### IN THE UNITED STATES COURT OF APPEALS 

### FOR THE DISTRICT OF COLUMBIA CIRCUIT ) ) ) ) ) ) ) 

### U.S. ENVIRONMENTAL PROTECTION ) 

# AGENCY, )
) ) ) 

### 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

- i -

### "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. 

# - 2 -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 

# - 3 -

### 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



# - 4 -

### 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:



# - 5 -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)

ofthis 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)

--------------------------------------------------------------------------------------- 

### (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
2(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

3specified 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).

440 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 Coriolis Mass Flo'Nmeters (incorporated by reference, see § 98.7).

5(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)

---- - -- - --- --- -- -- -- -- -- - - - - - - -- - - -- -- - -- -- - -- -- - -- - -- - --- - - -- -- - - -- - -- - -- ---- - -- --- -- -- - -- - - - -- - - -- - - -- - -- -- (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)

------------------------------------------------------------------------------------------------------------- (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)

- -- - -- - - -- ---- - --- - -- -- - ---- -- - --- -- - - -- - - -- --- - -- - -- - --- - -- - ---- -- ---- - -- - -- ----- -- - -- - -- ---- -- -- - -- -- - ---- -- (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
7installed 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 0ueFuel 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