come basis 

20 determined by date of unit commencement of construction, 

21 provided that such unit actually commences commercial 

22 operation. As such, allocations to units under subsection 

23 (b) will not be reduced as a result of new units com24 mencing commercial operation. 
218 

•S 131 IS 

1 ‘‘(d) UNALLOCATED ALLOWANCES.—Allowances not 

2 allocated under paragraph (2) shall be allocated to units 

3 in subsections (a) and (b) on a pro rata basis. 

4 ‘‘(e) AMOUNT OF ALLOWANCES.—For each year 

5 2010 and thereafter, if the Administrator has not promul6 gated the regulations determining allocation under sub7 section (a)— 

8 ‘‘(1) each affected unit shall comply with sec9 tion 472 by providing annual notice to the permit10 ting authority. Such notice shall indicate the amount 

11 of allowances the affected unit believes it has for the 

12 relevant year and the amount of mercury emissions 

13 for such year. The amount of mercury emissions 

14 shall be determined using reasonable industry ac15 cepted methods unless the Administrator has pro16 mulgated applicable monitoring and alternative mon17 itoring requirements; and 

18 ‘‘(2) upon promulgation of regulations under 

19 subsection (a) determining the allocations for 2010 

20 and thereafter, and promulgating regulations under 

21 section 403(b) providing for the transfer of mercury 

22 allowances and section 403(c) establishing an Allow23 ance Transfer System for mercury allowances, each 

24 unit’s emissions shall be compared to and reconcile 

25 with its actual allocations under the promulgated 
219 

•S 131 IS 

1 regulation. Each unit will have nine (9) months to 

2 submit allowances to the Administrator, without rec3 ompense, for any allowances shortfall. The sub4 mitted allowances may have been obtained and held 

5 by any mechanism consistent with the Act including, 

6 but not limited to, direct sale. 

7 ‘‘SEC. 475. MERCURY EARLY ACTION REDUCTION CREDITS. 

8 ‘‘(a) IN GENERAL.—The Administrator shall promul9 gate regulations within 18 months authorizing the alloca10 tion of mercury allowances to units designated under this 

11 section that install or modify pollution control equipment 

12 or combustion technology improvements identified in such 

13 regulations after the date of enactment of this section and 

14 prior to January 1, 2010. 

15 ‘‘(b) NONALLOCATION OF ALLOWANCES.—No allow16 ances shall be allocated under this paragraph for emis17 sions reductions: attributable to pollution control equip18 ment or combustion technology improvements that were 

19 operational or under construction at any time prior to the 

20 date of enactment of this section; attributable to fuel 

21 switching; or required under any Federal regulation. 

22 ‘‘(c) AMOUNT OF ALLOWANCES.—The allowances al23 located to any unit under this paragraph shall be in addi24 tion to the allowances allocated under section 474 and 

25 shall be allocated in an amount equal to 1 allowance of 
220 

•S 131 IS 

1 mercury for each 1.05 ounces of reduction in emissions 

2 of mercury achieved by the pollution control equipment or 

3 combustion technology improvements starting with the 

4 year in which the equipment or improvement is imple5 mented. The early compliance reduction allowances avail6 able under this section shall be used and tradable in the 

7 same manner as allowances under section 474. 

8 ‘‘(d) EARLY COMPLIANCE ALLOWANCE CREDIT.— 

9 The Administrator shall promulgate regulations as nec10 essary to ensure affected units receive early compliance 

11 allowance credit. Early compliance allowances shall be al12 located at the end of an early compliance year. Should the 

13 Administrator fail to promulgate allocation regulations by 

14 the end of a given year, early compliance allowances for 

15 each year shall be allocated at the earliest possible time 

16 after allocation regulations are promulgated. 

17 ‘‘PART E—NATIONAL EMISSION STANDARDS; RE18 SEARCH, ENVIRONMENTAL ACCOUNT19 ABILITY; MAJOR SOURCE 

20 PRECONSTRUCTION REVIEW AND BEST 

21 AVAILABLE RETROFIT CONTROL TECH22 NOLOGY REQUIREMENTS 

23 ‘‘SEC. 481. NATIONAL EMISSION STANDARDS FOR AF24 FECTED UNITS. 

25 ‘‘(a) DEFINITIONS.—For purposes of this section: 
221 

•S 131 IS 

1 ‘‘(1) COMMENCED.—The term ‘commenced’, 

2 with regard to construction, means that an owner or 

3 operator has either undertaken a continuous pro4 gram of construction or has entered into a contrac5 tual obligation to undertake and complete, within a 

6 reasonable time, a continuous program of construc7 tion. For boilers and integrated gasification com8 bined cycle plants, this term does not include under9 taking such a program or entering into such an obli10 gation more than 36 months prior to the date on 

11 which the unit begins operation. For combustion 

12 turbines, this term does not include undertaking 

13 such a program or entering into such an obligation 

14 more than 18 months prior to the date on which the 

15 unit begins operation. 

16 ‘‘(2) CONSTRUCTION.—The term ‘construction’ 

17 means fabrication, erection, or installation of an af18 fected unit. 

19 ‘‘(3) AFFECTED UNIT.—The term ‘affected 

20 unit’ means any unit that is subject to emission limi21 tations under subpart 2 of part B, subpart 2 of part 

22 C, or part D. 

23 ‘‘(4) EXISTING AFFECTED UNIT.—The term 

24 ‘existing affected unit’ means any affected unit that 

25 is not a new affected unit. 
222 

•S 131 IS 

1 ‘‘(5) NEW AFFECTED UNIT.—The term ‘new af2 fected unit;’ means any affected unit, the construc3 tion or reconstruction of which is commenced after 

4 the date of enactment of the Clear Skies Act of 

5 2005, except that for the purpose of any revision of 

6 a standard pursuant to subsection (e), ‘new affected 

7 unit’ means any affected unit, the construction or 

8 reconstruction of which is commenced after the pub9 lication of regulations (or, if earlier, proposed regu10 lations) prescribing a standard under this section 

11 that will apply to such unit. 

12 ‘‘(6) RECONSTRUCTION.—The term ‘reconstruc13 tion’ means the replacement of components of a unit 

14 to such an extent that— 

15 ‘‘(A) the fixed capital cost of the new com16 ponents exceeds 50 percent of the fixed capital 

17 cost that would be required to construct a com18 parable entirely new unit; and 

19 ‘‘(B) it is technologically and economically 

20 feasible to meet the applicable standards set 

21 forth in this section. 

22 ‘‘(b) EMISSION STANDARDS.— 

23 ‘‘(1) IN GENERAL.—No later than 12 months 

24 after the date of enactment of the Clear Skies Act 

25 of 2005, the Administrator shall promulgate regula-
223 

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1 tions prescribing the standards in subsections (c) 

2 through (d) for the specified affected units and es3 tablishing requirements to ensure compliance with 

4 these standards, including monitoring, record5 keeping, and reporting requirements. 

6 ‘‘(2) MONITORING.— 

7 ‘‘(A) IN GENERAL.—The owner or operator 

8 of any affected unit subject to the standards for 

9 sulfur dioxide, nitrogen oxides, or mercury 

10 under this section shall meet the requirements 

11 of section 405, except that, where two or more 

12 units utilize a single stack, separate monitoring 

13 shall be required for each affected unit for the 

14 pollutants for which the unit is subject to such 

15 standards. 

16 ‘‘(B) REQUIREMENTS.—The Administrator 

17 shall, by regulation, require— 

18 ‘‘(i) the owner or operator of any af19 fected unit subject to the standards for 

20 sulfur dioxide, nitrogen oxides, or mercury 

21 under this section to— 

22 ‘‘(I) install and operate CEMS 

23 for monitoring output, including elec24 tricity and useful thermal energy, on 
224 

•S 131 IS 

1 the affected unit and to quality assure 

2 the data; and 

3 ‘‘(II) comply with recordkeeping 

4 and reporting requirements, including 

5 provisions for reporting output data in 

6 megawatt hours. 

7 ‘‘(ii) the owner or operator of any af8 fected unit subject to the standards for 

9 particulate matter under this section to— 

10 ‘‘(I) install and operate CEMS 

11 for monitoring particulate matter on 

12 the affected unit and to quality assure 

13 the data; 

14 ‘‘(II) comply with recordkeeping 

15 and reporting requirements; and 

16 ‘‘(III) comply with alternative 

17 monitoring, quality assurance, record18 keeping, and reporting requirements 

19 for any period of time for which the 

20 Administrator determines that CEMS 

21 with appropriate vendor guarantees 

22 are not commercially available for 

23 particulate matter. 

24 ‘‘(3) COMPLIANCE.—For boilers, integrated 

25 gasification combined cycle plants, and coal fired or 
225 

•S 131 IS 

1 gas-fired combustion turbines the Administrator 

2 shall require that the owner or operator demonstrate 

3 compliance with the standards daily, using a 30-day 

4 rolling average, except that in the case of mercury, 

5 the compliance period shall be the calendar year. 

6 For combustion turbines that are oil-fired the Ad7 ministrator shall require that the owner or operator 

8 demonstrate compliance with the standards hourly, 

9 using a 4-hour rolling average. 

10 ‘‘(c) BOILERS AND INTEGRATED GASIFICATION COM11 BINED CYCLE PLANTS.— 

12 ‘‘(1) IN GENERAL.—After the effective date of 

13 standards promulgated under subsection (b), no 

14 owner or operator shall cause any boiler or inte15 grated gasification combined cycle plant that is a 

16 new affected unit to discharge into the atmosphere 

17 any gases which contain— 

18 ‘‘(A) sulfur dioxide in excess of 2.0 lb/ 

19 MWh; 

20 ‘‘(B) nitrogen oxides in excess of 1.0 lb/ 

21 MWh; 

22 ‘‘(C) particulate matter in excess of 0.20 

23 lb/MWh; or 

24 ‘‘(D) if the unit is coal-fired, mercury in 

25 excess of 0.015 lb/GWh, unless— 
226 

•S 131 IS 

1 ‘‘(i) mercury emissions from the unit, 

2 determined assuming no use of on-site or 

3 off-site pre-combustion treatment of coal 

4 and no use of technology that captures 

5 mercury, are reduced by 80 percent; 

6 ‘‘(ii) flue gas desulfurization (FGD) 

7 and selective catalytic reduction (SCR) are 

8 applied to the unit; or 

9 ‘‘(iii) a technology is applied to the 

10 unit and the permitting authority deter11 mines that the technology is equivalent in 

12 terms of mercury capture to the applica13 tion of FGD and SCR. 

14 ‘‘(2) EXEMPTION.—Notwithstanding subpara15 graph (1)(D), integrated gasification combined cycle 

16 plants with a combined capacity of less than 5 GW 

17 are exempt from the mercury requirement under 

18 subparagraph (1)(D) if they are constructed as part 

19 of a demonstration project under the Secretary of 

20 Energy that will include a demonstration of removal 

21 of significant amounts of mercury as determined by 

22 the Secretary of Energy in conjunction with the Ad23 ministrator as part of the solicitation process. 

24 ‘‘(3) DISCHARGES.—After the effective date of 

25 standards promulgated under subsection (b), no 
227 

•S 131 IS 

1 owner or operator shall cause any oil-fired boiler 

2 that is an existing affected unit to discharge into the 

3 atmosphere any gases which contain particulate mat4 ter in excess of 0.30 lb/MWh. 

5 ‘‘(d) COMBUSTION TURBINES.— 

6 ‘‘(1) GAS-FIRED COMBUSTION TURBINES.— 

7 After the effective date of standards promulgated 

8 under subsection (b), no owner or operator shall 

9 cause any gas-fired combustion turbine that is a new 

10 affected unit to discharge into the atmosphere any 

11 gases which contain nitrogen oxides in excess of— 

12 ‘‘(A) 0.56 lb/MWh (15 ppm at 15 percent 

13 oxygen), if the unit is a simple cycle combustion 

14 turbine; 

15 ‘‘(B) 0.084 lb/MWh (3.5 ppm at 15 per16 cent oxygen), if the unit is not a simple cycle 

17 combustion turbine and either uses add-on con18 trols or is located within 50 km of a class I 

19 area; or 

20 ‘‘(C) 0.21 lb/MWh (9 ppm at 15 percent 

21 oxygen), if the unit is not a simple cycle turbine 

22 and neither uses add-on controls nor is located 

23 within 50 km of a class I area. 

24 ‘‘(2) COAL-FIRED COMBUSTION TURBINES.— 

25 After the effective date of standards promulgated 
228 

•S 131 IS 

1 under subsection (b), no owner or operator shall 

2 cause any coal-fired combustion turbine that is a 

3 new affected unit to discharge into the atmosphere 

4 any gases which contain sulfur dioxide, nitrogen ox5 ides, particulate matter, or mercury in excess of the 

6 emission limits under subparagraphs (c)(1) (A) 

7 through (D). 

8 ‘‘(3) COMBUSTION TURBINES THAT ARE NOT

9 GAS-FIRED OR COAL-FIRED.—After the effective date 

10 of standards promulgated under subsection (b), no 

11 owner or operator shall cause any combustion tur12 bine that is not gas-fired or coal-fired and that is a 

13 new affected unit to discharge into the atmosphere 

14 any gases which contain— 

15 ‘‘(A) sulfur dioxide in excess of 2.0 lb/ 

16 MWh; 

17 ‘‘(B) nitrogen oxides in excess of— 

18 ‘‘(i) 0.289 lb/MWh (12 ppm at 15 

19 percent oxygen), if the unit is not a simple 

20 cycle combustion turbine, is dual-fuel capa21 ble, and uses add-on controls; or is not a 

22 simple cycle combustion turbine and is lo23 cated within 50 km of a class I area; and 

24 ‘‘(ii) 1.01 lb/MWh (42 ppm at 15 per25 cent oxygen), if the unit is a simple cycle 
229 

•S 131 IS 

1 combustion turbine; is not a simple cycle 

2 combustion turbine and is not dual-fuel ca3 pable; or is not a simple cycle combustion 

4 turbine, is dual-fuel capable, and does not 

5 use add-on controls. 

6 ‘‘(C) particulate matter in excess of 0.20 

7 lb/MWh. 

8 ‘‘(e) PERIODIC REVIEW AND REVISION.— 

9 ‘‘(1) IN GENERAL.—The Administrator shall, at 

10 least every eight years following the promulgation of 

11 standards under subsection (b), review and, if appro12 priate, revise such standards to reflect the degree of 

13 emission limitation demonstrated by substantial evi14 dence to be achievable through the application of the 

15 best system of emission reduction which (taking into 

16 account the cost of achieving such reduction and any 

17 nonair quality health and environmental impacts and 

18 energy requirements). When implementation and en19 forcement of any requirement of this Act indicate 

20 that emission limitations and percent reductions be21 yond those required by the standards promulgated 

22 under this section are achieved in practice, the Ad23 ministrator shall, when revising standards promul24 gated under this section, consider the emission limi25 tations and percent reductions achieved in practice. 
230 

•S 131 IS 

1 ‘‘(2) EXCEPTION.—Notwithstanding the re2 quirements of paragraph (1) the Administrator need 

3 not review any standard promulgated under sub4 section (b) if the Administrator determines that such 

5 review is not appropriate in light of readily available 

6 information on the efficacy of such standard. 

7 ‘‘(f) EFFECTIVE DATE.—The standard promulgated 

8 pursuant to this section shall become effective upon pro9 mulgation. 

10 ‘‘(g) DELEGATION.— 

11 ‘‘(1) IN GENERAL.—Each State may develop 

12 and submit to the Administration a procedure for 

13 implementing and enforcing standards promulgated 

14 under this section for affected units located in such 

15 State. If the Administrator finds the State proce16 dure is adequate, the Administrator shall delegate to 

17 such State any authority the Administrator has 

18 under this Act to implement and enforce such stand19 ards. 

20 ‘‘(2) ENFORCEMENT.—Nothing in this sub21 section shall prohibit the Administrator from enforc22 ing any applicable standard under this section. 

23 ‘‘(h) VIOLATIONS.—After the effective date of stand24 ards promulgated under this section, it shall be unlawful 

25 for any owner or operator of any affected unit to operate 
231 

•S 131 IS 

1 such unit in violation of any standard, established by this 

2 section applicable to such unit. 

3 ‘‘(i) COORDINATION WITH OTHER AUTHORITIES.— 

4 For purposes of sections III(e), 113, 114, 116, 120, 303, 

5 304, 307, and other provisions for the enforcement of this 

6 Act, each standard established pursuant to this section 

7 shall be treated in the same manner as a standard of per8 formance under section 111, and each affected unit sub9 ject to standards under this section shall be treated in the 

10 same manner as a stationary source under section 111. 

11 ‘‘(j) STATE AUTHORITY.—Nothing in this section 

12 shall preclude or deny the right of any State or political 

13 subdivision thereof to adopt or enforce any regulation, re14 quirement, limitation, or standard relating to affected 

15 units, or other EGUs, that is more stringent than a regu16 lation, requirement, limitation, or standard in effect under 

17 this section or under any other provision of this Act. 

18 ‘‘(k) OTHER AUTHORITY UNDER THIS ACT.—Noth19 ing in this section shall diminish the authority of the Ad20 ministrator or a State to establish any other requirements 

21 applicable to affected units under any other authority of 

22 law, including the authority to establish for any air pollut23 ant a national ambient air quality standard, except that 

24 no new affected unit subject to standards under this sec-
232 

•S 131 IS 

1 tion shall be subject to standards under section 111 of 

2 this Act. 

3 ‘‘SEC. 482. RESEARCH, ENVIRONMENTAL MONITORING, AND 

4 ASSESSMENT. 

5 ‘‘(a) PURPOSES.—The Administrator, in collabora6 tion with the Secretary of Energy and the Secretary of 

7 the Interior, shall conduct a comprehensive program of re8 search, environmental monitoring, and assessment to en9 hance scientific understanding of the human health and 

10 environmental effects of particulate matter and mercury 

11 and to demonstrate the efficacy of emission reductions 

12 under this title for purposes of reporting to Congress 

13 under (e)(2). The purposes of such a program are to— 

14 ‘‘(1) expand current research and knowledge of 

15 the contribution of emissions from electricity genera16 tion to exposure and health effects associated with 

17 particulate matter and mercury; 

18 ‘‘(2) enhance current research and development 

19 of promising multi-pollutant control strategies and 

20 CEMS for mercury; 

21 ‘‘(3) produce peer-reviewed scientific and tech22 nology information; 

23 ‘‘(4) improve environmental monitoring and as24 sessment of sulfur dioxide, nitrogen oxides and mer25 cury, and their transformation products, to track 
233 

•S 131 IS 

1 changes in human health and the environment at2 tributable to emission reductions under this title; 

3 and 

4 ‘‘(5) periodically provide peer-reviewed reports 

5 on the costs, benefits, and effectiveness of emission 

6 reductions achieved under this title. 

7 ‘‘(b) RESEARCH.—The Administrator shall enhance 

8 planned and ongoing laboratory and field research and 

9 modeling analyses, and conduct new research and analyses 

10 to produce peer-reviewed information concerning the 

11 human health and environmental effects of mercury and 

12 particulate matter and the contribution of United States 

13 electrical generating units to those effects. Such informa14 tion shall be included in the report under subsection (d). 

15 In addition, such research and analyses shall— 

16 ‘‘(1) improve understanding of the rates and 

17 processes governing chemical and physical trans18 formations of mercury in the atmosphere, including 

19 speciation of emissions from electricity generation 

20 and the transport of these species; 

21 ‘‘(2) improve understanding of the contribution 

22 of mercury emissions from electricity generation to 

23 mercury in fish and other biota, including— 

24 ‘‘(A) the response of and contribution to 

25 mercury in the biota owing to atmospheric dep-
234 

•S 131 IS 

1 osition of mercury from U.S. electricity genera2 tion on both local and regional scales; 

3 ‘‘(B) long-term contributions of mercury 

4 from U.S. electricity generation on mercury ac5 cumulations in ecosystems, and the effects of 

6 mercury reductions in that sector on the envi7 ronment and public health; 

8 ‘‘(C) the role and contribution of mercury, 

9 from U.S. electricity generating facilities and 

10 anthropogenic and natural sources to fish con11 tamination and to human exposure, particularly 

12 with respect to sensitive populations; 

13 ‘‘(D) the contribution of U.S. electricity 

14 generation to population exposure to mercury in 

15 freshwater fish and seafood and quantification 

16 of linkages between U.S. mercury emissions and 

17 domestic mercury exposure and its health ef18 fects; and 

19 ‘‘(E) the contribution of mercury from 

20 U.S. electricity generation in the context of 

21 other domestic and international sources of 

22 mercury, including transport of global anthro23 pogenic and natural background levels; 

24 ‘‘(3) improve understanding of the health ef25 fects of fine particulate matter components related 
235 

•S 131 IS 

1 to electricity generation emissions (as distinct from 

2 other fine particle fractions and indoor air expo3 sures) and the contribution of U.S. electrical gener4 ating units to those effects including— 

5 ‘‘(A) the chronic effects of fine particulate 

6 matter from electricity generation in sensitive 

7 population groups; and 

8 ‘‘(B) personal exposure to fine particulate 

9 matter from electricity generation; and 

10 ‘‘(4) improve understanding, by way of a review 

11 of the literature, of methods for valuing human 

12 health and environmental benefits associated with 

13 fine particulate matter and mercury. 

14 ‘‘(c) INNOVATIVE CONTROL TECHNOLOGIES.—The 

15 Administrator shall collaborate with the Secretary of En16 ergy to enhance research and development, and conduct 

17 new research that facilitates research into and develop18 ment of innovative technologies to control sulfur dioxide, 

19 nitrogen oxides, mercury, and particulate matter at a 

20 lower cost than existing technologies. Such research and 

21 development shall provide updated information on the cost 

22 and feasibility of technologies. Such information shall be 

23 included in the report under subsection (d). In addition, 

24 the research and development shall— 
236 

•S 131 IS 

1 ‘‘(1) upgrade cost and performance models to 

2 include results from ongoing and future electricity 

3 generation and pollution control demonstrations by 

4 the Administrator and the Secretary of Energy; 

5 ‘‘(2) evaluate the overall environmental implica6 tions of the various technologies tested including the 

7 impact on the characteristics of coal combustion res8 idues; 

9 ‘‘(3) evaluate the impact of the use of selective 

10 catalytic reduction on mercury emissions from the 

11 combustion of all coal types; 

12 ‘‘(4) evaluate the potential of integrated gasifi13 cation combined cycle to adequately control mercury; 

14 ‘‘(5) expand current programs by the Adminis15 trator to conduct research and promote, lower cost 

16 CEMS capable of providing real-time measurements 

17 of both speciated and total mercury and integrated 

18 compact CEMS that provide cost-effective real-time 

19 measurements of sulfur dioxide, nitrogen oxides, and 

20 mercury; 

21 ‘‘(6) expand lab- and pilot-scale mercury and 

22 multi-pollutant control programs by the Secretary of 

23 Energy and the Administrator, including develop24 ment of enhanced sorbents and scrubbers for use on 

25 all coal types; 
237 

•S 131 IS 

1 ‘‘(7) characterize mercury emissions from low2 rank coals, for a range of traditional control tech3 nologies, like scrubbers and selective catalytic reduc4 tion; and 

5 ‘‘(8) improve low cost combustion modifications 

6 and controls for dry-bottom boilers. 

7 ‘‘(d) ENVIRONMENTAL ACCOUNTABILITY.— 

8 ‘‘(1) MONITORING AND ASSESSMENT.—The Ad9 ministrator shall conduct a program of environ10 mental monitoring and assessment to track on a 

11 continuing basis, changes in human health and the 

12 environment attributable to the emission reductions 

13 required under this title. Such a program shall— 

14 ‘‘(A) develop and employ methods to rou15 tinely monitor, collect, and compile data on the 

16 status and trends of mercury and its trans17 formation products in emissions from affected 

18 facilities, atmospheric deposition, surface water 

19 quality, and biological systems. Emphasis shall 

20 be placed on those methods that— 

21 ‘‘(i) improve the ability to routinely 

22 measure mercury in dry deposition proc23 esses; 

24 ‘‘(ii) improve understanding of the 

25 spatial and temporal distribution of mer-
238 

•S 131 IS 

1 cury deposition in order to determine 

2 source-receptor relationships and patterns 

3 of long-range, regional, and local deposi4 tion; 

5 ‘‘(iii) improve understanding of aggre6 gate exposures and additive effects of 

7 methylmercury and other pollutants; and 

8 ‘‘(iv) improve understanding of the ef9 fectiveness and cost of mercury emissions 

10 controls; 

11 ‘‘(B) modernize and enhance the national 

12 air quality and atmospheric deposition moni13 toring networks in order to cost-effectively ex14 pand and integrate, where appropriate, moni15 toring capabilities for sulfur, nitrogen, and mer16 cury to meet the assessment and reporting re17 quirements of this section; 

18 ‘‘(C) perform and enhance long-term moni19 toring of sulfur, nitrogen, and mercury, and pa20 rameters related to acidification, nutrient en21 richment, and mercury bioaccumulation in 

22 freshwater and marine biota; 

23 ‘‘(D) maintain and upgrade models that 

24 describe the interactions of emissions with the 

25 atmosphere and resulting air quality implica-
239 

•S 131 IS 

1 tions and models that describe the response of 

2 ecosystems to atmospheric deposition; and 

3 ‘‘(E) assess indicators of ecosystems health 

4 related to sulfur, nitrogen, and mercury, includ5 ing characterization of the causes and effects of 

6 episodic exposure to air pollutants and evalua7 tion of recovery. 

8 ‘‘(2) REPORTING REQUIREMENTS.—Not later 

9 than January 1, 2008, and not later than every 4 

10 years thereafter, the Administrator shall provide a 

11 peer reviewed report to the Congress on the costs, 

12 benefits, and effectiveness of emission reduction pro13 grams under this title. 

14 ‘‘(A) The report under this subparagraph 

15 shall address the relative contribution of emis16 sion reductions from U.S. electricity generation 

17 under this title compared to the emission reduc18 tions achieved under other titles of the Clean 

19 Air Act with respect to— 

20 ‘‘(i) actual and projected emissions of 

21 sulfur dioxide, nitrogen oxides, and mer22 cury; 

23 ‘‘(ii) average ambient concentrations 

24 of sulfur dioxide and nitrogen oxides trans25 formation products, related air quality pa-
240 

•S 131 IS 

1 rameters, and indicators of reductions in 

2 human exposure; 

3 ‘‘(iii) status and trends in total at4 mospheric deposition of sulfur, nitrogen, 

5 and mercury, including regional estimates 

6 of total atmospheric deposition; 

7 ‘‘(iv) status and trends in visibility; 

8 ‘‘(v) status of terrestrial and aquatic 

9 ecosystems (including forests and forested 

10 watersheds, streams, lakes, rivers, estu11 aries, and nearcoastal waters); 

12 ‘‘(vi) status of mercury and its trans13 formation products in fish; 

14 ‘‘(vii) causes and effects of atmos15 pheric deposition, including changes in sur16 face water quality, forest and soil condi17 tions; 

18 ‘‘(viii) occurrence and effects of coast19 al eutrophication and episodic acidification, 

20 particularly with respect to high elevation 

21 watersheds; and 

22 ‘‘(ix) reduction in atmospheric deposi23 tion rates that should be achieved to pre24 vent or reduce adverse ecological effects. 
241 

•S 131 IS 

1 ‘‘(B) The report under this subparagraph 

2 shall address the relative contribution of the 

3 United States to world-wide emissions as well 

4 as a comparison of the stringency of fossil fuel5 fired requirements under the Act to other coun6 tries. 

7 ‘‘SEC. 483. MAJOR SOURCE PRECONSTRUCTION REVIEW RE8 QUIREMENTS AND BEST AVAILABLE RET9 ROFIT CONTROL TECHNOLOGY REQUIRE10 MENTS; APPLICABILITY TO AFFECTED UNITS. 

11 ‘‘(a) MAJOR SOURCE EXEMPTION.—An affected unit 

12 shall be considered neither a major emitting facility or 

13 major stationary source nor a part of a major emitting 

14 facility or major stationary source, for purposes of compli15 ance with the requirements of parts C and part D of title 

16 I, and shall not otherwise be subject to the requirements 

17 of section 169A or 169B, for a period of 20 years after 

18 the date of enactment of this section. This applicability 

19 provision only applies to affected units that are either sub20 ject to the performance standards of section 481 or meet 

21 the following requirements within 3 years after the date 

22 of enactment of the Clear Skies Act of 2005: 

23 ‘‘(1) The owner or operator of the affected unit 

24 properly operates, maintains and repairs pollution 

25 control equipment to limit emissions of particulate 
242 

•S 131 IS 

1 matter, or the owner or operator of the affected unit 

2 is subject to an enforceable permit issued pursuant 

3 to title V or a permit program approved or promul4 gated as part of an applicable implementation plan 

5 to limit the emissions of particulate matter from the 

6 affected unit to 0.03 lb/mmBtu within eight years 

7 after the date of enactment of the Clear Skies Act 

8 of 2005, and 

9 ‘‘(2) The owner or operator of the affected unit 

10 uses good combustion practices to minimize emis11 sions of carbon monoxide. Good combustion prac12 tices may be accomplished through control tech13 nology, combustion technology improvements, or 

14 workplace practices. 

15 ‘‘(b) CLASS I AREA PROTECTIONS.—Notwith16 standing the provisions of subsection (a), an affected unit 

17 located within 50 km of a Class I area on which construc18 tion commences after the date of enactment of the Clear 

19 Skies Act of 2005 is subject to those provisions under part 

20 C of title I pertaining to the review of a new or recon21 structed major stationary source’s impact on a Class I 

22 area. 

23 ‘‘(c) PRECONSTRUCTION REQUIREMENTS.—Each 

24 State shall include in its plan under section 110, as pro25 gram to provide for the regulation of the construction of 
243 

•S 131 IS 

1 an affected unit that ensures that the following require2 ments are met prior to the commencement of construction 

3 of an affected unit— 

4 ‘‘(1) in an area designated as attainment or 

5 unclassifiable under section 107(d), the owner or op6 erator of the affected unit must demonstrate to the 

7 State that the emissions increase from the construc8 tion or operation of such unit will not cause, or con9 tribute to, air pollution in excess of any national am10 bient air quality standard; 

11 ‘‘(2) in an area designated as nonattainment 

12 under section 107(d), the State must determine that 

13 the emissions increase from the construction or oper14 ation of such unit will not interfere with any pro15 gram to assure that the national ambient air quality 

16 standards are achieved provided that interference 

17 with any program will be deemed not to occur, with 

18 respect to each nonattainment area located wholly or 

19 partially within the State, if on the date of submis20 sion of a complete permit application and through21 out a continuous period of three years immediately 

22 preceding such date, the nonattainment area was in 

23 full compliance with all requirements of this Act, in24 cluding but not limited to requirements for State 

25 Implementation Plans; 
244 

•S 131 IS 

1 ‘‘(3) for a reconstructed unit, prior to beginning 

2 operation, the unit must comply with either the per3 formance standards of section 481 or best available 

4 control technology as defined in part C of title I for 

5 the pollutants whose hourly emissions will increase 

6 at the unit’s maximum capacity; and 

7 ‘‘(4) the State must provide for an opportunity 

8 for interested persons to comment on the Class I 

9 area protections and preconstruction requirements 

10 as set forth in this section. 

11 ‘‘(d) DEFINITIONS.—For purposes of this section: 

12 ‘‘(1) AFFECTED UNIT.—The term ‘affected 

13 unit’ means any unit that is subject to emission limi14 tations under subpart 2 of part B, subpart 2 of part 

15 C, or part D. 

16 ‘‘(2) CONSTRUCTION.—The term ‘construction’ 

17 includes the construction of a new affected unit and 

18 the modification of any affected unit. 

19 ‘‘(3) MODIFICATION.—The term ‘modification’ 

20 means any physical change in, or change in the 

21 method of operation of, an affected unit that in22 creases the maximum hourly emissions of any pollut23 ant regulated under this Act above the maximum 

24 hourly emissions achievable at that unit during the 

25 five years prior to the change or that results in the 
245 

•S 131 IS 

1 emission of any pollutant regulated under this Act 

2 and not previously emitted. 

3 ‘‘(e) SAVINGS CLAUSE.—Nothing in this section shall 

4 preclude or deny the right of any State or political subdivi5 sion thereof to adopt to enforce any regulation, require6 ment, limitation, or standard relating to affected units 

7 that is more stringent than a regulation, requirement, lim8 itation, or standard in effect under this section or under 

9 any other provision of this Act.’’. 

10 SEC. 3. OTHER AMENDMENTS. 

11 (a) TITLE I.—Title I of the Clean Air Act is amended 

12 as follows: 

13 (1) In section 103 by repealing subparagraphs 

14 (E) and (F). 

15 (2) In section 107(d)(1)(A)— 

16 (i) by striking ‘‘or’’ at the end of 

17 clause (ii); 

18 (ii) by striking the period at the end 

19 of clause (iii) and inserting ‘‘, or’’; and 

20 (iii) by adding at the end the fol21 lowing: 

22 ‘‘(iv) notwithstanding clauses (i) 

23 through (iii) and subsection (d)(3), if re24 quested by a State, an area may be redes25 ignated as transitional for the PM 2.5 na-
246 

•S 131 IS 

1 tional primary or secondary ambient air 

2 quality standards or the 8-hour ozone na3 tional primary or secondary ambient air 

4 quality standard if— 

5 ‘‘(I) the Administrator has per6 formed air quality modeling and, in 

7 the case of an area that needs addi8 tional local control measures, the 

9 State has performed supplemental air 

10 quality modeling, demonstrating that 

11 the area will attain the applicable 

12 standard or standards not later than 

13 December 31, 2015; 

14 ‘‘(II) such modeling demonstra15 tion and all necessary local controls 

16 have been approved into the State im17 plementation plan not later than 1 

18 year after the date of enactment of 

19 the Clear Skies Act of 2005; and 

20 ‘‘(III) the redesignation is made 

21 not later than 180 days after the date 

22 of that approval.’’ 

23 (3) In section 110 as follows: 
247 

•S 131 IS 

1 (A) By amending clause (i) of subsection 

2 (a)(2)(D) by inserting ‘‘except as provided in 

3 subsection (q),’’ before the word ‘‘prohibiting’’. 

4 (B) By adding the following new sub5 sections at the end thereof: 

6 ‘‘(q) REVIEW OF CERTAIN PLANS.— 

7 ‘‘(1) IN GENERAL.—The Administrator shall, in 

8 reviewing, under subsection (a)(2)(D)(i), any plan 

9 with respect to affected units, within the meaning of 

10 section 126(d)(l)— 

11 ‘‘(A) consider, among other relevant fac12 tors, emissions reductions required to occur by 

13 the attainment date or dates of any relevant 

14 nonattainment areas in the other State or 

15 States; 

16 ‘‘(B) not require submission of plan provi17 sions mandating emissions reductions from such 

18 affected units, unless the Administrator deter19 mines that— 

20 ‘‘(i) emissions from such units may be 

21 reduced at least as cost-effectively as emis22 sions reductions in the State or each other 

23 State from each other principal category of 

24 sources of the relevant pollutant, pollut25 ants, or pre-cursors thereof, including in-
248 

•S 131 IS 

1 dustrial boilers, on-road mobile sources, 

2 and off-road mobile sources, and any other 

3 category of sources that the Administrator 

4 may identify, and 

5 ‘‘(ii) reductions in such emissions will 

6 improve air quality in the other State’s or 

7 States’ nonattainment areas at least as 

8 cost-effectively as reductions in emissions 

9 in the State or each other State from each 

10 other principal category of sources of the 

11 relevant pollutant, pollutants, or pre12 cursors thereof, to the maximum extent 

13 that a methodology is reasonably available 

14 to make such a determination; 

15 ‘‘(C) develop an appropriate peer reviewed 

16 methodology for making determinations under 

17 subparagraph (B) by December 31, 2006; and 

18 ‘‘(D) not require submission of plan provi19 sions subjecting affected units, within the 

20 meaning of section 126(d)(1), to requirements 

21 with an effective date prior to December 31, 

22 2014. 

23 ‘‘(2) PROXIMITY.—In making the determination 

24 under clause (ii) of subparagraph (B) of paragraph 

25 (1), the Administrator will use the best available 
249 

•S 131 IS 

1 peer-reviewed models and methodology that consider 

2 the proximity of the source or sources to the other 

3 State or States and incorporate other source charac4 teristics. 

5 ‘‘(3) EFFECT ON REGULATIONS.—Nothing in 

6 paragraph (1) shall be interpreted to require revi7 sions to the provisions of 40 CFR parts 51.121 and 

8 51.122 (2001). 

9 ‘‘(r) TRANSITIONAL AREAS.— 

10 ‘‘(1) MAINTENANCE.— 

11 ‘‘(A) SUBMISSION OF INVENTORY AND

12 ANALYSIS.—By December 31, 2011, each area 

13 designated as transitional pursuant to section 

14 107(d)(1) shall submit an updated emission in15 ventory and an analysis of whether growth in 

16 emissions, including growth in vehicle miles 

17 traveled, will interfere with attainment by De18 cember 31, 2014. 

19 ‘‘(B) REVIEW.—No later than December 

20 31, 2011, the Administrator shall review each 

21 transitional area’s maintenance analysis, and, if 

22 the Administrator determines that growth in 

23 emissions will interfere with attainment by De24 cember 31, 2014, the Administrator shall con25 sult with the State and determine what action, 
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1 if any, is necessary to assure that attainment 

2 will be achieved by December 31, 2014. 

3 ‘‘(2) PREVENTION OF SIGNIFICANT DETERIORA4 TION.—Each area designated as transitional pursu5 ant to section 107(d)(1) shall be treated as an at6 tainment or unclassifiable area for purposes of the 

7 prevention of significant deterioration provisions of 

8 part C of this title. 

9 ‘‘(3) CONSEQUENCES OF FAILURE TO ATTAIN

10 BY 2015.—No later than June 30, 2016, the Admin11 istrator shall determine whether each area des12 ignated as transitional for the 8-hour ozone stand13 ard or for the PM 2.5 standard has attained that 

14 standard. If the Administrator determines that a 

15 transitional area has not attained the standard, the 

16 area shall be redesignated as nonattainment within 

17 one year of the determination and the State shall be 

18 required to submit a State implementation plan revi19 sion satisfying the provisions of section 172 within 

20 three years of redesignation as nonattainment.’’. 

21 (4) In section 111(b)(1) by adding the following 

22 new subparagraph (C) after subparagraph (B): 

23 ‘‘(C) No standards of performance promul24 gated under this section shall apply to units 
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1 subject to regulations promulgated pursuant to 

2 section 481.’’. 

3 (5) In section 112: 

4 (A) By amending paragraph (1) of sub5 section (c) to read as follows: 

6 ‘‘(1) IN GENERAL.—Not later than 12 months 

7 after November 15, 1990, the Administrator shall 

8 publish, and shall from time to time, but not less 

9 often than every eight years, revise, if appropriate, 

10 in response to public comment or new information, 

11 a list of all categories and subcategories of major 

12 sources and area sources (listed under paragraph 

13 (3)) of the air pollutants listed pursuant to sub14 section (b). Electric utility steam generating units 

15 not subject to section 3005 of the Solid Waste Dis16 posal Act shall not be included in any category or 

17 subcategory listed under this subsection. The Ad18 ministrator shall have the authority to regulate the 

19 emission of hazardous air pollutants listed under 

20 section 112(b), other than mercury compounds, by 

21 electric utility steam generating units, provided that 

22 any determination shall be based on public health 

23 concerns and, on an individual source basis shall: 

24 consider the effects of emissions controls installed or 

25 anticipated to be installed in order to meet other 
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1 emission reduction requirements under this Act by 

2 2018; and, be based on a peer reviewed study with 

3 notice and opportunity to comment, to be completed 

4 not before January 2015. Any such regulations shall 

5 be promulgated within, and shall not take effect be6 fore, the date eight years after the commencement 

7 date of the requirements set forth in section 472. To 

8 the extent practicable, the categories and subcat9 egories listed under this subsection shall be con10 sistent with the list of source categories established 

11 pursuant to section 111 and part C. Nothing in the 

12 preceding sentence limits the Administrator’s au13 thority to establish subcategories under this section, 

14 as appropriate.’’. 

15 (B) By amending subparagraph (A) of 

16 subsection (n)(1) to read as follows: 

17 ‘‘(A) STUDY.—The Administrator shall 

18 perform a study of the hazards to public health 

19 reasonably anticipated to occur as a result of 

20 emissions by electric utility steam generating 

21 units of pollutants listed under subsection (b) 

22 after imposition of the requirements of this Act. 

23 The Administrator shall report the results of 

24 this study to the Congress within three years 

25 after November 15, 1990.’’ 
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1 (6) Section 126 is amended as follows: 

2 (A) By replacing ‘‘section 110(a)(2)(D)(ii) 

3 or this section’’ in subsection (b) with ‘‘section 

4 110(a)(2)(D)(i)’’. 

5 (B) In the language at end of subsection 

6 (c) by striking ‘‘section 110(a)(2)(D)(ii)’’ and 

7 inserting ‘‘section 110(a)(2)(D)(i)’’ and deleting 

8 the last sentence. 

9 (D) By adding at the end the following: 

10 ‘‘(d) DEFINITION OF AFFECTED UNIT.— 

11 ‘‘(1) IN GENERAL.—For purposes of this sub12 section, the term ‘affected unit’ means any unit that 

13 is subject to emission limitations under subpart 2 of 

14 part B, subpart 2 of part C, or part D, or is a des15 ignated unit under section 407. 

16 ‘‘(2) FINDING FOR AFFECTED UNITS.—To the extent 

17 that any petition submitted under subsection (b) after the 

18 date of enactment of the Clear Skies Act of 2005 seeks 

19 a finding for any affected unit, then, notwithstanding any 

20 provision in subsections (a) through (c) to the contrary: 

21 ‘‘(A) In determining whether to make a finding 

22 under subsection (b) for any affected unit, the Ad23 ministrator shall consider, among other relevant fac24 tors, emissions reductions required to occur by the 

25 attainment date or dates of any relevant nonattain-
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1 ment areas in the petitioning State or political sub2 division. 

3 ‘‘(B) The Administrator may not determine 

4 that affected units emit, or would emit, any air pol5 lutant in violation of the prohibition of section 

6 110(a)(2)(D)(i) unless that Administrator deter7 mines that— 

8 ‘‘(i) such emissions may be reduced at 

9 least as cost-effectively as emissions from each 

10 other principal category of sources of sulfur di11 oxide or nitrogen oxides, including industrial 

12 boilers, on-road mobile sources, and off-road 

13 mobile sources, and any other category of 

14 sources that the Administrator may identify; 

15 and 

16 ‘‘(ii) reductions in such emissions will im17 prove air quality in the petitioning State’s non18 attainment area or areas at least as cost-effec19 tively as reductions in emissions from each 

20 other principal category of sources of sulfur di21 oxide or nitrogen oxides to the maximum extent 

22 that a methodology is reasonably available to 

23 make such a determination. 

24 In making the determination under clause (ii), the 

25 Administrator shall use the best available peer-re-
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1 viewed models and methodology that consider the 

2 proximity of the source or sources to the petitioning 

3 State or political subdivision and incorporate other 

4 sources characteristics. 

5 ‘‘(C) The Administrator shall develop an appro6 priate peer reviewed methodology for making deter7 minations under subparagraph (B) by December 31, 

8 2006. 

9 ‘‘(D) The Administrator shall not make any 

10 findings with respect to an affected unit under this 

11 section prior to December 1, 2011. For any petition 

12 submitted prior to January 1, 2010, the Adminis13 trator shall make a finding or deny the petition by 

14 the December 31, 2011. 

15 ‘‘(E) The Administrator, by rulemaking, shall 

16 extend the compliance and implementation deadlines 

17 in subsection (c) to the extent necessary to assure 

18 that no affected unit shall be subject to any such 

19 deadline prior to January 1, 2014.’’. 

20 (b) TITLE III.—Section 307(d)(1)(G) of title III of 

21 the Clean Air Act is amended to read as follows: 

22 ‘‘(G) the promulgation or revision of any 

23 regulation under title IV,’’. 

24 (c) NOISE POLLUTION.—Title IV of the Clean Air 

25 Act (relating to noise pollution) (42 U.S.C. 7641 et seq.) 
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1 is redesignated as title VII and amended by renumbering 

2 sections 401 through 403 as sections 701 through 703, 

3 respectively, and conforming all cross-references thereto 

4 accordingly. 

5 (d) SECTION 406.—Title IV of the Clean Air Act 

6 Amendments of 1990 (relating to acid deposition control) 

7 is amended by repealing section 406 (industrial sulfur di8 oxide emissions). 

9 (e) MONITORING.—Section 821 (a) of title VIII of 

10 the Clean Air Act Amendments of 1990 (miscellaneous 

11 provisions) is amended to read as follows: 

12 ‘‘(a) MONITORING.—The Administrator shall promul13 gate regulations within eighteen months after November 

14 15, 1990, to require that all affected sources subject to 

15 subpart 1 of part B of title IV of the Clean Air Act as 

16 of December 31, 2009, shall also monitor carbon dioxide 

17 emissions according to the same timetable as in section 

18 405(b). The regulations shall require that such data be 

19 reported to the Administrator. The provisions of section 

20 405(e) of title IV of the Clean Air Act shall apply for pur21 poses of this section in the same manner and to the same 

22 extent as such provision applies to the monitoring and 

23 data referred to in section 405. The Administrator shall 
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1 implement this subsection under 40 CFR part 75 (2002), 

2 amended as appropriate by the Administrator.’’. 

Æ