II 

110TH CONGRESS 

1ST SESSION S. 1168 

To amend the Clean Air Act to establish a regulatory program for sulfur 

dioxide, nitrogen oxides, mercury, and carbon dioxide emissions from 

the electric generating sector. 

IN THE SENATE OF THE UNITED STATES 

APRIL 19, 2007 

Mr. ALEXANDER (for himself and Mr. LIEBERMAN) 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 establish a regulatory program for sulfur dioxide, nitrogen oxides, mercury, and 

carbon dioxide emissions from the electric generating 

sector. 

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 ‘‘Clean Air/Climate Change Act of 2007’’. 

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

7 this Act is as follows: 

Sec. 1. Short title; table of contents. 


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Sec. 2. Findings and purposes. 

TITLE I—GENERAL PROVISIONS 

Sec. 101. New source performance standard. 

Sec. 102. New source review program. 

Sec. 103. Integrated air quality planning for the electric generating sector. 

Sec. 104. Revisions to sulfur dioxide allowance program. 

Sec. 105. Air quality forecasts and warnings. 

Sec. 106. Relationship to other law. 

TITLE II—GREENHOUSE GAS OFFSETS 

Sec. 201. Greenhouse gas offsets. 

1 SEC. 2. FINDINGS AND PURPOSES. 

2 (a) FINDINGS.—Congress finds that— 

3 (1) in 1992, the United States became a signa4 tory to the United Nations Framework Convention 

5 on Climate Change in recognition of the need to 

6 begin to decrease greenhouse gas emission levels to 

7 1990 levels; 

8 (2) fossil fuel-fired electric generating sources, 

9 consisting of units fueled by coal, fuel oil, and natural gas, produce nearly 2 10 ⁄3 of the electricity gen11 erated in the United States; 

12 (3) fossil fuel-fired electric generating units 

13 produce approximately 67 percent of the total sulfur 

14 dioxide emissions, 23 percent of the total nitrogen 

15 oxides emissions, 40 percent of the total mercury 

16 emissions, and 40 percent of the total carbon dioxide 

17 emissions in the United States; 


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1 (4) as of the date of enactment of this Act, 

nearly 3 2 ⁄4 of all coal-fired electricity generating units 

3 are more than 30 years old; 

4 (5)(A) many electric generating units have been 

5 exempt from the emission limitations applicable to 

6 new units based on the expectation that over time 

7 the units would be retired or updated with new pol8 lution control equipment; but 

9 (B) many of the exempted units continue to op10 erate and emit pollutants at relatively high rates; 

11 (6) many owners of electric generating units 

12 have failed— 

13 (A) to install best available control tech14 nology for emissions reductions; and 

15 (B) to retire the units, as anticipated by 

16 Congress in the new source review provisions of 

17 the prevention of significant deterioration and 

18 nonattainment programs of the Clean Air Act 

19 (42 U.S.C. 7401 et seq.); 

20 (7) the Clean Air Act (42 U.S.C. 7401 et seq.) 

21 regulates substances (including carbon dioxide) 

22 that— 

23 (A) are emitted into the ambient air; and 

24 (B) affect the weather and the climate; 

25 (8)(A) as of the date of enactment of this Act— 


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1 (i) many class I areas (as designated under 

2 section 162(a) of the Clean Air Act (42 U.S.C. 

3 7472(a))) are impaired by haze pollution; 

4 (ii) the ecosystems of many class I areas 

5 are adversely affected by deposits of acidic and 

6 toxic compounds; and 

7 (iii) the air quality of many class I areas 

8 fails to meet national ambient air quality stand9 ards; and 

10 (B)(i) fossil-fuel fired electric generating units 

11 are a major source of air pollution impacting class 

12 I areas; and 

13 (ii) proposed new fossil-fuel fired electric gener14 ating units threaten to increase air pollution in class 

15 I areas throughout the United States; 

16 (9) according to the Energy Outlook for 2006 

17 of the Energy Information Administration, carbon 

18 dioxide emissions from electric generating units in 

19 the Unites States have increased by 32 percent dur20 ing the period of 1990 through 2006 to at least 

21 2,300,000,000 metric tons of carbon dioxide in 

22 2006; 

23 (10) the ability of owners of electric generating 

24 units to plan effectively for the future is impeded by 


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1 the uncertainties surrounding future environmental 

2 regulatory requirements; 

3 (11) according to the National Energy Tech4 nology Laboratory of the Department of Energy— 

5 (A) as of the date of enactment of this 

6 Act, 159 new coal-fired electric generating units 

7 are proposed to be constructed, which would 

8 produce 96 gigawatts of new electric generating 

9 capacity; and 

10 (B) if the units described in subparagraph 

11 (A) are constructed, the units would produce— 

12 (i) an incremental increase of 

13 500,000,000 tons of carbon dioxide per 

14 year from the production by the power sec15 tor in the United States as in existence on 

16 the date of enactment of this Act; and 

17 (ii) an estimated 30,000,000,000 ad18 ditional tons of carbon dioxide over the 

19 course of the useful lives of the units (as20 suming a lifespan of 60 years); 

21 (12) by December 31, 2015, emissions of car22 bon dioxide from the United States electric utility 

23 sector should be limited to 2,100,000,000 metric 

24 tons; 


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1 (13) a report of the Congressional Budget Of2 fice, dated September 19, 2006, concluded that— 

3 (A) relying exclusively on research and de4 velopment funding is not the most effective 

5 strategy for reducing greenhouse gas emissions; 

6 and 

7 (B) combining research and development 

8 funding with a gradually-increasing limitation 

9 on emissions is a more cost-effective approach; 

10 (14)(A) agriculture can be part of the solution 

11 to reducing greenhouse gas emissions; 

12 (B) less productive agricultural land can be re13 forested with carbon dioxide-consuming trees; 

14 (C) farming practices can be improved to in15 crease the absorption and retention of carbon in ag16 ricultural soils; 

17 (D) biomass from agricultural sources (includ18 ing corn and grass) can be used to produce biofuels 

19 that can take the place of high-carbon fossil fuels 

20 used in transportation and power generation; and 

21 (E) many of the farming practices and land use 

22 changes involved in achieving those reductions have 

23 multiple benefits, including— 

24 (i) improving soil, water, and air quality; 

25 (ii) increasing wildlife habitat; and 


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1 (iii) providing additional recreational op2 portunities; and 

3 (15) States and regions have adopted programs 

4 to address carbon dioxide emissions from electric 

5 generating units, and Federal regulations relating to 

6 carbon dioxide emissions should take those programs 

7 into consideration. 

8 (b) PURPOSES.—The purposes of this Act are— 

9 (1) to protect and preserve the environment and 

10 safeguard public health by ensuring that substantial 

11 emission reductions are achieved at fossil fuel-fired 

12 electric generating units; 

13 (2) to ensure that air quality of national parks 

14 and all other class I areas (as designated by section 

15 162(a) of the Clean Air Act (42 U.S.C. 7472(a))) 

16 affected by emissions from fossil fuel-fired electric 

17 generating units is significantly improved; 

18 (3) to reduce significantly the quantities of 

19 mercury, sulfur dioxide, nitrogen oxides, and carbon 

20 dioxide that enter the environment as a result of the 

21 combustion of fossil fuels; 

22 (4) to encourage the development and use of re23 newable energy; 

24 (5) to internalize the cost of protecting the val25 ues of public health, air, land, and water quality; 


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1 (6) to provide a period of environmental regu2 latory stability for owners and operators of electric 

3 generating units so as to promote improved manage4 ment of existing assets and new capital investments; 

5 and 

6 (7) to achieve emission reductions from electric 

7 generating units in a cost-effective manner. 

8 TITLE I—GENERAL PROVISIONS 

9 SEC. 101. NEW SOURCE PERFORMANCE STANDARD. 

10 Section 111 of the Clean Air Act (42 U.S.C. 7411) 

11 is amended by adding at the end the following: 

12 ‘‘(k) STANDARD OF PERFORMANCE FOR NEW ELEC13 TRIC GENERATING FACILITIES.— 

14 ‘‘(1) IN GENERAL.—Each electric generating 

15 unit constructed or modified after January 1, 2015, 

16 shall meet a standard of performance equivalent to 

17 an emission limitation of 1,100 pounds of carbon di18 oxide per megawatt-hour or less. 

19 ‘‘(2) ELIGIBILITY FOR CARBON DIOXIDE AL20 LOWANCES.—Beginning on January 1, 2007, each of 

21 the first 30 electric generating units to achieve the 

22 standard of performance described in paragraph (1) 

23 (or a revised standard under paragraph (4), as ap24 plicable) shall be eligible to participate in the Cli25 mate Champions Program under section 707. 


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1 ‘‘(3) TREATMENT OF CERTAIN CARBON DIOX2 IDE.—Carbon dioxide that is injected into a geologi3 cal formation in a manner that prevents any release 

4 of the carbon dioxide into the atmosphere shall not 

5 be considered to be carbon dioxide emissions from 

6 an electric generating unit for purposes of the stand7 ard of performance under paragraph (1). 

8 ‘‘(4) REVIEW.— 

9 ‘‘(A) IN GENERAL.—Not later than Janu10 ary 1, 2015, and every 8 years thereafter, the 

11 Administrator shall review the applicable stand12 ards of performance for new electric generating 

13 units with respect to carbon dioxide emissions 

14 to determine whether the emission limitation for 

15 the units under paragraph (1) should be de16 creased, based on the best available techno17 logical system of continuous emission reduction. 

18 ‘‘(B) TREATMENT.—A determination by 

19 the Administrator under subparagraph (A) shall 

20 be— 

21 ‘‘(i) published in the Federal Register 

22 not later than the deadline described in 

23 that subparagraph for the applicable re24 view; and 


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1 ‘‘(ii) considered to be final agency ac2 tion for purposes of section 307(b)(1).’’. 

3 SEC. 102. NEW SOURCE REVIEW PROGRAM. 

4 Section 165 of the Clean Air Act (42 U.S.C. 7475) 

5 is amended by adding at the end the following: 

6 ‘‘(f) REVISIONS TO NEW SOURCE REVIEW PRO7 GRAM.— 

8 ‘‘(1) DEFINITIONS.—In this subsection: 

9 ‘‘(A) AFFECTED UNIT.—The term ‘af10 fected unit’ has the meaning given the term in 

11 section 701. 

12 ‘‘(B) NEW SOURCE REVIEW PROGRAM.— 

13 The term ‘new source review program’ means 

14 the program to carry out this part and part D. 

15 ‘‘(2) PERFORMANCE STANDARDS.— 

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

17 subparagraph (B), beginning January 1, 2020, 

18 and on each January 1 thereafter, each affected 

19 unit that has been in operation 40 or more 

20 years as of that January 1 shall meet perform21 ance standards of— 

22 ‘‘(i) 2 lbs/MWh for sulfur dioxide; and 

23 ‘‘(ii) 1 lbs/MWh for nitrogen oxides. 

24 ‘‘(B) EXCEPTION.— 


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1 ‘‘(i) IN GENERAL.—Notwithstanding 

2 subparagraph (A), an affected unit that, as 

3 of January 1, 2020, is required to meet a 

4 more stringent performance standard than 

5 the applicable standard under subpara6 graph (A) shall continue to meet the more 

7 stringent standard. 

8 ‘‘(ii) MODIFICATION OF AFFECTED

9 UNITS.—The requirements of this section 

10 shall not affect in any way any require11 ment under section 111(a)(4), this part, or 

12 part D governing modifications of major 

13 stationary sources. 

14 ‘‘(3) NO EFFECT ON OTHER REQUIREMENTS

15 AND RETENTION OF STATE AUTHORITY.—Nothing in 

16 this subsection affects— 

17 ‘‘(A) any State authority under section 

18 116; or 

19 ‘‘(B) the obligation of any State or local 

20 government or any major emitting facility to 

21 comply with the requirements of this section.’’. 

22 SEC. 103. INTEGRATED AIR QUALITY PLANNING FOR THE 

23 ELECTRIC GENERATING SECTOR. 

24 The Clean Air Act (42 U.S.C. 7401 et seq.) is amend25 ed by adding at the end the following: 


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1 ‘‘TITLE VII—INTEGRATED AIR 

2 QUALITY PLANNING FOR THE 

3 ELECTRIC GENERATING SEC4 TOR 

‘‘TITLE VII—INTEGRATED AIR QUALITY PLANNING FOR THE 

ELECTRIC GENERATING SECTOR 

‘‘Sec. 701. Definitions. 

‘‘Sec. 702. National pollutant tonnage limitations. 

‘‘Sec. 703. Nitrogen oxide trading program. 

‘‘Sec. 704. Mercury program. 

‘‘Sec. 705. Carbon dioxide allowance trading program. 

‘‘Sec. 706. Conventional pulverized coal facilities. 

‘‘Sec. 707. Climate Champions Program. 

‘‘Sec. 708. Auction of carbon dioxide allowances. 

5 ‘‘SEC. 701. DEFINITIONS. 

6 ‘‘In this title: 

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

8 source’ means a source that includes 1 or more af9 fected units. 

10 ‘‘(2) AFFECTED UNIT.— 

11 ‘‘(A) CARBON DIOXIDE.— 

12 ‘‘(i) IN GENERAL.—The term ‘affected 

13 unit’, with respect to carbon dioxide, 

14 means an electric generating unit that, on 

15 or after January 1, 2000, served a gener16 ator producing electricity for sale with a 

17 nameplate capacity of greater than 25 

18 megawatts. 


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1 ‘‘(ii) EXCLUSION.—The term ‘affected 

2 unit’, with respect to carbon dioxide, does 

3 not include a unit that— 

4 ‘‘(I) cogenerates useful steam 

5 and electricity; but 

6 ‘‘(II) is not a cogeneration unit. 

7 ‘‘(B) MERCURY.— 

8 ‘‘(i) IN GENERAL.—The term ‘affected 

9 unit’, with respect to mercury, means a 

10 coal-fired electric generating unit that, on 

11 or after January 1, 1985, served a gener12 ator producing electricity for sale with a 

13 nameplate capacity greater than 25 

14 megawatts. 

15 ‘‘(ii) EXCLUSION.—The term ‘affected 

16 unit’, with respect to mercury, does not in17 clude a unit that— 

18 ‘‘(I) cogenerates useful steam 

19 and electricity; but 

20 ‘‘(II) is not a cogeneration unit. 

21 ‘‘(C) NITROGEN OXIDES.— 

22 ‘‘(i) IN GENERAL.—The term ‘affected 

23 unit’, with respect to nitrogen oxides, 

24 means a fossil fuel-fired electric generating 

25 unit that, on or after January 1, 1985, 


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1 served a generator producing electricity for 

2 sale with a nameplate capacity greater 

3 than 25 megawatts. 

4 ‘‘(ii) EXCLUSION.—The term ‘affected 

5 unit’, with respect to nitrogen oxides, does 

6 not include a unit that— 

7 ‘‘(I) cogenerates useful steam 

8 and electricity; but 

9 ‘‘(II) is not a cogeneration unit. 

10 ‘‘(D) SULFUR DIOXIDE.—The term ‘af11 fected unit’, with respect to sulfur dioxide, has 

12 the meaning given the term in section 402. 

13 ‘‘(3) CAIR.—The term ‘CAIR’ means the rule 

14 promulgated by the Administrator entitled the 

15 ‘Clean Air Interstate Rule’ (70 Fed. Reg. 25162 

16 (May 12, 2005)) (as in effect on the date of enact17 ment of this title). 

18 ‘‘(4) CAIR STATE.—The term ‘CAIR State’ 

19 means each State that is subject to the annual emis20 sion limitation and allowance trading program for 

21 nitrogen oxides and sulfur dioxide under CAIR, in22 cluding, as of the date of enactment of this Act— 

23 ‘‘(A) Alabama; 

24 ‘‘(B) Delaware; 

25 ‘‘(C) the District of Columbia; 


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1 ‘‘(D) Florida; 

2 ‘‘(E) Georgia; 

3 ‘‘(F) Illinois; 

4 ‘‘(G) Indiana; 

5 ‘‘(H) Iowa; 

6 ‘‘(I) Kentucky; 

7 ‘‘(J) Louisiana; 

8 ‘‘(K) Maryland; 

9 ‘‘(L) Michigan; 

10 ‘‘(M) Minnesota; 

11 ‘‘(N) Mississippi; 

12 ‘‘(O) Missouri; 

13 ‘‘(P) New Jersey; 

14 ‘‘(Q) New York; 

15 ‘‘(R) North Carolina; 

16 ‘‘(S) Ohio; 

17 ‘‘(T) Pennsylvania; 

18 ‘‘(U) South Carolina; 

19 ‘‘(V) Tennessee; 

20 ‘‘(W) Texas; 

21 ‘‘(X) Virginia; 

22 ‘‘(Y) West Virginia; and 

23 ‘‘(Z) Wisconsin. 

24 ‘‘(5) CARBON DIOXIDE ALLOWANCE.—The term 

25 ‘carbon dioxide allowance’ means an authorization 


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1 allocated by the Administrator under this title to 

2 emit 1 ton of carbon dioxide during or after a speci3 fied calendar year. 

4 ‘‘(6) COGENERATION UNIT.—The term ‘cogen5 eration unit’ means a unit that— 

6 ‘‘(A) cogenerates— 

7 ‘‘(i) useful steam; and 

8 ‘‘(ii) electricity; and 

9 ‘‘(B) supplies, in any calendar year, to any 

10 utility power distribution system for sale— 

‘‘(i) more than 1 11 ⁄3 of the potential 

12 electric output capacity of the unit; and 

13 ‘‘(ii) more than 219,000 megawatt14 hours of electrical output. 

15 ‘‘(7) DESIGNATED REPRESENTATIVE.—The 

16 term ‘designated representative’ means a responsible 

17 person or official authorized by the owner or oper18 ator of an affected source to represent the owner or 

19 operator in any matter relating to— 

20 ‘‘(A) the holding, transfer, or disposition of 

21 an allowance under this title; or 

22 ‘‘(B) any submission concerning, and com23 pliance with, any requirement of this title for 

24 the affected source. 


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1 ‘‘(8) FOSSIL FUEL.—The term ‘fossil fuel’ in2 cludes— 

3 ‘‘(A) natural gas; 

4 ‘‘(B) petroleum; 

5 ‘‘(C) coal; and 

6 ‘‘(D) any form of solid, liquid, or gaseous 

7 fuel derived from a material described in any of 

8 subparagraphs (A) through (C). 

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

10 fuel-fired’ means the combustion of any quantity of 

11 a fossil fuel during any calendar year. 

12 ‘‘(10) GREENHOUSE GAS.—The term ‘green13 house gas’ means any of— 

14 ‘‘(A) carbon dioxide; 

15 ‘‘(B) methane (CH4); 

16 ‘‘(C) nitrous oxide (N20); 

17 ‘‘(D) hydrofluorocarbons (HFC–23, HFC– 

18 32, HFC–41, HFC–43–10mee, HFC–125, 

19 HFC–134, HFC–134a, HFC–152a, HFC–143, 

20 HFC–143a, HFC–227ea, HFC–236fa, and 

21 HFC–245ca); 

22 ‘‘(E) perfluorocarbons (CF4, C2F6, C3F8, 

23 C4F10, C–C4F8, C5F12, and C6F14); and 

24 ‘‘(F) sulfur hexafluoride (SF6). 


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1 ‘‘(11) NEW UNIT.—The term ‘new unit’ means 

2 an affected unit that has operated for not more than 

3 3 years and is not eligible to receive nitrogen oxide 

4 allowances under the regulations promulgated by the 

5 Administrator pursuant to section 705(b). 

6 ‘‘(12) NITROGEN OXIDE ALLOWANCE.—The 

7 term ‘nitrogen oxide allowance’ means an authoriza8 tion allocated by the Administrator under this title 

9 to emit 1 ton of nitrogen oxides during or after a 

10 specified calendar year. 

11 ‘‘(13) SEQUESTRATION.—The term ‘sequestra12 tion’ means the action of sequestering carbon dioxide 

13 by— 

14 ‘‘(A) enhancing a natural carbon dioxide 

15 sink (such as through afforestation); or 

16 ‘‘(B)(i) capturing the carbon dioxide emit17 ted from relevant industrial units and a fossil 

18 fuel-based energy system; and 

19 ‘‘(ii)(I) storing the carbon dioxide in a geo20 logic formation in a manner that prevents any 

21 release of the carbon dioxide; or 

22 ‘‘(II) converting the carbon dioxide to a be23 nign solid material through a biological or 

24 chemical process. 


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1 ‘‘(14) SULFUR DIOXIDE ALLOWANCE.—The 

2 term ‘sulfur dioxide allowance’ has the meaning 

3 given the term ‘allowance’ in section 402. 

4 ‘‘(15) UNIT.—The term ‘unit’ means a combus5 tion device. 

6 ‘‘(16) USEFUL ENERGY.—The term ‘useful en7 ergy’, with respect to a cogeneration unit, means the 

8 total quantity of useful energy (including electrical 

9 generation and useful steam) as determined by the 

10 Administrator. 

11 ‘‘(17) ZONE 1 STATE.—The term ‘Zone 1 State’ 

12 means— 

13 ‘‘(A) any CAIR State; 

14 ‘‘(B) Arkansas; 

15 ‘‘(C) Connecticut; 

16 ‘‘(D) Massachusetts; 

17 ‘‘(E) Maine; 

18 ‘‘(F) New Hampshire; 

19 ‘‘(G) Rhode Island; and 

20 ‘‘(H) Vermont. 

21 ‘‘(18) ZONE 2 STATE.—The term ‘Zone 2 State’ 

22 means any of the 48 contiguous States that is not 

23 a Zone 1 State. 


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1 ‘‘SEC. 702. NATIONAL POLLUTANT TONNAGE LIMITATIONS. 

2 ‘‘(a) SULFUR DIOXIDE.—The annual tonnage limita3 tion for emissions of sulfur dioxide shall be equal to— 

4 ‘‘(1) for each of calendar years 2010 through 

5 2014, for affected units subject to CAIR, 3,500,000 

6 tons, in accordance with CAIR; and 

7 ‘‘(2) for calendar year 2015 and each calendar 

8 year thereafter, for all affected units in the 48 con9 tiguous States, 2,000,000 tons. 

10 ‘‘(b) NITROGEN OXIDES.—The Administrator shall 

11 allocate an annual tonnage limitation for emissions of ni12 trogen oxides in a quantity that is equal to— 

13 ‘‘(1) for each of calendar years 2009 through 

14 2014, for affected units subject to CAIR, 1,450,000 

15 tons; and 

16 ‘‘(2) for calendar year 2015 and each calendar 

17 year thereafter— 

18 ‘‘(A) for affected units in Zone 1 States, 

19 1,300,000 tons; and 

20 ‘‘(B) for affected units in Zone 2 States, 

21 320,000 tons. 

22 ‘‘(c) MERCURY.—The emission of mercury from af23 fected units shall be limited in accordance with section 

24 704. 

25 ‘‘(d) CARBON DIOXIDE.—The annual tonnage limita26 tion for emissions of carbon dioxide from affected units 


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1 in the 48 contiguous States shall be equal to, as deter2 mined by the Administrator based on certified and quality3 assured continuous emissions monitoring data for carbon 

4 dioxide reported to the Administrator by affected units in 

5 accordance with this Act— 

6 ‘‘(1) for each of calendar years 2011 through 

7 2014, 2,300,000,000 metric tons; 

8 ‘‘(2) for each of calendar years 2015 through 

9 2019, 2,100,000,000 metric tons; 

10 ‘‘(3) for each calendar years 2020 through 

11 2024, 1,800,000,000 metric tons; and 

12 ‘‘(4) for calendar year 2025 and each calendar 

13 year thereafter, 1,500,000,000 metric tons. 

14 ‘‘(e) REDUCTION OF EMISSIONS FROM SPECIFIED

15 AFFECTED UNITS.—Notwithstanding the annual tonnage 

16 limitations and mercury emissions requirements estab17 lished under this section, the Federal Government or a 

18 State government may require that emissions from a spec19 ified affected unit be reduced. 

20 ‘‘(f) CAIR STATES.— 

21 ‘‘(1) IN GENERAL.—Each CAIR State shall 

22 comply with the applicable requirements of CAIR. 

23 ‘‘(2) EXCEPTION.—Notwithstanding paragraph 

24 (1), CAIR shall not apply to— 


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1 ‘‘(A) annual emissions of nitrogen oxides 

2 emitted during calendar year 2015 and there3 after; or 

4 ‘‘(B) annual emissions of sulfur dioxide 

5 emitted during calendar year 2015 and there6 after. 

7 ‘‘SEC. 703. NITROGEN OXIDE TRADING PROGRAM. 

8 ‘‘(a) REGULATIONS.— 

9 ‘‘(1) IN GENERAL.—Not later than 2 years 

10 after the date of enactment of this title, the Admin11 istrator shall promulgate regulations to establish for 

12 affected units in the 48 contiguous States a nitrogen 

13 oxide allowance trading program. 

14 ‘‘(2) REQUIREMENTS.—Regulations promul15 gated under paragraph (1) shall establish require16 ments for the allowance trading program under this 

17 section, including requirements concerning— 

18 ‘‘(A)(i) the allocation, issuance, recording, 

19 tracking, transfer, and use of nitrogen oxide al20 lowances; and 

21 ‘‘(ii) the public availability of all informa22 tion concerning the activities described in clause 

23 (i) that is not confidential business information; 

24 ‘‘(B) compliance with subsection (d)(1); 


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1 ‘‘(C) the monitoring and reporting of emis2 sions under paragraphs (2) and (3) of sub3 section (d); and 

4 ‘‘(D) excess emission penalties under sub5 section (d)(4). 

6 ‘‘(b) NITROGEN OXIDE ALLOCATIONS.— 

7 ‘‘(1) TIMING OF ALLOCATIONS.—Not later than 

8 2 years after the date of enactment of this title, the 

9 Administrator shall allocate nitrogen oxide allow10 ances to affected units. 

11 ‘‘(2) ALLOCATIONS TO AFFECTED UNITS.— 

12 ‘‘(A) ZONE 1 STATES.—The Administrator 

13 shall allocate, to each affected unit in a Zone 1 

14 State, a quantity of nitrogen oxide allowances 

15 that is equal to the product obtained by multi16 plying— 

17 ‘‘(i) the quantity of nitrogen oxide al18 lowances available for allocation under sec19 tion 702(b)(2)(A); and 

20 ‘‘(ii) the quotient obtained by divid21 ing— 

22 ‘‘(I) the adjusted average heat 

23 input (measured in mmBtus), of the 

24 affected unit during calendar years 

25 2006 through 2008; by 


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1 ‘‘(II) the sum of the adjusted 

2 heat input quantities described in sub3 clause (I) with respect to all affected 

4 units in all Zone 1 States. 

5 ‘‘(B) ZONE 2 STATES.—The Administrator 

6 shall allocate, to each affected unit in a Zone 2 

7 State, a quantity of nitrogen oxide allowances 

8 that is equal to the product obtained by multi9 plying— 

10 ‘‘(i) the quantity of nitrogen oxide al11 lowances available for allocation under sec12 tion 702(b)(2)(B); and 

13 ‘‘(ii) the quotient obtained by divid14 ing— 

15 ‘‘(I) the adjusted average heat 

16 input (measured in mmBtus), of the 

17 affected unit during calendar years 

18 2006 through 2008; by 

19 ‘‘(II) the sum of the adjusted 

20 heat input quantities described in sub21 clause (I) with respect to all affected 

22 units in all Zone 2 States. 

23 ‘‘(C) ADJUSTED HEAT INPUT.— 

24 ‘‘(i) IN GENERAL.—The adjusted heat 

25 input for a calendar year of an affected 


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1 unit that begins operation before January 

2 1, 2006, shall be equal to the product ob3 tained by multiplying (using factors, emis4 sion rates, and categories of units deter5 mined by the Administrator)— 

6 ‘‘(I) the heat input of the af7 fected unit for the calendar year; and 

8 ‘‘(II) a factor reflecting— 

9 ‘‘(aa) the category of the af10 fected unit, based on the types of 

11 fuels combusted by the affected 

12 unit during the calendar year; 

13 and 

14 ‘‘(bb) the actual nitrogen ox15 ides emission rate (expressed in 

16 tons of nitrogen oxides emitted 

17 per mmBtu) that is generally ap18 plicable to that category of af19 fected units. 

20 ‘‘(ii) AVERAGE.—The average ad21 justed heat input of an affected unit for a 

22 3-calendar year period described in sub23 paragraph (A)(ii)(I) or (B)(ii)(I) shall be 

24 equal to the quotient obtained by divid25 ing— 


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1 ‘‘(I) the sum of the adjusted heat 

2 input quantities, as determined under 

3 clause (i), for each calendar year of 

4 the 3-calendar year period; by 

5 ‘‘(II) 3. 

6 ‘‘(3) ADJUSTMENT OF ALLOCATIONS.—If, for 

7 any calendar year, the total quantities of allowances 

8 allocated under paragraph (2) are not equal to the 

9 applicable quantities determined under section 

10 702(b)(2), the Administrator shall adjust the quan11 tities of allowances allocated to affected units on a 

12 pro rata basis so that the quantities are equal to the 

13 applicable quantities determined under section 

14 702(b)(2). 

15 ‘‘(4) ALLOWANCE NOT A PROPERTY RIGHT.—A 

16 nitrogen oxide allowance— 

17 ‘‘(A) is not a property right; and 

18 ‘‘(B) may be terminated or limited by the 

19 Administrator. 

20 ‘‘(5) NO JUDICIAL REVIEW.—An allocation of 

21 nitrogen oxide allowances by the Administrator 

22 under this subsection, and a determination of a 

23 value used in calculating the allocation, shall not be 

24 subject to judicial review. 


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1 ‘‘(c) NITROGEN OXIDE ALLOWANCE TRANSFER SYS2 TEM.— 

3 ‘‘(1) USE OF ALLOWANCES.—The regulations 

4 promulgated under subsection (a)(1) shall— 

5 ‘‘(A) prohibit the use (but not the transfer 

6 in accordance with paragraph (3)) of any nitro7 gen oxide allowance before the calendar year for 

8 which the allowance is allocated; 

9 ‘‘(B) provide that unused nitrogen oxide 

10 allowances may be carried forward and added 

11 to nitrogen oxide allowances allocated for subse12 quent years; 

13 ‘‘(C) provide that unused nitrogen oxide al14 lowances may be transferred by— 

15 ‘‘(i) the person to which the allow16 ances are allocated; or 

17 ‘‘(ii) any person to which the allow18 ances are transferred; and 

19 ‘‘(D) provide that, to achieve compliance 

20 with paragraphs (1) and (4) of subsection (d)— 

21 ‘‘(i) the owner and operator of an af22 fected unit in a Zone 1 State shall use only 

23 nitrogen oxide allowances allocated to af24 fected units in Zone 1 States; and 


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1 ‘‘(ii) the owner and operator of an af2 fected unit in a Zone 2 State shall use only 

3 nitrogen oxide allowances allocated to af4 fected units in Zone 2 States. 

5 ‘‘(2) USE BY PERSONS TO WHICH ALLOWANCES

6 ARE TRANSFERRED.—Any person to which nitrogen 

7 oxide allowances are transferred under paragraph 

8 (1)(C)— 

9 ‘‘(A) may use the nitrogen oxide allow10 ances in the calendar year for which the nitro11 gen oxide allowances were allocated, or in a 

12 subsequent calendar year, to achieve compliance 

13 with subsection (d)(1); or 

14 ‘‘(B) may transfer the nitrogen oxide al15 lowances to any other person. 

16 ‘‘(3) CERTIFICATION OF TRANSFER.—A trans17 fer of a nitrogen oxide allowance shall not take ef18 fect until a certification of the transfer, authorized 

19 by a responsible official of the person making the 

20 transfer, is received and recorded by the Adminis21 trator. 

22 ‘‘(4) PERMIT REQUIREMENTS.—An allocation 

23 or transfer of nitrogen oxide allowances to an af24 fected unit shall, after recording by the Adminis25 trator, be considered to be part of the federally enVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00028 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 forceable permit of the affected unit under this Act, 

2 without a requirement for any further review or revi3 sion of the permit. 

4 ‘‘(d) COMPLIANCE AND ENFORCEMENT.— 

5 ‘‘(1) IN GENERAL.—For calendar year 2015 

6 and each calendar year thereafter, the owner and op7 erator of each affected source shall hold for the af8 fected source and surrender to the Administrator a 

9 quantity of nitrogen oxide allowances that is equal 

10 to the total tons of nitrogen oxides emitted by the 

11 affected units of the affected source during the cal12 endar year. 

13 ‘‘(2) MONITORING SYSTEM.—The Administrator 

14 shall promulgate regulations requiring— 

15 ‘‘(A) installation, operation, reporting, and 

16 certification of continuous emissions monitoring 

17 systems, or any alternative monitoring system 

18 or methodology that, as determined by the Ad19 ministrator, provides information with the same 

20 precision, reliability, accessibility, and timeli21 ness as that provided by continuous emission 

22 monitoring system, to measure the quantity of 

23 nitrogen oxides that is emitted from each af24 fected unit; 


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1 ‘‘(B) quality assurance, verification, and 

2 reporting of nitrogen oxides emissions at each 

3 affected unit; and 

4 ‘‘(C) if continuous emission monitoring 

5 system data, or data from an alternative moni6 toring system approved by the Administrator, is 

7 not available for an affected unit during any pe8 riod of a calendar year for which the data is re9 quired to be certified under this subsection, and 

10 if the owner or operator of the affected unit 

11 cannot provide information satisfactory to the 

12 Administrator on emissions during that pe13 riod— 

14 ‘‘(i) treatment of the affected unit as 

15 operating in an uncontrolled manner dur16 ing the entire period for which the data 

17 was not available; and 

18 ‘‘(ii) calculation of emissions for that 

19 period as prescribed by the Administrator. 

20 ‘‘(3) REPORTING.— 

21 ‘‘(A) IN GENERAL.—Not less often than 

22 quarterly, the designated representative of the 

23 owner or operator of an affected unit shall sub24 mit to the Administrator a report on the moni25 toring of emissions of nitrogen oxides carried 


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1 out by the owner or operator in accordance with 

2 the regulations promulgated under paragraph 

3 (2). 

4 ‘‘(B) AUTHORIZATION.—Each report sub5 mitted under subparagraph (A) shall be author6 ized by the designated representative of the af7 fected unit, who shall certify the accuracy of 

8 the report. 

9 ‘‘(C) PUBLIC REPORTING.—The Adminis10 trator shall make available to the public, 

11 through 1 or more published reports and 1 or 

12 more forms of electronic media, data concerning 

13 the emissions of nitrogen oxides from each af14 fected unit. 

15 ‘‘(4) EXCESS EMISSIONS.—The owner and oper16 ator of an affected source the affected units of which 

17 emit, during a calendar year specified in paragraph 

18 (1), nitrogen oxides in excess of the nitrogen oxide 

19 allowances held for use by the affected source for 

20 the calendar year shall offset, and pay an excess 

21 emissions penalty for, the excess emissions by sur22 rendering to the Administrator a quantity of nitro23 gen oxides allowances for the following calendar 

24 year, or such earlier period as the Administrator 


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1 may prescribe, equal to the product obtained by mul2 tiplying— 

3 ‘‘(A) the number of tons of the excess 

4 emissions; and 

5 ‘‘(B) 2. 

6 ‘‘(e) EFFECT.—Nothing in this section limits or oth7 erwise affects the application of section 113, 114, 120, or 

8 304. 

9 ‘‘SEC. 704. MERCURY PROGRAM. 

10 ‘‘(a) DEFINITION OF INLET MERCURY.—In this sec11 tion, the term ‘inlet mercury’ means the quantity of mer12 cury found— 

13 ‘‘(1) in the as-fired coal of an affected unit; or 

14 ‘‘(2) for an affected unit using coal that is sub15 jected to an advanced coal cleaning technology, in 

16 the as-mined coal of the affected unit. 

17 ‘‘(b) ANNUAL LIMITATION FOR CERTAIN UNITS.— 

18 An affected unit that begins operation on or after the date 

19 of enactment of this title shall be subject to the less strin20 gent of the following emission limitations on an annual 

21 average calendar year basis with respect to inlet mercury: 

22 ‘‘(1) 90 percent capture of inlet mercury. 

23 ‘‘(2) An emission rate of 0.0060 lbs/GWh. 

24 ‘‘(c) ANNUAL LIMITATION FOR EXISTING UNITS.— 

25 An affected unit in operation on the date of enactment 


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1 of this title shall be subject to the following emission limi2 tations on an annual average calendar year basis with re3 spect to inlet mercury: 

4 ‘‘(1) FIRST FULL CALENDAR YEAR BEGINNING

5 4 YEARS AFTER THE DATE OF ENACTMENT OF

6 TITLE THROUGH 2014.—For each of the first full 

7 calendar year beginning 4 years after the date of en8 actment of this title through calendar year 2014, the 

9 less stringent limitation of— 

10 ‘‘(A) 60 percent capture of inlet mercury; 

11 and 

12 ‘‘(B) an emission rate of 0.02 lbs/GWh. 

13 ‘‘(2) 2015 AND THEREAFTER.—Beginning on 

14 January 1, 2015, the less stringent limitation of— 

15 ‘‘(A) 90 percent capture of inlet mercury; 

16 and 

17 ‘‘(B) an emission rate of 0.0060 lbs/GWh. 

18 ‘‘(d) AVERAGING ACROSS UNITS.—An owner or oper19 ator of an affected unit may demonstrate compliance with 

20 the annual average limitations under subsections (b) and 

21 (c) by averaging emissions from all affected units at an 

22 affected source. 

23 ‘‘(e) MONITORING SYSTEM.—The Administrator shall 

24 promulgate regulations requiring— 


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1 ‘‘(1) installation, operation, reporting, and cer2 tification of continuous emissions monitoring sys3 tems, or any alternative monitoring system or meth4 odology that, as determined by the Administrator, 

5 provides information with the same precision, reli6 ability, accessibility, and timeliness as that provided 

7 by continuous emission monitors, to measure the 

8 quantity of mercury emitted from each affected unit; 

9 ‘‘(2) quality assurance, verification, and report10 ing of mercury emissions data at each affected unit; 

11 and 

12 ‘‘(3) if continuous emission monitoring system 

13 data, or data from an alternative monitoring system 

14 approved by the Administrator, is not available for 

15 an affected unit during any period of a calendar 

16 year for which the data is required to be certified 

17 under this subsection, and if the owner or operator 

18 of the affected unit cannot provide information satis19 factory to the Administrator on emissions during 

20 that period— 

21 ‘‘(A) treatment of the affected unit as op22 erating in an uncontrolled manner during the 

23 entire period for which the data was not avail24 able; and 


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1 ‘‘(B) calculation of emissions for that pe2 riod as prescribed by the Administrator. 

3 ‘‘(f) REPORTING.— 

4 ‘‘(1) IN GENERAL.—Not less often than quar5 terly, the owner or operator of an affected unit shall 

6 submit to the Administrator a report on the moni7 toring of emissions of mercury carried out by the 

8 owner or operator in accordance with the regulations 

9 promulgated under subsection (e). 

10 ‘‘(2) AUTHORIZATION.—Each report submitted 

11 under paragraph (1) shall be authorized by a des12 ignated representative of the affected unit, who shall 

13 certify the accuracy of the report. 

14 ‘‘(3) PUBLIC REPORTING.—The Administrator 

15 shall make available to the public, through 1 or 

16 more published reports and 1 or more forms of elec17 tronic media, data concerning the emission of mer18 cury from each affected unit. 

19 ‘‘(g) EXCESS EMISSIONS.— 

20 ‘‘(1) PENALTY.— 

21 ‘‘(A) IN GENERAL.—The owner and oper22 ator of an affected unit described in subpara23 graph (B) shall pay an excess emissions penalty 

24 determined under paragraph (2). 


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1 ‘‘(B) DESCRIPTION OF AFFECTED

2 UNITS.—An affected unit referred to in sub3 paragraph (A) is an affected unit that— 

4 ‘‘(i) for an affected unit dem5 onstrating compliance at the unit level, 

6 emits mercury in excess of an emission 

7 limitation described in subsection (b) or 

8 (c); or 

9 ‘‘(ii) for an affected unit dem10 onstrating compliance under subsection 

11 (d), is part of an affected source that emits 

12 mercury in excess of the emission limita13 tion applicable to the affected source. 

14 ‘‘(2) DETERMINATION OF EXCESS EMISSIONS

15 PENALTY.—The excess emissions penalty for mer16 cury shall be an amount equal to $50,000 for each 

17 pound of mercury emitted in excess of the emission 

18 limitation described in subsection (b) or (c), as pro19 rated for each fraction of a pound. 

20 ‘‘(3) PENALTY ADJUSTMENT.—For each fiscal 

21 year, the Administrator, by regulation, shall adjust 

22 the penalty specified in paragraph (2) to reflect 

23 changes for the 12-month period ending the pre24 ceding November 30 in the Consumer Price Index 


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1 for All Urban Consumers published by the Bureau 

2 of Labor Statistics of the Department of Labor. 

3 ‘‘(h) PETITION FOR EXTENSION.—The Adminis4 trator, or the appropriate agency of a State with a pro5 gram approved under title IV, may issue for an affected 

6 unit in existence on the date of enactment of this title 

7 a permit that provides an extension of not more than 1 

8 additional year of a deadline for compliance with any 

9 standard under this section, if the Administrator or agen10 cy determines the extension is necessary for the installa11 tion at the affected unit of an appropriate control tech12 nology. 

13 ‘‘(i) EFFECT OF SECTION.—Nothing in this section 

14 limits or otherwise affects the application of section 113, 

15 114, 120, or 304. 

16 ‘‘SEC. 705. CARBON DIOXIDE ALLOWANCE TRADING PRO17 GRAM. 

18 ‘‘(a) REGULATIONS.— 

19 ‘‘(1) IN GENERAL.—Not later than 2 years 

20 after the date of enactment of this title, the Admin21 istrator shall promulgate regulations to establish a 

22 carbon dioxide allowance trading program for af23 fected units in the United States. 

24 ‘‘(2) REQUIREMENTS.— 


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1 ‘‘(A) OTHER REQUIRED PROGRAMS.—In 

2 promulgating regulations pursuant to para3 graph (1), the Administrator shall ensure that 

4 no carbon dioxide allowance is provided for an 

5 offset project the greenhouse gas reductions 

6 under which are effectively required by any 

7 other Federal, State, or local law (including 

8 regulations) or judicial or administrative order. 

9 ‘‘(B) OTHER STANDARDS.—In promul10 gating regulations pursuant to paragraph (1), 

11 the Administrator shall require that— 

12 ‘‘(i) each reduction or removal of 

13 greenhouse gas emissions for which an off14 set project receives carbon dioxide allow15 ances under this section— 

16 ‘‘(I) is not double counted under 

17 this or any other allowance program; 

18 ‘‘(II) is a permanent reduction in 

19 greenhouse gas emissions; and 

20 ‘‘(III) is monitored as the Ad21 ministrator determines to be appro22 priate with respect to the specific off23 set project type and quantity of car24 bon dioxide allowances provided for 

25 the reduction; and 


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1 ‘‘(ii) each offset project shall reflect a 

2 level of performance that, with respect to 

3 emission reductions or a technology or 

4 practice, is significantly better than aver5 age, as compared with recently carried out 

6 activities or practices. 

7 ‘‘(3) STATE OFFSET METHODS.—In promul8 gating regulations under paragraph (1), the Admin9 istrator shall take into consideration offset methods 

10 developed, as of the date of enactment of this title, 

11 by California or any other State pursuant to the Re12 gional Greenhouse Gas Initiative or a similar regu13 latory program with of comparable rigor, as deter14 mined by the Administrator. 

15 ‘‘(b) NEW UNIT RESERVE.— 

16 ‘‘(1) ESTABLISHMENT.— 

17 ‘‘(A) IN GENERAL.—For each of calendar 

18 years 2011 through 2020, the Administrator 

19 shall establish, by regulation, a reserve of car20 bon dioxide allowances to be allocated to new 

21 affected units fueled by coal that meet the cri22 teria under the Climate Champions Program 

23 under section 707 for the calendar year. 

24 ‘‘(B) REQUIRED QUANTITY.—For a cal25 endar year described in subparagraph (A), the 


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1 quantity of carbon dioxide allowances in the re2 serve established under this paragraph shall not 

3 exceed 5 percent of the annual tonnage limita4 tion for carbon dioxide specified in section 

5 702(d) for that calendar year. 

6 ‘‘(2) REQUIRED ALLOCATIONS.—For each of 

7 calendar years 2011 through 2014, the Adminis8 trator shall allocate allowances in the reserve estab9 lished under paragraph (1) to each of the 30 entities 

10 identified under section 707(b)(1). 

11 ‘‘(3) UNUSED CARBON DIOXIDE ALLOW12 ANCES.—For each calendar year, the Administrator 

13 shall reallocate, to all affected units, any unused car14 bon dioxide allowances from the new unit reserve es15 tablished under paragraph (1) in the proportion 

16 that— 

17 ‘‘(A) the number of carbon dioxide allow18 ances allocated to each affected unit for the cal19 endar year; bears to 

20 ‘‘(B) the number of carbon dioxide allow21 ances allocated to all affected units for the cal22 endar year. 

23 ‘‘(c) CARBON DIOXIDE ALLOCATIONS.— 

24 ‘‘(1) ALLOCATIONS TO AFFECTED UNITS THAT

25 ARE NOT NEW UNITS.— 


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1 ‘‘(A) IN GENERAL.—Not later than 2 years 

2 after the date of enactment of this title, the Ad3 ministrator shall allocate, to each affected unit 

4 that is not a new unit, a quantity of carbon di5 oxide allowances that is equal to the product 

6 obtained by multiplying— 

7 ‘‘(i) the quantity of carbon dioxide al8 lowances available for allocation under 

9 paragraph (2); and 

10 ‘‘(ii) the quotient obtained by divid11 ing— 

12 ‘‘(I) the adjusted average heat 

13 input (measured in mmBtus), of the 

14 affected unit during any 3-consecu15 tive-calendar-year period during the 

16 period beginning on January 1, 2000, 

17 and ending on December 31, 2007; 

18 and 

19 ‘‘(II) the sum of the adjusted 

20 heat input quantities described in sub21 clause (I) with respect to all affected 

22 units that are not new units. 

23 ‘‘(B) ADJUSTED HEAT INPUT.— 

24 ‘‘(i) IN GENERAL.—The adjusted heat 

25 input for a calendar year of an affected 


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1 unit that begins operation before January 

2 1, 2005, shall be equal to the product ob3 tained by multiplying (using factors, emis4 sion rates, and categories of units deter5 mined by the Administrator)— 

6 ‘‘(I) the heat input of the af7 fected unit for the calendar year; 

8 ‘‘(II) a factor reflecting the cat9 egory of the affected unit, based on 

10 the types of fuels combusted by the 

11 affected unit during the calendar year; 

12 and 

13 ‘‘(III) the actual carbon dioxide 

14 emission rate (expressed in tons of 

15 carbon dioxide emitted per mmBtu) 

16 that is generally applicable to that 

17 category of affected units. 

18 ‘‘(ii) AVERAGE.—The average ad19 justed heat input of an affected unit for a 

20 3-calendar year period described in sub21 paragraph (A)(ii)(I)(bb) shall be equal to 

22 the quotient obtained by dividing— 

23 ‘‘(I) the sum of the adjusted heat 

24 input quantities, as determined under 


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1 clause (i), for each calendar year of 

2 the 3-calendar year period; and 

3 ‘‘(II) 3. 

4 ‘‘(2) QUANTITY TO BE ALLOCATED.—For each 

5 calendar year, the quantity of carbon dioxide allow6 ances allocated under paragraph (1)(A) to affected 

7 units that are not new units shall be equal to the 

8 difference between— 

9 ‘‘(A) the annual tonnage limitation for 

10 emissions of carbon dioxide from affected units 

11 specified in section 702(d) for the calendar 

12 year; and 

13 ‘‘(B) the sum of— 

14 ‘‘(i) the quantity of carbon dioxide al15 lowances placed in the new unit reserve es16 tablished under subsection (b) for the cal17 endar year; and 

18 ‘‘(ii) the quantity of carbon dioxide al19 lowances made available for auction under 

20 section 708. 

21 ‘‘(3) ADJUSTMENT OF ALLOCATIONS.—If the 

22 total quantity of carbon dioxide allowances to be al23 located under paragraph (1) for a calendar year is 

24 more than the total quantity of carbon dioxide allow25 ances available for allocation under paragraph (2) 


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1 for the calendar year, the Administrator shall allo2 cate to each affected unit a quantity of carbon diox3 ide allowances equal to the proportion that— 

4 ‘‘(A) the quantity of carbon dioxide allow5 ances to be allocated to the affected unit under 

6 paragraph (1) for the calendar year; bears to 

7 ‘‘(B) the total quantity of carbon dioxide 

8 allowances to be allocated to all affected units 

9 under paragraph (1) for the calendar year. 

10 ‘‘(4) ALLOCATIONS TO NEW UNITS.—The Ad11 ministrator shall promulgate regulations to establish 

12 a methodology for allocating carbon dioxide allow13 ances to new units from the new unit reserve under 

14 subsection (b). 

15 ‘‘(d) USE AND TRANSFER OF CARBON DIOXIDE AL16 LOWANCES.— 

17 ‘‘(1) USE BEFORE APPLICABLE CALENDAR

18 YEAR.—A carbon dioxide allowance may not be used 

19 before the calendar year for which the carbon diox20 ide allowance was allocated. 

21 ‘‘(2) TRANSFER.— 

22 ‘‘(A) IN GENERAL.—Notwithstanding para23 graph (1), carbon dioxide allowances may be 

24 transferred before the calendar year for which 

25 the carbon dioxide allowances were allocated. 


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1 ‘‘(B) LIMITATION.—The transfer of a car2 bon dioxide allowance shall not take effect until 

3 receipt and recording by the Administrator of a 

4 certification of the transfer, which is executed 

5 by an authorized official of the person making 

6 the transfer. 

7 ‘‘(3) USE BY PERSONS TO WHICH CARBON DI8 OXIDE ALLOWANCES ARE TRANSFERRED.—Any per9 son to which carbon dioxide allowances are trans10 ferred under paragraph (2)(A) may use the carbon 

11 dioxide allowances in the calendar year for which the 

12 carbon dioxide allowances were allocated, or in a 

13 subsequent calendar year, to demonstrate compli14 ance with subsection (e)(1). 

15 ‘‘(4) PERMIT REQUIREMENTS.—An allocation 

16 or transfer of carbon dioxide allowances to an af17 fected unit shall be considered to be part of the fed18 erally enforceable permit of the affected unit under 

19 this Act, without a requirement for further review or 

20 revision of the permit. 

21 ‘‘(e) COMPLIANCE AND ENFORCEMENT.— 

22 ‘‘(1) IN GENERAL.—For the first full calendar 

23 year beginning 4 years after the date of enactment 

24 of this title and each calendar year thereafter, the 

25 owner or operator of each affected source shall hold 


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1 for the affected source and surrender to the Admin2 istrator a quantity of carbon dioxide allowances 

3 equal to the total tons of carbon dioxide emitted by 

4 each affected unit of the affected source during the 

5 calendar year. 

6 ‘‘(2) EXCESS EMISSIONS.—The owner and oper7 ator of an affected source any affected unit of which 

8 emits carbon dioxide in excess of the carbon dioxide 

9 allowances held for use by the affected source for 

10 the calendar year shall offset, and pay an excess 

11 emissions penalty for, the excess emissions by sur12 rendering to the Administrator a quantity of carbon 

13 dioxide allowances for the following calendar year or 

14 such other period as the Administrator may pre15 scribe equal to the product obtained by multi16 plying— 

17 ‘‘(A) the number of tons of the excess 

18 emissions; and 

19 ‘‘(B) 2. 

20 ‘‘(3) MONITORING SYSTEM.—The Administrator 

21 shall promulgate regulations requiring— 

22 ‘‘(A) installation, operation, reporting, and 

23 certification of continuous emissions monitoring 

24 systems, or any alternative monitoring system 

25 or methodology that, as determined by the AdVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00046 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 ministrator, provides information with the same 

2 precision, reliability, accessibility, and timeli3 ness as that provided by continuous emission 

4 monitors, to measure the quantity of carbon di5 oxide emitted from each affected unit; 

6 ‘‘(B) quality assurance, verification, and 

7 reporting of carbon dioxide emissions data at 

8 each affected unit; and 

9 ‘‘(C) if continuous emission monitoring 

10 system data, or data from an alternative moni11 toring system approved by the Administrator, is 

12 not available for an affected unit during any pe13 riod of a calendar year for which the data is re14 quired to be certified under this subsection, and 

15 if the owner or operator of the affected unit 

16 cannot provide information satisfactory to the 

17 Administrator on emissions during that pe18 riod— 

19 ‘‘(i) treatment of the affected unit as 

20 operating in an uncontrolled manner dur21 ing the entire period for which the data 

22 was not available; and 

23 ‘‘(ii) calculation of emissions for that 

24 period as prescribed by the Administrator. 

25 ‘‘(4) REPORTING.— 


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1 ‘‘(A) IN GENERAL.—Not less often than 

2 quarterly, the owner or operator of an affected 

3 unit shall submit to the Administrator a report 

4 on the monitoring of emissions of carbon diox5 ide carried out by the owner or operator in ac6 cordance with the regulations promulgated 

7 under paragraph (3). 

8 ‘‘(B) AUTHORIZATION.—Each report sub9 mitted under subparagraph (A) shall be author10 ized by the designated representative of the af11 fected unit, who shall certify the accuracy of 

12 the report. 

13 ‘‘(C) PUBLIC REPORTING.—The Adminis14 trator shall make available to the public, 

15 through 1 or more published reports and 1 or 

16 more forms of electronic media, data concerning 

17 the emission of carbon dioxide from each af18 fected unit. 

19 ‘‘(f) EFFECT OF SECTION.—Nothing in this section 

20 limits or otherwise affects the application of section 113, 

21 114, 120, or 304. 

22 ‘‘(g) ALLOWANCE NOT A PROPERTY RIGHT.—A car23 bon dioxide allowance— 

24 ‘‘(1) is not a property right; and 


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1 ‘‘(2) may be terminated or limited by the Ad2 ministrator. 

3 ‘‘(h) NO JUDICIAL REVIEW.—An allocation or 

4 issuance of a carbon dioxide allowance by the Adminis5 trator, and the determination of any value used in calcu6 lating the allocation or issuance, shall not be subject to 

7 judicial review. 

8 ‘‘SEC. 706. CONVENTIONAL PULVERIZED COAL FACILITIES. 

9 ‘‘The correspondence of the Office of Air Quality 

10 Planning and Standards addressing best available control 

11 technology requirements for proposed coal-fired power 

12 plant projects and dated December 13, 2005— 

13 ‘‘(1) shall be considered to be inconsistent with 

14 section 169(3); and 

15 ‘‘(2) shall be treated as void and of no effect as 

16 of the date of issuance of the correspondence. 

17 ‘‘SEC. 707. CLIMATE CHAMPIONS PROGRAM. 

18 ‘‘(a) ESTABLISHMENT.—The Administrator shall es19 tablish a program, to be known as the ‘Climate Champions 

20 Program’. 

21 ‘‘(b) REWARDS; RECEIPT OF ALLOWANCES.—Under 

22 the Climate Champions Program, the Administrator 

23 shall— 

24 ‘‘(1) identify and provide such reward as the 

25 Administrator determines to be appropriate to each 


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1 of the first 30 entities to complete construction of a 

2 new coal-fired electric generating unit that meets 

3 each applicable new source performance standard 

4 under section 102 after the date of enactment of 

5 this title; and 

6 ‘‘(2) distribute to the 30 entities identified 

7 under paragraph (1) the carbon dioxide allowances 

8 reserved for the entities for the calendar year under 

9 section 705(b)(2). 

10 ‘‘SEC. 708. AUCTION OF CARBON DIOXIDE ALLOWANCES. 

11 ‘‘(a) IN GENERAL.—Not later than 2 years after the 

12 date of enactment of this title, the Administrator shall 

13 promulgate regulations establishing a procedure for the 

14 auction of 25 percent of the quantity of carbon dioxide 

15 allowances available for calendar year 2011 and each cal16 endar year thereafter. 

17 ‘‘(b) DEPOSIT OF PROCEEDS.—The Administrator 

18 shall deposit the proceeds from each auction carried out 

19 pursuant to this section into a fund of the Administrator 

20 for use, without further appropriation, for mitigating any 

21 increase in the cost of electricity to electricity consumers 

22 and energy-intensive industries, as determined by the Ad23 ministrator.’’. 


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1 SEC. 104. REVISIONS TO SULFUR DIOXIDE ALLOWANCE 

2 PROGRAM. 

3 (a) IN GENERAL.—Title IV of the Clean Air Act (re4 lating to acid deposition control) (42 U.S.C. 7651 et seq.) 

5 is amended by adding at the end the following: 

6 ‘‘SEC. 417. REVISIONS TO SULFUR DIOXIDE ALLOWANCE 

7 PROGRAM. 

8 ‘‘(a) REGULATIONS.—Not later than 2 years after 

9 the date of enactment of the Clean Air/Climate Change 

10 Act of 2007, the Administrator shall promulgate such revi11 sions to the regulations to implement this title as the Ad12 ministrator determines to be necessary to implement sec13 tion 702(a). 

14 ‘‘(b) SULFUR DIOXIDE ALLOCATIONS.— 

15 ‘‘(1) ALLOCATIONS TO ALLOWANCE TRACKING

16 SYSTEM ACCOUNTS.— 

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

18 shall allocate 95 percent of the quantity of sul19 fur dioxide allowances provided to achieve com20 pliance with the requirement under section 

21 702(a)(2) to accounts of the allowance tracking 

22 system under section 403(d) in accordance with 

23 the calculation under subparagraph (B). 

24 ‘‘(B) CALCULATION FOR ALLOCATIONS.— 

25 ‘‘(i) DEFINITION OF EXISTING QUAN26 TITY.—In this subparagraph, the term ‘exVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00051 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 isting quantity’, with respect to sulfur di2 oxide allowances, means, as determined by 

3 the Administrator in accordance with part 

4 73 of title 40, Code of Federal Regulations 

5 (or successor regulations)— 

6 ‘‘(I) for sulfur dioxide allowances 

7 allocated for any calendar year before 

8 calendar year 2016, the quantity of 

9 sulfur dioxide allowances allocated for 

10 the calendar year under sections 404 

11 through 406, and recorded in an ac12 count of the allowance tracking sys13 tem under section 403(d), as of 12:00 

14 p.m., Eastern Standard Time, on the 

15 date that is 180 days after the date of 

16 enactment of the Clean Air/Climate 

17 Change Act of 2007; and 

18 ‘‘(II) for sulfur dioxide allow19 ances allocated for calendar year 2016 

20 or any calendar year thereafter, the 

21 quantity described in subclause (I), 

22 reduced by— 

23 ‘‘(aa) 7 percent for calendar 

24 year 2016; and 


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1 ‘‘(bb) an additional 7 per2 cent for each calendar year there3 after. 

4 ‘‘(ii) CALCULATION.—For calendar 

5 year 2015 and each calendar year there6 after, the Administrator shall allocate to 

7 each account of the allowance tracking sys8 tem under section 403(d) a quantity of sul9 fur dioxide allowances equal to the product 

10 obtained by multiplying— 

11 ‘‘(I) the total quantity of allow12 ances to be allocated under subpara13 graph (A); and 

14 ‘‘(II) the proportion that— 

15 ‘‘(aa) the total existing 

16 quantity of sulfur dioxide allow17 ances for all calendar years in 

18 the account; bears to 

19 ‘‘(bb) the total existing 

20 quantities of sulfur dioxide allow21 ances for all calendar years in all 

22 accounts. 

23 ‘‘(2) ALLOCATIONS TO CERTAIN EXISTING

24 UNITS.— 


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1 ‘‘(A) DEFINITION OF EXISTING AFFECTED

2 UNIT.—In this paragraph, the term ‘existing af3 fected unit’ means an affected unit that— 

4 ‘‘(i) was an affected unit on December 

5 31, 2006; 

6 ‘‘(ii) began operation before January 

7 1, 2001; and 

8 ‘‘(iii) does not receive any sulfur diox9 ide allowance for a calendar year under 

10 section 404, 405, 406, or 410. 

11 ‘‘(B) ALLOCATION.—For calendar year 

12 2015 and each calendar year thereafter, the Administrator shall allocate 31 13 ⁄2 percent of the 

14 quantity of sulfur dioxide allowances provided 

15 to achieve compliance with the requirement 

16 under section 702(a)(2) to existing affected 

17 units in accordance with the applicable calcula18 tion under subparagraph (C). 

19 ‘‘(C) CALCULATIONS.— 

20 ‘‘(i) COAL-FIRED EXISTING AFFECTED

21 UNITS.—For calendar year 2015 and each 

22 calendar year thereafter, the Administrator 

23 shall allocate to each existing affected unit 

24 that is a coal-fired existing affected unit a 

25 quantity of sulfur dioxide allowances equal 


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1 to the product (expressed in tons) obtained 

2 by multiplying— 

3 ‘‘(I) the total baseline heat input 

4 of the existing affected unit, as deter5 mined under paragraph (4) (expressed 

6 in mmBtus); and 

7 ‘‘(II) 0.40 lb/mmBtu. 

8 ‘‘(ii) OIL-FIRED EXISTING AFFECTED

9 UNITS.—For calendar year 2015 and each 

10 calendar year thereafter, the Administrator 

11 shall allocate to each existing affected unit 

12 that is an oil-fired existing affected unit a 

13 quantity of sulfur dioxide allowances equal 

14 to the product (expressed in tons) obtained 

15 by multiplying— 

16 ‘‘(I) the total baseline heat input 

17 of the existing affected unit, as deter18 mined under paragraph (4) (expressed 

19 in mmBtus); and 

20 ‘‘(II) 0.20 lb/mmBtu. 

21 ‘‘(iii) OTHER EXISTING AFFECTED

22 UNITS.—For calendar year 2015 and each 

23 calendar year thereafter, the Administrator 

24 shall allocate to each existing affected unit 

25 that is not a coal-fired or oil-fired existing 


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1 affected unit a quantity of sulfur dioxide 

2 allowances equal to the product (expressed 

3 in tons) obtained by multiplying— 

4 ‘‘(I) the total baseline heat input 

5 of the existing affected unit, as deter6 mined under paragraph (4) (expressed 

7 in mmBtus); and 

8 ‘‘(II) 0.05 lb/mmBtu. 

9 ‘‘(D) ADJUSTMENT OF ALLOCATIONS.—If 

10 the total quantity of sulfur dioxide allowances 

11 to be allocated under subparagraph (C) for a 

12 calendar year is more than the total quantity of 

13 sulfur dioxide allowances available for allocation 

14 under subparagraph (B) for the calendar year, 

15 the Administrator shall allocate to each existing 

16 affected unit a quantity of sulfur dioxide allow17 ances equal to the product obtained by multi18 plying— 

19 ‘‘(i) the quantity of sulfur dioxide al20 lowances to be allocated to the existing af21 fected unit under subparagraph (C) for the 

22 calendar year; and 

23 ‘‘(ii) the proportion that— 

24 ‘‘(I) the quantity of sulfur diox25 ide allowances to be allocated to the 


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1 existing affected unit under subpara2 graph (C) for the calendar year; bears 

3 to 

4 ‘‘(II) the total quantity of sulfur 

5 dioxide allowances to be allocated to 

6 all existing affected units under sub7 paragraph (C) for the calendar year. 

8 ‘‘(E) EXCESS SUPPLY OF SULFUR DIOXIDE

9 ALLOWANCES.—Any sulfur dioxide allowance 

10 that is available for allocation under subpara11 graph (B) for a calendar year, but that is not 

12 allocated for the calendar year under subpara13 graph (C), shall be allocated in accordance with 

14 paragraph (3). 

15 ‘‘(3) ALLOCATION TO CERTAIN NEW UNITS.— 

16 ‘‘(A) DEFINITION OF NEW AFFECTED

17 UNIT.—In this paragraph, the term ‘new af18 fected unit’ means an affected unit that— 

19 ‘‘(i) was an affected unit on December 

20 31, 2006; 

21 ‘‘(ii) began operation during the pe22 riod beginning on January 1, 2001, and 

23 ending on December 31, 2006; and 


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1 ‘‘(iii) does not receive any sulfur diox2 ide allowance for a calendar year under 

3 section 404, 405, 406, or 410. 

4 ‘‘(B) ALLOCATION.—For calendar year 

5 2015 and each calendar year thereafter, the Administrator shall allocate 11 6 ⁄2 percent of the 

7 quantity of sulfur dioxide allowances provided 

8 to achieve compliance with the requirement 

9 under section 702(a)(2) to new affected units in 

10 accordance with the applicable calculation under 

11 subparagraph (C). 

12 ‘‘(C) CALCULATIONS.— 

13 ‘‘(i) COAL-FIRED AND OIL-FIRED NEW

14 AFFECTED UNITS.—For calendar year 

15 2015 and each calendar year thereafter, 

16 the Administrator shall allocate to each 

17 new affected unit that is a coal-fired or oil18 fired new affected unit a quantity of sulfur 

19 dioxide allowances equal to the product 

20 (expressed in tons) obtained by multi21 plying— 

22 ‘‘(I) the total baseline heat input 

23 of the new affected unit, as deter24 mined under paragraph (4) (expressed 

25 in mmBtus); and 


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1 ‘‘(II) 0.19 lb/mmBtu. 

2 ‘‘(ii) OTHER NEW AFFECTED

3 UNITS.—For calendar year 2015 and each 

4 calendar year thereafter, the Administrator 

5 shall allocate to each new affected unit 

6 that is not a coal-fired or oil-fired new af7 fected unit a quantity of sulfur dioxide al8 lowances equal to the product (expressed 

9 in tons) obtained by multiplying— 

10 ‘‘(I) the total baseline heat input 

11 of the new affected unit, as deter12 mined under paragraph (4) (expressed 

13 in mmBtus); and 

14 ‘‘(II) 0.02 lb/mmBtu. 

15 ‘‘(D) ADJUSTMENT OF ALLOCATIONS.—If 

16 the total quantity of sulfur dioxide allowances 

17 to be allocated under subparagraph (C) for a 

18 calendar year is more than the total quantity of 

19 sulfur dioxide allowances available for allocation 

20 under subparagraph (B) for the calendar year, 

21 the Administrator shall allocate to each new af22 fected unit a quantity of sulfur dioxide allow23 ances equal to the product obtained by multi24 plying— 


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1 ‘‘(i) the quantity of sulfur dioxide al2 lowances to be allocated to the new af3 fected unit under subparagraph (C) for the 

4 calendar year; and 

5 ‘‘(ii) the proportion that— 

6 ‘‘(I) the quantity of sulfur diox7 ide allowances to be allocated to the 

8 new affected unit under subparagraph 

9 (C) for the calendar year; bears to 

10 ‘‘(II) the total quantity of sulfur 

11 dioxide allowances to be allocated to 

12 all new affected units under subpara13 graph (C) for the calendar year. 

14 ‘‘(E) USE OF OTHER EXCESS SULFUR DI15 OXIDE ALLOWANCES.—The Administrator shall 

16 allocate to new affected units any excess allow17 ance provided pursuant to paragraph (2)(E) in 

18 accordance with subparagraphs (C) and (D). 

19 ‘‘(F) REMAINING SULFUR DIOXIDE ALLOW20 ANCES.—The Administrator shall allocate, on a 

21 pro rata basis in accordance with paragraphs 

22 (1) and (2), any sulfur dioxide allowance that 

23 is available for allocation, but that is not allo24 cated, for a calendar year under subparagraph 

25 (C) to— 


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1 ‘‘(i) appropriate accounts of the allow2 ance tracking system under section 403(d); 

3 and 

4 ‘‘(ii) existing affected units (as de5 fined in paragraph (2)(A)). 

6 ‘‘(4) DETERMINATION OF BASELINE HEAT

7 INPUT.—For purposes of calculations under para8 graphs (2)(C) and (3)(C), the baseline heat input of 

9 an existing affected unit (as defined in paragraph 

10 (2)(A)) or a new affected unit (as defined in para11 graph (3)(A)) shall be equal to the quotient obtained 

12 by dividing— 

13 ‘‘(A) the sum of the heat input of the af14 fected unit for each of calendar years 2005 

15 through 2007; by 

16 ‘‘(B) 3. 

17 ‘‘(5) WITHDRAWAL OF ALLOWANCES.—After 

18 completing the allocations of sulfur dioxide allow19 ances under paragraphs (1), (2), and (3), the Ad20 ministrator shall withdraw from each compliance ac21 count and general account in the allowance tracking 

22 system under section 403(d), and from the special 

23 allowance reserve under section 416, all sulfur diox24 ide allowances allocated or deposited for calendar 

25 year 2015 or any calendar year thereafter. 


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1 ‘‘(6) TIMING OF ALLOCATIONS.—The Adminis2 trator shall carry out each allocation of sulfur diox3 ide allowances required under this subsection for cal4 endar year 2015 or any calendar year thereafter by 

5 not later than December 31, 2011. 

6 ‘‘(7) NO JUDICIAL REVIEW.—An allocation of 

7 sulfur dioxide allowances by the Administrator under 

8 this subsection, and the determination of a value 

9 used in calculating such an allocation, shall not be 

10 subject to judicial review.’’. 

11 (b) DEFINITIONS.—Section 402 of the Clean Air Act 

12 (relating to acid deposition control) (42 U.S.C. 7651a) is 

13 amended— 

14 (1) by striking paragraph (2) and inserting the 

15 following: 

16 ‘‘(2) AFFECTED UNIT.— 

17 ‘‘(A) IN GENERAL.—The term ‘affected 

18 unit’ means— 

19 ‘‘(i) for a calendar year before cal20 endar year 2015, a unit that is subject to 

21 emission reduction requirements or limita22 tions under section 404, 405, 406, 409, or 

23 410; and 

24 ‘‘(ii) subject to subparagraph (B), for 

25 calendar year 2015 and each calendar year 


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1 thereafter, a fossil fuel-fired electric gener2 ating unit that, on or after January 1, 

3 1985, served a generator with a nameplate 

4 capacity greater than 25 megawatts pro5 ducing electricity for sale. 

6 ‘‘(B) EXCLUSION.—For purposes of sub7 paragraph (A)(ii), the term ‘affected unit’ does 

8 not include a unit that— 

9 ‘‘(i) cogenerates steam and electricity; 

10 but 

11 ‘‘(ii) is not a cogeneration unit. 

12 ‘‘(C) RELATED DEFINITIONS.—For pur13 poses of this paragraph, the terms ‘cogeneration 

14 unit’, ‘fossil fuel-fired’, and ‘unit’ have the 

15 meanings given the terms in section 701.’’; and 

16 (2) by striking paragraph (3) and inserting the 

17 following: 

18 ‘‘(3) ALLOWANCE.— 

19 ‘‘(A) IN GENERAL.—Notwithstanding any 

20 other provision of this title, the term ‘allowance’ 

21 or ‘sulfur dioxide allowance’ means— 

22 ‘‘(i) except as provided in clause (ii), 

23 an authorization allocated by the Adminis24 trator under this title to an affected unit 

25 to emit, during or after a specified calVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00063 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 endar year, a quantity of sulfur dioxide 

2 emissions equal to 1 ton of sulfur dioxide; 

3 and 

4 ‘‘(ii) with respect to a sulfur dioxide 

5 allowance allocated to a unit in a CAIR 

6 State for any of calendar years 2010 

7 through 2014, an authorization allocated 

8 by the Administrator under this title, or 

9 under CAIR, to a unit to emit, during or 

10 after the applicable calendar year, a quantity of sulfur dioxide emissions equal to 1 11 ⁄2

12 ton of sulfur dioxide. 

13 ‘‘(B) RELATED DEFINITIONS.—For pur14 poses of subparagraph (A), the terms ‘CAIR’ 

15 and ‘CAIR State’ have the meanings given the 

16 terms in section 701.’’. 

17 (c) COMPLIANCE.— 

18 (1) PROHIBITION.—Section 403(g) of the Clean 

19 Air Act (relating to acid deposition control) (42 

20 U.S.C. 7651b(g)) is amended by striking the second 

21 sentence and inserting the following: ‘‘It shall be un22 lawful for the affected units of any affected source 

23 to emit sulfur dioxide during a calendar year in ex24 cess of the tons of sulfur dioxide emissions author25 ized by the allowances held by the owner or operator 


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1 of the affected source for the affected source for the 

2 calendar year.’’. 

3 (2) PERMITS AND COMPLIANCE PLANS.—Sec4 tion 408 of the Clean Air Act (relating to acid depo5 sition control) (42 U.S.C. 7651g) is amended— 

6 (A) in subsection (a), by striking para7 graph (1) and inserting the following: 

8 ‘‘(1) annual emissions of sulfur dioxide in ex9 cess of the tons of sulfur dioxide emissions author10 ized by the allowances held by the owner or oper11 ator, or the designated representative of an owner or 

12 operator, of the affected source for the affected 

13 source for the calendar year,’’; and 

14 (B) in subsection (b), in the fourth sen15 tence, by striking ‘‘to emit not less than the 

16 total annual emissions of the unit’’ and insert17 ing ‘‘authorizing tons of emissions not less than 

18 the total annual emissions of the unit’’. 

19 (d) EXCESS EMISSIONS.—Section 411 of the Clean 

20 Air Act (relating to acid deposition control) (42 U.S.C. 

21 7651j) is amended by striking subsection (e) and inserting 

22 the following: 

23 ‘‘(e) EXCESS EMISSIONS OF SULFUR DIOXIDE.— 

24 ‘‘(1) PENALTY.— 


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1 ‘‘(A) IN GENERAL.—Notwithstanding sub2 sections (a), (b), and (c), the owner and oper3 ator of an affected source the affected units of 

4 which emit, during calendar year 2007 or any 

5 calendar year thereafter, sulfur dioxide in ex6 cess of the tons of sulfur dioxide emissions au7 thorized by the allowances held for use by the 

8 affected source for that calendar year shall off9 set, and pay an excess emissions penalty for, 

10 the excess emissions by surrendering to the Ad11 ministrator a quantity of sulfur dioxide allow12 ances for the following calendar year, or such 

13 earlier period as the Administrator may pre14 scribe, authorizing a number of tons of sulfur 

15 dioxide emissions equal to the product obtained 

16 by multiplying— 

17 ‘‘(i) subject to subparagraph (B), the 

18 number of tons of the excess emissions; 

19 and 

20 ‘‘(ii) 2. 

21 ‘‘(B) TREATMENT OF CERTAIN QUAN22 TITIES OF EMISSIONS.—For purposes of sub23 paragraph (A)(i), a quantity of excess emissions 

24 equal to less than 1 ton shall be considered to 


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1 be a quantity of excess emissions equal to 1 

2 ton. 

3 ‘‘(2) TREATMENT OF PENALTY.—An offset and 

4 penalty imposed under paragraph (1) shall be in lieu 

5 of any offset and penalty required under subsection 

6 (a), (b), or (c) with respect to sulfur dioxide emis7 sions. 

8 ‘‘(f) SAVINGS PROVISION.—Nothing in this section 

9 limits or otherwise affects the application of section 113, 

10 114, 120, or 304.’’. 

11 (e) TECHNICAL AMENDMENTS.— 

12 (1) Title IV of the Clean Air Act (relating to 

13 noise pollution) (42 U.S.C. 7641 et seq.)— 

14 (A) is amended by redesignating sections 

15 401 through 403 as sections 801 through 803, 

16 respectively; and 

17 (B) is redesignated as title VIII and moved 

18 to appear at the end of that Act. 

19 (2) The table of contents for title IV of the 

20 Clean Air Act (relating to acid deposition control) 

21 (42 U.S.C. prec. 7651) is amended by adding at the 

22 end the following: 

‘‘Sec. 417. Revisions to sulfur dioxide allowance program.’’. 

23 SEC. 105. AIR QUALITY FORECASTS AND WARNINGS. 

24 (a) REQUIREMENT FOR FORECASTS AND WARN25 INGS.—The Secretary of Commerce, acting through the 


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1 Administrator of the National Oceanic and Atmospheric 

2 Administration, in cooperation with the Administrator of 

3 the Environmental Protection Agency, shall issue air qual4 ity forecasts and air quality warnings as part of the mis5 sion of the Department of Commerce. 

6 (b) REGIONAL WARNINGS.—In carrying out sub7 section (a), the Secretary of Commerce shall establish 

8 within the National Oceanic and Atmospheric Administra9 tion a program to provide region-oriented forecasts and 

10 warnings regarding air quality for each of the following 

11 regions of the United States: 

12 (1) The Northeast, composed of Connecticut, 

13 Maine, Massachusetts, New Hampshire, New York, 

14 Rhode Island, and Vermont. 

15 (2) The Mid-Atlantic, composed of Delaware, 

16 the District of Columbia, Maryland, New Jersey, 

17 Pennsylvania, Virginia, and West Virginia. 

18 (3) The Southeast, composed of Alabama, Flor19 ida, Georgia, North Carolina, and South Carolina. 

20 (4) The South, composed of Arkansas, Lou21 isiana, Mississippi, Oklahoma, Tennessee, and 

22 Texas. 

23 (5) The Midwest, composed of Illinois, Indiana, 

24 Iowa, Kentucky, Michigan, Minnesota, Missouri, 

25 Ohio, and Wisconsin. 


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1 (6) The High Plains, composed of Kansas, Ne2 braska, North Dakota, and South Dakota. 

3 (7) The Northwest, composed of Idaho, Mon4 tana, Oregon, Washington, and Wyoming. 

5 (8) The Southwest, composed of Arizona, Cali6 fornia, Colorado, New Mexico, Nevada, and Utah. 

7 (9) Alaska. 

8 (10) Hawaii. 

9 (c) PRIORITY AREA.—In establishing the program 

10 described in subsection (a), the Secretary of Commerce 

11 and the Administrator shall identify and expand, to the 

12 maximum extent practicable, Federal air quality forecast 

13 and warning programs in effect as of the date of establish14 ment of the program. 

15 (d) AUTHORIZATION OF APPROPRIATIONS.—There 

16 are authorized to be appropriated such sums as are nec17 essary to carry out this section. 

18 SEC. 106. RELATIONSHIP TO OTHER LAW. 

19 (a) REGULATION OF HAZARDOUS AIR POLLUT20 ANTS.—Section 112(n)(1) of the Clean Air Act (42 U.S.C. 

21 7412(n)(1)) is amended by striking subparagraph (A) and 

22 inserting the following: 

23 ‘‘(A) REGULATIONS.— 

24 ‘‘(i) IN GENERAL.—Not later than 18 

25 months after the date of enactment of the 


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1 Clean Air/Climate Change Act of 2007, the 

2 Administrator shall promulgate regulations 

3 under this section limiting the emission 

4 from electric utility steam generating units 

5 of hazardous air pollutants, other than 

6 mercury, as the Administrator determines 

7 to be appropriate and necessary in accord8 ance with the standards under this section, 

9 including subsections (b)(2) and (f). 

10 ‘‘(ii) REQUIREMENTS.—The regula11 tions under clause (i) shall— 

12 ‘‘(I) require compliance with ap13 plicable standards as expeditiously as 

14 practicable, but not later than 3 years 

15 after the effective date of the regula16 tions; and 

17 ‘‘(II) be in accordance with other 

18 applicable requirements under this 

19 section. 

20 ‘‘(iii) EFFECTIVE DATE.—The regula21 tions under clause (i) shall be effective on 

22 the date of promulgation of the regula23 tions.’’. 


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1 (b) SAFE DRINKING WATER ACT.—Section 1412(b) 

2 of the Safe Drinking Water Act (42 U.S.C. 300g–1(b)) 

3 is amended by adding at the end the following: 

4 ‘‘(16) CARBON DIOXIDE.—Not later than 2 

5 years after the date of enactment of the Clean Air/ 

6 Climate Change Act of 2007, the Administrator 

7 shall promulgate regulations establishing standards 

8 for underground injection of carbon dioxide in a 

9 manner that protects human health and the environ10 ment.’’. 

11 (c) NO EFFECT ON OTHER FEDERAL AND STATE

12 REQUIREMENTS.—Except as otherwise specifically pro13 vided in this Act, nothing in this Act or an amendment 

14 made by this Act— 

15 (1) affects any permitting, monitoring, or en16 forcement obligation of the Administrator of the En17 vironmental Protection Agency under the Clean Air 

18 Act (42 U.S.C. 7401 et seq.) or any remedy pro19 vided under that Act; 

20 (2) affects any requirement applicable to, or li21 ability of, an electric generating unit under that Act; 

22 (3) requires a change in, affects, or limits any 

23 State law that regulates electric utility rates or 

24 charges, including prudence review under State law; 

25 or 


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1 (4) precludes a State or political subdivision of 

2 a State from adopting and enforcing any require3 ment for the control or abatement of air pollution, 

4 except that a State or political subdivision may not 

5 adopt or enforce any emission standard or limitation 

6 that is less stringent than the requirements imposed 

7 under that Act. 

8 TITLE II—GREENHOUSE GAS 

9 OFFSETS 

10 SEC. 201. GREENHOUSE GAS OFFSETS. 

11 The Clean Air Act (42 U.S.C. 7401 et seq.) (as 

12 amended by section 101) is amended by adding at the end 

13 the following: 

14 ‘‘TITLE VIII—GREENHOUSE GAS 

15 OFFSETS 

‘‘TITLE VIII—GREENHOUSE GAS OFFSETS 

‘‘Sec. 801. Definitions. 

‘‘Sec. 802. General requirements. 

‘‘Sec. 803. Standards for offset allowances. 

16 ‘‘SEC. 801. DEFINITIONS. 

17 ‘‘In this title: 

18 ‘‘(1) ALLOWANCE.—The term ‘allowance’ 

19 means— 

20 ‘‘(A) a carbon dioxide allowance, as defined 

21 in section 701; and 

22 ‘‘(B) an offset allowance. 

23 ‘‘(2) ANAEROBIC DIGESTER.— 


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1 ‘‘(A) IN GENERAL.—The term ‘anaerobic 

2 digester’ means a device that promotes the de3 composition of organic material to simple or4 ganic and gaseous biogas products, usually by 

5 collecting the material under controlled tem6 perature and volume. 

7 ‘‘(B) INCLUSION.—The term ‘anaerobic di8 gester’ includes a biogas recovery system. 

9 ‘‘(3) ANAEROBIC STORAGE.—The term ‘anaer10 obic storage’ means storage of organic material in 

11 an oxygen-free environment or under oxygen-free 

12 conditions, including by using holding tanks, ponds, 

13 or lagoons. 

14 ‘‘(4) ANSI.—The term ‘ANSI’ means the 

15 American National Standards Institute. 

16 ‘‘(5) ASHRAE.—The term ‘ASHRAE’ means 

17 the American Society of Heating, Refrigerating and 

18 Air Conditioning Engineers. 

19 ‘‘(6) BIOGAS.—The term ‘biogas’ means a 

20 gas— 

21 ‘‘(A) the principal components of which are 

22 methane and carbon dioxide; and 

23 ‘‘(B) that results from the decomposition 

24 of organic matter under anaerobic conditions. 


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1 ‘‘(7) BOILER.—The term ‘boiler’ means a self2 contained, low-pressure appliance for supplying heat 

3 in the form of steam or hot water to a residential 

4 building or commercial building. 

5 ‘‘(8) COMMERCIAL BUILDING.—The term ‘com6 mercial building’ means a building to which ANSI/ 

7 ASHRAE/IESNA Standard 90.1 applies. 

8 ‘‘(9) ELIGIBLE BIOMASS.—The term ‘eligible 

9 biomass’ includes sustainable harvested woody or 

10 herbaceous fuel sources that are available on a re11 newable or recurring basis (excluding old-growth 

12 timber), as determined by the Administrator, includ13 ing— 

14 ‘‘(A) dedicated energy crops and trees; 

15 ‘‘(B) agricultural food and feed crop resi16 dues; 

17 ‘‘(C) aquatic plants; 

18 ‘‘(D) unadulterated wood and wood resi19 dues; 

20 ‘‘(E) animal wastes; 

21 ‘‘(F) other clean organic wastes not mixed 

22 with other solid wastes; 

23 ‘‘(G) biogas; and 


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1 ‘‘(H) other neat liquid biofuels derived 

2 from any fuel source described in subpara3 graphs (A) through (G). 

4 ‘‘(10) ENERGY CONSERVATION MEASURE.—The 

5 term ‘energy conservation measure’ means an activ6 ity the purpose of which is to increase the energy ef7 ficiency of a building or to improve the management 

8 of energy demand, including through— 

9 ‘‘(A) physical changes to equipment; 

10 ‘‘(B) modifications to the building; 

11 ‘‘(C) revisions of operating and mainte12 nance procedures; 

13 ‘‘(D) software changes; and 

14 ‘‘(E) new methods of training or managing 

15 users of the building or operations and mainte16 nance staff. 

17 ‘‘(11) ENERGY PERFORMANCE.—The term ‘en18 ergy performance’ means the relative energy effi19 ciency of a building, building equipment, or building 

20 component, measured based on— 

21 ‘‘(A) for a building, the quantity of energy 

22 required to provide building services; and 

23 ‘‘(B) for building equipment and compo24 nents, the impact of equipment or components 

25 on energy usage. 


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1 ‘‘(12) FORESTED CONDITION.—The term ‘for2 ested condition’, with respect to land, means land— 

3 ‘‘(A) the area of which is at least 1 acre, 

4 with strips of forest at least 120 feet wide, 

5 measured stem-to-stem from the outer-most 

6 edge, for a continuous length of at least 363 

7 feet; and 

8 ‘‘(B)(i) at least 10 percent of the area of 

9 which is stocked by trees of any size, or has 

10 been at least 10-percent stocked by trees at any 

11 time, and that is not subject to any nonforest12 related use that prevents normal tree regenera13 tion and succession, such as regular mowing, 

14 intensive grazing, or recreation activities; or 

15 ‘‘(ii) for any western woodland species for 

16 which the stocking described in clause (i) can17 not be determined, at least 5 percent of which 

18 has a crown cover of trees of any size, or has 

19 had at least 5-percent cover at any time, and 

20 that is not subject to any nonforest-related use 

21 that prevents normal tree regeneration and suc22 cession, such as regular mowing, intensive graz23 ing, or recreation activities. 

24 ‘‘(13) FURNACE.—The term ‘furnace’ means a 

25 self-contained, indirect-fired appliance that— 


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1 ‘‘(A) supplies heated air to a residential 

2 building or commercial building through ducts 

3 to conditioned spaces; and 

4 ‘‘(B) has a heat input rate of less than 

5 225,000 Btu per hour. 

6 ‘‘(14) HVAC SYSTEM.— 

7 ‘‘(A) IN GENERAL.—The term ‘HVAC sys8 tem’ means any system or combination of sys9 tems that provides, collectively or individually, 

10 heating, ventilation, or air conditioning to a 

11 building. 

12 ‘‘(B) INCLUSIONS.—The term ‘HVAC sys13 tem’ includes equipment, distribution networks, 

14 and terminals for a system described in sub15 paragraph (A). 

16 ‘‘(15) IESNA.—The term ‘IESNA’ means the 

17 Illuminating Engineering Society of North America. 

18 ‘‘(16) MARKET PENETRATION RATE.—The term 

19 ‘market penetration rate’ means, as determined by 

20 the Administrator, the rate of diffusion of a tech21 nology, product, or practice in a defined market, ex22 pressed as— 

23 ‘‘(A) a percentage of annual sales of the 

24 technology, product, or practice; or 


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1 ‘‘(B) a percentage of existing installed 

2 stock— 

3 ‘‘(i) for a product or category of prod4 ucts; or 

5 ‘‘(ii) that uses a technology, product, 

6 or practice. 

7 ‘‘(17) OFFSET ALLOWANCE.—The term ‘offset 

8 allowance’ means an allowance awarded under this 

9 title for— 

10 ‘‘(A) each sequestration of, reduction in, or 

11 prevention of, 1 ton of carbon dioxide or carbon 

12 dioxide-equivalent emissions, as determined by 

13 the Administrator; or 

14 ‘‘(B) an eligible emission credit retirement 

15 under section 802(a). 

16 ‘‘(18) OFFSET PROJECT.—The term ‘offset 

17 project’ means a project that— 

18 ‘‘(A) provides for a reduction in green19 house gases or greenhouse gas emissions 

20 through— 

21 ‘‘(i) the capture and destruction of 

22 methane from a landfill; 

23 ‘‘(ii) a reduction in emissions of sulfur 

24 hexafluoride; 


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1 ‘‘(iii) the sequestration of carbon 

2 through afforestation; 

3 ‘‘(iv) a reduction or avoidance of car4 bon dioxide emissions from natural gas, oil, 

5 or propane end-use combustion through 

6 end-use energy efficiency; or 

7 ‘‘(v) the prevention of methane emis8 sions through the use of agricultural ma9 nure management operations; 

10 ‘‘(B) is carried out in any State or other 

11 United States jurisdiction pursuant to a memo12 randum of understanding between the project 

13 sponsor and the Administrator; and 

14 ‘‘(C) begins operation on or after the date 

15 of enactment of this title. 

16 ‘‘(19) RESIDENTIAL BUILDING.—The term ‘res17 idential building’ means a low-rise building (includ18 ing a single family home, a multifamily structure of 

19 3 stories or less above grade, and a manufactured 

20 modular or mobile home) to which ANSI/ASHRAE/ 

21 IESNA Standard 90.1 does not apply. 

22 ‘‘(20) RESNET.—The term ‘RESNET’ means 

23 the Residential Energy Services Network. 


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1 ‘‘(21) SF6-CONTAINING OPERATING EQUIP2 MENT.—The term ‘SF6-containing operating equip3 ment’ means any equipment that— 

4 ‘‘(A) is used for the transmission or dis5 tribution of electricity; and 

6 ‘‘(B) contains sulfur hexafluoride. 

7 ‘‘(22) TOTAL SOLIDS.—The term ‘total solids’ 

8 means the content of solid materials in a given sam9 ple, including suspended solids, dissolved solids, and 

10 suspended volatile solids. 

11 ‘‘(23) TRANSMISSION OR DISTRIBUTION ENTI12 TY.— 

13 ‘‘(A) IN GENERAL.—The term ‘trans14 mission or distribution entity’ means an entity 

15 that transmits or distributes electricity from an 

16 electric generator to the electrical load of a cus17 tomer. 

18 ‘‘(B) INCLUSIONS.—The term ‘trans19 mission or distribution entity’ includes all re20 lated assets and equipment of an entity de21 scribed in subparagraph (A) that are located 

22 within the service area of the entity, as defined 

23 by the applicable State regulatory agency. 

24 ‘‘(24) VERIFICATION.—The term ‘verification’ 

25 means any activity conducted by a project sponsor to 


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1 ensure the adequacy and consistency of a component 

2 of an offset project, including monitoring and re3 porting to the Administrator on any violation of this 

4 title. 

5 ‘‘(25) UNFCCC.—The term ‘UNFCCC’ means 

6 the United Nations Framework Convention on Cli7 mate Change, done at New York on May 9, 1992. 

8 ‘‘(26) VOLATILE SOLIDS.—The term ‘volatile 

9 solids’ means the fraction of total solids of a given 

10 sample that is comprised primarily of organic mat11 ter. 

12 ‘‘SEC. 802. GENERAL REQUIREMENTS. 

13 ‘‘(a) ELIGIBLE CARBON DIOXIDE EMISSION OFFSET

14 PROJECTS AND ELIGIBLE EMISSION CREDIT RETIRE15 MENTS.—Subject to subsection (c) and in accordance with 

16 the calculations and other requirements of section 803, the 

17 Administrator may award offset allowances to the sponsor 

18 of any offset project or eligible emission credit retirement 

19 if the sponsor has met all applicable requirements of this 

20 title. 

21 ‘‘(b) PROJECT SPONSOR.—Any person may act as the 

22 sponsor of an offset project or eligible emission credit re23 tirement if the person meets all the requirements estab24 lished by the Administrator. 


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1 ‘‘(c) REQUIREMENTS FOR THE AWARD OF OFFSET

2 ALLOWANCES.—Except as provided in section 803, with 

3 respect to the awarding of offset allowances under this sec4 tion— 

5 ‘‘(1) an offset allowance may not be awarded 

6 for an offset project that is required to be carried 

7 out pursuant to any Federal, State, or local law (in8 cluding a regulation), other than this Act, or admin9 istrative or judicial order; 

10 ‘‘(2) offset allowances shall not be awarded to 

11 an offset project that includes an electric generation 

12 component; and 

13 ‘‘(3) an offset allowance shall not be awarded to 

14 an offset project that is awarded credits or allow15 ances under any other mandatory or voluntary 

16 greenhouse gas program, as determined by the Ad17 ministrator. 

18 ‘‘(d) OFFSET PROJECT AUDIT.—The sponsor of an 

19 offset project shall provide to the Administrator (or a des20 ignee) access to the physical location at which the offset 

21 project is carried out to ensure compliance with this title. 

22 ‘‘(e) INELIGIBILITY BECAUSE OF NONCOMPLI23 ANCE.—If the Administrator determines that an offset 

24 project or sponsor of an offset project has not complied, 


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1 or is not in compliance, with this title, the Administrator 

2 may— 

3 ‘‘(1) revoke and retire any offset allowances in 

4 the account of the sponsor of the offset project; and 

5 ‘‘(2) revoke any other approvals issued by the 

6 Administrator with respect to the offset project. 

7 ‘‘(f) REGULATIONS.— 

8 ‘‘(1) IN GENERAL.—Not later than 2 years 

9 after the date of enactment of this title, the Admin10 istrator shall promulgate regulations to carry out 

11 this title. 

12 ‘‘(2) INTERACTION WITH DEPARTMENT OF AG13 RICULTURE.— 

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

15 subparagraph (B), the Administrator shall pro16 mulgate all regulations relating to greenhouse 

17 gas offsets under this title. 

18 ‘‘(B) OFFSETS.—The Administrator, in 

19 consultation with the Secretary of Agriculture, 

20 shall promulgate regulations, in accordance 

21 with the requirements of this title, relating to 

22 greenhouse gas offsets produced by agricultural 

23 sequestration practices. 

24 ‘‘(3) ADDITIONAL PROJECT TYPES.—In promul25 gating regulations pursuant to this subsection, the 


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1 Administrator shall establish requirements, in ac2 cordance with the requirements of this title, relating 

3 to types of greenhouse gas offset projects not other4 wise addressed under this title. 

5 ‘‘SEC. 803. STANDARDS FOR OFFSET ALLOWANCES. 

6 ‘‘(a) LANDFILL METHANE CAPTURE AND DESTRUC7 TION OFFSET PROJECTS.— 

8 ‘‘(1) IN GENERAL.—An offset project for the 

9 capture and destruction of methane shall be eligible 

10 to receive allowances under this title if the offset 

11 project— 

12 ‘‘(A) captures and destroys methane from 

13 a landfill that is not subject to— 

14 ‘‘(i) the regulations entitled ‘Stand15 ards of Performance for New Stationary 

16 Sources; Municipal Solid Waste Landfills’ 

17 under subpart www of part 60 of title 40, 

18 Code of Federal Regulations (or successor 

19 regulations); or 

20 ‘‘(ii) any other relevant Federal regu21 lations, including emissions guidelines for 

22 municipal solid waste landfills under— 

23 ‘‘(I) subpart cc of part 60 of that 

24 title; or 


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1 ‘‘(II) subpart aaaa of part 63 of 

2 that title; and 

3 ‘‘(B) meets the requirements of this sub4 section. 

5 ‘‘(2) REQUIREMENT.—To be eligible to receive 

6 an allowance under this subsection, an offset project 

7 described in paragraph (1) shall use a landfill gas 

8 collection system that provides for continuous meter9 ing and data computation of— 

10 ‘‘(A) the landfill gas volumetric flow rate; 

11 and 

12 ‘‘(B) methane concentration. 

13 ‘‘(3) EMISSIONS CALCULATIONS.— 

14 ‘‘(A) EMISSIONS BASELINE.— 

15 ‘‘(i) IN GENERAL.—The emissions 

16 baseline of an offset project that receives 

17 allowances under this subsection shall be 

18 the potential fugitive landfill emissions of 

19 methane (measured in tons of carbon diox20 ide equivalent), as calculated based on the 

21 quantity of methane collected and metered 

22 for thermal destruction as part of the off23 set project in accordance with the following 

24 formula: Emissions (tons of carbon dioxide 


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1 equivalent) = (V × M × (1–OX) × GWP)/ 

2 2000. 

3 ‘‘(ii) ABBREVIATIONS.—In the for4 mula contained in clause (i)— 

5 ‘‘(I) ‘V’ represents the volume of 

6 methane collected (expressed in cubic 

7 feet); 

8 ‘‘(II) ‘M’ represents the mass of 

9 methane per cubic foot (with a default 

10 value of 0.04246 pounds per cubic 

11 foot at 1 atmosphere and 20 °C); 

12 ‘‘(III) ‘OX’ represents the oxida13 tion factor, which is the estimated 

14 portion of collected methane that 

15 would have oxidized to carbon dioxide 

16 if not collected (with a default value 

17 of 0.10); and 

18 ‘‘(IV) ‘GWP’ represents the car19 bon dioxide-equivalent global warming 

20 potential of methane (with a default 

21 value of 23). 

22 ‘‘(B) EMISSIONS REDUCTIONS.— 

23 ‘‘(i) IN GENERAL.—The emissions re24 ductions of an offset project under this 

25 subsection shall be the potential fugitive 


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1 landfill emissions of methane (measured in 

2 tons of carbon dioxide equivalent) that 

3 would have occurred if metered methane 

4 collected from the landfill for thermal de5 struction as part of the offset project was 

6 not collected and destroyed, as calculated 

7 in accordance with the following formula: 

8 Emissions reductions (tons of carbon diox9 ide equivalent) = (V × M × (1–OX) × Cef

10 × GWP)/2000. 

11 ‘‘(ii) ABBREVIATIONS.—In the for12 mula contained in clause (i)— 

13 ‘‘(I) ‘V’ represents the volume of 

14 methane collected (expressed in cubic 

15 feet); 

16 ‘‘(II) ‘M’ represents the mass of 

17 methane pre cubic foot (with a default 

18 value of 0.04246 pounds per cubic 

19 foot at 1 atmosphere and 20 °C); 

20 ‘‘(III) ‘OX’ represents the oxida21 tion factor, which is the estimated 

22 portion of collected methane that 

23 would have oxidized to carbon dioxide 

24 if not collected (with a default value 

25 of 0.10); 


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1 ‘‘(IV) ‘Cef’ represents the com2 bustion efficiency of methane control 

3 technology (with a default value of 

4 0.98); and 

5 ‘‘(V) ‘GWP’ represents the car6 bon dioxide-equivalent global warming 

7 potential of methane (with a default 

8 value of 23). 

9 ‘‘(4) MONITORING AND VERIFICATION.—Not 

10 less frequently than once each year, the sponsor of 

11 an offset project that receives an allowance under 

12 this subsection shall submit to the Administrator a 

13 monitoring and verification report, including— 

14 ‘‘(A) data relating to monthly volumetric 

15 flow rate and methane concentration of the off16 set project, including documentation that the 

17 methane was actually supplied to an applicable 

18 combustion source; and 

19 ‘‘(B) verification of landfill gas methane 

20 composition through landfill gas sampling and 

21 independent laboratory analysis using applicable 

22 laboratory test methods of the Environmental 

23 Protection Agency. 

24 ‘‘(b) SULFUR HEXAFLUORIDE OFFSET PROJECTS.— 


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1 ‘‘(1) IN GENERAL.—An offset project to pre2 vent, through capture and storage, recycling, or de3 struction, the emission into the atmosphere of sulfur 

4 hexafluoride from equipment in the electricity trans5 mission and distribution sector shall be eligible to re6 ceive allowances under this title. 

7 ‘‘(2) REQUIREMENTS.— 

8 ‘‘(A) IN GENERAL.—To be eligible to re9 ceive an allowance under this subsection, an off10 set project described in paragraph (1) shall in11 clude incremental action beyond action taken 

12 with respect to the offset project during the cal13 endar year preceding the year in which an ap14 plication is submitted (referred to in this sub15 section as the ‘baseline year’) to achieve a re16 duction in sulfur hexafluoride emissions, in ac17 cordance with the guidance under— 

18 ‘‘(i) the International Electrotechnical 

19 Commission document numbered 1634 and 

20 entitled ‘High-voltage switchgear and con21 trol gear—Use and handling of sulfur 

22 hexafluoride (SF6) in high-voltage 

23 switchgear and control gear’ (CEI/IEC 

24 1634, 1995–04); and 


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1 ‘‘(ii) the Electric Power Research In2 stitute document entitled ‘Practical Guide 

3 to SF6 Handling Practices’ (TR–113933, 

4 2002). 

5 ‘‘(B) ENTITY-WIDE EMISSIONS RATES.— 

6 ‘‘(i) CALCULATION.— 

7 ‘‘(I) IN GENERAL.—The entity8 wide sulfur hexafluoride emissions 

9 rate of an offset project, measured as 

10 a percentage, shall be calculated in ac11 cordance with the following formula: 

12 SF6 emissions rate (%) = (total SF6

13 emissions for reporting year)/(total 

14 SF6 nameplate capacity at end of re15 porting year). 

16 ‘‘(II) DESCRIPTION.—In the for17 mula contained in subclause (I), ‘SF6

18 nameplate capacity’ means the capac19 ity of all SF6-containing operating 

20 equipment owned or operated as part 

21 of the offset project, measured at the 

22 full and proper SF6-charge of that 

23 equipment, rather than the actual 

24 charge of the equipment, which may 

25 reflect leakage. 


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1 ‘‘(ii) REQUIREMENT.— 

2 ‘‘(I) IN GENERAL.—Subject to 

3 subclauses (II) and (III) and except 

4 as provided in clause (iii), to be eligi5 ble to receive allowances under this 

6 subsection, the entity-wide emissions 

7 rate for the baseline year of an offset 

8 project shall be lower than the appli9 cable emissions rate contained in the 

10 following table: 

‘‘Emissions Rates by Region 

A ............................................................................. 9.68% 

B ............................................................................. 5.22% 

C ............................................................................. 9.68% 

D ............................................................................. 5.77% 

E ............................................................................. 3.65% 

National .................................................................. 9.68% 

11 ‘‘(II) ADJUSTMENT.— 

12 ‘‘(aa) FINDING.—Congress 

13 finds that the emissions rates 

14 contained in the table under sub15 clause (I) are based on weighted 

16 average emissions rates for cal17 endar year 2004 for the Environ18 mental Protection Agency sulfur 

19 hexafluoride partnership utilities 

20 in each region. 


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1 ‘‘(bb) DETERMINATION.—If 

2 the Administrator determines 

3 that an emissions rate contained 

4 in the table under subclause (I) 

5 for any region is in error and is 

6 higher than the national weighted 

7 average emissions rate, the na8 tional emissions rate contained in 

9 that table shall apply with re10 spect to the region. 

11 ‘‘(III) REGION DESCRIPTIONS.— 

12 For purposes of the table under in 

13 subclause (I)— 

14 ‘‘(aa) Region A is comprised 

15 of the States of Connecticut, 

16 Delaware, Maine, Massachusetts, 

17 New Jersey, New York, New 

18 Hampshire, Pennsylvania, Rhode 

19 Island, and Vermont; 

20 ‘‘(bb) Region B is comprised 

21 of the States of Alabama, Flor22 ida, Georgia, Kentucky, Mary23 land, Mississippi, North Carolina, 

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1 ginia, West Virginia, and the 

2 District of Columbia; 

3 ‘‘(cc) Region C is comprised 

4 of the States of Colorado, Illi5 nois, Indiana, Michigan, Min6 nesota, Montana, North Dakota, 

7 Ohio, South Dakota, Utah, Wis8 consin, and Wyoming; 

9 ‘‘(dd) Region D is comprised 

10 of the States of Arkansas, Iowa, 

11 Kansas, Louisiana, Missouri, Ne12 braska, New Mexico, Oklahoma, 

13 and Texas; and 

14 ‘‘(ee) Region E is comprised 

15 of the States of Alaska, Arizona, 

16 California, Hawaii, Idaho, Ne17 vada, Oregon, and Washington. 

18 ‘‘(iii) EXCEPTION.—Notwithstanding 

19 clause (ii), an offset project shall be eligi20 ble to receive allowances under this sub21 section regardless of the entity-wide emis22 sions rate for the baseline year of the off23 set project if the sponsor of the offset 

24 project demonstrates to the satisfaction of 


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1 the Administrator that each of the fol2 lowing conditions is met: 

3 ‘‘(I) The offset project is being 

4 carried out at a transmission or dis5 tribution entity the service area of 

6 which is predominantly urban. 

7 ‘‘(II) The optimal management of 

8 sulfur hexafluoride is prevented by at 

9 least 2 of the following factors: 

10 ‘‘(aa) The transmission or 

11 distribution entity for which the 

12 offset project is being carried out 

13 is comprised of older-than-aver14 age installed transmission or dis15 tribution equipment compared to 

16 the national average age of the 

17 equipment. 

18 ‘‘(bb) A majority of the elec19 tricity load of the transmission or 

20 distribution entity for which the 

21 offset project is being carried out 

22 is served by equipment that is lo23 cated underground, precluding 

24 management of sulfur 


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1 hexafluoride emissions through 

2 regular ongoing maintenance. 

3 ‘‘(cc) The transmission or 

4 distribution entity for which the 

5 offset project is being carried out 

6 is unable to remove a substantial 

7 portion of equipment from service 

8 because doing so would impair 

9 system reliability. 

10 ‘‘(dd) The required equip11 ment purpose or design for a 

12 substantial portion of the equip13 ment of the transmission or dis14 tribution entity for which the off15 set project is being carried out 

16 results in inherently leak-prone 

17 equipment. 

18 ‘‘(3) EMISSIONS CALCULATIONS.— 

19 ‘‘(A) IN GENERAL.—To be eligible to re20 ceive allowances under this subsection, the 

21 sponsor of an offset project shall submit to the 

22 Administrator an annual report describing the 

23 sulfur hexafluoride emissions of the offset 

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1 propriate), calculated in accordance with this 

2 paragraph. 

3 ‘‘(B) DETERMINATION OF BASELINE EMIS4 SIONS.— 

5 ‘‘(i) IN GENERAL.—The baseline sul6 fur hexafluoride emissions of an offset 

7 project that receives an allowance under 

8 this subsection shall be determined based 

9 on the sulfur hexafluoride emissions emit10 ted by the transmission or distribution en11 tity for the baseline year of the offset 

12 project. 

13 ‘‘(ii) LIMITATION.—The baseline year 

14 for an offset project an application of 

15 which is submitted before January 1, 

16 2009, shall be not earlier than 2005. 

17 ‘‘(iii) MONITORING.—The sponsor of 

18 an offset project that receives an allowance 

19 under this subsection shall systematically 

20 track and account for all uses of sulfur 

21 hexafluoride by the transmission or dis22 tribution entity for which the offset project 

23 is being carried out to determine entity24 wide emissions of sulfur hexafluoride, in25 cluding monitoring all electric transmission 


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1 and distribution assets and all SF6-con2 taining operating equipment owned or op3 erated by the transmission or distribution 

4 entity. 

5 ‘‘(C) MASS BALANCE METHOD.— 

6 ‘‘(i) IN GENERAL.—For purposes of 

7 this paragraph, the sulfur hexafluoride 

8 emissions of an offset project for a cal9 endar year shall be determined based on 

10 the following mass balance formula: SF6

11 emissions (lbs) = (SF6 change in inven12 tory) + (SF6 purchases and acquisitions) 

13 – (SF6 sales and disbursements) – (change 

14 in total SF6 nameplate capacity of equip15 ment). 

16 ‘‘(ii) DESCRIPTION.—In the formula 

17 contained in clause (i)— 

18 ‘‘(I) ‘SF6 change in inventory’ 

19 means the difference between, with re20 spect to the applicable offset project— 

21 ‘‘(aa) the quantity of sulfur 

22 hexafluoride gas in storage (in23 cluding gas held in cylinders and 

24 gas carts, but not including gas 

25 held in SF6-containing operating 


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1 equipment) on January 1 of the 

2 applicable calendar year; and 

3 ‘‘(bb) the quantity of sulfur 

4 hexafluoride gas in storage on 

5 December 31 of the applicable 

6 calendar year; 

7 ‘‘(II) ‘SF6 purchases and acquisi8 tions’ means the total quantity of sul9 fur hexafluoride gas acquired from 

10 other entities during the applicable 

11 calendar year, as contained in storage 

12 containers or SF6-containing oper13 ating equipment; 

14 ‘‘(III) ‘SF6 sales and disburse15 ments’ means the total quantity of 

16 sulfur hexafluoride gas sold or other17 wise distributed to other entities dur18 ing the applicable calendar year, as 

19 contained in storage containers or 

20 SF6-containing operating equipment; 

21 and 

22 ‘‘(IV) ‘change in total SF6 name23 plate capacity of equipment’ (meas24 ured at the full and proper SF6- 

25 charge of that equipment, rather than 


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1 the actual charge of the equipment, 

2 which may reflect leakage), means the 

3 net change in the total volume of SF6- 

4 containing operating equipment dur5 ing the applicable calendar year, equal 

6 to the difference between— 

7 ‘‘(aa) the total volume of 

8 SF6-containing operating equip9 ment obtained during the appli10 cable calendar year; and 

11 ‘‘(bb) the total volume of 

12 SF6-containing operating equip13 ment retired during the applica14 ble calendar year. 

15 ‘‘(D) EMISSIONS.— 

16 ‘‘(i) IN GENERAL.—The sulfur 

17 hexafluoride emissions of an offset project 

18 for a calendar year shall be calculated in 

19 accordance with the following formula: 

20 Emissions (tons of carbon dioxide equiva21 lent) = [(Viby – Viey) + (PApsd + PAe + 

22 PArre) – (SDop + SDrs + SDdf + SDsor) 

23 – (CNPne – CNPrse)] × GWP/2000. 

24 ‘‘(ii) DESCRIPTION.—In the formula 

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1 fur hexafluoride value shall be expressed in 

2 pounds— 

3 ‘‘(I) ‘Viby’ represents the sulfur 

4 hexafluoride inventory of the offset 

5 project in cylinders, gas carts, and 

6 other storage containers (not includ7 ing SF6-containing operating equip8 ment) on January 1 of the applicable 

9 calendar year; 

10 ‘‘(II) ‘Viey’ represents the sulfur 

11 hexafluoride inventory of the offset 

12 project in cylinders, gas carts, and 

13 other storage containers (not includ14 ing SF6-containing operating equip15 ment) on December 31 of the applica16 ble calendar year; 

17 ‘‘(III) ‘PApsd’ represents the 

18 quantity of sulfur hexafluoride pur19 chased from suppliers and distributors 

20 in cylinders for the offset project dur21 ing the applicable calendar year; 

22 ‘‘(IV) ‘PAe’ represents the quan23 tity of sulfur hexafluoride provided by 

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1 taining operating equipment during 

2 the applicable calendar year; 

3 ‘‘(V) ‘PArre’ represents the quan4 tity of sulfur hexafluoride returned to 

5 the offset project entity after off-site 

6 recycling during the applicable cal7 endar year; 

8 ‘‘(VI) ‘SDop’ represents sales of 

9 sulfur hexafluoride by the offset 

10 project to other entities during the ap11 plicable calendar year, including 

12 through sulfur hexafluoride gas re13 maining in SF6-containing operating 

14 equipment sold by the offset project; 

15 ‘‘(VII) ‘SDrs’ represents the 

16 quantity of sulfur hexafluoride re17 turned by the offset project to the 

18 supplier during the applicable cal19 endar year; 

20 ‘‘(VIII) ‘SDdf’ represents the 

21 quantity of sulfur hexafluoride sent by 

22 the offset project to destruction facili23 ties during the applicable calendar 

24 year; 


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1 ‘‘(IX) ‘SDsor’ represents the 

2 quantity of sulfur hexafluoride sent 

3 off-site for recycling by the offset 

4 project during the applicable calendar 

5 year; 

6 ‘‘(X) ‘CNPne’ represents the total 

7 sulfur hexafluoride nameplate capacity 

8 (measured at full and proper charge) 

9 of SF6-containing operating equip10 ment of the offset project acquired 

11 during the applicable calendar year; 

12 ‘‘(XI) ‘CNPrse’ represents the 

13 total sulfur hexafluoride nameplate 

14 capacity (measured at full and proper 

15 charge) of SF6-containing operating 

16 equipment retired or sold by the offset 

17 project during the applicable calendar 

18 year; and 

19 ‘‘(XII) ‘GWP’ represents the car20 bon dioxide equivalent global warming 

21 potential of sulfur hexafluoride (the 

22 default value of which is 22,200). 

23 ‘‘(E) EMISSIONS REDUCTIONS.— 

24 ‘‘(i) IN GENERAL.—The emissions re25 duction of an offset project for a calendar 


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1 year shall be determined in accordance 

2 with the following formula: Emissions re3 duction (tons of carbon dioxide equivalent) 

4 = (total pounds of SF6 emissions in base5 line year) – (total pounds of SF6 emissions 

6 in reporting year) × GWP/2000. 

7 ‘‘(ii) DESCRIPTION.—For purposes of 

8 the formula contained in clause (i)— 

9 ‘‘(I) each value shall be deter10 mined in accordance with the calcula11 tions described in this paragraph; and 

12 ‘‘(II) ‘GWP’ represents the car13 bon dioxide equivalent global warming 

14 potential of sulfur hexafluoride (the 

15 default value of which is 22,200). 

16 ‘‘(4) MONITORING AND VERIFICATION.— 

17 ‘‘(A) IN GENERAL.—Not less frequently 

18 than once each year, the sponsor of an offset 

19 project that receives an allowance under this 

20 subsection shall submit to the Administrator a 

21 monitoring and verification report that in22 cludes— 

23 ‘‘(i) the information and documenta24 tion described in paragraph (3)(A); 


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1 ‘‘(ii) an identification of each facility 

2 managed by the transmission or distribu3 tion entity for which the offset project is 

4 being carried out from which sulfur 

5 hexafluoride gas is acquired or disbursed, 

6 including— 

7 ‘‘(I) a log of each such acquisi8 tion or dispersal describing— 

9 ‘‘(aa) the weight of each cyl10 inder transported before ship11 ment from the facility; and 

12 ‘‘(bb) the weight of each cyl13 inder after return to the facility; 

14 and 

15 ‘‘(II) a cylinder-specific log (in16 cluding the location, weight, and spe17 cific identifying information of any 

18 applicable equipment) for each cyl19 inder used at the facility— 

20 ‘‘(aa) to fill equipment with 

21 sulfur hexafluoride; or 

22 ‘‘(bb) to reclaim sulfur 

23 hexafluoride from equipment; and 

24 ‘‘(iii) an inventory of all SF6-con25 taining operating equipment and all other 


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1 sulfur hexafluoride-related items (including 

2 cylinders, gas carts, and other storage con3 tainers) used by the transmission or dis4 tribution entity for which the offset project 

5 is being carried out. 

6 ‘‘(B) RETURN OF LOGS.—The project 

7 sponsor shall submit to the facility in control of 

8 each applicable cylinder a copy of each log de9 scribed in subparagraph (A)(ii)(II) relating to 

10 the cylinder by not later than the earlier of— 

11 ‘‘(i) the date on which the sponsor 

12 completes use of the cylinder; and 

13 ‘‘(ii) the date on which the cylinder is 

14 empty. 

15 ‘‘(c) SEQUESTRATION OF CARBON DUE TO

16 AFFORESTATION OR REFORESTATION.— 

17 ‘‘(1) IN GENERAL.—An offset project that se18 questers carbon through the conversion of nonfor19 ested land to a forested condition may receive allow20 ances under this title if— 

21 ‘‘(A) the offset project occurs on land that 

22 has been in a nonforested state for at least 10 

23 years immediately preceding the date of imple24 mentation of the offset project; 


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1 ‘‘(B) the offset project is, as determined by 

2 the Administrator— 

3 ‘‘(i) not common practice in the geo4 graphic area in which the offset project 

5 will occur; 

6 ‘‘(ii) managed in accordance with 

7 widely-accepted environmentally sustain8 able forestry practices; and 

9 ‘‘(iii) designed to promote restoration 

10 of native forests by using mainly native 

11 species and avoiding the introduction of 

12 invasive nonnative species; and 

13 ‘‘(iv) before any commercial timber 

14 harvest-related activity occurs pursuant to 

15 the offset project, an appropriate certifi16 cation is obtained by the sponsor of the 

17 offset project through— 

18 ‘‘(I) the Forest Stewardship 

19 Council; 

20 ‘‘(II) the Sustainable Forestry 

21 Institute; 

22 ‘‘(III) the American Tree Farm 

23 System; or 


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1 ‘‘(IV) such other similar organi2 zation as the Administrator deter3 mines to be appropriate. 

4 ‘‘(2) CARBON SEQUESTRATION BASELINE.— 

5 ‘‘(A) IN GENERAL.—To be eligible to re6 ceive allowances under this subsection, the 

7 sponsor of an offset project shall determine, 

8 using data from the 1-year period ending on the 

9 date on which the offset project begins oper10 ation, the carbon content of certain carbon 

11 pools in accordance with this paragraph. 

12 ‘‘(B) CARBON POOLS.— 

13 ‘‘(i) MANDATORY.—As a condition of 

14 receiving allowances under this subsection, 

15 the sponsor of an offset project shall deter16 mine the carbon content of the following 

17 carbon pools: 

18 ‘‘(I) Live above-ground tree bio19 mass. 

20 ‘‘(II) Live below-ground tree bio21 mass. 

22 ‘‘(III) Soil carbon. 

23 ‘‘(IV)(aa) Except as provided in 

24 item (bb), dead organic matter and 

25 coarse woody debris. 


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1 ‘‘(bb) If the Administrator deter2 mines that the baseline measurement 

3 of the dead organic matter or coarse 

4 woody debris carbon pool for an offset 

5 project is at or near zero, the deter6 mination of the carbon content of that 

7 carbon pool shall be discretionary 

8 under clause (ii). 

9 ‘‘(ii) DISCRETIONARY.—The sponsor 

10 of an offset project may elect to determine 

11 the carbon content of the following carbon 

12 pools: 

13 ‘‘(I) Live above-ground non-tree 

14 biomass. 

15 ‘‘(II) Dead organic matter and 

16 forest floor. 

17 ‘‘(iii) DIVISION INTO SUBPOPULA18 TIONS.— 

19 ‘‘(I) IN GENERAL.—To increase 

20 the accuracy of the calculation of car21 bon content under this subparagraph, 

22 the sponsor of the offset project shall 

23 divide the land within the jurisdiction 

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1 tions that form relatively homogenous 

2 units. 

3 ‘‘(II) FACTORS FOR CONSIDER4 ATION.—In dividing land of the offset 

5 project under subclause (I), the spon6 sor shall take into consideration— 

7 ‘‘(aa) vegetation and tree 

8 species (including existing vegeta9 tion and trees and vegetation and 

10 trees to be used as part of the 

11 offset project); and 

12 ‘‘(bb) site-specific factors, 

13 such as soil type, elevation, slope, 

14 and age class. 

15 ‘‘(iv) SUBPOPULATION CALCULA16 TION.— 

17 ‘‘(I) IN GENERAL.—The carbon 

18 content of each subpopulation of a 

19 carbon pool under this subparagraph 

20 shall be calculated in accordance with 

21 the following formula: carbon dioxide 

22 (tons) = [(A × C/ha)(44/12)] / 

23 0.9072. 

24 ‘‘(II) DESCRIPTION.—In the for25 mula contained in subclause (I)— 


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1 ‘‘(aa) ‘A’ represents the area 

2 in hectares of the applicable sub3 population; and 

4 ‘‘(bb) ‘C/ha’ represents the 

5 average carbon content per hec6 tare of each carbon pool. 

7 ‘‘(v) CARBON POOL CALCULATIONS.— 

8 ‘‘(I) IN GENERAL.—The carbon 

9 content of each carbon pool shall be 

10 calculated using a measurement pro11 tocol and sample size that achieves 

12 demonstrated, quantified accuracy for 

13 the combined carbon pool calculation 

14 under subparagraph (C), such that 

15 the Administrator is 95-percent con16 fident that the calculated value is 

17 within 10 percent of the true mean. 

18 ‘‘(II) REQUIREMENTS.—Measure19 ment and sampling practices under 

20 this subparagraph shall meet the fol21 lowing requirements: 

22 ‘‘(aa) Adequate sample size 

23 that meets each applicable re24 quirement with respect to each 

25 applicable subpopulation. 


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1 ‘‘(bb) Minimum required 

2 number of sampling plots for 

3 each subpopulation, as deter4 mined in accordance with the for5 mula contained in subclause 

6 (III). 

7 ‘‘(III) FORMULA.— 

8 ‘‘(aa) IN GENERAL.—The 

9 formula referred to in subclause 

10 (II)(bb) is the following: n = (s 

× 1.960)/(mean × re)2 11 . 

12 ‘‘(bb) DESCRIPTION.—In the 

13 formula contained in item (aa)— 

14 ‘‘(AA) ‘n’ represents 

15 the required number of sam16 ple plots for each applicable 

17 subpopulation; 

18 ‘‘(BB) ‘s’ represents 

19 the standard deviation; 

20 ‘‘(CC) ‘mean’ rep21 resents the average carbon 

22 content calculated for the 

23 sample population; and 

24 ‘‘(DD) ‘re’ represents 

25 the level of sampling error 


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1 (with a default value of 

2 0.08) to ensure a total max3 imum error of not more 

4 than 10 percent, assuming a 

5 total error due to measure6 ment error of 0.02. 

7 ‘‘(C) TOTAL CARBON CONTENT CALCULA8 TION.— 

9 ‘‘(i) IN GENERAL.—The carbon con10 tent of all carbon pools within the jurisdic11 tion of an offset project shall be deter12 mined, based on the values calculated 

13 under subparagraph (B)(iv), in accordance 

14 with the following formula: TCpb = TClatb

15 + TClbtb + TCs [+ TClantb + TCdoff + 

16 TCdocwd]. 

17 ‘‘(ii) DESCRIPTION.—In the formula 

18 contained in clause (i)— 

19 ‘‘(I) ‘TCpb’ represents the total 

20 carbon content of all carbon pools 

21 within the jurisdiction of an offset 

22 project; 

23 ‘‘(II) ‘TClatb’ represents the total 

24 carbon content of live above-ground 


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1 tree biomass in all applicable sub2 populations; 

3 ‘‘(III) ‘TClbtb’ represents the 

4 total carbon content of live below5 ground tree biomass in all applicable 

6 subpopulations; 

7 ‘‘(IV) ‘TCs’ represents the total 

8 carbon content of soil carbon in all 

9 applicable subpopulations; 

10 ‘‘(V) ‘TClantb’ represents the total 

11 carbon content of live above-ground 

12 non-tree biomass in all applicable sub13 populations; 

14 ‘‘(VI) ‘TCdoff’ represents the 

15 total carbon content of dead organic 

16 matter and forest floor in all applica17 ble subpopulations; and 

18 ‘‘(VII) ‘TCdocwd’ represents the 

19 total carbon content of dead organic 

20 matter and coarse woody debris in all 

21 applicable subpopulations. 

22 ‘‘(D) REQUIREMENT.—Calculations under 

23 this paragraph shall be in accordance with ap24 plicable forestry best practices and guidance 

25 contained in section 3 of part 1 of chapter 1 of 


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1 the technical guidelines for the voluntary re2 porting of greenhouse gases program of the De3 partment of Energy, dated March 2006 (or suc4 cessor guidelines). 

5 ‘‘(3) CALCULATING SEQUESTRATION ALLOW6 ANCES.— 

7 ‘‘(A) IN GENERAL.—For any year, the Ad8 ministrator shall allocate allowances under this 

9 subsection based on the quantity of carbon se10 questered as a result of the applicable offset 

11 project, based on the difference between, ex12 pressed as tons of carbon dioxide— 

13 ‘‘(i) the aggregate carbon uptake and 

14 carbon emissions of the carbon pools of the 

15 offset project during the applicable year; 

16 and 

17 ‘‘(ii) the carbon content of the carbon 

18 pools of the offset project for the preceding 

19 year or the baseline year, as appropriate. 

20 ‘‘(B) FORMULA.— 

21 ‘‘(i) IN GENERAL.—For purposes of 

22 allocating allowances under this subsection, 

23 the quantity of carbon sequestered shall be 

24 calculated using a stock-change approach, 


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1 in accordance with the following formula: 

2 NCSt = It – It–1. 

3 ‘‘(ii) DESCRIPTION.—In the formula 

4 contained in clause (i)— 

5 ‘‘(I) ‘NCSt’ represents the net 

6 carbon sequestered during reporting 

7 period t; 

8 ‘‘(II) ‘It’ represents the inventory 

9 of carbon stock for all carbon pools in 

10 all applicable subpopulations within 

11 the jurisdiction of the offset project 

12 during reporting period t; and 

13 ‘‘(III) ‘It–1’ represents the inven14 tory of carbon stock for all carbon 

15 pools in all applicable subpopulations 

16 within the jurisdiction of the offset 

17 project during the reporting period 

18 immediately preceding reporting pe19 riod t. 

20 ‘‘(C) REQUIREMENTS.— 

21 ‘‘(i) REMEASUREMENT.—Except as 

22 provided in paragraph (2)(B)(i)(IV)(bb), 

23 the carbon content of each carbon pool cal24 culated under paragraph (2) shall be re25 measured for each year during which the 


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1 applicable offset project receives an allow2 ance under this subsection, with equal or 

3 greater precision, in accordance with that 

4 paragraph. 

5 ‘‘(ii) DETERMINATION OF CARBON

6 STOCK.—Each calculation of the carbon 

7 stock of a subpopulation of a carbon pool 

8 under this paragraph shall be made in ac9 cordance with paragraph (2). 

10 ‘‘(iii) POTENTIAL LOSSES.— 

11 ‘‘(I) IN GENERAL.—Subject to 

12 subclause (II), the sponsor of an off13 set project shall decrease the net value 

14 of change in carbon stock calculated 

15 in accordance with this paragraph by 

16 not more than 10 percent of the value 

17 to account for potential losses of se18 questered carbon in any carbon pool 

19 of the offset project. 

20 ‘‘(II) INSURANCE.—The require21 ment under subclause (I) shall not 

22 apply to any offset project that ob23 tains long-term insurance approved by 

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1 bon for which an allowance is issued 

2 under this subsection. 

3 ‘‘(4) MONITORING AND VERIFICATION.—Not 

4 less frequently than once every 5 years, the sponsor 

5 of an offset project that receives allowances under 

6 this subsection shall submit to the Administrator a 

7 monitoring and verification report, including— 

8 ‘‘(A) a calculation of total carbon stock 

9 within the jurisdiction of the offset project; and 

10 ‘‘(B) data from the direct measurement of 

11 carbon content for each carbon pool used to de12 termine the baseline and reporting period car13 bon content of the offset project. 

14 ‘‘(5) CARBON SEQUESTRATION PERMANENCE.— 

15 ‘‘(A) IN GENERAL.—To address the per16 manence of sequestered carbon, the sponsor of 

17 each offset project that receives an allowance 

18 under this subsection shall place land within the 

19 jurisdiction of the offset project under a legally20 binding permanent conservation easement, ap21 proved by the Administrator, that requires the 

22 land to be maintained in a forested condition in 

23 perpetuity. 


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1 ‘‘(B) REQUIREMENTS.—A conservation 

2 easement under subparagraph (A) shall include 

3 a requirement that— 

4 ‘‘(i) the carbon density within the ju5 risdiction of the offset project shall be 

6 maintained at long-term levels; and 

7 ‘‘(ii) land within the jurisdiction of 

8 the offset project shall be managed in ac9 cordance with environmentally sustainable 

10 forestry practices. 

11 ‘‘(d) REDUCTION AND AVOIDANCE OF CARBON DIOX12 IDE EMISSIONS FROM NATURAL GAS, OIL, AND PROPANE

13 END-USE COMBUSTION DUE TO END-USE ENERGY EFFI14 CIENCY.— 

15 ‘‘(1) DEFINITIONS.—In this subsection: 

16 ‘‘(A) BUILDING ENVELOPE.—The term 

17 ‘building envelope’ means the elements of a 

18 building that separate conditioned space from 

19 unconditioned space, or that enclose semiheated 

20 space, through which thermal energy may be 

21 transferred to or from the exterior, 

22 unconditioned space, or conditioned space, in23 cluding any element that separates the interior 

24 of a building from the outdoor environment 


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1 (such as walls, windows, foundation, basement 

2 slab, ceiling, roof, and insulation). 

3 ‘‘(B) PASSIVE SOLAR.—The term ‘passive 

4 solar’, with respect to a building, means a com5 bination of building design features and build6 ing components that use solar energy to reduce 

7 or eliminate the need for— 

8 ‘‘(i) mechanical heating and cooling; 

9 and 

10 ‘‘(ii) daytime artificial lighting. 

11 ‘‘(C) WHOLE-BUILDING RETROFIT.—The 

12 term ‘whole-building retrofit’ means any build13 ing project that— 

14 ‘‘(i) involves the replacement of more 

15 than 1 building system or set of building 

16 components; and 

17 ‘‘(ii) requires a building permit. 

18 ‘‘(D) ZERO-NET ENERGY BUILDING.—The 

19 term ‘zero-net energy building’ means a build20 ing designed to produce as much energy, using 

21 renewable energy sources, as the building is 

22 projected to use, as measured on an annual 

23 basis. 


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1 ‘‘(2) ELIGIBILITY.—An offset project shall be 

2 eligible to receive allowances under this title if the 

3 offset project— 

4 ‘‘(A) reduces carbon dioxide emissions by 

5 reducing on-site combustion of natural gas, oil, 

6 or propane for end-use in a commercial building 

7 or a residential building by improving the en8 ergy efficiency of fuel usage or the energy-effi9 cient delivery of energy services; and 

10 ‘‘(B) meets the other requirements of this 

11 subsection. 

12 ‘‘(3) REQUIREMENTS.— 

13 ‘‘(A) IN GENERAL.—To be eligible to re14 ceive allowances under this subsection, an offset 

15 project shall reduce carbon dioxide emissions 

16 through 1 or more of the following measures: 

17 ‘‘(i) Measures to improve the energy 

18 efficiency of combustion equipment that 

19 provide space heating and hot water, in20 cluding a reduction in fossil fuel consump21 tion through the use of renewable energy. 

22 ‘‘(ii) Measures to improve the effi23 ciency of a heating distribution system, in24 cluding proper sizing and commissioning of 

25 heating systems. 


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1 ‘‘(iii) Installation or improvement of 

2 energy management systems. 

3 ‘‘(iv) Measures to improve the effi4 ciency of hot water distribution systems 

5 and reduction in demand for hot water. 

6 ‘‘(v) Measures to improve the thermal 

7 performance of the building envelope or re8 duce building envelope air leakage. 

9 ‘‘(vi) Measures to improve the passive 

10 solar performance of buildings and use of 

11 active heating systems using renewable en12 ergy. 

13 ‘‘(vii) Use of a less carbon-intensive 

14 fuel in combustion systems, including the 

15 use of liquid or gaseous renewable fuels, 

16 but not including a conversion to elec17 tricity. 

18 ‘‘(B) NEW BUILDINGS.—To be eligible to 

19 receive allowances under this subsection for an 

20 offset project a component of which is a new 

21 building, the new building shall be designed— 

22 ‘‘(i) to replace an existing building on 

23 the offset project site; or 

24 ‘‘(ii) to be a zero-net energy building. 

25 ‘‘(C) PERFORMANCE STANDARDS.— 


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1 ‘‘(i) IN GENERAL.—To be eligible to 

2 receive allowances under this subsection, 

3 an offset project shall meet the applicable 

4 performance requirements of this subpara5 graph. 

6 ‘‘(ii) SIZING AND INSTALLATION.— 

7 Any combustion equipment and related air 

8 handling equipment (including any HVAC 

9 system) installed as part of an offset 

10 project shall be sized and installed in ac11 cordance with— 

12 ‘‘(I) for commercial HVAC sys13 tems— 

14 ‘‘(aa) ANSI/ASHRAE/ 

15 IESNA Standard 90.1–2004, en16 titled ‘Energy Standard for 

17 Buildings Except Low-Rise Resi18 dential Buildings’ (or a successor 

19 standard); and 

20 ‘‘(bb) ANSI/ASHRAE 

21 Standard 62.1–2004, entitled 

22 ‘Ventilation for Acceptable In23 door Air Quality’ (or a successor 

24 standard); and 


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1 ‘‘(II) for residential HVAC sys2 tems— 

3 ‘‘(aa) for sizing specifica4 tions, the eighth edition of the 

5 Air Conditioner Contractors of 

6 America Manual J, entitled ‘Res7 idential Load Calculation’ (or 

8 successor specifications); and 

9 ‘‘(bb) for applicable installa10 tion specifications, the document 

11 of the Consortium for Energy Ef12 ficiency entitled ‘Specification of 

13 Energy-Efficient Installation and 

14 Maintenance Practices for Resi15 dential HVAC Systems’ and 

16 dated 2000 (or a successor docu17 ment). 

18 ‘‘(iii) WHOLE-BUILDING ENERGY PER19 FORMANCE.—Any eligible new building or 

20 whole-building retrofit that is part of an 

21 offset project shall meet the following re22 quirements: 

23 ‘‘(I) COMMERCIAL BUILDINGS.— 

24 ‘‘(aa) IN GENERAL.—Except 

25 as provided in item (bb), comVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00123 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 mercial buildings shall exceed by 

2 at least 30 percent the energy 

3 performance requirements of 

4 ANSI/ASHRAE/IESNA Stand5 ard 90.1–2004, entitled ‘Energy 

6 Standard for Buildings Except 

7 Low-Rise Residential Buildings’ 

8 (or a successor standard). 

9 ‘‘(bb) EXCEPTION.—A mul10 tifamily residential building clas11 sified as a commercial building 

12 under ANSI/ASHRAE/IESNA 

13 Standard 90.1–2004 (or a suc14 cessor standard) shall exceed the 

15 energy performance requirements 

16 described in item (aa) by at least 

17 20 percent. 

18 ‘‘(II) RESIDENTIAL BUILD19 INGS.—Residential buildings shall ex20 ceed the energy performance require21 ments of the 2004 International En22 ergy Conservation Code (or a suc23 cessor code) by at least 30 percent. 

24 ‘‘(D) OFFSET PROJECTS INITIATED BE25 FORE JANUARY 1, 2009.—To be eligible to reVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00124 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 ceive allowances under this subsection, each en2 ergy conservation measure implemented as part 

3 of an offset project initiated before January 1, 

4 2009, shall meet the following requirements: 

5 ‘‘(i) COMBUSTION EQUIPMENT.— 

6 ‘‘(I) IN GENERAL.—Combustion 

7 equipment installed as part of the off8 set project shall meet the energy effi9 ciency performance standards re10 quired under this clause. 

11 ‘‘(II) COMMERCIAL BOILERS.— 

12 ‘‘(aa) IN GENERAL.—Com13 mercial boilers shall meet or ex14 ceed the energy efficiency criteria 

15 specified in the following table: 

‘‘Minimum Commercial Boiler Energy Efficiency 

Technology Size (Btu/hour) Rating method Minimum 

efficiency 

Gas-fired 125,000–300,000 ..................... AFUE ........... 88% 

Gas-fired 300,000–12,500,000 ................ Thermal efficiency.90% 

Oil-fired 300,000 or more ...................... Thermal efficiency.88% 

16 ‘‘(bb) GAS-FIRED BOIL17 ERS.—A gas-fired boiler installed 

18 as part of the offset project shall 

19 be installed with— 


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1 ‘‘(AA) controls allowing 

2 the gas-fired boiler to oper3 ate in condensing mode, 

4 such that the design and op5 eration of the boiler leads to 

6 the production of condensate 

7 in flue gases; and 

8 ‘‘(BB) vents designed 

9 for positive vent static pres10 sure and vent gas tempera11 ture that leads to conden12 sate production in the vent. 

13 ‘‘(cc) THERMAL EFFI14 CIENCY.—For purposes of the 

15 table contained in item (aa), the 

16 term ‘thermal efficiency’ means 

17 the percentage obtained by divid18 ing (as measured under steady19 state conditions, at full-rated use20 ful thermal output, with 140°F 

21 supply from, and 120°F return 

22 water temperature to, the boil23 er)— 


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1 ‘‘(AA) the useful energy 

2 output of a boiler, expressed 

3 in Btus; by 

4 ‘‘(BB) the energy input 

5 of the boiler, expressed in 

6 Btus. 

7 ‘‘(III) RESIDENTIAL COMBUS8 TION EQUIPMENT.— 

9 ‘‘(aa) IN GENERAL.—Resi10 dential combustion equipment, 

11 including furnaces, boilers, and 

12 water heaters, shall meet or ex13 ceed the energy efficiency criteria 

14 specified in the following table: 

‘‘Minimum Residential Combustion Equipment Energy Efficiency 

Technology Rating method Minimum efficiency 

Gas-fired furnace ........................ AFUE .................. 94% 

Oil-fired furnace ......................... AFUE .................. 92% 

Gas- or oil-fired boiler ................ AFUE .................. 90% 

Gas- or oil-fired water heater ..... Energy factor ...... 0.62 

15 ‘‘(bb) DEFINITIONS.—In the 

16 table contained in item (aa): 

17 ‘‘(AA) BOILER.—The 

18 term ‘boiler’ means any 

19 equipment with a heat input 

20 rate of less than 300,000 

21 Btu per hour. 


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1 ‘‘(BB) FURNACE.—The 

2 term ‘furnace’ means any 

3 equipment with a heat input 

4 rate of less than 225,000 

5 Btu per hour. 

6 ‘‘(CC) WATER HEAT7 ER.—The term ‘water heat8 er’ has the meaning given 

9 the term in section 430.2 of 

10 title 10, Code of Federal 

11 Regulations (or a successor 

12 regulation). 

13 ‘‘(ii) OTHER ENERGY CONSERVATION

14 MEASURES.—Each other energy conserva15 tion measure carried out as part of the off16 set project shall meet— 

17 ‘‘(I) subject to subclause (II), the 

18 more stringent energy performance re19 quirements of, as applicable— 

20 ‘‘(aa) the requirements of 

21 the document entitled ‘Energy 

22 Benchmark for High Perform23 ance Buildings, Version 1.1, New 

24 Buildings Institute’ and dated 


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1 2005 (or a successor document); 

2 or 

3 ‘‘(bb) the requirements of 

4 State building energy codes; and 

5 ‘‘(II) for energy conservation 

6 measures not subject to the require7 ments of the document described in 

8 subclause (I)(aa), the more stringent 

9 energy performance requirements of, 

10 as applicable— 

11 ‘‘(aa) the requirements of 

12 the document entitled ‘Federal 

13 Energy Management Program 

14 Product Energy Efficiency Rec15 ommendations’, issued pursuant 

16 to Executive orders 13123 and 

17 13221 (64 Fed. Reg. 30851 

18 (June 8, 1999); 66 Fed. Reg. 

19 40571 (August 2, 2001)) (or a 

20 successor document); or 

21 ‘‘(bb) the Energy Star cri22 teria issued jointly by the Admin23 istrator and the Secretary of En24 ergy. 


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1 ‘‘(E) MAXIMUM MARKET PENETRATION

2 RATE FOR OFFSET PROJECTS COMMENCED ON

3 OR AFTER JANUARY 1, 2009.—To be eligible to 

4 receive allowances under this subsection for an 

5 offset project initiated on or after January 1, 

6 2009, the sponsor of the offset project shall 

7 demonstrate to the satisfaction of the Adminis8 trator that the energy conservation measures 

9 implemented as part of the offset project have 

10 a market penetration rate of less than 5 per11 cent. 

12 ‘‘(4) EMISSIONS BASELINE DETERMINATION.— 

13 ‘‘(A) ENERGY USAGE, EMISSIONS FACTORS, 

14 AND OXIDATION FACTORS.— 

15 ‘‘(i) IN GENERAL.—The emissions 

16 baseline of an offset project that receives 

17 allowances under this subsection shall be 

18 determined by multiplying— 

19 ‘‘(I) the energy usage (measured 

20 in MMBtus), by fuel type, for each 

21 energy conservation measure carried 

22 out under the offset project, as deter23 mined using historic fuel use data 

24 from the most recent calendar year 

25 for which data is available; and 


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1 ‘‘(II) the applicable emissions 

2 factor (measured in pounds of carbon 

3 dioxide per MMBtu) and oxidation 

4 factor for each fuel type, in accord5 ance with the following table: 

‘‘Emissions and Oxidation Factors 

Fuel type Emissions 

factor Oxidation factor 

Natural gas ............................... 116.98 0.995 

Propane .................................... 139.04 0.995 

Distillate fuel oil ....................... 161.27 0.99 

Kerosene ................................... 159.41 0.99 

6 ‘‘(ii) ENERGY USAGE DETERMINA7 TION.— 

8 ‘‘(I) IN GENERAL.—For purposes 

9 of the calculation under clause (i), the 

10 energy usage for each energy con11 servation measure carried out under 

12 the offset project shall be determined 

13 in accordance with the following for14 mula: Energy usage (MMBtu) = 

15 BEUAECM × A. 

16 ‘‘(II) DESCRIPTION.—In the for17 mula contained in subclause (I)— 

18 ‘‘(aa) ‘BEUAECM’ represents 

19 the annual pre-installation base20 line energy use (measured in 

21 MMBtus), by fuel type, attribVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00131 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 utable to each application to be 

2 targeted by the energy conserva3 tion measure, as determined in 

4 accordance with paragraph (6); 

5 and 

6 ‘‘(bb) ‘A’ represents adjust7 ments required to account for 

8 differing conditions during the 

9 pre-installation and post-installa10 tion periods, such as weather, 

11 building occupancy, and changes 

12 in building use or function, as 

13 adjusted in accordance with para14 graph (6). 

15 ‘‘(III) ADDITIONAL REQUIRE16 MENTS.— 

17 ‘‘(aa) IN GENERAL.—Sub18 ject to item (bb), for purposes of 

19 determining the variable under 

20 subclause (II)(aa), if a building 

21 code or equipment standard re22 quires that equipment or mate23 rials installed as part of the off24 set project meet certain minimum 

25 energy performance requireVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00132 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 ments, the annual pre-installation 

2 baseline energy usage for the ap3 plicable application shall be de4 termined based on the assump5 tion that the equipment or mate6 rials are installed in accordance 

7 with those requirements. 

8 ‘‘(bb) REPLACEMENT OF

9 COMBUSTION EQUIPMENT.—For 

10 an offset project under which ex11 isting combustion equipment is 

12 replaced, the minimum energy 

13 performance required by a build14 ing code or equipment standard 

15 shall be considered to be the min16 imum energy performance stand17 ard that applies to new equip18 ment that uses the same fuel 

19 type as the equipment being re20 placed. 

21 ‘‘(B) ANNUAL BASELINE EMISSIONS.— 

22 ‘‘(i) IN GENERAL.—The annual base23 line emissions of an offset project that re24 ceives allowances under this subsection 

25 shall be calculated in accordance with the 


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1 following formula: Emissions (pounds of 

2 carbon dioxide) = è BEUi × EFi × OFi. 

3 ‘‘(ii) DESCRIPTION.—In the formula 

4 contained in clause (i)— 

5 ‘‘(I)(aa) the figure above the 

6 sigma shall be ‘n’; and 

7 ‘‘(bb) the figure below the sigma 

8 shall be ‘i = 1’; 

9 ‘‘(II) ‘BEUi’ represents the an10 nual baseline energy usage for fuel 

11 type i (measured in MMBtus), as de12 termined in accordance with para13 graph (6); 

14 ‘‘(III) ‘EFi’ represents the emis15 sions factor (measured in pounds of 

16 carbon dioxide per MMBtu) for fuel 

17 type i, as determined in accordance 

18 with the table contained in subpara19 graph (A)(i)(II); and 

20 ‘‘(IV) ‘OFi’ represents the oxida21 tion factor for fuel type i, as deter22 mined in accordance with the table 

23 contained in subparagraph (A)(i)(II). 

24 ‘‘(5) CALCULATING EMISSIONS REDUCTIONS.— 


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1 ‘‘(A) IN GENERAL.—The emissions reduc2 tions of an offset project that receives allow3 ances under this subsection shall be determined, 

4 based on the annual energy savings, by fuel 

5 type, for each energy conservation measure car6 ried out under the offset project, in accordance 

7 with this paragraph. 

8 ‘‘(B) ANNUAL ENERGY SAVINGS.— 

9 ‘‘(i) IN GENERAL.—The annual en10 ergy savings of an offset project that re11 ceives allowances under this subsection 

12 shall be determined in accordance with the 

13 following formula: Energy savings 

14 (MMBtu) = (BEUAECM × A) – 

15 (PIEUECM × A). 

16 ‘‘(ii) DESCRIPTION.—In the formula 

17 contained in clause (i)— 

18 ‘‘(I) ‘BEUAECM’ represents the 

19 annual pre-installation baseline energy 

20 use (measured in MMBtus), by fuel 

21 type, of an application subject to an 

22 energy conservation measure under 

23 the offset project, as determined sub24 ject to clause (iii); 


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1 ‘‘(II) ‘PIEUECM’ represents the 

2 annual post-installation energy use 

3 (measured in MMBtus), by fuel type, 

4 attributable to the energy conserva5 tion measure, as verified in accord6 ance with ASHRAE Guideline 14– 

7 2002, entitled ‘Measurement of En8 ergy and Demand Savings’ (or a suc9 cessor guideline); and 

10 ‘‘(III) ‘A’ represents adjustments 

11 required to account for differing con12 ditions during the pre-installation and 

13 post-installation periods, such as 

14 weather, building occupancy, and 

15 changes in building use or function, 

16 as adjusted in accordance with— 

17 ‘‘(aa) for commercial build18 ings, ASHRAE Guideline 14– 

19 2002, entitled ‘Measurement of 

20 Energy and Demand Savings’, 

21 and section 11 and appendix G of 

22 ANSI/ASHRAE/IESNA Stand23 ard 90.1–2004 (or successor 

24 specifications); and 


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1 ‘‘(bb) for residential build2 ings, RESNET National Home 

3 Energy Rating Technical Guide4 lines, 2006 (Chapter 3 and Ap5 pendix A of 2006 Mortgage In6 dustry National Home Energy 

7 Rating System Standards) (or 

8 successor guidelines). 

9 ‘‘(iii) PRE-INSTALLATION BASELINE

10 ENERGY USE DETERMINATIONS FOR NEW

11 BUILDINGS.—The pre-installation baseline 

12 energy use of any new building in which an 

13 energy conservation measure will be car14 ried out under an offset project shall be 

15 determined based on a reference building 

16 that is equivalent in basic configuration, 

17 orientation, and location to the new build18 ing, in accordance with ASHRAE Guide19 line 14–2002, entitled ‘Measurement of 

20 Energy and Demand Savings’ and section 

21 11 and appendix G of ANSI/ASHRAE/ 

22 IESNA Standard 90.1–2004 (or successor 

23 specifications). 

24 ‘‘(C) ANNUAL EMISSIONS REDUCTIONS.— 


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1 ‘‘(i) IN GENERAL.—The annual emis2 sions reductions of an offset project that 

3 receives allowances under this subsection 

4 shall be determined in accordance with the 

5 following formula: Emissions reduction 

6 (pounds of carbon dioxide) = è ESi × EFi

7 × OFi. 

8 ‘‘(ii) DESCRIPTION.—In the formula 

9 contained in clause (i)— 

10 ‘‘(I)(aa) the figure above the 

11 sigma shall be ‘n’; and 

12 ‘‘(bb) the figure below the sigma 

13 shall be ‘i = 1’; 

14 ‘‘(II) ‘ESi’ represents the energy 

15 savings for fuel type i (measured in 

16 MMBtus), as determined in accord17 ance with paragraph (6); 

18 ‘‘(III) ‘EFi’ represents the emis19 sions factor (measured in pounds of 

20 carbon dioxide per MMBtu) for fuel 

21 type i, as determined in accordance 

22 with the table contained in subpara23 graph (A)(i)(II); and 

24 ‘‘(IV) ‘OFi’ represents the oxida25 tion factor for fuel type i, as deterVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00138 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 mined in accordance with the table 

2 contained in subparagraph (A)(i)(II). 

3 ‘‘(6) MONITORING AND VERIFICATION.— 

4 ‘‘(A) IN GENERAL.—Not less frequently 

5 than once each year, the sponsor of each offset 

6 project that receives an allowance under this 

7 subsection shall submit to the Administrator a 

8 monitoring and verification report. 

9 ‘‘(B) CERTIFICATION.—Each report under 

10 subparagraph (A) shall be certified. 

11 ‘‘(C) GENERAL ENERGY REQUIREMENTS.— 

12 Monitoring and verification of energy usage 

13 under this paragraph shall be conducted in ac14 cordance with the following protocols and proce15 dures, as applicable: 

16 ‘‘(i) COMMERCIAL BUILDINGS.— 

17 ‘‘(I) EXISTING BUILDINGS.—For 

18 commercial buildings in existence on 

19 the date on which the applicable offset 

20 project enters operation, baseline en21 ergy usage shall be determined in ac22 cordance with— 

23 ‘‘(aa) the detailed specifica24 tions in ASHRAE Guideline 14– 

25 2002, entitled ‘Measurement of 


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1 Energy and Demand Savings’, as 

2 applicable (or successor specifica3 tions); and 

4 ‘‘(bb)(AA) volume I of the 

5 International Performance Meas6 urement and Verification Pro7 tocol, entitled ‘Concepts and Op8 tions for Determining Energy 

9 and Water Savings’, specifically 

10 the documents entitled ‘Option 

11 B. Retrofit Isolation’ and ‘Option 

12 D. Calibrated Simulation’ (or 

13 successor specifications); or 

14 ‘‘(BB) if a building project 

15 carried out under the offset 

16 project involves only energy con17 servation measures implemented 

18 as part of a carbon dioxide emis19 sions offset project, the document 

20 of the volume referred to in 

21 subitem (AA) entitled ‘Option C. 

22 Whole Facility’ (or successor 

23 specifications). 

24 ‘‘(II) NEW BUILDINGS.—For new 

25 commercial buildings constructed 


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1 under the applicable offset project, 

2 baseline energy usage shall be deter3 mined in accordance with— 

4 ‘‘(aa) the detailed specifica5 tions in ASHRAE Guideline 14– 

6 2002, entitled ‘Measurement of 

7 Energy and Demand Savings’, as 

8 applicable (or successor specifica9 tions); and 

10 ‘‘(bb) volume III of the 

11 International Performance Meas12 urement and Verification Pro13 tocol, entitled ‘Concepts and Op14 tions for Determining Energy 

15 Savings in New Construction’, 

16 specifically the document entitled 

17 ‘Option D. Calibrated Simula18 tion’ (or successor specifications). 

19 ‘‘(ii) RESIDENTIAL BUILDINGS.—For 

20 any residential building relating to the ap21 plicable offset project, baseline energy 

22 usage shall be determined in accordance 

23 with the RESNET National Home Energy 

24 Rating Technical Guidelines, 2006 (Chap25 ter 3 and Appendix A of 2006 Mortgage 


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1 Industry National Home Energy Rating 

2 System Standards) (or successor guide3 lines). 

4 ‘‘(D) ISOLATION OF ENERGY CONSERVA5 TION MEASURES.— 

6 ‘‘(i) IN GENERAL.—For purposes of 

7 calculating baseline energy usage and en8 ergy savings under this subsection, the 

9 sponsor of the offset project shall isolate 

10 the impact of each eligible energy con11 servation measure, to the maximum extent 

12 practicable, through direct metering or, 

13 subject to subparagraph (E), energy sim14 ulation modeling. 

15 ‘‘(ii) PROJECTS WITH MULTIPLE

16 MEASURES.— 

17 ‘‘(I) IN GENERAL.—For offset 

18 projects under which multiple energy 

19 conservation measures are carried out, 

20 and for which individual energy con21 servation measures could affect the 

22 performance of other energy conserva23 tion measures, the total energy sav24 ings due to individual energy con25 servation measures shall be adjusted 


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1 to account for the interaction of the 

2 energy conservation measures in ac3 cordance with this clause. 

4 ‘‘(II) COMMERCIAL BUILDINGS.— 

5 For commercial buildings, the adjust6 ment under subclause (I) shall be in 

7 accordance with ASHRAE Guideline 

8 14–2002, entitled ‘Measurement of 

9 Energy and Demand Savings’, and 

10 ANSI/ASHRAE/IESNA Standard 

11 90.1–2004, entitled ‘Energy Standard 

12 for Buildings Except Low-Rise Resi13 dential Buildings’ (or successor speci14 fications). 

15 ‘‘(III) RESIDENTIAL BUILD16 INGS.—For residential buildings, the 

17 adjustment under subclause (I) shall 

18 be in accordance with RESNET Na19 tional Home Energy Rating Technical 

20 Guidelines, 2006 (Chapter 3 and Ap21 pendix A of 2006 Mortgage Industry 

22 National Home Energy Rating Sys23 tem Standards) (or successor guide24 lines). 

25 ‘‘(E) SIMULATION MODELING.— 


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1 ‘‘(i) IN GENERAL.—Any reduction in 

2 energy usage due to an energy conserva3 tion measure under an offset project shall 

4 be calculated based only on actual energy 

5 usage data. 

6 ‘‘(ii) LIMITATION.—Energy simulation 

7 modeling— 

8 ‘‘(I) shall only be used to deter9 mine the relative percentage contribu10 tion to total fuel usage, for each fuel 

11 type, of an application targeted by an 

12 energy conservation measure under an 

13 offset project; and 

14 ‘‘(II) shall be carried out under 

15 subclause (I) in accordance with— 

16 ‘‘(aa) for commercial build17 ings in existence on the date on 

18 which the applicable offset 

19 project is commenced, ASHRAE 

20 Guideline 14–2002, entitled 

21 ‘Measurement of Energy and De22 mand Savings’ and section 11 

23 and appendix G of ANSI/ 

24 ASHRAE/IESNA Standard 


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1 90.1–2004 (or successor speci2 fications); and 

3 ‘‘(bb) for residential build4 ings, RESNET National Home 

5 Energy Rating Technical Guide6 lines, 2006 (Chapter 3 and Ap7 pendix A of 2006 Mortgage In8 dustry National Home Energy 

9 Rating System Standards) (or 

10 successor guidelines). 

11 ‘‘(F) SAMPLING FOR RESIDENTIAL BUILD12 INGS.— 

13 ‘‘(i) IN GENERAL.—The sponsor of 

14 any offset project that carries out similar 

15 energy conservation measures in multiple 

16 residential buildings may use representa17 tive sampling of the residential buildings to 

18 determine the aggregate baseline energy 

19 usage and energy savings of the offset 

20 projects. 

21 ‘‘(ii) REQUIREMENTS.—Representa22 tive sampling carried out under clause (i) 

23 shall be in accordance with sound statis24 tical methods, such that there is 95 perVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00145 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 cent confidence that the reported value is 

2 within 10 percent of the true mean. 

3 ‘‘(e) AVOIDED METHANE EMISSIONS FROM AGRI4 CULTURAL MANURE MANAGEMENT OPERATIONS.— 

5 ‘‘(1) IN GENERAL.—An offset project that cap6 tures and destroys methane from animal manure 

7 and organic food waste using an anaerobic digester 

8 in accordance with this subsection shall be eligible to 

9 receive allowances under this title. 

10 ‘‘(2) REQUIREMENTS.— 

11 ‘‘(A) IN GENERAL.—To be eligible to re12 ceive allowances under this subsection, an offset 

13 project described in paragraph (1) shall— 

14 ‘‘(i) involve the destruction of the por15 tion of methane generated by an anaerobic 

16 digester that would have been generated in 

17 the absence of the offset project through 

18 the uncontrolled anaerobic storage of ma19 nure or organic food waste; 

20 ‘‘(ii) use only manure-based anaerobic 

21 digester systems, using livestock manure to 

22 provide greater than 50 percent of annual 

23 digester feedstock; and 

24 ‘‘(iii) use organic food waste for an25 aerobic digesters only in a quantity that 


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1 would have been stored in anaerobic condi2 tions in the absence of the offset project. 

3 ‘‘(B) DETERMINATION OF MARKET PENE4 TRATION RATE.— 

5 ‘‘(i) IN GENERAL.—The market pene6 tration rate of a State shall be determined 

7 using the most recent market data avail8 able on the date of submission of an appli9 cation, in accordance with the following 

10 formula: MP (%) = MGAD / MGSTATE. 

11 ‘‘(ii) DESCRIPTION.—In the formula 

12 contained in clause (i)— 

13 ‘‘(I) ‘MGAD’ represents the aver14 age annual manure production for the 

15 number of dairy cows and swine serv16 ing all anaerobic digester projects in 

17 the applicable State on the date of 

18 submission of an application; and 

19 ‘‘(II) ‘MGSTATE’ represents the 

20 average annual manure production of 

21 all dairy cows and swine in the State 

22 on the date of submission of the appli23 cation). 

24 ‘‘(3) EMISSIONS BASELINE.— 


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1 ‘‘(A) IN GENERAL.—The emissions base2 line of an offset project that receives allowances 

3 under this subsection shall represent the poten4 tial emissions of the methane that, in the ab5 sence of the offset project, would have been— 

6 ‘‘(i) produced in a baseline scenario 

7 under uncontrolled anaerobic storage con8 ditions; and 

9 ‘‘(ii) released directly into the atmos10 phere. 

11 ‘‘(B) CALCULATION.— 

12 ‘‘(i) IN GENERAL.—The baseline 

13 methane emissions of an offset project 

14 under this subsection shall be calculated in 

15 accordance with the following formula: 

16 CO2e (tons) = (Vm × M)/2000 × GWP. 

17 ‘‘(ii) DESCRIPTION.—In the formula 

18 contained in clause (i)— 

19 ‘‘(I) ‘CO2e’ represents the poten20 tial carbon dioxide-equivalent emis21 sions due to calculated methane pro22 duction under site-specific anaerobic 

23 storage and weather conditions; 

24 ‘‘(II) ‘Vm’ (expressed in cubic 

25 feet) represents the volume of methVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00148 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 ane produced each month from deg2 radation of volatile solids in a baseline 

3 uncontrolled anaerobic storage sce4 nario (as calculated under clauses (iii) 

5 and (iv)) under site-specific storage 

6 and weather conditions for the facility 

7 at which the manure or organic food 

8 waste is generated; 

9 ‘‘(III) ‘M’ represents the mass of 

10 methane per cubic foot (with a default 

11 value of 0.04246 pounds per cubic 

12 foot at 1 atmosphere and 20 °C); and 

13 ‘‘(IV) ‘GWP’ represents the glob14 al warming potential of methane (with 

15 a default value of 23). 

16 ‘‘(iii) VOLATILE SOLIDS.— 

17 ‘‘(I) IN GENERAL.—For purposes 

18 of clause (ii)(II), the estimated quan19 tity of volatile solids degraded each 

20 month under the baseline uncontrolled 

21 anaerobic storage scenario (measured 

22 in kilograms) shall be calculated in ac23 cordance with the following formula: 

24 VSdeg = VSavail × f. 


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1 ‘‘(II) VOLATILE SOLIDS AVAIL2 ABLE FOR DEGRADATION.— 

3 ‘‘(aa) IN GENERAL.—In the 

4 formula contained in subclause 

5 (I), ‘VSavail’ represents the quan6 tity of volatile solids available for 

7 degradation in manure or organic 

8 food waste storage each month, 

9 determined in accordance with 

10 the following formula: VSavail = 

VSp + 1 11 ⁄2 VSin – VSout. 

12 ‘‘(bb) DESCRIPTION.—In the 

13 formula contained in item (aa)— 

14 ‘‘(AA) ‘VSp’ represents 

15 the quantity of volatile solids 

16 (expressed in kilograms) 

17 present in manure or or18 ganic food waste storage at 

19 the beginning of the applica20 ble month (including any 

21 manure or waste remaining 

22 from a preceding month); 

23 ‘‘(BB) ‘VSin’ represents 

24 the quantity of volatile solids 

25 (expressed in kilograms) 


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1 added to manure or organic 

2 food waste storage during 

3 the course of the applicable 

4 month, which is halved to 

5 represent the average mass 

6 of volatile solids available for 

7 degradation for the month; 

8 and 

9 ‘‘(CC) ‘VSout’ rep10 resents the quantity (ex11 pressed in kilograms) of 

12 volatile solids removed from 

13 the manure or organic food 

14 waste storage for land appli15 cation or export, which may 

16 be assumed based on stand17 ard farm practice. 

18 ‘‘(III) VAN’T HOFF-ARRHENIUS

19 FACTOR.— 

20 ‘‘(aa) IN GENERAL.—In the 

21 formula contained in subclause 

22 (I), ‘f’ represents the van’t Hoff23 Arrhenius factor, which measures 

24 the conversion efficiency of vola25 tile solids to methane, for a given 


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1 month, determined using a base 

2 temperature of 30 °C in accord3 ance with the following formula: f 

4 = exp[E(T2 – T1)]/[(GC × T1 × 

5 T2)]. 

6 ‘‘(bb) DESCRIPTION.—In the 

7 formula contained in item (aa)— 

8 ‘‘(AA) ‘E’ represents 

9 the activation energy con10 stant (with a default value 

11 of 15,175 cal/mol); 

12 ‘‘(BB) ‘T2’ represents 

13 the average monthly ambient 

14 temperature for the facility 

15 at which manure or organic 

16 food waste is generated (as 

17 converted from Celsius to 

18 Kelvin), as determined by 

19 the nearest National Weath20 er Service-certified weather 

21 station (if reported tempera22 ture °C > 5 °C; if reported 

23 temperature °C < 5 °C, 

24 then F = 0.104); 


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1 ‘‘(CC) ‘T1’ equals 

2 303.16; and 

3 ‘‘(DD) ‘GC’ represents 

4 the ideal gas constant (with 

5 a default value of 1.987 cal/ 

6 K mol). 

7 ‘‘(IV) GENERAL VOLATILE SOL8 IDS CALCULATIONS.— 

9 ‘‘(aa) IN GENERAL.—For 

10 purposes of this clause, a quan11 tity of volatile solids may be de12 termined in accordance with the 

13 following formula: VS = Mm × 

14 TS≠ × VS≠. 

15 ‘‘(bb) DESCRIPTION.—In the 

16 formula contained in item (aa)— 

17 ‘‘(AA) ‘Mm’ represents 

18 the mass (expressed in kilo19 grams) of manure or organic 

20 food waste produced per 

21 month; 

22 ‘‘(BB) ‘TS≠’ represents 

23 the concentration (expressed 

24 as a percentage) of total sol25 ids in manure or organic 


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1 food waste, as determined in 

2 accordance with the testing 

3 method of the Environ4 mental Protection Agency 

5 numbered 160.3 (as con6 tained in the document of 

7 the Environmental Protec8 tion Agency entitled ‘Meth9 ods for the Chemical Anal10 ysis of Water and Wastes’ 

11 (EPA/600/4–79/020)) (or a 

12 successor document); and 

13 ‘‘(CC) ‘VS≠’ represents 

14 the concentration (expressed 

15 as a percentage) of volatile 

16 solids in total solids, as de17 termined in accordance with 

18 the testing method of the 

19 Environmental Protection 

20 Agency numbered 160.4 (as 

21 contained in the document 

22 of the Environmental Pro23 tection Agency entitled 

24 ‘Methods for the Chemical 

25 Analysis of Water and 


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1 Wastes’ (EPA/600/4–79/ 

2 020)) (or a successor docu3 ment). 

4 ‘‘(iv) VOLUME OF METHANE PRO5 DUCED.— 

6 ‘‘(I) IN GENERAL.—For purposes 

7 of clause (ii)(II), the volume of meth8 ane produced each month from deg9 radation of volatile solids in a baseline 

10 uncontrolled anaerobic storage sce11 nario (measured in cubic feet) shall be 

12 calculated in accordance with the fol13 lowing formula: Vm = (VSdeg × Bo) × 

14 35.3147. 

15 ‘‘(II) DESCRIPTION.—In the for16 mula contained in subclause (I)— 

17 ‘‘(aa) ‘VSdeg’ represents the 

18 quantity (measured in kilograms) 

19 of volatile solids degraded, as de20 termined in accordance with 

21 clause (iii); and 

22 ‘‘(bb) ‘Bo’ represents the 

23 quantity of manure or organic 

24 food waste type-specific max25 imum methane generation conVerDate Aug 31 2005 01:41 Apr 23, 2007 Jkt 059200 PO 00000 Frm 00155 Fmt 6652 Sfmt 6201 E:\BILLS\S1168.IS S1168

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1 stant (expressed as cubic meters 

2 of methane per kilogram of vola3 tile solids degraded), as deter4 mined in accordance with sub5 clause (III). 

6 ‘‘(III) METHANE GENERATION

7 CONSTANT.—For purposes of sub8 clause (II)(bb), the quantity of ma9 nure or organic food waste type-spe10 cific maximum methane generation 

11 constant shall be— 

12 ‘‘(aa) for dairy cow manure, 

13 0.24 cubic meters of methane per 

14 kilogram of volatile solids de15 graded; and 

16 ‘‘(bb) for any other type of 

17 manure— 

18 ‘‘(AA) the constant 

19 specified in the document of 

20 the Environmental Protec21 tion Agency entitled ‘Inven22 tory of United States Green23 house Gas Emissions and 

24 Sinks: 1990–2004, Annex 

25 3.10, Table 3–89’ and dated 


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1 April 2006 (or a successor 

2 document); or 

3 ‘‘(BB) such other meth4 ane generation constant as 

5 the sponsor of the applicable 

6 offset project may specify, if 

7 the sponsor provides to the 

8 Administrator appropriate 

9 justification and documenta10 tion for the constant. 

11 ‘‘(4) EMISSIONS REDUCTIONS.— 

12 ‘‘(A) IN GENERAL.—The emissions reduc13 tions of an offset project that receives allow14 ances under this subsection shall be determined 

15 based on the potential emissions (measured in 

16 tons of carbon dioxide equivalent) of methane 

17 that would have been produced, and released di18 rectly into the atmosphere, in the absence of 

19 the offset project under a baseline scenario that 

20 represents uncontrolled anaerobic storage condi21 tions, as determined in accordance with para22 graph (3), taking into account fugitive methane 

23 emissions that may be released into the atmos24 phere through leaks in the anaerobic digester 

25 equipment. 


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1 ‘‘(B) LIMITATION.—The emissions reduc2 tions of an offset project shall not exceed the 

3 potential emissions of the anaerobic digester of 

4 the offset project, as determined based on the 

5 annual volume of methane produced by the an6 aerobic digester and monitored in accordance 

7 with paragraph (5). 

8 ‘‘(C) REGIONAL-TYPE DIGESTER OFFSET

9 PROJECTS.— 

10 ‘‘(i) IN GENERAL.—If an offset 

11 project is a regional-type digester offset 

12 project, as determined by the Adminis13 trator, carbon dioxide emissions due to 

14 transportation of manure and organic food 

15 waste from the site at which the manure 

16 and organic food waste was generated to 

17 the anaerobic digester shall be subtracted 

18 from the emissions reduction value deter19 mined under paragraph (3) for the offset 

20 project. 

21 ‘‘(ii) DETERMINATION OF CARBON DI22 OXIDE EMISSIONS.—For purposes of clause 

23 (i), carbon dioxide emissions due to trans24 portation of manure and organic food 

25 waste from the site at which the manure 


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1 and organic food waste was generated to 

2 the anaerobic digester shall be determined 

3 in accordance with 1 of the following meth4 ods: 

5 ‘‘(I) Documentation of all quan6 tities of fuel used to transport from 

7 off-site all shipments of manure and 

8 organic food waste to the anaerobic 

9 digester of the offset project during 

10 the applicable year (including a log of 

11 transport miles for each shipment), 

12 from which carbon dioxide emissions 

13 shall be determined through the appli14 cation of the following emissions fac15 tors (based on the type of fuel used): 

16 ‘‘(aa) For diesel fuel, 22.912 

17 pounds of carbon dioxide per gal18 lon. 

19 ‘‘(bb) For gasoline, 19.878 

20 pounds of carbon dioxide per gal21 lon. 

22 ‘‘(cc) For any other fuel, 

23 such emissions factor as the Ad24 ministrator determines to be ap25 propriate. 


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1 ‘‘(II) Documentation of the total 

2 quantity (expressed in tons) of ma3 nure and organic food waste trans4 ported from off-site for input into the 

5 anaerobic digester of the offset project 

6 during the applicable year (including 

7 a log of transport miles for each ship8 ment), as monitored under paragraph 

9 (5), from which carbon dioxide emis10 sions shall be determined through the 

11 application of the following ton-mile 

12 transport emission factors (based on 

13 the type of fuel used): 

14 ‘‘(aa) For diesel fuel, 0.131 

15 pounds of carbon dioxide per ton16 mile. 

17 ‘‘(bb) For gasoline, 0.133 

18 pounds of carbon dioxide per ton19 mile. 

20 ‘‘(cc) For any other fuel, 

21 such emissions factor as the Ad22 ministrator determines to be ap23 propriate. 

24 ‘‘(5) MONITORING AND VERIFICATION.— 


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1 ‘‘(A) IN GENERAL.—The sponsor of each 

2 offset project that receives allowances under 

3 this subsection shall— 

4 ‘‘(i) ensure that the offset project uses 

5 a system that provides metering of biogas 

6 volumetric flow rate and determination of 

7 methane concentration; and 

8 ‘‘(ii) submit to the Administrator an 

9 annual report, including a description of 

10 the monthly biogas volumetric flow rate 

11 and methane concentration determinations 

12 for the offset project. 

13 ‘‘(B) REGIONAL-TYPE DIGESTER OFFSET

14 PROJECTS.— 

15 ‘‘(i) IN GENERAL.—The sponsor of an 

16 offset project that is a regional-type di17 gester offset project, as determined by the 

18 Administrator, shall ensure monthly sam19 pling of the manure and organic food 

20 waste from each distinct source supplying 

21 the anaerobic digester to determine the 

22 quantity of volatile solids present in the 

23 manure and waste. 

24 ‘‘(ii) SUPPORTING MATERIAL.—In the 

25 annual report relating to the offset project 


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1 submitted under subparagraph (A)(ii), the 

2 sponsor shall provide supporting material 

3 and receipts tracking the monthly receipt 

4 from each supplier to the offset project of 

5 quantities of manure and organic food 

6 waste (measured in kilograms) for the an7 aerobic digester. 

8 ‘‘(iii) EMISSIONS REDUCTION CAL9 CULATION REQUIREMENT.—The emissions 

10 reduction of an offset project described in 

11 clause (i) shall be calculated according to, 

12 and apportioned among sources based on, 

13 as determined in accordance with para14 graphs (3) and (4)— 

15 ‘‘(I) the mass (measured in kilo16 grams) of manure and organic food 

17 waste digested as a result of the offset 

18 project; and 

19 ‘‘(II) the percentage of volatile 

20 solids present before digestion. 

21 ‘‘(C) ADDITIONAL MONTHLY SAMPLES.— 

22 The sponsor of an offset project that includes 

23 the digestion of organic food waste shall ensure 

24 monthly sampling of the organic food waste to 

25 determine in accordance with paragraphs (3) 


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1 and (4), and apportion accordingly, the quan2 tity of volatile solids present in the waste before 

3 digestion. 

4 ‘‘(D) OTHER MONITORING REQUIRE5 MENTS.—In addition to the requirements of 

6 subparagraphs (A) through (C), an offset 

7 project shall meet the applicable requirements 

8 contained in the following table: 

‘‘Input Monitoring Requirements 

Input parameter Measurement unit Frequency of 

sampling Sampling method 

Influent flow into 

digester.

Kilograms per 

month (wet 

weight).

Monthly total into 

digester 

Recorded weight; 

digester influent pump flow; 

livestock population and application of 

standard 

Influent total solids concentration.Percent of sample Monthly, depending on recorded 

variations 

EPA Method 

Number 160.3, 

Methods for the 

Chemical Analysis of Water 

and Wastes 

(EPA/600/4– 

79/020) 

Influent volatile 

solids concentration.

Percent of total 

solids.

Monthly, depending on recorded 

variations 

EPA Method 

Number 160.4, 

Methods for the 

Chemical Analysis of Water 

and Wastes 

(EPA/600/4– 

79/020) 

Average monthly 

ambient temperature.

Temperature 

(Celsius).

Monthly (based 

on farm averages) 

Closest National 

Weather Service-certified 

weather station 

9 ‘‘(f) ELIGIBLE BIOMASS.— 


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1 ‘‘(1) IN GENERAL.—An offset project that co2 fires eligible biomass to reduce emissions of carbon 

3 dioxide and that meets the requirements of this sub4 section shall be eligible to receive allowances under 

5 this title. 

6 ‘‘(2) APPLICATION.—To be eligible to receive an 

7 allowance under this subsection, the owner or oper8 ator of an offset project described in paragraph (1) 

9 shall submit to the Administrator an application at 

10 such time, in such manner, and containing such in11 formation as the Administrator may require. 

12 ‘‘(3) EMISSIONS CALCULATIONS.— 

13 ‘‘(A) AS-FIRED CARBON DIOXIDE EMIS14 SIONS FACTOR.— 

15 ‘‘(i) IN GENERAL.—The as-fired car16 bon dioxide emissions factor of an offset 

17 project under this subsection may be deter18 mined— 

19 ‘‘(I) as measured and recorded 

20 by a continuous emissions monitor of 

21 the offset project for each period dur22 ing which only eligible biomass was 

23 fired by the offset project; or 

24 ‘‘(II) in accordance with clause 

25 (ii) or (iii), as applicable. 


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1 ‘‘(ii) SOLID FUEL.— 

2 ‘‘(I) IN GENERAL.—The as-fired 

3 carbon dioxide emissions factor of an 

4 offset project under this subsection 

5 that uses solid fuel shall be deter6 mined in accordance with the fol7 lowing formula: CO2 lbs/MMBtu = 

8 ((C × FIN)/HI) (44/12). 

9 ‘‘(II) ABBREVIATIONS.— 

10 ‘‘(aa) IN GENERAL.—In the 

11 formula contained in subclause 

12 (I)— 

13 ‘‘(AA) ‘C’ represents 

14 the carbon content of bio15 mass (expressed as a per16 centage by dry weight) for a 

17 distinct fuel type; 

18 ‘‘(BB) ‘FIN’ represents 

19 the total biomass fuel input 

20 (expressed in pounds) for a 

21 distinct fuel type; and 

22 ‘‘(CC) ‘HI’ represents 

23 the heat input, as-fired (ex24 pressed in MMBtus), as de25 termined in accordance with 


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1 the following formula: HI = 

2 è (HHVDRY (1– 

3 MCWAS-FIRED-i)) × FIN-i. 

4 ‘‘(bb) DESCRIPTION.—In the 

5 formula contained in item 

6 (aa)(CC)— 

7 ‘‘(AA) the figure above 

8 the sigma shall be ‘n’; 

9 ‘‘(BB) the figure below 

10 the sigma shall be ‘i = 1’; 

11 ‘‘(CC) ‘HHVDRY’ rep12 resents the higher heating 

13 value (expressed in Btu/lb) 

14 on a dry basis for a distinct 

15 fuel type fired; 

16 ‘‘(DD) ‘MCWAS-FIRED-i’ 

17 represents the moisture con18 tent on a wet basis (ex19 pressed as a percentage) for 

20 each shipment i fired; and 

21 ‘‘(EE) ‘FIN-i’ represents 

22 the biomass fuel input (ex23 pressed in pounds) for each 

24 shipment i fired. 

25 ‘‘(iii) GASEOUS FUEL.— 


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1 ‘‘(I) IN GENERAL.—The as-fired 

2 carbon dioxide emissions factor of an 

3 offset project under this subsection 

4 that uses gaseous fuel shall be deter5 mined in accordance with the fol6 lowing formula: CO2 lbs/MMBtu = (C 

7 × (FIN × D))/HI) (44/12). 

8 ‘‘(II) ABBREVIATIONS.— 

9 ‘‘(aa) IN GENERAL.—In the 

10 formula contained in subclause 

11 (I)— 

12 ‘‘(AA) ‘C’ represents 

13 the carbon content of bio14 mass (expressed as a per15 centage by weight) for a dis16 tinct fuel type; 

17 ‘‘(BB) ‘FIN’ represents 

18 the total biomass fuel input 

19 (expressed in pounds) for a 

20 distinct fuel type; 

21 ‘‘(CC) ‘D’ represents 

22 the density of biogas (ex23 pressed in pounds per stand24 ard cubic feet) for a distinct 

25 fuel type; and 


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1 ‘‘(DD) ‘HI’ represents 

2 the heat input, as-fired (ex3 pressed in MMBtus), as de4 termined in accordance with 

5 the following formula: HI = 

6 HHV × FIN. 

7 ‘‘(bb) DESCRIPTION.—In the 

8 formula contained in item 

9 (aa)(DD)— 

10 ‘‘(AA) ‘HHV’ rep11 resents the higher heating 

12 value (expressed in Btus per 

13 standard cubic feet) for a 

14 distinct fuel type; and 

15 ‘‘(BB) ‘FIN’ represents 

16 the biogas fuel input (ex17 pressed in standard cubic 

18 feet). 

19 ‘‘(B) CARBON DIOXIDE EMISSIONS DUE TO

20 FIRING OF ELIGIBLE BIOMASS.— 

21 ‘‘(i) IN GENERAL.—The carbon diox22 ide emissions due to firing of eligible bio23 mass of an offset project under this sub24 section shall be determined in accordance 


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1 with the following formula: CO2 tons = è 

2 (BHI-i × BEF-i × BOF-i)/2000. 

3 ‘‘(ii) ABBREVIATIONS.—In the for4 mula contained in clause (i)— 

5 ‘‘(I)(aa) the figure above the 

6 sigma shall be ‘n’; and 

7 ‘‘(bb) the figure below the sigma 

8 shall be ‘i = 1’; 

9 ‘‘(II) ‘BHI-i’ represents the eligi10 ble biomass heat input, as-fired (ex11 pressed in MMBtus), for the reporting 

12 quarter for each distinct type i of eli13 gible biomass fired; 

14 ‘‘(III) ‘BEF-i’ represents the eligi15 ble biomass emissions factor for the 

16 reporting quarter (expressed in 

17 pounds of carbon dioxide per MMBtu) 

18 for each distinct type i of eligible bio19 mass fired; and 

20 ‘‘(IV) ‘BOF-i’ represents the eligi21 ble biomass oxidation factor for each 

22 distinct type i of eligible biomass 

23 fired, derived for solid fuel based on 

24 the ash content of the eligible biomass 

25 fired and the carbon content of that 


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1 ash, as determined pursuant to para2 graph (4)(A) (with a default value for 

3 gaseous biomass fuel of 0.995). 

4 ‘‘(C) APPLICABLE STANDARDS.—Each fuel 

5 sampling method and technology used to make 

6 a calculation under this paragraph shall be in 

7 accordance with the applicable standards con8 tained in the New York State Renewable Port9 folio Standard Biomass Guidebook dated May 

10 2006 (or successor standards). 

11 ‘‘(4) MONITORING AND VERIFICATION.— 

12 ‘‘(A) IN GENERAL.—Not less frequently 

13 than once each quarter of each calendar year 

14 during which an offset project receives an allow15 ance under this title, the owner or operator of 

16 the offset project shall submit to the Adminis17 trator a report describing— 

18 ‘‘(i) a chemical analysis (including 

19 carbon content and heating value) of eligi20 ble biomass fired by the offset project; 

21 ‘‘(ii) the moisture content of eligible 

22 biomass for each shipment received for fir23 ing by the offset project; 


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1 ‘‘(iii) the total eligible biomass fuel 

2 input (expressed in units of mass or vol3 ume, as appropriate) to the offset project; 

4 ‘‘(iv) the total eligible biomass heat 

5 input, on an as-fired basis (expressed in 

6 MMBtus), to the offset project; 

7 ‘‘(v) the heat input rate (expressed in 

8 MMBtus per hour) of eligible biomass to 

9 the offset project; 

10 ‘‘(vi) the fuel feed rate of eligible bio11 mass to the offset project (expressed in 

12 units of mass or volume per hour, as ap13 propriate); 

14 ‘‘(vii) the total number of operating 

15 hours during which eligible biomass was 

16 fired by the offset project; 

17 ‘‘(viii) the number of tons of carbon 

18 dioxide emitted from the offset project due 

19 to firing of eligible biomass; 

20 ‘‘(ix) the fuel sampling frequency, 

21 monitoring technology, and methodology 

22 used by the offset project, including sup23 porting documentation; 


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1 ‘‘(x) the additional information re2 quired under subparagraph (B), if any; 

3 and 

4 ‘‘(xi) the carbon dioxide emissions fac5 tor of the offset project, calculated in ac6 cordance with paragraph (3). 

7 ‘‘(B) ADDITIONAL DATA REQUIRE8 MENTS.— 

9 ‘‘(i) INDEPENDENT SYSTEM OPER10 ATOR DATA.—The owner or operator of an 

11 offset project located in a State that re12 quires the use of information submitted to 

13 an independent system operator to estab14 lish the megawatt-hours of the offset 

15 project shall submit to the Administrator, 

16 together with the report under subpara17 graph (A)— 

18 ‘‘(I) the megawatt-hour value 

19 submitted to the independent system 

20 operator; and 

21 ‘‘(II) a statement certifying that 

22 the megawatt-hour value reflects the 

23 total actual electrical output for all 

24 offset projects at the facility used by 

25 the independent system operator to 


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1 determine the settlement resources of 

2 energy market participants. 

3 ‘‘(ii) GROSS OUTPUT DATA.—The 

4 owner or operator of an offset project that 

5 submits to the Administrator information 

6 described in clause (i), and that is located 

7 in a State that requires the use of gross 

8 output data with respect to the offset 

9 project, shall submit to the Administrator, 

10 together with the information under clause 

11 (i), an electronic data report describing the 

12 gross output (expressed in megawatts) of 

13 the offset project, as calculated by adding, 

14 for each hour of the applicable quarter 

15 during which the offset project was in op16 eration, the product obtained by multi17 plying— 

18 ‘‘(I) the gross output (expressed 

19 in megawatts) of the offset project for 

20 the hour; and 

21 ‘‘(II) the proportion that— 

22 ‘‘(aa) the number of minutes 

23 of the hour during which the off24 set project was in operation; 

25 bears to 


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1 ‘‘(bb) 60.’’. 

Æ 


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