IN THE UNITED STATES COURT OF APPEALS

FOR THE DISTRICT OF COLUMBIA CIRCUIT

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U.S. ENVIRONMENTAL PROTECTION ) AGENCY, )

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AMERICAN PETROLEUM

INS TITUTE, et al.,

Petitioners,

v.

No. 09-1328

Respondent.

SETTLEMENT AGREEMENT

WHREAS the American Petroleum Institute and the National

Petrochemical & Refiners Association in No. 09-1328 (referred to as

"Petitioners") 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. 56,260 (Oct. 30, 2009) ("GHG Reporting

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

Protection Agency ("EP A");

WHEREAS No. 09-1328 has been consolidated with other petitions

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

petition;

WHEREAS 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 Petitioners in their petition for review;

WHEREAS the EP A and American Petroleum Institute (collectively the

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

protracted and costly litigation and to preserve judicial resources;

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 will notify the

Court that they have reached a settlement, subject to required notice provisions

described in paragraph 7 below, and wil request that No. 09-1328 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 EPA 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 EPA 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 Petitioners shall

promptly file a stipulation of dismissal with prejudice of No. 09-1328, or in the

event not all such changes are made, a stipulation of dismissal with prejudice of

No. 09-1328 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. 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.

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In addition, Petitioners 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 Petitioners reserve any rights they 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 a change that is substantially the same

substance as the proposed amendment attached as Attachment A to this

Agreement, Petitioners' 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 Petitioners .recognize that

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

addresses other matters or provisions than set forth in Attachment A or that is

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

agreement then Petitioners' 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

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

7. EP A and Petitioners 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 113(g) of the Clean Air Act. This Agreement shall

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

Petitioners.

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

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

of administrative law.

9. Any obligations ofEPA 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

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

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

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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 Division

DA VID J. KAPLAN

U.S. Department of Justice

Environmental Defense Section

PO Box 23986

Washington D.C. 20026-3986

(202) 514-0997

Counsel for United States

Environmental Protection Agency

Dated:

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ROGER R. MARTELLA, JR.

Sidley Austin LLP

1501 K Street, N.W.

Washington, D.C. 20005

(202) 736-8097

Counsel for American Petroleum

Institute and National Petrochemical

& Refiners Association

Dated:
ATTACHMENT A

(i Measurement Device Installation.

(l) General. If an owner or operator required to report under subpart p, subpart X or

subpart Y has process equipment or units that operate continuously and it is riot possible to

install a required flow meter or other measurement device by April L 2010, (or by any later date

in 2010 approved by the Administrator as part of an extension of best available monitoring

methods per §98.3(d)) without process equipment or unit shutdown, or through a hot tap, the

owner or operator may request an extension from the Administrator to delay installng the

measurement device until the next scheduled process equipment or unit shutdown. If approval

for such an extension is granted by the Administrator, the owner or operator must use best

available monitoring methods during the extension period.

(2) Requests for extension of the use of best available monitoring methods for

measurement device installation. The owner or operator must first provide the Administrator an

initial notification of the intent to submit an extension request for use of best available

monitoring methods beyond December 31, 2010 (or an earlier date approved by EP A) in cases

where measurement device installation would require a process equipment or unit shutdown, or

could only be done through a hot tap. The owner or operator must follow-upthis initial

notification with the complete extension request containing the information specified in

98.3(i( 4) below.

(3) Timing of request.

(i The initial notice of intent must be submitted no later than January L 201 L or by the

end of the approved use of best available monitoring methods extension in 2010, whichever is

earlier. The completed extension request must be submitted to the Administrator no later than

February 15,2011.

(m Any subsquent extensions to the original request must be submitted to the

Administrator within 4 weeks of the owner or operator identifying the need to extend the request,

but in any event nolater than 4 weeks before the date for the planned process equipment or unit

shutdown that was provided in the original request.

(4) Content of the request. Requests must contain the following information:

(i) Specific measurement device for which the request is being made and the location

where each measurement device wil be installed.

(ii) Identification of the specific rule requirements (by rule subpart, section, and

paragraph numbers) requiring the measurement device.

(iii) A description of the reasons why the needed equipment could not be installed before

April 1, 2010, or by the expiration date for the use of best available monitoring methods, in cases

where an extension has been granted under §98.3(d).

(iv) Supporting documentation showing that it is not practicable to isolate the process

equipment or unit and install the measurement device without a full shutdown or a hot tap, and

that there was no opportunity during 2010 to install the device. Include the date of the three

most recent shutdowns for each relevant process equipment or unit, the frequency of shutdowns

for each relevant process equipment or unit, and the date of the next planned process equipment

or unit shutdown.
(v) Include a description of the proposed best available monitoring method for

estimating GHG emissions during the time prior to installation of the meter.

(5) Approval criteria. The owner or operator must demonstrate to the Administrator's

satisfaction that it is not reasonably feasible to install the measurement device before April L

2010 (or by the expiration date for the use of best available monitoring methods, in cases where

an extension has been granted under §98.3( d)) without a process equipment or unit shutdown, or

through a hot tap, and that the proposed method for estimating GHG emissions during the time

before which the measurement device will be installed is appropriate. The Administrator wil

not initially approve the use of the proposed best available monitoring method past December

3 L 2013.

(6) Measurement device installation deadline. Any owner or operator that submits both

a timely initial notice of intent and a timely completed extension request under paragraph (i(3)

of this section to extend use of best available monitoring methods for measurement device

installation must install al i such devices by July 1, 201 1 unless the extension request under this

paragraph (i is approved by the Administrator before July L 2011.

(7) One time extension past December 31, 2013. If an owner or operator determines that

a scheduled process equipment or unit shutdown will not occur by December 31.2013, the

owner or operator may re-apply to use best available monitoring methods for one additional time

period, not to extend beyond December 31,2015. To extend use of best available monitoring

methods past December 3 i, 20 i 3, the owner or operator must submit a new extension request by

June L 2013 that contains the information required in paragraph (i(4) of this section. The owner

or operator must demonstrate to the Administrator's satisfaction that it continues to not be

reasonably feasible to install the measurement device before December 31, 2013 without a

process equipment or unit shutdown, or that installation of the measurement device could only be

done through a hot tap, and that the proposed method for estimating GHG emissions during the

time before which the measurement device will be installed is appropriate. An owner or operator

that submits a request under this paragraph to extend use of best available monitoring methods

for measurement device installation must install all such devices by December 31, 2013, unless

the extension request under this paragraph is approved by the Administrator.

40 C.F.R. § 98.30)

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(i) Calibration and accuracy requirements. The owner or operator of a facilty or

supplier that is subject to the requirements of this part must meet the applicable flow meter

calibration and accuracy requirements of this paragraph (i). The accuracy specifications in this

paragraph (i) do not apply where either the use of company records (as defined in 998.6) or the

use of "best available information" is specified in an applicable subpart of this part to quantify

fuel usage and/or other parameters. * * * *

(1) Except as otherwise provided in paragraphs (i)(4) through (i)(6) of 

this section, flow

meters and other devices (e.g., belt scales) that measure liquid and gaseous fuel feed rates,

process stream flow rates, or feedstock flow rates data used toand provide data for the calculate

GHG emissions calculations, shall be calibrated prior to April 1, 2010 using the procedures

specified in this paragraph (i) when and each such calibration is specified in a relevant subpart of

this par. Each of these flow meters shall meet the applicable accuracy specification in paragraph

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(i(2) or (i(3) of this section. All other measurement devices (e.g., weighing devices) that are

required by a relevant subpart of this part, and that are used to provide data for the GHG

emissions calculations, shall also be calibrated prior to April 1, 2010; however, the accuracy

specifications in paragraphs (i(2) and (i)(3) of this section do not apply to these devices. Rather,

each of these measurement devices shall be calibrated to meet the accuracy requirement

specified for the device in the applicable subpart of this part, or, in the absence of such accuracy

requirement, the device must be calibrated to an accuracy within the appropriate error range for

the specific measurement technology, based on an applicable operating standard, including but

not limited to industry standards and manufacturer's specifications. The procedures and methods

used to quality-assure the data from each measurement device shall be documented in the written

monitoring plan, pursuant to paragraph (g)(5)(i)(C) of this section.

ul All flow meters and other measurement devices that are subiect to the provisions of

this paragraph (i) must be calibrated according to one of the following. You may use the

manufacturer's recommended procedures;i an appropriate industry consensus standard method;i

or a method specified in a relevant subpart of this part. The calibration methodes) used shall be

documented in the monitoring plan required under paragraph (g) of this section. Al

measurement devices shall be calibrated to an accuracy of 5 percent.

ilFor facilities and suppliers that become subject to this part after April 1, 2010, tH

initial calibration shall be conducted on the date that that data collection is required to begin.

Subsequent calibrations shall be performed at the frequency specified in each applicable subpart.

all flow meters and other measurement devices (if any) that are required by the relevant

subpart(s) of this part to provide data for the GHG emissions calculations shall be installed no

later than the date on which data collection is required to begin using the measurement device,

and the initial calibration(s) required by this paragraph (i (if any) shall be performed no later

than that date.

(iii) Except as otherwise provided in paragraphs (i( 4) through (i( 6) of this section,

subsequent recalibrations of the flow meters and other measurement devices subiect to the

requirements of this paragraph (i) shall be performed at one of the following frequencies:

(A) You may use the frequency specified in each applicable subpart of this part.

(B) You may use the frequency recommended by the manufacturer or by an industry

consensus standard practice, if no recalibration frequency is specified in an applicable subpart.

40 C.F.R.§ 98.3(i)

(2) Operate and maintain all flow meters used for gas and liquid feedstocks and products

according to the manufacturer's recommended procedures. You must calibrate each of these 

flow meters according to one of the following. You may use either an industry consensus

standard method or methods by follo'vving the procedures in § 98.3(i) and using any of the flow

meter methods specified in paragraphs (b)(2)(i) through (b)(2)(xv) of this section, as applicable,

use a standard method published by a consensus bused standards organization (e.g., /\STM, ,A.PI,

etc.), or follow procedures specified by the flow meter manufacturer. Each flow meter must

meet the applicable accuracy specification in -B§ 98.3(i), except as otherwise specified in

§98.3(i(4) through (i(6). You must Rlecalibrate each flow meter according to one of the 

following frequencies. You may recalibrate either biennially.L -Bat the minimum frequency

3
specified by the manufacturer, or at the interval specified by the industry consensus standard

practice used.

(i) ,'\SME MFC 3M 2001 Measurement of Fluid Flo',v in Pipes Using Orifice, Nozzle, and

Venturi (incorporated by reference, see § 98.7).

(ii) ,A.SME MFC 1 M 1986 (Reaffrmed 1997) Measurement of Gas Flo'N by Turbine Meters

(incorporated by reference, see § 98.7).

(iii) i\SMEMFC 5M 1985 (Reaffrmed 1991) Measurement of Liquid Flo"Y in Closed Conduits

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

(iv) /\SME MFC 6M 1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters

(incorporated by reference, see § 98.7).

('I) ,A.SME MFC 7M i 987 (Reaffirmed i 992) Measurement of Gas FIO\v by Means of Critical

Flo"v Venturi Nozzles (incorporated by reference, see § 98.7).

(vi) ASME MFC 9M i 988 (Reaffirmed 200 I) Measurement of Liquid FlmN in Closed Conduits

by 'Neighing Method (incorporated by reference, see § 98.7).

(vii) ,A.SME MFC i 1 M 2006 Measurement of Fluid Flow by Meilns of Coriolis Mass

Flo\'imeters (incorporated by reference, see § 98.7).

('/iii) ,A.SME MFC 11M 2003 (Reaffrmed 2008), Measurement of Fluid Flow Using Small

Bore Precision Orifice Meters (incorporated by reference, see § 98.7).

(ix) l.SME MFC 16 2007 Measurement of Liquid Flow in Closed Conduits with

Electromagnetic Flowmeters (incorporated by reference, see § 98.7).

(x) ,'\SME MFC IBM 2001 (Reaffrmed 2006), Measurement of Fluid Flow Using Variable

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

(xi) ,A.SME MFC 22 2007 Measurement of Liquid by Turbine Flowmeters (incorporated by

reference, see § 98.7).

(xii) ,A.G,A. Report No. 3: Orifice Metering of Natural Gas and Other Related Hydrocarbon

Fluids, Part I: General Equations and Uncertainty Guidelines (1990), Part 2: Specification and

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

(xiii) ,'\GA Transmission Measurement Committee Report No.7: Measurement of Natural Gas

by Turbine Meter (2006)/February (incorporated by reference, see § 98.7).

(xiv) ,A.G,A. Report No.1 i: Measurement of Natural Gas by Corio lis Meter (2003) (incorporated

by reference, see § 98.7).

(xv) ISO 8316: Measurement of Liquid Flow in Closed Conduits Method by Collection of the

Liquid in a Volumetric Tank (1987 10 01) First Edition (incorporated by reference, see § 98.7).

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40 C.F.R. § 98.244(b)(2)

(b) All ~flow meters, gas composition monitors, and heating value monitors

that are used to provide data for the GHG emissions calculations in this

subpart for sources other than those subject to the requirements in paragraph

(a) of this sectionstationar)' combustion sources shall be calibrated according

to the procedures in the applicable methods specified in paragraphs (c)

through (eg) of this section, QLthe procedures specified by the manufacturer~

In the case of gas f10w meters, all gas now meters must meet the calibration

accuracy requirements in ~§98.3(i). You must Rlecalibrate each ~flow

meter according to one of the following frequencies. You may recalibrate

either biennially (every two years)~-e at the minimum frequency specified by

the manufacturer, or at the interval specified by the industry consensus

standard practice used. You must Rlecalibrate each gas composition monitor

and heating value monitor according to one of the following frequencies.

You may recalibrate either annuallY~-e at the minimum frequency specified

by the manufacturer, or at the interval specified by the industry consensus

standard practice used.

(c) For flare or sour gas flow meters, operate-, calibrate, and maintain the flow

meter according to one of the following. You may use a using ~any of

the follo\ving methods, a method published by a consensus-based standards

organization (e.g;, i\.STM, ,A,PI, etc.) or folIo':¡ the procedures specified by the

flow meter manufacturer. Consensus-based standards include, but are not

limited to, the following: ASTM International, the American Society of

Mechanical Engineers (ASME), and the American Gas Association

(AGA)Flow meters must have a rated accuracy of +/ 5 percent or lov./er.

(1) ,'\SME MFC 3M 2001 Measurement of Fluid FloVl in Pipes Using Orifice, Nozzle, and

Venturi (incorporated by reference, see § 98.7).

(2) ASME MFC 1M 1986 (Reaffrmed 1997) Measurement of Gas Flow by Turbine Meters

(incorporated by reference, see§ 98.7).

(3) ASME MFC 6M 1998 Measurement of Fluid Flow in Pipes Using Vortex Flowmeters

(incorporated by reference, see § 98.7).

(1) ASME MFC 7M 1987 (Reaffirmed 1992) Measurement of Gas Flow by Means of Critical

Flo\v Venturi Nozzles (incorporated by reference, see § 98.7).

(5) ,A.SME MFC 11M 2006 Measurement of Fluid Flow by Means of Corio lis Mass Flo'Nmeters

(incorporated by reference, see § 98.7).

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(6) ¡\SME MFC 11M 2003 Measurement of Fluid Flo'.v Using Small Bore Precision Orifice

Meters (incorporated by reference, see § 98.7).

(7) ,A.SME MFC IBM 2001 Measurement of Fluid Flow Using Variable Area Meters

(incorporated by reference, see § 98.7).

(8) ,'\G,A. Report No. 11 Measurement of Natural Gas by Coriolis Meter (2003) (incorporated by

reference, see § 98.7).

40 C.F.R. §§ 98.254(b) & (c)

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(7) If the results of an initial calibration or a recalibration fail to meet the required

accuracy specification, data from the flow meter shall be considered invalid, beginning with the

hour of the failed calibration and continuing until a successful calibration is completed. You

shall follow the missing data provisions provided in the relevant missing data sections, during

the period of data invalidation.

40 C.F.R. § 98.3(i) (7)

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(6) For units and processes that operate continuously with infrequent outages, it may not

be possible to meet the April 1, 20 I O~ deadline for the initial calibration of a flow meter or other

measurement device without removing the de'.'ice from service and shipping it to a remote

location, thereby disrupting normal process operation...

40 C.F.R. § 98.3(i)(6)

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(i) In cases where there are only two transmitters (i.e., differential pressure and either

temperature or total pressure) in the immediate vicinity of the flow meter's primary element

(e.g., the orifice plate), or when there is only a differential pressure transmitter in close proximity

to the primary element, calibration of these existing transmitters to a CE of2.0 percent or less at

each measurement point is still required, in accordance with paragraph (i)(3) of this section;

alternatively, when two transmitters are cal ibrated, the results are acceptable if the sum of the CE

values for the two transmitters at each calibration level does not exceed 4.0 percent. However,

note that installation and calibration of an additional transmitter (or transmitters) at the flow

monitor location to measure temperature or total pressure or both is not required in these cases.

Instead, you may use assumed values for temperature and/or total pressure, based on

measurements of these parameters at a remote location ( or locations), provided that the following

conditions are met:

(A) You must demonstrate that measurements at the remote location( s) can, when

appropriate correction factors are applied, reliably and accurately represent the actual

temperature or total pressure at the flow meter under all expected ambient conditions.

6
(B) You must make all temperature and/or total pressure measurements in the

demonstration described in paragraph (i)(3)(i of this section with calibrated gauges, sensors,

transmitters, or other appropriate measurement devices. At a minimum, calibrate each of these

devices to an accuracy within the appropriate error range for the specific measurement

technology, according to one of the following. You may calibrate using an industry consensus

standard or a manufacturer's specification;

(C) You must document the methods used for the demonstration described in paragraph

(i(3)(i of this section in the written monitoring plan under paragraph (g)(5)(i(C) of this section.

You must also include the data from the demonstration, the mathematical correlation( s) between

the remote readings and actual flow meter conditions derived from the data, and any supporting

engineering calculations in the monitoring plan. You must maintain all of this information in a

format suitable for auditing and inspection;

(D) You must use the mathematical correlation( s) derived from the demonstration

described in paragraph (i)(3)(i) of this section to convert the remote temperature or the total

pressure readings, or both,to the actual temperature or total pressure at the flow meter, or both,

on a daily basis. You shall then use the actual temperature and total pressure values to correct

the measured flow rates to standard conditions; and

(E) You shall periodically check the correlation( s) between the remote and actual

readings (at least once a year), and make any necessary adjustments to the mathematical

relationship( s ).

40 C. F. R. § 98.3(i)(3)(i)

*** HHV = Default high heat value of the fuel from Table C-1 of this subpart; alternatively,

for Tier 3, if actual HHV data are available for the reporting year, yOU may average these data

using the procedures specified in paragraph (a)(2)(ii) of this section, and use the average value in

Equation C-8 (mmBtu per mass or volume). ***

40 C.F.R. § 98.33(c)(1)

(d) Optional combustion methodology for ethylene production processes. For aleach

ethylene production process, calculate GQ-GHG emissions from each combustion efunit that

burns fuel that contains any off-gas from the ethylene process off gas as specified in paragraphs

(d)(1) through (5) of this section.

(1) Except as specified in paragraphs (d)(2) and (d)(5) of this section, calculate CO?

emissions using the Tier 3 or Tier 4 methodology in subpart C of this part.

. (2) You may use either Equation C-L or Equation C-2a in subpart C to calculate CO2

emissions from combustion of any ethylene process off-gas streams that meet either of the

conditions in paragraphs (d)(2)(i or (d)(2)(ii) of this section (for any default values in the

calculation, use the defaults for fuel gas in Table C-L of subpart C of this part). Follow the

otherwise applicable procedures in subpart C to calculate emissions from combustion of all other

fuels in the combustion unit.

(i) The annual average flow rate of fuel gas (that contains ethylene process off-gas) in

the fuel gas .line to the combustion unit, prior to any split to individual burners or ports, does not

exceed 345 scfm at 60° F and 14.7 PSIA, and a flow meter is not

7
installed at any point in the line supplying fuel gas or an upstream common pipe. Calculate the

anual average flow rate using company records assuming total flow is evenly distributed over

525,600 minutes per year.

(ii) The combustion unit has a maximum rated heat input capacity of less than 30

MMBtu/hr, and a flow meter is not installed at any point in the line supplying fuel gas (that

contains ethylene process off-gas) or an upstream common pipe.

(3) Except as specified in paragraph (d)(5) of this section, ælcalculate CH4 and N20

emissions using the applicable procedures in §98.33(c) for the same tier methodology that you

used for calculating CO2 emissions.

ulfFor all gasieous fuels that contain ethvlene process off-gas, use the emission factors

for "Petroleum" in Table C-2 of subpart C of this part (General Stationary Fuel Combustion

Sources)

(ii)For Tier 3, use either the default high heat value for fuel gas in Table C- 1 of subpart C

of this part or a calculated HHV, as allowed in Equation C-8 of subpart C of this part).

.c Y ou are not required to use the same Tier for each stationary combustion unit that

burns ethylene process off-gas.

uLFor each flare, calculate CO2, CH4, and N20 emissions using the methodology

specified in §98.253(b)(1) through (b)(3).

40 C.F.R. § 98.243(d)

(a) C02, CH4, and N20 combustion emissions from stationary combustion units and

from each flare. Calculate and report these emissions from stationary combustion units under

subpart C of this part (General Stationary Fuel Combustion Sources) by following the

requirements of subpart C, except for GQ-emissions from combustion of refinery fuel gas. For

C02 emissions from combustion of fuel gas, use either equation C-5 in subpar C of this part or

the Tier 4 methodology in subpart C of this part, unless either of the conditions in paragraphs

(a)(l) or (2) of this section are met, in which case use either equations C-l or C-2a in subpart C

of this part. For CH4 and N)O emissions from combustion of fuel gas, use the applicable

procedures in 98.33(c) for the same tier methodology that was used for calculating CO?

emissions. (Use the default CH4 and N20 emission factors for "Petroleum (All fuel types in - -

Table C-l)" in Table C-2of this part. For Tier 3, use either the default high heat value for fuel

gas in Table C-L of subpart C of this part or a calculated HHV, as allowed in Equation C-8 .of

subpart C of this part. ) You may aggregate units, monitor common stacks, or monitor common

(fuel) pipes as provided in §98.36(c) when calculating and reporting emissions from stationary

combustion units. Calculate and report the emissions from flares under this subpart.

(1) The annual average fuel gas flow rate in the fuel gas line to the combustion unit,

prior to any split to individual burners or ports, does not exceed 345 scfm at 60° F and 14.7 PSIA

and either of the conditions in paragraph (a)(1)(i or (ii) of this section exist. Calculate the annual

average flow rate using company records assuming total flow is evenly distributed over 525,600

minutes per year.

(i) A flow meter is not installed at any point in the line supplying fuel gas or an upstream

common pipe.

8
(ii) The fuel gas line contains only vapors from loading or unloading, waste or

wastewater handling, and remediation activities that are combusted in a thermal oxidizer or

thermal incinerator.

(2) The combustion unit has a maximum rated heat input capacity of less than 30

MMBtu/hr and either of the following conditions exist:

(i A flow meter is not installed at any point in the line supplying fuel gas or an upstream

common pipe; or

(ii) The fuel gas line contains only vapors from loading or unloading, waste or

wastewater handling, and remediation activities that are combusted in a thermal oxidizer or

thermal incinerator.

40 C.F.R. § 98.252(a)

Table C-L of Subpart C-Default C02 Emission Factors and High Heat Values for Various T fF i . ypes 0 ue

Fuel Type Default High Default C02 Emission Factor

Heat Value

***

Stil gas

~*** ~***

*** m m Btu/scf kg CO2 1m m Btu

*** *** ***

Fuel Gas¿ 1.388 x IO.J 59.00

¿

Reporters subiect to subpaii X of this paii that aie complyiig with 98.243(d) or Subpart Y of this part

may only use the default HHV and the default COJ emission tàctor for fuel gas combustion under the

conditions prescribed in &98.243(d)(2)(i) or (2)(ii) and &98.252(a)(1) or (a)(2), respectively. Otherwise,

Tier 3 (Equation C-5) or Tier 4 must be used.

40 C.F.R. Part 98, Subpart C, Table C-L

9