IN THE UNITED STATES COURT OF APPEALS

FOR THE DISTRICT OF COLUMIA CIRCUIT

)

UTILITY AIR REGULATORY GROUP, )

) v. )Petitioner, )

) AGENCY, ) U.S. ENVIRONMNTAL PROTECTION )

)

Respondent. )

)

No. 09-1333

SETTLEMENT AGREEMENT

WHREAS the Utility Air Regulatory Group in No. 09-1333 (referred to as

"Petitioner") filed in the Court of Appeals for the D.C. Circuit a petition for review

captioned above that challenges the regulation titled "Mandatory Reporting of

Greenhouse Gases," 74 Fed. Reg. 56,330 (Oct. 30,2009) ("GHG Reporting

Rule"), which was promulgated under the Clean Air Act by the Environmental

Protection Agency ("EP A");

WHREAS No. 09-1333 has been consolidated with other petitions

challenging the GHG Reporting Rule, with No. 09-1325 designated as the lead

petition;

WHREAS EP A intends to undertake a rulemaking to make certain

amendments to portions of the GHG Reporting Rule that may resolve the concerns

raised by Petitioner in its petition for review;

WHREAS the EP A and Utility Air Regulatory Group (collectively the

"Parties") wish to implement this Settlement Agreement ("Agreement") to avoid

protracted and costly litigation and to preserve judicial resources;

- i -
NOW, THEREFORE, the Parties, intending to be bound by this Agreement,

hereby stipulate and agree as follows:

1. Promptly after execution of this Agreement, the Parties wil notify the

Court that they have reached a settlement on issues 1 and 2 in UARG's

Nonbinding Statement of Issues (filed Feb. 8,2010), subject to required notice

provisions described in paragraph 7 below, and will request that No. 09-1333 be

severed from lead No. 09-1325 and the other consolidated cases and be held in

abeyance pending finalization and completion of the terms of their settlement,

with EP A to file status reports on 120-day intervals. The Parties wil further

request in that motion that issue 3 in UARG's Nonbinding Statement of Issues be

severed from No. 09-1333 and placed in a new docket, to be held in abeyance,

with EP A to file status reports on 120-day intervals.

2. EP A shall as expeditiously as practicable publish a notice of proposed

rulemaking on the issue of whether the GHG Reporting Rule should be amended

by the inclusion of proposed amendments of the same substance as set forth in

Attachment A to this Agreement.

3. If and when EP A promulgates in final form an amendment to the

GHG Reporting Rule that includes changes that are substantially the same

substance as set forth in Attachment A to this Agreement, then Petitioner shall

promptly file a stipulation of dismissal with prejudice of No. 09-1333, or in the

event that not all such changes were made, a stipulation of dismissal with

prejudice of No 09-1333 for the issues that correspond to such changes that were

made, with the creation of a new docket for those issues that were not resolved.

- 2 -
Such stipulation of dismissal shall be in accordance with Rule 42 of the Federal

Rules of Appellate Procedure, with each party to bear its own costs and attorneys'

fees. In addition, Petitioner shall not challenge the validity of the portion of the

final rule adopting such amendments of substantially the same substance as set

forth in Attachment A in any court or administrative proceeding, and the right to

raise such challenge is waived, provided that Petitioner reserves any rights it may

have to challenge in any court or administrative proceeding any portion of such

final rule that is not of substantially the same substance as set forth in Attachment

A to this Agreement.

4. If and when EP A promulgates in final form an amendment to the

GHG Reporting Rule that includes changes that are substantially the same

substance as set forth in Attachment A to this Agreement, Petitioner's pending

administrative petition for reconsideration of the GHG Reporting Rule, or the

issues raised in that petition that correspond to such changes in the event not all

such changes are made, shall be deemed withdrawn.

5. For purposes of this Agreement, EPA and Petitioner recognize that

the publication of new or modified regulations in the proposed or final rule that

address other matters or provisions than that set forth in Attachment A or that in

the proposed or final rule are otherwise substantially more detailed, extensive and

comprehensive than that set forth in Attachment A would not on that basis alone

cause the final changes referenced in paragraphs 2, 3 and 4 above not to be the

same substance or substantially the same substance as set forth in Attachment A.

6. IfEPA does not take action in accordance with the terms of this

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agreement then Petitioner's sole remedy under this Agreement regarding the rules

under review in these cases shall be the right to request that the Court lift the stay

of proceedings and establish a schedule for briefing and oral argument.

7. EP A and Petitioner agree and acknowledge that before this

Agreement is final, EP A must provide notice in the Federal Register and an

opportunity for comment pursuant to Clean Air Act section 113(g), 42 U.S.C. §

7413(g). EPA shall submit said notice of this Agreement to the Federal Register

for publication as expeditiously as possible. After this Agreement has undergone

an opportunity for notice and comment, the Administrator and/or the Attorney

General, as appropriate, shall promptly consider any such written comments in

determining whether to withdraw or withhold her consent to the Agreement, in

accordance with section i 13(g) of the Clean Air Act. This Agreement shall

become final on the date that EP A provides written notice of such finality to

Petitioner.

8. Nothing in the terms of this Agreement shall be construed to limit or

modify the discretion accorded EP A by the Clean Air Act or by general principles

of administrative law.

9. Any obligations of EP A to obligate or expend funds under this

Agreement are subject to the availability of appropriations in accordance with the

Anti-Deficiency Act, 31 U.S.C. § 1341. This Settlement Agreement shall not be

construed to require the United States to obligate or pay funds in contravention of

said Anti-Deficiency Act, 31 U.S.C. § 1341.

10. Except as provided in this Settlement Agreement, none of the parties

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hereto waives or relinquishes any legal rights, claims, or defenses it may have.

11. The undersigned representatives of each part certify that they are

fully authorized by the party that they represent to bind that respective party to the

terms of this Agreement.

IGNACIA S. MORENO

Assistant Attorney General

Environment and Nat. Resources Div.

DAVID J. KALAN

U.S. Department of Justice

Environmental Defense Section

PO Box 23986

Washington D.C. 20026-3986

(202) 514-0997

LAURN FREEMAN

Hunton & Wiliams LLP

1900 K Street, N.W.

Washington, DC 20006

(202) 778-2248

Counsel for United States

Environmental Protection Agency

Counsel for Utility Air

Regulatory Group

Dated: Dated:

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DRAFT -- CONFIDENTIAL SETTLEMENT COMMUNICATION

ATTACHMENT A

(i) Anual emissions (excluding including biogenic CO2) aggregated for all GHG from

all applicable source categories in subpars C through 11 of this part and expressed in metric tons

of C02e calculated using Equation A- 1 of this subpart.

(ii) Anual emissions of biogenic C02 aggregated for all applicable source categories in

subparts C through JJ ofthis par in metric tons. Units that use the methodologies in par 75 of

this chapter to calculate CO) mass emissions are not required to separately report biogenic CO)

emissions, but may do so as an option.

(iii) Annual emissions from each applicable source category in subparts C through 11 of

this par, expressed in metric tons of each applicable GHG listed in this paragraph (4)(iii)(A)

through (4)(iii)(E).

(A) Biogenic CO2. Units that use the methodologies in part 75 of this chapter to calculate

CO) mass emissions are not required to separately report biogenic CO) emissions, but may do so

as an option.

(B) CO2 (excluding including biogenic COi).

(C) CH4.

(D) N20.

(E) Each fluorinated GHG (including those not listed in Table A-I of this subpar).

40 C.F.R. § 98.3( c)( 4)(i)-(iii)

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(4) Missing data computations. For each missing data event, also retain a record of the

duration cause of the event, and the corrective actions taken to restore malfunctioning monitoring

equipment, the cause of the event, and the actions taken to prevent or minimize occurrence in the fu.

40 C.F.R. § 98.3(g)(4)

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(h) Annual GHG report revisions.

ffThe owner or operator shall submit a revised annual GHG report within 45 days of

discovering that or being notified by BPi\' of errors in an annual GHG report that the owner or
operator previously submitted contains one or more substantive errors. The revised report must

correct all identified substantive errors.

(2) The Administrator may notify the owner or operator in writing that an annual GHG

report previously submitted by the owner or operator contains one or more substantive errors.

Such notification wil identify each such substantive error. The owner or operator shalL. within

45 days of receipt of the notification, either resubmit the report that, for each identified

substantive error, corrects the identified substantive error (in accordance with the applicable

requirements of part 98) or provide information demonstrating that the previously submitted

report does not contain the identified substantive error or that the identified error is not a

substantive error.

(3) A substantive error is an error that impacts the quantity of GHG emissions reported or

otherwise prevents the reported data from being validated or verified.

(4) Notwithstanding paragraphs (h)(1) and (2) of this section, upon request by the owner

or operator, the Administrator may provide reasonable extensions of the 45-day period for

submission of the revised report or information under paragraphs (h)(l) and (2). ifthe

Administrator receives a request for extension of the 45-day period, by email to an address

prescribed by the Administrator, at least 2 business days prior to the expiration of the 45-day

period, and the Administrator does not respond to the request by the end of such period, the

extension request is deemed to be automatically granted for 30 more days. During the automatic

30-day extension, the Administrator wil determine what extension, if any, beyond the automatic

extension is reasonable and wil provide any such additional extension.

Ji The owner or operator shall retain documentation for 3 years to support any

revisions made to an anual GHG report.

40 C.F.R. § 98.3(h)

* * * The accuracy specifications in this paragraph (i) do not apply where either the use of

company records (as defined in S98.6)or the use of "best available information" is specified in

an applicable subpar of this part to quantify fuel usage and/or other parameters. Furher, the

provisions ofthis paragraph (i) do not apply to stationary fuel combustion units that use the

methodologies in par 75 of this chapter to calculate CO) mass emissions. * * *

Intro paragraph in 40 C.F.R. & 98.3(i)

(ii) The minimum required sampling frequency number of HHV samples required

sampling frequency for determining the annual average HHV (e.g., monthly, quarterly, semiannually, or by lot) is specified (e.g., monthly, quarterly, semi annually, or by lot) in §98.34.

The method for computing the anual average HHV is a function of unit size and how frequently

you perform or receive from the fuel supplier the results of fuel sampling for HHV. The method

is specified in paragraph (a)(2)(ii)(A) or (a)(2)(ii)(B) of this section, as applicable.

2
(A) If the results of fuel sampling are received monthly or more frequently, then for each

unit with a maximum rated heat input capacity greater than or equal to i 00 mmBtulr (or for a

group of units that includes at least one unit of that size). the annual average HHV shall be

calculated using Equation C-2b of this section. If multiple HHV determinations are made in any

month, average the values for the month arithmetically.

(B) If the results of fuel sampling are received less frequently than monthly, thor, for

a unit with a maximum rated heat input capacity less than 100 mmBtu/ (or a group of such

units) regardless of the sampling frequency, the annual average HHV shall be computed as the

mithmetic average HHV for all values for the year (including valid samples and substitute data

values under §98.35).

40 C.F.R. § 98.33(a)(2)(ii)

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(i)iv) For units that qualify to use the alternative CO) emissions calculation methods in

paragraphs (a)(5)(i) through (a)(5)(iii) of this section, lifboth biomass and fossil fuel are

com busted during the year, separate calculation and reporting of the biogenic CO) mass

emissions determine and report the biogenic CO;l mass emissions separately, (as described in

paragraph (e) of this section) is optionaL.

40 C.F.R. § 98.33(a)(5)(iii)(D)

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(4) * * *

(HI)A = Cumulative annual heat input derived from combustion of the fuel, derived from

the electronic data reports required undcr §75.61 of this chaptcr or, for Tier '1

units, from the best available information as described in paragraph (c)( '1)(ii) of

this section (mmBtti).

* * *

(i) If only one type of fuel listed in Table C-2 is combusted durinK normal operationthe

reporting year, substitute the cumulative annual heat input from combustion of the fuel into

Equation C- 10 of this section to calculate the annual CH4 or N20 emissions. For units in the

Acid Rain Program and units that report heat input data to EP A year-round according to part 75

of this chapter, obtain the cumulative annual heat input directly from the electronic data reports

required under &75.64 of this chapter. For Tier 4 units, use the best available information, as

described in paragraph (c)(4)(ii)(C) of this section, to estimate the cumulative annual heat input

(Hl)~

(ii) If more than one type offuel listed in Table C-2 is combusted during normal

operation the reporting year, use Equation C- 10 of this section separately for each type of fueL,

except as provided in, except as provided in -paragraph (c)(4)(ii)(B) of this section. Determine

3
the appropriate values of (Hl)A as follows:~ If flow rate and diluent gas monitors are used to

measure the unit heat input,

(A) For units in the Acid Rain Program and other units that report heat input data to

EPA year-round according to part 75 of this chapter, obtain (Hl)A for each type of fuel from the

electronic data reports required under &75.64 of this chapter, except as otherwise provided in

paragraphs (c)(4)(ii(B) and (c)(4)(ii)(D) of this section.

e

(B) For a unit that uses CEMS to monitor hourly heat input according to part 75 of this 

chapter, the value of (HIh obtained from the electronic data reports under &75.64 of this chapter

may be attributed exclusively to the fuel with the highest F-factor, when the reporting option in

3.3.6.5 of appendix F to part 75 ofthis chapter is selected and implemented.

(C) For Tier 4 units, use the best available information (e.g., fuel feed rate

measurements, fuel heating values, engineering analysis) to estimate the annual heat input from

value of(Hl)A-each type of fueL. Instrumentation used to make these estimates is not subject

to the calibration requirements of &98.3(i) or to the OA requirements of &98.34.

(D) Units in the Acid Rain Program and other units that report heat input data to EP A

year-round according to part 75 of this chapter may use the best available information described

in paragraph (c)(4)(ii)(C) of this section, to estimate (HI)~ for each fuel type, whenever fuelspecific heat input values canot be directly obtained from the electronic data reports under

&75.64 of this chapter.

40 C.F.R. § 98.33(c)

(e) * * * Notwithstanding these requirements, separate reporting of biogenic CO?

emissions is optional for units subject to subpar D of this par and for units that use the CO)

mass emissions calculation methodologies in par 75 of this chapter, pUrsuant to paragraph (a)(5)

of this section: however, if the owner or operator opts to report biogenic CO) emissions

separately for these units, the appropriate methodes) in this paragraph (e) shall be used.

40 C.F.R. § 98.33(e)

(ii) For coal and fuel oil, and for any other solid or liquid fuel that is delivered in lots,

analysis of at least one representative sample from each fuel lot is required. For fuel oiL. as an

alternative to sampling each fuel lot. a sample may be taken upon each addition of oil to the

unit's storage tank. Flow proportional sampling, continuous drip sampling, or daily manual oil

sampling may also be used, in lieu of sampling each fuel lot. For the purposes of this section, a

fuel lot is defined as aeither:

(A) A shipment or delivery of a single fuel (e.g" ship load, barge load, group of trucks,

oil delivery via pipeline from a tank farm, group of railroad cars, etc.)~: or

4
(B) If multiple deliveries of a particular type of fuel are received from the same supply

source in a given calendar month, the deliveries for that month are considered, collectively, to

comprise a fuel lot, requiring only one representative sample.

40 C.F.R. § 98.34(a)(2)(ii)

(6) You must Y!!se one of the followingan applicable appropriate fuel sampling and

analysis methods. You may use a methods published by a consensus standards organization if

such a method exists, or yOU may use industry consensus standard practice in this paragraph

Wfto determine the high heat values. Consensus-based standards organizations include, but

are not limited to, the following: ASTM hlternationaI. the American National Standards Institute

(ANSI), the American Gas Association (AGA), the American Society of Mechanical Engineers

(ASME), the American Petroleum Institute (API), and the North American Energy Standards

Board (NAESB). Alternatively, for gaseous fuels, the HHV may be calculated using

chromatographic analysis together with standard heating values of the fuel constituents, provided

that the gas chromatograph is operated, maintained, and calibrated according to the

manufacturer's instructions. The methodes) used shall be documented in the monitoring plan

required under &98.3(g)(5).

(i) /\.STM D1809 06 Standard Test Method for Heat of Combustion of Liquid 

Hydrocarbon Fuels by Bomb Calorimeter (Precision Method) (incorporated by reference, see

§98.7).

(ii) j\STM D210 02 (Reapproved 2007) Standard Test Method for Heat of Combustion

of Liquid Hydrocarbon Fuels by Bomb Calorimeter (incorporated by reference, see §98.7).

(iii) /\STM DI826 91 (Reapproved 2003) Standard Test Method for Calorific (Heating)

Value of Gases in Natural Gas Range by Continuous Recording Calorimeter (incorporated by

reference, see §98.7).

(iv) /\STM D3588 98 (Reapproved 2003) Standard Practice for Calculating Heat Value,

Compressibility Factor, and Relative Density of Gaseous Fuels (incorporated by reference, see

§98.7).

(':) ASTM D1891 89 (Reapproved 2006) Standard Test Method for Heating Value of

Gases in Natural Gas Range by Stoichiometric Combustion (incorporated by reference, see

§98.7).

(vi) GP/\. Standard 2172 09 Calculation of Gross Heating Value, Relative Density,

Compressibility and Theoretical Hydrocarbon Liquid Content for Natural Gas Mixtures for

Custody Transfer (incorporated by reference, see §98.7).

(vii) GP/, Standard 2261 00, Analysis for Natural Gas and Similar Gaseous Mixtures by

Gas Chromatography (incorporated by reference, see §98.7).

(viii) LA,STM D5865 07a, Standard Test Method for Gross Calorific Value of Coal and

Coke (incorporated by reference, see §98.7).

40 C.F.R. §98.34(a)(6)

5
(1) You must Gçalibrate each oil and gas flow meter according to §98.3(i) and the

provisions of this paragraph (b )il.

(i) Perform calibrations using any ofthe test methods and procedures in this paragraph

(b)(1 )(i). The methode s) used shall be documented in the monitoring plan required under

§98.3(g)(5).

(A) You may use A~ appropriate flow meter calibration method published by a

consensus standards organization, if such a method existsapplicable flow meter test method

listed in paragraphs (b)( 1 )(i) through (b)( 1)('1iii) of this section. Consensus-based standards

organizations include, but are not limited to, the following: ASTM International. the American

National Standards Institute (ANSI), the American Gas Association (AGA). the American

Society of Mechanical Engineers (ASME), the American Petroleum Institute (API), and the

North American Energy Standards Board (NAESB).

(B) You may use Tlhe calibration procedures specified by the flow meter manufacturer.

(C) You may use A~n industry-accepted or industry consensus standard calibration

practice 

* * *

40 C.F.R. §98.34(b)(1)

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(B) For coal and fuel oil and for any other solid or liquid fuel that is delivered in lots,

analysis of at least one representative sample from each fuel lot is required. For fuel oiL. as an

alternative to sampling each fuel lot, a sample may be taken upon each addition of oil to the

unit's storage tank. Flow proportional sampling, continuous drip sampling, or daily manual oil

sampling may also be used, in lieu of sampling each fuel lot. For the purposes of this section, a

fuel lot is defined as either:

'il A shipment or delivery of a single fuel (e.g., ship load, barge load, group of 

trucks,

group of railroad cars, oil delivery via pipeline from a tan far, etc.); or

(2) If multiple deliveries of a particular type of fuel are received from the same supply

source in a given calendar month, the deliveries for that month are considered, collectively, to

comprise a fuel lot. requiring only one representative sample.

40 C.F.R. § 98.34(b)(3)(ii)(B)

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(1) Use any applicable standard method from the following list to quality assure the data

from each fuel flow meter.

(i) AGA Report No.3, Orifice Metering of Natural Gas and Other Related Hydrocarbon Fluids,

Part 1: General Equations and Uncertainty Guidelines (1990) and Part 2: Specification and

Installation Requirements (2000)(incorporated by reference, see §98.7).

(ii) f~Gf~ Transmission Measurement Committee Report No.7, Measurement of 

Gas by Turbine

Meters (2006) (incorporated by reference, see §98.7).

(iii) ,,\.8ME MFC 3M 2001 Measurement of 

Fluid Flow in Pipes Using Orifice, Nozzle, and

Venturi (incorporated by reference, see §98.7).

6
(iv) .\SME MFC 1M 1986 (Reaffirmed 1997), Measurement of Gas Flow by Turbine Metcrs

(incorporated by reference, see §98.7).

(v) /\SME MFC 5M 1985 (Reaffirmed 1991), Measurement of Liquid Flow in Closed

Conduits Using Transit Time Ultrasonic Flowmeters (incorporated by reference, see §98.7).

(vi) ASME MFC 6M 1998 Measurement of Fluid Flov.' in Pipes Using Vortex Flowmeters

(incorpomted by refcrence, see §98.7).

(vii) ¡\SME MFC 7M 1987 (Reaffrmed 1992), Measurement of Gas Flow by Means of

Critical Flov¡ Venturi Nozzles (incorpomted by reference, see §98.7).

(viii) .A.SME MFC 9M 1988 (Reaffrmed 2001), Measurement of Liquid Flow in Closed

Conduits by Weighing Method (incorpomted by reference, see §98.7).

(~) You must Y!!se one of the following any applicable appropriate fuel sampling and analysis

methods-. You may use a method published by a consensus standards organization if such a

method exists, or yOU may use industry consensus standard practice methods from the following

l-to determine the carbon content and molecular weight (for gaseous fuel) of the fueL.

Consensus-based standards organizations include, but are not limited to, the following: ASTM

InternationaL. the American National Standards Institute (ANSI). the American Gas Association

(AGA), the American Society of Mechanical Engineers (ASME), the American Petroleum

Institute (API), and the North American Energy Standards Board (NAESB). Alternatively, the

results of chromatographic analysis of the fuel may be used, provided that the gas chromatograph

is operated, maintained, and calibrated according to the manufacturer's instructions. The

methodes) used shall be documented in the monitoring plan required under &98.3(g)(5).

40 C.F.R. § 98.34(b)(4)-(5)

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(f) IWhenever company records are used in the calculation of C02 emissions, the

records required under § 98.3(g)Ql shall include an explanation of how the following

parameters are determined from both the company records (or, if applicable, from the best

available information): and an explanation ofho'.v those records are used to estimate the

following parameters:

(1) Fuel consumption, when the Tier 1 and Tier 2 Calculation Methodologies are used-:~

including when 98.36(c)(4) applies.

(2) Fuel consumption, when solid fuel is combusted and the Tier 3 Calculation

Methodology is used.

(3) FossilJuel consumption when § 98.33(e)Q) applies to a unit that uses CEMS to

quantify C02 emissions and that com busts both fossil and biomass fuels.

(4) Sorbent usage, when § 98.33(d) applies.

(5) Quantity of steam generated by a unit when § 98.33(a)(2) applies.

(6) Biogenic fuel consumption under § 98.33(e)(5).

7
(7) Fuel usage for CH4 and N)O emissions calculations under &98.33( c)( 4)(ii).

(8) Mass of biomass combusted, for premixed fuels that contain biomass and fossil fuels

under §98.33( e)(1 )(iii).

40 C.F.R. § 98.34(t)

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(Delete 40 C.F.R. § 98.34(g))

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(4) The following alternative reporting option applies to situations where a common

liquid or gaseous fuel supply is shared between one or more large combustion units, such as

boilers or combustion turbines (including units subject to subpar D of this par), and small

combustion sources on-site, including but not limited to space heaters and hot water heaters. In

this case, you may simplify reporting by attributing all of the GHG emissions from combustion 

of the shared fuel to the large combustion unites). provided that:

(i) The total quantity of the fuel combusted during the report year in the unts sharng

the fuel supply is measured, either at the "gate" to the facility or at a point inside the facility,

using a fuel flow meter, billing meter, or tan drop measurements (as applicable):

(ii) On an anual basis, at least 95 percent (by mass or volume) of the shared fuel is

combusted in the large combustion unites), and the remainder is com busted in the small

combustion sources. Company records may be used to determine the percentage distribution of

the shared fuel to the large and small units: and

(iii) The use of this reporting option is documented in the monitoring plan required

under &98.3(g)(5). Indicate in the monitoring plan which units share the common fuel supply

and the method used to demonstrate that this alternative reporting option applies. For the small

combustion sources on-site, a description of the types of units and the approximate number of

units is suffcient.

40 C.F.R. § 98.36(c)(4).

.u *** Subpar D units are not required to report biogenic CO) emissions under

&§98.3(c)(4)(ii) and (c)(4)(iii)(A).

* * *

í. Annual CO) mass emissions from the combustion of biomass, expressed in metric

tons CO)e (optional).

40 C.F.R. §§ 98.36(d)(l)(ii) and (ix)

8
(ii) ***

(9E) Annual CO2,-Glh, and N;lG emissions at each monitored location, across all fuel

types; expressed in metric tons of C02e.

***

(I) Anual CO) mass emissions from the combustion of biomass, expressed in metric

tons COze (optional).

40 C.F.R. § 98.36( d) (2)(ii)

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(oo') *** ii

(9E) The total annual CO2,.4, and N;lG emissions at each monitored location,

expressed in metric tons of C02e.

***

(I) Annual CO) mass emissions from the combustion of biomass, expressed in metric

tons CO)e (optional).

40 C.F.R. § 98.36(d)(2)(iii)

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The annual report shall comply with the data reporting requirements. specified in

§98.36fQ(b) and, if applicable, §98.36(c)(2) or (c)(3).

40 C.F.R. § 98.46

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You shall comply with the recordkeeping requirements of §§98.3(g) and 98.37. Records

retained under § 75.57(h) of 40 CFR Part 75 for missing data events satisfy the recordkeeping

requirements of § 98.3(g)(4) for those same events.

40 C.F.R. § 98.47

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9