Petition for Reconsideration of 

Subpart W of the Final Rule for Mandatory Reporting of Greenhouse 

Gases: Petroleum and Natural Gas Systems 

75 Fed. Reg. 74,458 (Nov. 30, 2010); Docket No. EPA-HQ-OAR-2009-0923 

March 2, 2011 

_____________________________________________________________________ 

I. Introduction 

The American Gas Association, founded in 1918, represents 199 local energy 

companies that deliver clean natural gas throughout the United States. There are 

more than 70 million residential, commercial and industrial natural gas customers in 

the U.S., of which 91 percent — more than 64 million customers — receive their gas 

from AGA members. AGA is an advocate for natural gas utility companies and their 

customers and provides a broad range of programs and services for member natural 

gas pipelines, marketers, gatherers, international natural gas companies and 

industry associates. Today, natural gas meets almost one-fourth of the United 

States' energy needs. 

AGA appreciates the effort that the U.S. Environmental Protection Agency (“EPA” or 

“Agency”) made to understand our issues and to address the concerns we raised in 

our comments on the Subpart W proposed rule. In particular, we appreciate EPA’s 

clarification in the final rule that our members’ more than 64 million residential, 

commercial and industrial customer meters will not be subject to annual on-site 

surveys or other reporting requirements under Subpart W. We also appreciate 

EPA’s decision to allow an array of effective leak survey options, as we requested, 

rather than requiring that all leak surveys be performed using infrared cameras. 

These two changes significantly reduce burdens and costs as compared to the 

proposed rule. 
Unfortunately, in attempting to address these concerns in the final rule, the Agency 

has adopted new terms and requirements with no clear meaning that unless 

changed will make it impossible for our members to determine with assurance how 

to comply with the rule, yield conflicting and unreliable emissions data, and thereby 

undermine the purposes of Subpart W. We believe these new problems can be 

resolved if we are allowed to provide comments and discuss our proposed solutions 

with the Agency. AGA is therefore petitioning for EPA’s reconsideration of the 

Subpart W final rule captioned above (Subpart W Rule) pursuant to section 

307(d)(7)(B) of the Clean Air Act (CAA or Act). In addition, we request that EPA 

stay the effectiveness of these provisions in the Subpart W Rule pending 

reconsideration. 

Section 307(d)(7)(B) of the Act provides that the EPA Administrator is required to 

convene a proceeding to reconsider a final rule, 

“[i]f the person raising an objection can demonstrate to the Administrator that it 

was impracticable to raise such objection within [the period for public comment] 

or if the grounds for such objection arose after the period for public comment (but 

within the time specified for judicial review) and if such objection is of central 

relevance to the outcome of this rule.” 

CAA §307(d)(7)(B), 42 U.S.C. §7607(d)(7)(B). AGA’s objections clearly meet this 

standard. We object to terms and requirements that appeared for the first time in the 

final rule in November 2010, thus providing us no opportunity to comment on them 

during the period for public comment on the proposed rule, which closed on June 11, 

2010. 

We also object to terms that were used in different ways in the proposed rule than in 

the final rule. Here, too, the grounds for our objection did not arise until after the 

comment period closed. Further, these terms and requirements are of “central 

relevance to the outcome of this rule.” AGA members cannot decipher the meaning 

of these new terms – which are subject to conflicting interpretations. 

It is conceivable that the electronic reporting forms or software that EPA has 

promised might upon review resolve some of these issues. But EPA did not provide 

these materials for review and comment during the comment period. On March 1, 

2011, the Agency announced that it will release the reporting software sometime 

later this spring. We will need an opportunity to test this software and the forms to 

be sure they align with what is required in the Subpart W Rule, once we know what 

that is. 

2
As a result of these uncertainties, it will be impossible in present circumstances for 

Designated Representatives to provide the required certification of compliance with 

the related Subpart W reporting requirements and emission factor formulas with 

assurance. In addition, the conflicting interpretations of key terms and requirements 

are likely to result in either significant over reporting or under reporting or inaccurate 

reporting of greenhouse gas emissions. Clearly, these objections are of central 

relevance to the outcome of this rule. 

II. Objections and Request for Administrative Stay 

A. Request for Administrative Stay of Subpart W Rule 

EPA should stay the application of the Subpart W Rule pending reconsideration. 

The Administrative Procedure Act (APA) provides that “[w]hen an Agency finds that 

justice so requires, it may postpone the effective date of action taken by it, pending 

judicial review.” 5 U.S.C. §705. APA section 705 clearly shows that the standard for 

an Agency’s administrative stay (justice so requires) differs significantly from the 

standard for a judicial stay of the Agency’s action (irreparable harm). There is no 

need to show irreparable harm to support an administrative stay. EPA has applied 

the APA’s “justice so requires” standard for administrative stays in Clean Air Act 

cases.1

 EPA can and should find that in this instance, justice requires staying the 

Subpart W Rule pending reconsideration. Certainly it is unjust to require 

compliance from natural gas local distribution companies (LDCs) when they cannot 

determine what they are required to do under the Rule, and absent a stay, they will 

be forced to make a “guess” to begin performing leak surveys and collecting data on 

emissions this year. The resulting information would be gathered under different 

interpretations of the rule, as each LDC did the best it could, and therefore would be 

of little use to EPA. Accordingly, there would be no significant damage to EPA’s 

mission from granting this stay. 

AGA accordingly requests a stay of the effective date for the Subpart W provisions 

affecting natural gas distribution, dehydration units at underground storage facilities, 

and LNG facilities pending reconsideration. 

                                                           

1

 See, e.g., Ohio: Approval and Promulgation of Implementation Plans, 46 Fed. Reg. 8,581, 8,582 n.1 

(Jan. 27, 1981). 

3
B. AGA’s Objections 

AGA requests reconsideration of Subpart W, as applied to Natural Gas Distribution 

Companies, Natural Gas Distribution Facilities, dehydration units and internal 

combustion units at Underground Storage Facilities, and LNG facilities, based on the 

following objections. 

1. Key New Terms Are Vague and Confusing 

The Subpart W obligations for LDCs are primarily focused on reporting emission leaks. 

The manner in which those leaks must be quantified and reported depends on the 

regulatory classification of the leaking equipment. Specifically, physical surveys of the 

number of leaks are required for “above ground meters and regulators at custody 

transfer city gate stations.” Emission factors for leaking component are then applied to 

those numbers to compute an end quantity. 

On the other hand, the rule requires “developed” emission factors to quantify emissions 

from “above ground meters and regulators at non-custody transfer city gate stations.” 

The rule does not define any of these terms (e.g., custody transfer city gates, non -

custody transfer city gates, meters and regulators). Most importantly, the basic 

distinction that required these new definitions was not present in the proposed rule. 

Accordingly, there was neither opportunity nor occasion to comment on these terms and 

their usage during the rulemaking. AGA members would like to work with EPA to 

develop clear definitions for the terms custody transfer city gates and non-custody 

transfer city gates. 

 

a) Non-custody Transfer City Gates Station 

Several provisions in the Subpart W Rule and preamble seem to imply that a “noncustody-transfer city gate station” will always have a meter. The emission factor 

equation W-32 for “non-custody-transfer city gate stations” clearly requires multiplying 

the emission factor times the number of above ground meter runs. 

There is a difference of opinion among AGA members whether a non-custody transfer 

station must have a meter to be a part of the reporting requirement. The term is not 

clearly defined in the rule. 

The term “city gate” is widely used in the industry, but unfortunately it means different 

things to different companies. It can mean the place where an LDC takes custody of 

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natural gas from the upstream supplier (either directly from a producer or from an 

interstate pipeline company). The term “city gate” is also used by some to refer to the 

place where natural gas is conveyed into a lower pressure distribution system for a town 

or city – either directly from the upstream supplier (producer or interstate pipeline) or 

from the LDC’s own intrastate high pressure transmission pipelines. 

Some companies do not use the term “city gate” to refer to the situation where natural 

gas goes from the company’s own transmission pipes to one of its distribution systems. 

Instead, these companies may use other terms such as “district regulator” or “metering 

and regulating station,” or “M&R” equipment, and these terms also can have varying 

meanings. AGA believes the best solution would be to work with EPA to develop clear, 

workable definitions for use in the Subpart W rule. This is essential to ensure that all 

operators report the same information required by EPA. 

It was not possible to comment on this issue, because the terms “city gate,” “custody 

transfer,” " non-custody transfer," “meter and regulator” and “meter run” were not used 

in proposed section 98.232(i)(1) until after the final rule went into place Moreover, the 

whole conceptual framework of the proposed rule was different, in that the proposed 

rule did not rely on making distinctions among different locations or types of equipment. 

b) Custody Transfer City Gate Stations 

In the Subpart W Rule, EPA introduced a new requirement that an LDC must perform 

annual leak surveys at all its “custody-transfer city gate stations.” This term appeared 

for the first time in the final rule and is not defined. Accordingly, AGA had no 

opportunity to comment on it. 

Various provisions in the Subpart W Rule and preamble indicate that the LDC should 

perform leak surveys on a list of specified equipment, apply certain default “leaker” 

emission factors to the components found to be leaking at the time of the survey, total 

those leaker emission factors for each station, and then total the emissions from all 

stations and divide by the number of meter runs to develop a company-specific 

emission factor for “city gate stations” that is to be applied to the population count of 

meter runs at non-custody transfer city gate stations regardless of whether it has a 

meter, depending on the definition of non-custody transfer station. 

The Subpart W Rule indicates that facilities that are part of a transmission system are 

not subject to Subpart W reporting. But in many cases, the meter runs at custody 

transfer stations are owned and operated by the upstream supplier (which is either the 

producer or an interstate transmission pipeline company). The upstream supplier needs 

5
to know the volume of natural gas conveyed, so that they know how much money to bill 

the LDC. The LDC does not own or operate the meter runs in these situations, the 

meters are not within the distribution system, and the LDC has no authority to leak test 

the equipment owned and operated by another entity. Since the equipment is within the 

transmission system, that would seem to place it outside the scope of the Subpart W 

Rule. This will lead to anomalous results. We believe it makes better sense to apply a 

standard emission factor to a population count of such stations, and this will yield better, 

more consistent data. 

2. There are Far Simpler Ways to Accomplish EPA’s Objectives 

Equally Well 

We urge EPA to allow LDCs to use the new, updated emission factors developed 

recently by the Gas Technology Institute (GTI) Operations Technology Development 

(OTD) group for custody transfer stations and below ground regulators, which were 

described in AGA’s comments and provided to EPA by member National Grid during the 

comment period. These new emission factors could be applied to a population count of 

both above and below ground regulator stations to provide a more comprehensive and 

accurate estimate of greenhouse gas emissions – using an easier and cheaper 

approach. 

3. New Emission Factor Formulas Are Confusing Or Contain 

Math Errors that Vastly Inflate Emission Estimates 

The new emission factor equations W-30, 31 and 32 in the final rule are confusing. 

Since these formulas were not included in the proposed rule, AGA did not have an 

opportunity to comment on them. Notably, Equation W-32 for non-custody city gate 

stations contains a math error that results in double counting annual hours of operation, 

thereby inflating emission estimates for non-custody-transfer city gate stations by a 

factor of 8,760. Specifically, Equation W-32 generates an annual emission factor (EF). 

Equation W-31 requires that this annual EF be multiplied by the annual hours of 

operation. Equation W-32 should be modified so that the EF that is calculated is an 

hourly emission factor 

Equation W-30 is also confusing. The formula and the final rule provisions that it 

references use terms such as “equipment leak source,” “facility” and “source” 

inconsistently to reference either components or leaks at a particular site or at the 

“facility” – which for purposes of the natural gas distribution source category 

encompasses the LDC’s entire statewide distribution system. This makes it impossible 

to understand what the company is supposed to be calculating – emissions per station 

or the sum of emissions from all stations? In addition, it is unclear how emissions from 

various component types are to be treated in the calculations. Equations W-30, W-32, 

6
and section 98.233(q)(8) and/or (r)(6) appear to be missing provisions or definitions that 

would explain what EPA intends to require. In addition, W-30 does not mesh properly 

with W-32, because Equation W-30 refers to “components,” whereas W-32 (which relies 

on the data used in W-30) refers to “meters” and “meter runs.” In EPA’s January 2011 

informal Q&A responses to AGA’s questions regarding the final rule, the Agency 

responded that the emission factor equations should be based on counts of “meter 

runs.” However, the disclaimer on EPA’s response makes it clear that AGA members 

cannot rely on this interpretation of the confusing provisions in the final rule: 

 “DISCLAIMER: Any communication on the GHG Reporting Program (GHGRP) is 

intended to provide general and administrative information about Part 98. This 

communication does not provide legal advice, and responses to questions 

received do not have legally binding effect or expressly or implicitly create, 

expand, or limit any legal rights, obligations, responsibilities, expectations, or 

benefits in regard to any person. Facility owners or operators and suppliers are 

responsible for determining how they would be affected by the requirements of 

the rule.” 

Since it is not possible for LDCs to determine what these equations in the final rule 

require, the remedy must be to revise the final rule so that it clearly explains what is or 

is not required under Equations W-30, W-31 and W-32, and to allow AGA and its 

members an opportunity to comment on the proposed changes to the equations before 

they are adopted in final form. 

4. New Electronic Reporting Form is Not Yet Available for 

Comment or Testing 

Stakeholders should be given the opportunity to comment and to have access to the 

reporting software to perform trial runs. Even if EPA fixes problems with the definitions 

and formulas, this will have no effect if the reporting software does not accurately reflect 

those changes. Stakeholders did not have an opportunity to review and comment on 

the forms and software during the comment period that ended on June 11, 2010. In 

fact, the forms and software are still not available for review. This is creating problems 

for reporting under other provisions of the Mandatory Reporting Rule (MRR) in addition 

to Subpart W. We need an opportunity to debug the system and perform quality 

assurance and quality control (QA/QC) testing to ensure that the software results in an 

accurate emissions report. Otherwise it will be impossible for Designated 

Representatives to certify with assurance that their company has filed an accurate 

report in compliance with the Subpart W Rule. 

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5. EPA Should Exclude Small Internal Combustion Sources, Not 

Just External Combustion 

Under the final rule, LDCs are required to report emissions under Subpart W if they 

operate a “distribution facility” (i.e. distribution system) that is estimated to emit 

methane from certain listed types of equipment equal to or exceeding 25,000 metric 

tons per year of CO2 equivalent (CO2e) emissions. If an LDC’s estimated system-wide 

methane leaks exceed this threshold, then it is required to report both estimated 

methane leaks from distribution equipment and combustion emissions -- carbon dioxide 

(CO2), methane (CH4), and nitrous oxide (N2O) from stationary combustion 

equipment.2

 Similarly, if an LDC or other company operates an underground storage 

facility whose methane and CO2 emissions from listed components exceed the 25,000 

ton per year threshold, then the underground storage operator is required to report both 

its estimated methane emissions and its combustion emissions from stationary fuel 

combustion equipment.3

 

In the final rule, EPA substantially expanded paragraph 98.233(z) beyond what 

appeared in the proposed rule. The effect of this change, plus changes at 98.232(i), (j) 

and (k) pertaining to gas distribution, appear to pull in a much broader spectrum of 

combustion units than would have been the case under the proposed rule. Under the 

proposed rule, only if the aggregate maximum rated heat input capacity of stationary 

fuel combustion units at a discrete facility totaled 30 mmBtu/hr or greater would there be 

a reporting obligation. The changes made to the final rule, again without opportunity for 

our members to review and comment, would appear to expand the reporting obligation 

to a much larger population of smaller units spread across the distribution system. 

EPA added a new exclusion from the reporting rule for small external combustion 

sources used in natural gas production or distribution that have a rated heat capacity 

less than or equal to 5 mmBtu/hr. AGA supports and appreciates this new exclusion for 

small external combustion sources. However, we do not understand why EPA excluded 

only external combustion sources such as small boilers, and did not also exclude small 

internal combustion sources such as small stationary engines and turbines with a rated 

heat capacity less than or equal to 5 mmBtu/hr, which equates to about 625 hp. Having 

                                                           

2

 See 75 Fed. Reg. at 74,498-90, 74,504; 40 C.F.R. §§98.231, (reporting threshold) 98.232(i)(6)(LDC 

requirement to report combustion emissions), 98.233(z) (method for calculating natural gas distribution 

combustion emissions). 

3

 See 75 Fed. Reg. at 74,489-90; 40 C.F.R. §§98.2 (reporting threshold), 98.232(f) (underground storage 

list of equipment and components), 232(k) (requirement for Subpart W facilities – other than production 

and distribution - to report combustion emissions under subpart C). 

8
to account for such small sources would impose a significant burden on LDC reporters 

that is not commensurate with the value of the data that would be provided. We note 

also that given the unusually broad definition of “distribution facility” – to encompass all 

distribution pipe and equipment operated by a gas utility across an entire state – this will 

sweep in thousands of small combustion units that would not be included in reporting 

requirements and burdens for other sectors – or for combustion facilities under Subpart 

C - where the definition of facility is limited to the traditional CAA concept of a 

contiguous property or plant site. AGA requests reconsideration of this new exclusion 

for small combustion sources and revision to include both small internal and external 

combustion sources, as well as to clarify that reporting of combustion emissions is only 

required where the aggregate maximum rated heat input capacity of stationary fuel 

combustion units totals 30 mmBtu/hr or greater at a discrete station site after the 

excluded units are deducted from emissions at that station. 

In addition, we do not understand why EPA provided no similar de minimis exemption 

for either internal or external small combustion sources operated at an underground 

storage facility. The final rule provides that the operator of an underground storage 

facility must report combustion emissions pursuant to 40 C.F.R. Part 98, Subpart C. 

Was it EPA’s intention to require an underground storage facility to report combustion 

emissions only if the combustion emissions from combustion sources at the 

underground storage facility independently exceed the 25,000 ton per year CO2e 

reporting threshold for Combustion Facilities under Subpart C? If so, section 98.232(k) 

should be revised to say this explicitly. If not, EPA should revise the final rule to provide 

a de minimis exemption for small internal and external combustion sources at 

underground storage facilities. 

6. The Rule Contains Conflicting Provisions Regarding Whether 

Emissions from Dehydration Units at Underground Storage 

Facilities Should or Should Not be Reported 

AGA requests reconsideration of sections 98.230 and 98.232 based on grounds that 

arose after the comment period on the proposed rule closed – and in fact arose after the 

publication of the final rule. AGA members believed they understood these provisions, 

as proposed and as finalized, but a recent pronouncement from EPA casts this in doubt. 

Based on this new pronouncement, we question whether it is possible to determine from 

the final rule whether or not emissions from dehydration units at natural gas 

underground storage facilities are required to be reported as underground storage 

facility emissions. Sections 98.230 and 98.232 contain potentially confusing statements 

in this regard. AGA members believe the rule was probably intended to exclude

emissions from such dehydration facilities, based on EPA’s explanation in the preamble 

9
that section 98.232 was intended to define specific emission sources that would be 

subject to reporting for a particular industry segment. Section 98.230(a) confusingly 

mentions dehydration units as included within the underground storage segment. But 

we have understood that section 98.232 is intended to limit the equipment sources 

actually subject to the reporting requirement for each segment. We have also 

understood that EPA included these listed sources in the section 98.232 reporting 

requirement because they were deemed to be significant contributors toward overall 

emissions in the segment. 

However, EPA’s recent response to AGA’s question 11(d) [EPA “Question Tracker 

479112”] in January 2011 has caused confusion, because it implies a different 

interpretation than the preamble and other EPA documents in the rulemaking record. 

 We asked whether or not to include dehydration emissions in reporting emissions for 

underground storage facilities, anticipating that the Agency would confirm that reporting 

is not required. Instead, EPA responded as follows, referencing 98.230 but ignoring the 

limitation in 98.232(f): 

“Response: Per 98.230(a)(5), natural gas underground storage processes and 

operations, including dehydration, are part of the definition of the underground 

storage segment. Therefore, if you have these processes at your facility, as 

defined in 40 CFR 98.6, you would be required to report on emissions from these 

dehydration units.” 

This informal Agency response contradicts the final rule preamble and Response to 

Comments document. AGA members had been relying on those documents to interpret 

sections 98.230 and 98.232. We understood that since dehydration units are not listed 

as being subject to the reporting requirement for underground storage facilities in 

section 98.232(f), the rule therefore does not require reporting dehydration emissions 

for this segment. If this is not the intent, then it is unclear what section 98.232 is 

supposed to achieve. 

The preamble and Response to Comments (RTC) support our interpretation that 

dehydration emissions are excluded from the reporting requirement. For example, the 

preamble to the final rule explains: 

“Reporters of an industry segment as defined by 40 CFR 98.230 would report 

emissions under subpart W only from the corresponding source types listed for 

that particular industry segment as defined in 40 CFR 98.232. For example, an 

onshore natural gas transmission compression reporter as defined by 40 CFR 

10
98.230(a)(4) would report emissions under subpart W only for sources defined in 

40 CFR 98.232(e).” 4

Similarly, the RTC explains: 

“EPA has clarified in today’s final rule that a segment shall report emissions from 

sources listed under that segment in Section 98.232 of the rule.”5 

“Today’s final rule covers all of the significant sources of emissions under each 

category source type, taking into consideration the reporting burden, and other 

relevant issues. Reporters only report emissions under subpart W from sources 

listed in Section 98.232 “GHGs to Report” for the specific industrial category for 

which the reporter’s facility qualifies. However, for threshold determination the 

reporter must combine emissions and follow the requirements of Section 98.2, for 

facilities that contain any source category for which calculation methods are 

provided.”6

Given EPA’s conflicting response to AGA, which references only 98.230 and ignores the 

limitation in 98.232(f), it seems that even EPA finds these provisions confusing. AGA 

requests reconsideration and revision of the rule to make it clear that operators of 

underground storage facilities (as well as transmission compression facilities) are not 

required to report emissions from dehydration units. 

III. Additional Requests for Relief Upon Reconsideration 

A. EPA Provides No Rational Explanation for Using Outdated, 

Inaccurate Emission Factors Rather than Modern, Updated Emission 

Factors 

In our comments on the Subpart W proposed rule, AGA urged EPA to use updated, 

modern emission factors as they become available. We noted that some updated 

emission factors are already available and should be adopted as approved default 

emission factors in the final rule. EPA declined to do so without adequate explanation. 

                                                           

4

 75 Fed. Reg. 74,462. 

5

 RTC, part 1, at 136 (pdf file page153 of 935). 

6

 RTC, part 1, at 67 (pdf file page 84 of 935). 

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Instead, the Subpart W Rule requires LDCs to use outdated emission factors to 

estimate their methane emissions. These old emission factors were developed over a 

decade ago by the Gas Research Institute (GRI) using data from testing a limited 

sample of equipment in work performed nearly 20 years ago. GRI developed the 

emission factors to facilitate a general estimate of nationwide methane emissions from 

gas distribution -- not for the purpose of estimating methane emissions from pipe and 

equipment used in an individual natural gas distribution system. 

Since that time, AGA member companies have been steadily reducing methane leaks 

and tightening their distribution systems through voluntary participation in EPA’s Natural 

Gas STAR program and mandatory compliance with continuously more stringent 

PHMSA regulations, resulting in fewer emissions. AGA and its members are supporting 

an ongoing joint research and field testing program with EPA and the Gas Technology 

Institute (GTI) (the successor to GRI) to develop updated, more accurate methane 

emission factors to facilitate more accurate GHG emission estimates for plastic 

distribution pipe, metering and regulator (M&R) stations and other natural gas 

distribution equipment. GTI’s Operations Technology Development (OTD) group issued 

a report in November 2009 providing a new updated emission factor for metering and 

regulating (M&R) stations that could be used to simplify and improve the accuracy of 

emissions reporting for above and below ground regulator stations. This could be used 

instead of the confusing and contradictory provisions in the final rule for “non-custodytransfer city gate stations.” AGA referenced this new emission factor in our June 11, 

2010 comments, and AGA member company National Grid provided a link to the OTD 

web site, where they told EPA the M&R emission factor report is available for free 

downloading. 7

 

In November 2010, in response to a request from the Agency, AGA submitted a list of 

our members’ priority questions regarding the final Subpart W Rule. In our question 

number 6 (EPA Question Tracker 479106), we submitted an electronic copy of the OTD 

emission factor report and asked whether EPA would consider changing the rule to 

incorporate the new OTD emission factor for regulator stations. EPA responded that it 

would take the submission into consideration in any future rule revisions, which we 

appreciate. However, the Agency also responded that it did not receive this data until 

November 2010. This is incorrect. AGA described the new emission factor in our 

comments, and our member National Grid provided a web link to the report in 

comments filed June 11, 2010, within the comment period. 

AGA requests that EPA allow the use of this new, more accurate emission factor for 

regulator stations upon reconsideration of the Subpart W Rule. In addition, we request 

                                                           

7

  For your convenience, here is the direct link: http://media.godashboard.com//gti/77b_OTD-10-

0002_GHG_Emission_Factors_FinalReport_v2.pdf 

12
that EPA revise the rule to facilitate expeditious adoption of other new emission factors 

as they are developed, including a new emission factor for buried plastic pipe that 

should be complete within the next two years. 

B. The Definition of Distribution “Facility” is Overbroad and Confusing 

The Subpart W Rule defines “Facility with respect to natural gas distribution for 

purposes of [Subpart W] and Subpart A” to mean: 

“the collection of all distribution pipelines, metering stations, and regulating 

stations that are operated by a Local Distribution Company (LDC) that is 

regulated as a separate operating company by a public utility commission or that 

are operated as an independent municipally-owned distribution system.” 

40 C.F.R. §78.238, 75 Fed. Reg. at 74,511. There are several problems with this 

definition. First, it is confusing. In discussing the reporting requirements for LDCs, both 

the Agency and our members find it difficult to avoid confusion when discussing 

requirements for individual locations – what one normally calls a facility – and the 

reporting system-wide “facility” as defined in the rule. Second, it is not clear whether a 

gas utility that operates distribution systems in multiple states - but subject to the 

regulation of a different public utility commission in each state - should count that multistate operation as a single “facility” or should count operations in state A as one “facility” 

and operations in state B as a second “facility.” Third, most LDCs are served by 

affiliate or interstate transmission pipelines, and the definition of a distribution facility as 

an LDC, which is regulated as a separate company by a Public Utilities Commission 

(PUC) is designed to fit that business model. However, California utilities and some 

other AGA members operate both transmission and distribution systems. The definition 

of a distribution facility needs to be clarified to determine the specific operations that are 

included in it. Fourth, by using such a broad definition of natural gas distribution 

“facility” – to include virtually everything operated by an LDC – the Agency has 

effectively set a far more stringent applicability threshold for LDCs than it has for all 

other sectors (other than for production, where EPA adopted a multi-state, geologic 

basin-wide definition of “facility.”) EPA has not provided satisfactory response to our 

detailed comments on this issue, and we believe there are more workable approaches 

that could be used. AGA requests reconsideration of the natural gas distribution 

“facility” definition. 

13
C. It Was Arbitrary and Capricious for EPA to Create a Subpart W 

Reporting Regulation for a Null Set – LNG Storage Facilities Will Not 

Exceed the 25,000 ton per year Threshold 

EPA’s Subpart W Rule creates an elaborate regulatory program for a null set. Liquefied 

natural gas (LNG) satellite and peak shaving facilities – defined as “LNG Storage 

Facilities” in the Subpart W Rule – are much smaller than LNG import and export 

terminals. They have far fewer combustion sources and components. As AGA 

demonstrated in its June 11, 2010 comments on the proposed rule, even if every 

combustion source operated at maximum throughput for vaporization and liquefaction 

systems and every component leaked methane (thus requiring the use of leaker 

emission factors for all components) the collective carbon dioxide equivalent emissions 

from even the largest LNG satellite or peak shaving facility could not exceed the 25,000 

metric ton per year threshold. And in fact, these facilities emit far less than one half of 

this worst case emissions scenario, because the combustion sources actually operate 

about one third of the year or less, and almost no components actually leak. 

We appreciate EPA’s creation of an applicability tool to help operators of these facilities 

determine that their facilities could not possibly exceed the applicability threshold. 

However, we did not have an opportunity to comment on this applicability tool, because 

it was created after the comment period ended. We are concerned that it could be used 

to infer that these facilities actually emit greenhouse gases at ‘worst case’ levels, which 

could be used to mislead policy makers as they evaluate future climate emission 

reduction programs. Further, it makes no sense to require facility operators to go 

through the effort to prove repeatedly what is already known: that LNG satellite or peak 

shaving (storage) facilities would not exceed the applicability threshold even if 

operated in a manner that would never be tolerated by other regulatory agencies or 

company shareholders. Creating a regulatory program for a null set is a classic 

example of wasteful, unnecessary and arbitrary and capricious rulemaking. EPA should 

revise the Subpart W rule to exclude LNG storage facilities – i.e. LNG satellite and peak 

shaving facilities. 

D. It Was Arbitrary and Capricious for EPA to Create a Subpart W 

Reporting Regulation for LNG Import and Export Facilities – Which 

Have Only Minimal Methane Leaks 

Nearly all of the greenhouse gas emissions from LNG import and export facilities come 

from combustion emissions, not methane leaks. As AGA explained in our June 11, 

2010 comments, for operational reasons, these facilities must be very tight. Almost no 

14
components leak. If combustion emissions exceed the 25,000 metric ton per year 

threshold, these facilities are already required to report CO2 emissions vented from 

reciprocating compressor (engines) or centrifugal compressors (turbines) under Subpart 

C. Why then create an additional regulatory burden on these facilities under Subpart W 

to conduct extensive on-site leak surveys to chase negligible methane leaks from 

valves, pump seals and other equipment? This will impose significant costs and 

resource demands to conduct on- site methane leak surveys to report truly negligible 

methane emissions. EPA has offered no rational explanation for requiring such a 

waste of resources to chase minimal emissions data. 

IV. CONCLUSION 

For the reasons discussed above, AGA urges EPA to reconsider the provisions in 

Subpart W applicable to natural gas distribution and underground storage facilities. 

AGA also urges EPA to stay the effectiveness of those provisions in Subpart W pending 

reconsideration, pursuant to the APA standard for an Agency’s administrative stay of a 

final rule. 

Dated March 2, 2011 

Respectfully submitted, 

American Gas Association 

By: ____________________________ 

Pamela A. Lacey 

 Senior Managing Counsel, Environment 

 American Gas Association 

 400 North Capitol Street N.W. 

 Washington, D.C. 20001 

placey@aga.org

 (202) 824-7340 

15




















BEFORE THE ADMINISTRATOR 

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

WASHINGTON, DC 

PETITION FOR RECONSIDERATION OF FINAL AGENCY ACTION: 

MANDATORY REPORTING OF GREENHOUSE GASES: 

PETROLEUM AND NATURAL GAS SYSTEMS

75 Fed. Reg. 74,458 (Nov. 30, 2010) 

Petitioners 

Chesapeake Energy Corporation 

American Exploration & Production Council 

Counsel for Petitioners 

Sandra Y. Snyder 

Kevin A. Ewing 

Lisa M. Jaeger 

Bracewell & Giuliani LLP 

2000 K Street, NW 

Suite 500 

Washington, DC 20006 

January 31, 2011 
 

1

INTRODUCTION 

Pursuant to § 307(d)(7)(B) of the Clean Air Act, 42 U.S.C. § 7607(d)(7)(B), 5 U.S.C. 

§§ 551 et seq. of the Administrative Procedure Act and for the reasons set forth below, 

Chesapeake Energy Corporation (Chesapeake) and the American Exploration & 

Production Council (AXPC) petition the Administrator of the United States 

Environmental Protection Agency (EPA) to reconsider specific provisions its final rule 

requiring owners and operators of petroleum and natural gas systems to monitor and 

report emissions of greenhouse gases (GHGs) from equipment leaks and vents. 

On April 12, 2010, EPA proposed the rule Mandatory Reporting of Greenhouse Gases: 

Petroleum and Natural Gas Systems (Subpart W Rule) (75 Fed. Reg. 18,608). On June 

11, 2010, the comment period closed. On November 30, 2010, EPA published the final 

Subpart W Rule (75 Fed. Reg. 74,458). 

Reconsideration of the rule is warranted because the grounds for the issues identified 

below, which are "of central relevance to the outcome of the rule," arose after the public 

comment period or could not be raised due to impracticability. 42 U.S.C. 

§ 7607(d)(7)(B). If this test is met, the Clean Air Act (CAA) requires that EPA “shall

convene a proceeding for reconsideration of the rule and provide the same procedural rights 

as would have been afforded had the information been available at the time the rule was 

proposed.” Id. Furthermore, during the reconsideration of the rule, EPA may stay the 

effectiveness of the rule. Id.

SUMMARY OF PETITION 

Chesapeake is one of the largest producers of natural gas and one of the most active 

drillers of new wells in the United States (U.S.). The company also owns substantial 

midstream, compression, drilling, and oilfield service assets. AXPC is a national trade 

association representing 25 of the largest independent natural gas and crude oil 

exploration and production companies in the U.S. Chesapeake and the members of 

AXPC will be directly and immediately affected by the requirements of the final Subpart 

W Rule. 

The Subpart W Rule imposes significant new legal obligations on covered sources to 

measure, monitor and report emissions of GHGs. As EPA's description of the source 

category suggests – "equipment leaks and vented GHG emissions"1

 – the overall source 

category is made up of hundreds of thousands of sources throughout the oil and gas 

sector. Failure to discern and properly measure what is a reportable emission as specified 

in the final rule may result in a source being out of compliance with mandatory federal 

requirements. Failure to comply with federal law is of such serious consequence that 

covered entities do not risk noncompliance. However, in its final form, the Subpart W 

Rule contains elements that will force covered sources to do precisely that. 

 1

 75 Fed. Reg. 74,460. 
 

2

As more fully described below, the final rule is severely flawed in several important 

respects. Several provisions are newly established in the final rule. Covered sources, had 

they been afforded the opportunity, would have commented on these elements, and 

demonstrated their unworkability for determining what constitutes compliance with the 

rule. Multiple other provisions in the final rule create internal inconsistencies or lack of 

clarity, creating additional uncertainty for determining compliance. Finally, the final rule 

contains certain provisions that were signaled in the proposed rule, but that lack any 

record support, including any support in EPA's Response to Comments. EPA has failed 

in those instances to meet its obligation to address significant comments with a 

reasonable degree of analytic rigor that reflects that EPA considered and fairly addressed 

the concerns raised in comments. These issues, which are of central relevance to the rule, 

merit reconsideration so that substantive and procedural flaws may be addressed 

administratively. 

SPECIFIC ISSUES FOR RECONSIDERATION 

A. IN THE FINAL RULE AND IN RESPONSE TO COMMENTS, EPA FAILS TO 

 JUSTIFY CERTAIN ASPECTS OF THE RULE EITHER THROUGH RECORD 

 DATA OR LEGAL ANALYSIS, WITH THE RESULT THAT THOSE 

 ELEMENTS ARE ARBITRARY AND CAPRICIOUS. 

1. Measurement of emissions. 

EPA proposed to require costly measurement and reporting of emissions from hundreds 

of thousands of sources. Commenters asked EPA to adopt a reasonable threshold for 

measurement, so that emissions could still be accounted for, but in a cost-effective way. 

Commenters recommended using the API Compendium for that purpose. Commenters 

also demonstrated that EPA has concluded that for other provisions in this very same 

GHG Mandatory Reporting Rule, measurement of emissions at de minimis levels not 

only do not justify the cost of measurement, but they need not even be accounted for 

through an accepted estimation methodology. 

In response to these substantive concerns, EPA offers this conclusory statement without 

reference to any supporting authority: “The emission factors in the US Inventory, and 

also in the API Compendium, have been demonstrated to underestimate emissions by an 

order of magnitude or more for sources including gas well liquids unloading, gas well 

completions and workovers, and centrifugal compressor wet seal degassing vents.” EPA, 

Mandatory Greenhouse Gas Reporting Rule Subpart W – Petroleum and Natural Gas: 

EPA's Response to Public Comments (Nov. 2010) (hereinafter "RTC") at 1348. EPA is 

obligated to respond to challenges in a coherent manner that is supported by studies 

provided in the administrative record. See Am. Min. Congress v. EPA, 907 F.2d 1179, 

1189 (D.C. Cir. 1990) (remanding a rule to the agency because EPA responded to 

petitioners' challenges with conclusory statements and no discussion of studies that it 

relied upon or why its conclusions were reasonable absent such studies). 
 

3

The Compendium was initially released in April 2001.2 The 2009 version - the third 

release of the Compendium - "represents industry best practices for estimating GHG 

emissions" and the "latest information available" on emission factors and methodologies. 

Id. at ii, 1-2. The Compendium has been regularly modified based upon comments 

received during "industry conferences, workshops, and focused outreach to other protocol 

development organizations, particularly those used by the oil and natural gas industry in 

other regions of the world." Id. at 1-2. It has also been subject to "broad peer review" by 

governmental agencies, non-governmental organizations, and industry associations. Id. at 

ii. The Compendium is widely understood by industry and EPA to provide "consistent, 

standardized methodologies for estimating GHG emissions. . ." Id. at 1-1; see also New 

Mexico Greenhouse Gas Mandatory Emissions Reporting, Emissions Quantification 

Procedures for 20.2.73 NMAC and 20.2.87 NMAC (requiring the reporting of GHG 

emissions in 2010 and allowing the use of the API Compendium). 

In fact, numerous protocols throughout the world, including those used in the European 

Union, Canada, and Australia, either allow or require the use of the Compendium when 

reporting GHG emissions.3

 It was "designed to strike a balance between flexibility and 

cost-effectiveness in accounting and reporting, and the need for consistency and accuracy 

in the reported results." Karin Ritter et al., The Road to Consistency in Greenhouse Gas 

Emissions Estimation and Reporting for the Oil & Gas Industry Sector, Paper No. 04-A583-AWMA, at 2 (Feb. 26, 2004). Knowing that the Compendium represents over a 

decade of knowledge that has been widely peer-reviewed and regularly updated would 

enable companies to certify the accuracy and integrity of their emissions data with great 

confidence. 

EPA’s plan to develop a screening tool, while it will assist in the reporting process, is not 

responsive to this comment. A screening tool streamlines the identification of emission 

sources. The Compendium is a highly respected methodology for estimating emissions.4

EPA does not even explain its inconsistent treatment of these low emissions as compared 

to other similar levels of emission by other sources subject to GHG reporting under the 

same rule. 

The unjustified burdens of emissions measurement in this rule should be reconsidered 

especially in light of the recent Executive Order (EO) on Regulation and Regulatory 

Reform.5

 The EO directs all federal agencies to assess the costs and benefits of their 

regulations, and to select the least burdensome regulatory approach. Subpart W imposes 

a highly burdensome measurement requirement on sources with no demonstrable 

 

2

 API, Compendium of Greenhouse Gas Emissions Methodologies for the Oil and Natural Gas Industry at 

1-2 (Aug. 2009). 

3

 Australian Government, Department of Climate Change, Technical Guidelines for the estimation of 

greenhouse gas emissions by facilities in Australia, ch. 3 (June 2009); Answers to Frequently Asked 

Questions on Greenhouse Gas Emissions Monitoring and Reporting under the EU Emissions Trading 

System Pursuant Directive 2003/87/EC, at 13 (Sept. 2007); Government of Alberta, Technical Guidance 

for Completing Specified Gas Baseline Emission Intensity Applications, at 30 (Feb. 2010). 

4 See n.3, supra. 5

 Exec. Order, Improving Regulation and Regulatory Review (Jan. 18, 2011), available at 

http://www.whitehouse.gov/the-press-office/2011/01/18/improving-regulation-and-regulatory-reviewexecutive-order.
 

4

corresponding benefit, while disregarding more cost-effective alternatives. As a result, 

Subpart W violates the letter and spirit of the EO.6

2. De minimis emissions from portable equipment. 

The final rule likewise fails to adequately support requiring the reporting of de minimis 

emissions from portable equipment as EPA proposed. 75 Fed. Reg. 18,636 (proposed 40 

C.F.R. § 98.230(a)(2)). Commenters explained why the information gained from 

measuring and reporting portable equipment emissions, which are de minimis, does not 

justify the additional resource strain on covered sources. 

In the final rule, EPA does not resolve the fundamental issue of imposing costly 

requirements to measure de minimis emissions. Instead, EPA asserts a truism that all 

emissions contribute to sector emissions overall. EPA also in part justifies requiring 

measurement of portable equipment emissions rather than relying on data from the EPA's 

Natural Gas STAR program, by alleging without support that “most” of the existing 

programs “use the same inaccurate oil and gas production sector factors from the EPA 

National Inventory to estimate emissions.” RTC at 956 (citing RTC at 32). The accuracy 

of existing emission factors and overall contribution to emissions do not respond to the 

fundamental problem. EPA is cognizant of the need to ensure the burden on sources is 

commensurate with the benefit of obtaining the precisely measured data. These 

emissions are no different in terms of their significance level than other emissions where 

EPA has concluded that “reporting of [these] GHG emissions is unreasonable given the 

cost of monitoring and the relative level of GHG emissions.” See 74 Fed. Reg. at 56,291 

(Oct. 30, 2009). 

 

6

 In relevant part, the EO states that every agency “must”: 

* * * 

(b)(1) propose or adopt a regulation only upon a reasoned determination that its benefits justify its 

costs (recognizing that some benefits and costs are difficult to quantify); (2) tailor its regulations 

to impose the least burden on society, consistent with obtaining regulatory objectives, taking into 

account, among other things, and to the extent practicable, the costs of cumulative regulations; (3) 

select, in choosing among alternative regulatory approaches, those approaches that maximize net 

benefits (including potential economic, environmental, public health and safety, and other 

advantages; distributive impacts; and equity); (4) to the extent feasible, specify performance 

objectives, rather than specifying the behavior or manner of compliance that regulated entities 

must adopt; and (5) identify and assess available alternatives to direct regulation, including 

providing economic incentives to encourage the desired behavior, such as user fees or marketable 

permits, or providing information upon which choices can be made by the public. 

(c) In applying these principles, each agency is directed to use the best available techniques to 

quantify anticipated present and future benefits and costs as accurately as possible. Where 

appropriate and permitted by law, each agency may consider (and discuss qualitatively) values that 

are difficult or impossible to quantify, including equity, human dignity, fairness, and distributive 

impacts. 

* * * 

Exec. Order, Improving Regulation and Regulatory Review (Jan. 18, 2011). 
 

5

In addition, EPA’s approach contradicts its oft-stated need for accurate emission data 

from all sectors covered in the Reporting Rule. See, e.g., 75 Fed. Reg. 74,474 (“[T]he 

high level of public interest in the data collected, as well as its importance to future 

policy, warrants establishment of a high standard for data quality and consistency. . . .” ); 

75 Fed. Reg. 74,484 (“EPA plans to collect complete and accurate facility-level GHG 

emissions from the petroleum and natural gas industry. Accurate and timely information 

on GHG emissions is essential for informing future climate change policy decisions); 75 

Fed. Reg. 74,467 (“facility” definition selected in part to avoid double-counting ); 75 

Fed. Reg. 74,498 (flare emissions “must be corrected for flare emissions calculated and 

reported under other paragraphs of this section to avoid double counting”). 

However, in the case of portable equipment, EPA knowingly imposes the requirement on 

the oil and gas industry to report these emissions while ignoring the inaccuracy imposed 

by double-counting these emissions reported elsewhere in the mandatory reporting rule. 

In the Response to Comments, EPA acknowledges that these same emissions are already 

reported under Subpart MM and double counting will result. RTC at 955-56. EPA 

accepts double counting in this instance, because “[a]lthough refineries will report total 

fuel supplied under Subpart MM, EPA will not know where the fuels are being 

combusted to inform any combustion equipment specific policy. . . .” RTC at 1600. 

The result is completely arbitrary: in the same rule, EPA demands exact measurement of 

very de minimis emissions, while inviting inaccuracy by expressly requiring doublecounting of emissions from the same sources. This irrational outcome should have and 

could have been addressed during the rulemaking process. EPA simply could have 

applied the reporting requirement to the equipment that utilizes field gas and not required 

reporting from diesel-fired equipment. Rather than using the rulemaking process to 

devise a rational methodology that would achieve accuracy and consistency in the rule, 

EPA finalized an irrational approach. 

3. Designated Representative. 

EPA emphasizes the need for accountability for data accuracy and adopts the model of a 

Designated Representative (DR). Petitioners do not challenge the need for accuracy nor 

the DR approach that requires the operator to act as the DR. However, in accordance 

with 40 C.F.R. § 98.4(i), the DR, an individual, must make the following four 

Certifications: 

(i) "I was selected as the designated representative...by an agreement binding on 

the owners and operators of the facility. . . ." (Certification 1) 

(ii) "... each such owner and operator shall be fully bound by my representations, 

actions, inactions, or submissions." (Certification 2) 

(iii) "...the owners and operators of the facility...shall be bound by any order 

issued to me by the administrator or a court regarding the facility. . . ." 

(Certification 3) 
 

6

(iv) ". . . I have given a written notice of my selection as the ‘designated 

representative’ . . . and of the agreement by which I was selected to each 

owner and operator of the facility. . . .” (Certification 4) 

The oil and gas industry explores for, and develops hydrocarbons pursuant to a customary 

form of agreement, the joint operating agreement (JOA). There are thousands of JOAs 

outstanding, each with multiple parties. A JOA is an agreement between co-owners of 

the rights to explore for and develop the oil and gas in certain described property. The 

parties typically designate one of the co-owners as operator to manage property 

operations, subject to the terms of the JOA. The scope of an operator’s authority is 

derived from the terms and conditions of the JOA. Although multiple standard forms of 

JOAs are in use by industry, contracting parties amend the terms of the standard forms to 

achieve the desired contractual relationships among the parties. 

One threshold issue that EPA has not adequately evaluated is whether these JOAs enable 

an operator to make all of Certifications 1 through 4 without obtaining the consent of 

other affected parties. The industry operates thousands of properties, each of which can 

have multiple interest owners of varying levels of sophistication and willingness to 

cooperate. Accordingly, obtaining consent could prove daunting and unsuccessful. It is 

possible that recalcitrant owners or those with minor ownership shares may seek 

commercial leverage against the other owners by refusing to approve the selection of the 

DR. Such scenarios could jeopardize the obligation to comply with the reporting 

requirement in a timely manner. 

Most JOA forms give the operator some form of control or management of property 

operations and directly or indirectly contemplate compliance with applicable laws or 

filing of reports with government authorities. Typically, the operator certifies to the 

accuracy of the reports submitted, but is not required to additionally make other legally 

binding certifications that would necessitate the operator to act as a fiduciary or agent for 

the owners. The specificity of the Certifications EPA requires – and the breadth of their 

legal implications – will require lawyers to review every JOA now in effect. While much 

of the industry tends to use form JOAs, not all the terms of those form JOAs are 

uniformly accepted and therefore each executed contract would need to be individually 

reviewed. At best, the Certification requirements create legal ambiguity and regulatory 

uncertainty for companies regarding this new obligation under longstanding existing 

contracts. If contracts must be reviewed and amended, companies will bear an additional 

legal and administrative burden. 

Commenters objected to this provision during the notice and comment period. See 

Comment EPA-HQ-OAR-2008-050800412.1. EPA rejected the suggestion that the 

operator of a facility be responsible for reporting. See EPA, Mandatory Greenhouse Gas 

Reporting rule: EPA's Response to Public Comments, Volume No. 11, Designated 

Representative and Data Collection, Reporting, Management, and Dissemination at 11 

(Sept. 2009) (hereinafter "RTC Vol. 11"). EPA’s response suggests that a contract that 

gives a majority owner operational and compliance control may constitute a contract 

binding owners and operators for purposes of DR selection. Not only is this response 

equivocal, it reflects that EPA has not met its obligation to gather data and develop an 

analytic record to support its conclusions. Upon even a cursory review of JOAs, EPA 
 

7

would have identified multiple provisions that immediately raise the question of possible 

legal impediments to compliance with the Certification requirements. For example, some 

form JOAs include provisions such as the following: 

• “The Operator is not the agent or fiduciary of the Non-Operating Parties.” 

• “It is not the intention of the parties to. . . render them liable as partners.” (i.e., to 

 make them jointly and severally liable) 

• “This agreement is not intended to. . . impose a partnership duty, obligation, or 

liability with regard to any one or more of the parties hereto. 

The inclusion of such provisions in executed JOAs may prohibit an operator from being 

able to make the DR Certifications required under Subpart A of the reporting rule. 

The rights and duties of JOA parties are the subject of the JOA—a contract between 

private parties. If a non-operator were to challenge—by litigation or otherwise—an 

operator’s authority to take action not expressly authorized by the JOA, EPA’s equivocal 

thoughts on the contract would not control a dispute between private parties. More 

fundamentally, EPA lacks the authority to reinterpret these contractual relationships, or to 

require that the parties renegotiate the terms of their contracts to accommodate an air 

emission reporting requirement. 

EPA borrowed this requirement from the Acid Rain Program. RTC Vol. 11 at 11. The 

Acid Rain program, 40 C.F.R. § 72.20, imposes emission caps and reductions through an 

emissions trading program on fossil fuel-fired power plants. Neither the emission control

program of the Acid Rain program, nor the utility sector, are the least bit analogous to an 

emission reporting rule for the oil and gas sectors. One oil or natural gas well may have 

multiple owners and in some cases even hundreds of owners. Ownership in a well often 

changes. EPA has not shown that it has given consideration to the unique burdens 

imposed by applying this requirement to the oil and gas sector, which would have 

become apparent to EPA had it developed the form for commenters to review and 

provide comment on during the rulemaking process. Providing the names of all owners 

for each individual well will require a certification form that allows the entry of 

voluminous ownership lists, and will require administrative process for continually 

updating the ownership form. Under 40 C.F.R. § 72.23(c), sources regulated under the 

Acid Rain program must update EPA within 30 days of a change to any owner or 

operator. If EPA were to impose such an obligation here, the agency must develop a 

process for handling ownership change notifications as ownership can change frequently 

at some wells. 

EPA insists that requiring ownership involvement will ensure accountability for the 

submission of such data, and alleges without any factual support that imposing this 

requirement to designate a representative will not interfere with contractual relationships 

between multiple owners. RTC Vol. 11 at 11. EPA must provide a reasoned basis for its 

decisions and provide regulatory certainty, which it utterly fails to do on this issue. See 

Am. Min. Congress v. EPA, 907 F.2d 1179, 1189 (D.C. Cir. 1990) (remanding a rule to 

the agency because EPA responded to petitioners' challenges with conclusory 

statements). 
 

8

B. THE FINAL RULE IMPOSES NEW COMPLIANCE REQUIREMENTS AND 

METHODOLOGIES THAT WERE NOT INCLUDED IN THE PROPOSED 

RULE, DEPRIVING COVERED SOURCES OF NOTICE AND AN 

OPPORTUNITY TO COMMENT. 

1. Dump valves. 

The final rule imposes for the first time the requirement to measure and report emissions 

from dump valves associated with onshore production storage tanks. 75 Fed. Reg. 

18640) (Storage Tanks – 40 C.F.R. § 98.233(j)(8), Eq.W-16). This is a new and 

unreasonable ongoing monitoring and record keeping burden to impose on industry 

without providing affected sectors an opportunity to comment on the proposal. Onshore 

production sites could have thousands of dump valves per reporting facility or basin that 

would require frequent monitoring and maintenance of records of dump valve checks at 

production sites that are mostly unmanned. 

2. Best Available Monitoring Methods (BAMM). 

As proposed, the rule did not allow Best Available Monitoring Methods (BAMM) for 

part of or all of 2011. 75 Fed. Reg. 18612. Commenters had sought an alternative 

compliance method. In the final rule (75 Fed. Reg. 74473), EPA states that parties may 

submit applications by April 30, 2011, and EPA "may" allow BAMM for "up to the 

entire 2011 calendar year." This rule creates uncertainty for sources, which rely on 

certainty in rule procedures and deadlines. 

EPA establishes neither a process nor agency deadlines for rendering decisions on 

whether BAMM will be permitted in a given case. Moreover, EPA provides no standards 

by which it will be guided in what appears will be case-by-case determinations. Because 

EPA did not inform covered sources in the proposal, or seek their input in a supplemental 

proposal, that BAMM would be permitted, covered sources could not have sought the 

inclusion of additional elements in the rule that would provide certainty in how such 

decisions are made, including deadlines by which EPA would decide whether the 

request would be approved. BAMM should be allowed without EPA approval for entities 

reporting under Subpart W for the entire first reporting year 2011 and for all data 

necessary to conduct the calculations required under the rule. 

3. Emissions manifolded to common vents. 

In the final rule, 40 C.F.R. §98.233(o), the requirement for centrifugal compressor 

venting, was changed to include a requirement to report emissions from dry seal 

centrifugal compressor vents and emissions from all vents (including emissions 

manifolded to common vents). Compare 75 Fed. Reg. 74,498 to 75 Fed. Reg. 18,642. 

Section 98.233(o) of the proposal covered only "Centrifugal compressor wet seal 

degassing vents" and required calculating "emissions from centrifugal compressor wet 

seal degassing vents." Section 98.233(o) of the final rule is now labeled "Centrifugal 

compressor venting" and requires calculating "CH4, CO2 and N2O (when flared) 

emissions from both wet seal and dry seal centrifugal compressor vents." 
 

9

This modified language not only expands the rule to cover equipment that was not 

identified in the proposed rule, but it is also inconsistent and creates ambiguity for 

covered sources regarding what is required. 40 C.F.R. § 98.233(o) states that it applies to 

"emissions from both wet seal and dry seal centrifugal compressor vents" yet certain 

subparts appear to only apply to wet seal oil degassing vents (see, e.g., 40 C.F.R. 

§ 98.233(o)(6), (7) (imposing requirements to conduct total compressor counts for wet 

seal centrifugal compressors). 

C. THE FINAL RULE IMPOSES A NEW OBLIGATION TO MONITOR AND 

 REPORT THAT WOULD REQUIRE MAJOR PIPING MODIFICATIONS AND 

 THAT WOULD UNDULY THREATEN WORKER SAFETY 

The final rule requires measuring "emissions from all vents (including emissions 

manifolded to common vents)." This requirement was not part of the proposed language 

for Section 98.233(o). As commenters noted, compressor emissions could be estimated 

using the API Compendium. See, e.g., RTC at 1554 (“The API Compendium would be 

preferable because the compliance costs associated with the direct measurement 

requirements for 'large' reciprocating compressor rod packing vents are not justifiable 

given the relatively small emissions that would be measured through use of such 

methods.”). EPA merely responded that “the API compendium factors do not account for 

emissions from unit isolation valves and therefore would not represent all the emissions 

required under this rule” (emphasis added). 

EPA does not explain why the cost of gathering these particular emissions is justified 

given the expense and small increase in the accuracy of the overall emissions reporting. 

The “reporting of [these] GHG emissions is unreasonable given the cost of monitoring 

and the relative level of GHG emissions.” See 74 Fed. Reg. at 56,291 (Oct. 30, 2009). 

Measuring these emissions also creates a significant safety risk for workers. While such 

measurements have been conducted on research projects for a limited number of engines, 

the potential for injury increases dramatically when this type of work is made mandatory 

on thousands of engines every year. 

D. THE FINAL RULE CONTAINS CONFLICTING AND INCONSISTENT 

 TREATMENT OF REQUIRED ELEMENTS AND DEFINITIONS THAT ARE 

 THE BASIS FOR DETERMINING COMPLIANCE. 

Air emissions inventory regulations must contain requirements with sufficient clarity that 

a knowledgeable person can be confident in knowing they have complied with the 

regulations. Precision is critical here, where designated representatives must sign – and 

be held legally responsible for – a certification of compliance under 40 C.F.R. § 98.4. 

When reporting GHG emissions, a designated representative must sign the following 

certification statement: 

 I am authorized to make this submission on behalf of the owners and 

operators of the facility or supplier, as applicable, for which the 
 

10

submission is made. I certify under penalty of law that I have personally 

examined, and am familiar with, the statements and information submitted 

in this document and all its attachments. Based on my inquiry of those 

individuals with primary responsibility for obtaining the information, I 

certify that the statements and information are to the best of my 

knowledge and belief true, accurate, and complete. I am aware that there 

are significant penalties for submitting false statements and information or 

omitting required statements and information, including the possibility of 

fine or imprisonment. 

The Subpart W Rule contains numerous requirements that are vague or subject to 

different interpretations. These inconsistencies in the rule place an unjustifiable burden 

on compliance personnel and the designated representative to certify, in good faith, 

compliance with a regulation that is facially unclear. In some instances, EPA was 

addressing comments, but in doing so created new, not previously proposed, 

inconsistencies. Through reconsideration of the rule, EPA could provide notice and 

comment and resolve vagueness and inconsistency in the final rule. As presently drafted, 

the unclear and inconsistent final provisions render the rule arbitrary and capricious and 

contrary to law. 

 

1. Excluding boosting stations. 

EPA changed the definition of "onshore natural gas processing facility" in 40 C.F.R. 

§ 98.230 from the proposed definition. The final rule states "This source category does 

not include reporting of emissions from gathering lines and boosting stations." Yet the 

definition also now states that the source category does include "all residue gas 

compression equipment owned or operated by the natural gas processing facility, whether 

inside or outside the processing facility fence." 

The final rule fails to distinguish between a boosting station, which is exempt, and 

an "onshore natural gas transmission compression facility," which must report under the 

rule. 

Onshore natural gas transmission compression

The term "onshore natural gas transmission compression" means a stationary 

combination of compressors that move natural gas at elevated pressure from production 

fields or natural gas processing facilities in transmission pipelines or into storage. 40 

C.F.R. § 98.230(a)(4). A transmission compressor station can include equipment to 

separate liquids or dehydrate natural gas. Id. However, according to the final rule this 

source category does not include gathering lines and boosting stations. Id.

Onshore natural gas processing

Onshore natural gas transmission compression stations are distinct from "onshore natural 

gas processing," which "separates and recovers natural gas liquids (NGLs) and/or other 

non-methane gases and liquids from a stream of produced natural gas using equipment 

performing one or more of the following processes: oil and condensate removal, water 
 

11

removal, separation of natural gas liquids, sulfur and carbon dioxide removal, 

fractionation of NGLs, or other processes, and also the capture of CO2 separated from 

natural gas streams." 40 C.F.R. § 98.230(a)(3). Gathering lines and boosting stations 

are not included in "natural gas processing"; however, residue gas compression 

equipment owned or operated by the natural gas processing facility is included, whether it 

is located inside or outside the fence line of the processing facility. 40 C.F.R. 

§ 98.230(a)(3). The technical support document to Subpart W notes that "processing 

plants process the gas received from production and/or gathering or boosting segments to 

remove hydrogen sulfide (H2S) and/or CO2 from the natural gas, if any, separate the 

higher molecular weight hydrocarbons (ethane, propane, butane, pentanes, etc.) from the 

natural gas and compress the natural gas to be injected into the onshore natural gas 

transmission segment." Subpart W, Background Technical Support Document at 26. 

Gathering lines and boosting stations

Notably, the terms "gathering line" and "boosting station" are not defined in Subpart W. 

However, in the Response to Comments, EPA states that it has eliminated from the rule 

"field gathering and/or boosting stations that gather and process natural gas from multiple 

wellheads, and compress and transport natural gas (including but not limited to flowlines 

or intra-facility gather lines or compressors) as feed to the natural gas processing 

facilities as being a part of the processing facility, as well as reference to gathering and 

boosting stations that send the natural gas to an onshore natural gas transmission facility. 

. . ." RTC at 938-39. This statement conflicts with the definition of the term "onshore 

natural gas transmission compression" which includes compressors that move natural gas 

from production fields or natural gas processing facilities in transmission pipelines. 40 

C.F.R. § 98.230(a)(4). 

API commented to EPA that "it is not clear where onshore natural gas compression 

begins." See Comment EPA-HQ-OAR-2009-0923-1151-7. In response, EPA merely 

noted that the "final rule does not require reporting of emissions from [the] gathering and 

booting segment of the industry." RTC at 78-79. This response is not helpful and 

gives industry no clarity regarding which compressor stations are required to report. 

2. Mapping wells to fields. 

EPA has not clarified how reporting entities are supposed to map wells to a particular 

“field.” Section 98.238 merely defines a “field” as “oil and gas fields identified in the 

United States as defined by the Energy Information Administration Oil and Gas Field 

Code Master List 2008, DOE/EIA 0370(08).” There are no coordinates provided in the 

EIA O&G Field Code Master List. There is no formal way to designate appropriate field 

names. EPA has also not addressed how to deal with wells that are not in a recognized 

field in the EIA Master List. Between the 2007 and 2008 versions, over 500 new fields 

were added and many fields recognized by states are not in the EIA Master List. 

Mapping wells to the proper field is central to compliance with the rule, because the rule 

requires aggregation of information by field for the following items: 

1. Liquid unloading (75 Fed. Reg. 74,493) 

2. Completions and workovers with fracing (75 Fed. Reg. 74,494) 
 

12

3. Completions and workovers without fracing (75 Fed. Reg. 74,495) 

4. Storage tank venting (75 Fed. Reg. 74,496) 

5. Associated gas venting/flaring (75 Fed. Reg. 74,497) 

6. Major equipment counts (75 Fed. Reg. 74,510) 

7. Gas composition (75 Fed. Reg. 74,496, 74,498, 74,500, 74,503, 74,504) 

EPA should use counties, not fields, as the smallest unit of reporting area. As EPA itself 

noted in this rulemaking, county boundaries are “likely to be familiar to the industry, i.e., 

if the owner or operator knows in which county their well is located, then they know to 

which basin they belong. Hence, in this action, EPA is finalizing the facility definition at 

the basin level for the onshore petroleum and natural gas production industry segment 

because the operational boundaries and basin demarcations are clearly defined and are 

widely known, and reporting at this level would provide the necessary coverage of GHG 

emissions to inform policy.” 75 Fed. Reg. 74,467. 

This lack of clarity creates another problem, also new to the final rule. The proposed rule 

stated that if no continuous gas analyzer was available, then quarterly gas composition 

samples must be taken. 75 Fed. Reg. 18,644. In response to comments, EPA modified 

this rule. The final rule now requires that gas composition be based on a representative 

analysis of produced oil and gas from the field. See, e.g., 75 Fed. Reg. 74,496 

(§ 98.233(j)), 74,498 (§ 98.233(n)), 75 Fed. Reg. 74,500 (§ 98.233(p), Eq. W-26), 75 

Fed. Reg. 74,503 (98.233(u)(2)(i))), 75 Fed. Reg. 74,504 (§ 98.233(z)(2)(ii)). Without 

sufficient clarity regarding what wells are in a particular field, it is difficult for covered 

sources to know with certainty what gas composition is considered representative for 

each well. 

3. Definition of “facility.” 

The proposed rule used a novel definition of “onshore petroleum and natural gas 

production facility” to include a range of elements not commonly understood in the oil 

and gas sectors to constitute a “facility.” EPA responded to comments by explaining that 

“EPA’s definition of ‘facility’ for purposes of the proposed Subpart W in no way impacts 

the 'facility' definition for similar sources under the NSR program or other existing CAA 

programs.” See response to EPA-HQ-OAR-2009-0923-1044-1 (RTC at 951). 

Commenters’ concern is not confusion with other CAA programs. Commenters’ concern 

remains: internal to Subpart W rule, EPA and the regulated community use “facility” to 

mean many different things. See, e.g., 75 Fed. Reg. 74,468 (discussing ownership 

structures in relation to booster stations); 75 Fed. Reg. 74,471 (monitoring methods 

currently used by a facility); 75 Fed. Reg. 74,475 (estimated compliance costs per 

facility). EPA has not provided a reasoned explanation for why a term other than 

“facility” cannot be adopted for Subpart W (such as “Reporting Area”) in order to avoid 

unintended confusion and inaccuracies in reporting. 

4. Pipeline quality natural gas. 

There is not a clear and unambiguous definition in the final rule for “pipeline quality” 

natural gas" (see 40 C.F.R. § 98.233(z)). The proposal did address the term “pipeline 
 

13

quality”, 75 Fed. Reg. 18,615, but nothing in the final rule provides such clarity, thereby 

raising a compliance and certification issue given the ambiguity in the rule. 

5. Producing horizon/formation. 

There is not a clear and unambiguous definition provided in the final rule for the term 

“producing horizon/formation.” See 40 C.F.R. § 98.233(f). For well venting for liquids 

unloadings, the final Subpart W rule utilizes the term "producing horizon/formation." Id. 

No definition is provided in the rule for this term, which imposes a compliance issue as 

its meaning could be interpreted differently by the reporting sources. 

6. Well testing venting and flaring. 

The final rule is unclear regarding the requirement to report emissions from well testing 

venting and flaring. 40 C.F.R. § 98.233(l). Most well testing takes place at the same 

time as well completion. In order to comply with this requirement, covered sources need 

a clear definition of when completion/flowback is finished and when well testing begins. 

Without such clarity, the results reported to EPA will be inconsistent and designated 

representatives will have difficulty certifying that their submissions are complete and 

accurate. 

7. Associated gas venting and flaring. 

40 C.F.R. § 98.233(m) imposes a requirement to report emissions from associated gas 

venting and flaring not in conjunction with well testing. While this regulation references 

40 C.F.R. § 98.233(l), that definition is unclear. Therefore, industry is left without clarity 

regarding what emissions are included in "associated gas venting and flaring not in 

conjunction with well testing." We presume that EPA intended in § 98.233(m) to require 

reporting of emissions from venting/flaring of associated gas from an oil well when there 

is no sales pipeline available, which is the typical setup for well testing. Whether EPA 

meant to impose the requirement to report emissions from all temporary venting events or 

only continuous venting/flaring (as from a stripper well) is unclear. Many individual 

triggers could lead to venting/flaring; therefore, if EPA intended to require reporting of 

temporary venting, such a requirement would impose a large burden on facilities by 

requiring continuous monitoring from all oil wells. 
 

14

8. Pneumatic devices. 

The requirement to report emissions from pneumatic devices, 40 C.F.R. § 98.233(a), is 

vague. EPA has imposed a requirement to count each pneumatic device according to its 

bleed rate. High-bleed pneumatic devices are classified as those that vent continuously to 

the atmosphere at a rate in excess of 6 scf/hr, whereas low-bleed pneumatic devices are 

those that bleed at rates equal to or less than 6 scf/hr. EPA has not clarified how industry 

must determine these rates. It is unclear whether it is sufficient to rely on the 

manufacturer's bleed rate data, whether direct measurements are required at each 

individual pneumatic device, or if BAMM can or should be used. Regardless of the 

method used to determine bleed rate, EPA has not given sufficient consideration to the 

burden imposed by requiring that the bleed rate of each device be determined in order to 

count and classify the devices. 

9. Blowdown vent stacks. 

The sources that are required to report emissions from blowdown vent stacks are not 

clear. Table 3 of the preamble lists onshore production as being required to report 

emissions from blowdown vent stacks. 75 Fed. Reg. 74463. In contrast, the statute does 

not require that blowdown vent stack emissions be reported for onshore petroleum and 

natural gas production facilities. See generally 40 C.F.R. § 98.232(c). For compliance 

purposes, sources need resolution of this inconsistency between the language in the 

preamble and the rule. 

CONCLUSION 

For all of the foregoing reasons, Chesapeake and AXPC respectfully request that EPA 

grant the Petition for Reconsideration. 
February 11, 2011

The Honorable Lisa P. Jackson, Administrator

U.S. Environmental Protection Agency

Ariel Rios Building 

1200 Pennsylvania Avenue, NW

Mail Code: 1101A 

Washington, D.C. 20460 

Re: Request for Administrative Reconsideration Subpart W of the Mandatory Reporting of 

Greenhouse Gases Rule: Petroleum and Natural Gas Systems

Dear Administrator Jackson:

The Gas Processors Association (“GPA”) hereby requests that the U.S. Environmental 

Protection Agency (“EPA” or the “Agency”) reconsider Subpart W of the Mandatory Reporting 

of Greenhouse Gases: Petroleum and Natural Gas Systems; Final Rule, published at 75 Fed. Reg. 

74458 (Nov. 30, 2010) (“Subpart W”). Pursuant to § 307(d)(7)(B) of the Clean Air Act 

(“CAA”), 42 U.S.C. § 7607(d)(7)(B), where it is impracticable to raise an objection during the 

period of public comment or if the grounds for such an objection arise after the public comment 

period (but within the time specified for judicial review), and if such objections are of central 

relevance to the outcome of the rule, EPA is authorized to reconsider a rule.

GPA is a non-profit trade organization made up of approximately 120 corporate 

members, all of whom are engaged in the processing of natural gas into merchantable pipeline 

gas, or in the manufacture, transportation, or further processing of liquid products from natural

gas. GPA’s membership accounts for approximately 92 percent of all natural gas liquids 

produced by the midstream energy sector in the United States. Our members also produce, 

gather, transmit, and market natural gas and natural gas liquids, and include a number of 

Canadian and international companies that produce natural gas liquids on a global scale.

As described more fully below, GPA is requesting reconsideration of the following key

aspects of Subpart W. GPA’s objections to these aspects of the final rule arose after the close of 

the public comment period and are of central relevance to the outcome of the final rule. Thus, 

reconsideration is authorized and appropriate. GPA’s objections are as follows:

1. Subpart W’s best available monitoring method (“BAMM”) provisions do not provide

reporting entities with adequate time to ensure compliance with the final rule.

2. Current compressor venting monitoring requirements are overly burdensome and present 

significant safety and operational process concerns to reporting entities.
The Honorable Lisa P. Jackson, Administrator

February 11, 2011

Page 2

3. The terms “gathering lines” and “booster stations” are not defined in the final rule, nor is 

sufficient detail provided regarding the definition of “gas processing facility.” Absent 

such definitions and clarifications, there will be substantial confusion as to which 

facilities are required to report emissions data.

4. The definition of a facility in Subpart W differs from the definition of a facility provided 

in all other applicable regulations under the Clean Air Act (“CAA”). This inconsistency 

will create unnecessary confusion among related programs and is not necessary or 

justified.

These objections are discussed in detail below.

1. Subpart W’s best available monitoring method (“BAMM”) provisions do not 

provide reporting entities with adequate time to ensure compliance with the final 

rule.

GPA member companies are currently assessing the availability of each individual data 

source required by the Subpart W to perform required calculations and comply with the rule. 

This process is arduous and time-consuming and requires significant personnel from many facets 

of GPA’s member companies’ complex organizations. The time period EPA has provided 

reporting entities to analyze their existing systems, identify parameters for which BAMM is 

required, and prepare and submit BAMM or BAMM extension requests is impractical and 

unrealistic.

Existing BAMM provisions are difficult to comply with, as BAMM is provided only for 

specific sources and methodologies. Given the significant complexities of the rule and the 

plethora of data parameters that must be assessed and collected for compliance, the use of 

BAMM provisions for one data point of an equation but not for others does not provide 

significant relief for reporting entities. Furthermore, because some of the data required under 

Subpart W may be BAMM estimates, but others must be actual data points, the final rule will 

result in inconsistencies that may impede reporting entities’ efforts to comply with the rule.

Additionally, the information required to be submitted in BAMM extension requests puts 

a considerable burden on reporting entities, especially where their time and resources would be 

better spent preparing and collecting data for compliance with Subpart W. For those data points 

identified for which BAMM is necessary, reporting entities are highly unlikely to be able to 

discuss, contract with, and collect the documentation required to support the BAMM request 

within the given timeframe.

EPA does not provide any deadlines in the final rule within which they will respond to 

BAMM extension requests, which is of considerable concern to reporting entities that will rely 

on BAMM to comply with Subpart W in the first year of reporting. Reporting entities will face 

significant uncertainty while waiting to hear from EPA on whether the request has been 

approved and may be left in an untenable position if EPA denies BAMM requests.
The Honorable Lisa P. Jackson, Administrator

February 11, 2011

Page 3

As a result, GPA requests that BAMM should be provided, without request, for entities 

impacted by Subpart W for the entire first reporting year (2011) and for all data points required 

for calculation methods prescribed by the rule.

2. Current compressor venting monitoring requirements are overly burdensome and 

present significant safety and operational process concerns to reporting entities.

The direct monitoring and measurement requirements under Subpart W for compressors 

are unnecessary and unwarranted for an emissions inventory and reporting rule. Widely

accepted estimation methods are available to calculate emissions from compressors that can 

deliver accurate results without requiring direct measurements. Furthermore, such direct 

measurement requirements are duplicative of ongoing EPA research and therefore not necessary 

under the reporting rule. In the rule’s Technical Support Document, EPA states that the data 

from the direct measurement portions of the rule is necessary to support future climate-related 

regulatory efforts, though no information is provided as to what such efforts are or what they will

involve. Given the substantial burden Subpart W’s direct measurement requirements place on 

reporting entities, EPA is not justified in seeking to impose such costs on industry absent a 

detailed showing as to the Agency’s needs and plans for such information.

Additionally, the final rule requires reporting entities to calculate emissions from 

centrifugal compressors for both wet seal and dry seal venting and from blowdown valve vents. 

These requirements, which were absent from the proposed rule, will more than double the 

number of measurements originally anticipated for centrifugal compressors and result in a 

substantial additional and unanticipated burden to measure, collect, and quantify such data. 

The final rule also requires reporting entities to calculate emissions from reciprocating 

compressor blowdown valve vents. The proposed rule had only required emissions calculations 

for rod pack venting and unit isolation valve venting systems. This new and, again, 

unanticipated set of requirements will more than double the number of measurements for 

reciprocating compressors. 

Finally, Subpart W requires annual measurements on each vent for each compressor, and 

the final rule indicates under § 98.233(o)(1) and § 98.233(p) that if sources are vented through a 

common manifold, each vent source must be measured separately. In practical terms, it is not 

possible for reporting entities to comply with this requirement under current operating 

conditions. Compliance would require pipes to be cut in order to provide adequate access points 

to install meter ports. This would result in entire facilities needing to be shut down, blown down, 

and purged in order to ensure appropriate safety conditions to proceed with such pipe 

modifications — again representing an excessive, overly burdensome, and avoidable compliance 

burden for reporting entities.

GPA therefore requests that EPA allow for the use of accepted estimation methods 

available to calculate emissions from compressor vents in lieu of conducting direct 

measurements.
The Honorable Lisa P. Jackson, Administrator

February 11, 2011

Page 4

3. The terms “gathering lines” and “booster stations” are not defined in the final rule, 

nor is sufficient detail provided regarding the definition of “gas processing facility.”

Subpart W states under § 98.230(a)(3) that gathering lines and booster stations are 

excluded from reporting obligations. However, the definition of a gas processing facility also 

includes several processes typical of standard booster stations (i.e., water removal). This 

definition therefore seems to imply that booster stations exhibiting any of these characteristics 

with an average annual throughput ≥ 25 MMscfd are subject to Subpart W’s reporting 

requirements. Definitions of gathering lines and booster stations appeared in the proposed rule, 

but were removed from the final rule. Without such definitions, GPA and its member companies 

are concerned that their reporting liability could inappropriately extend to booster stations falling 

under the definition provided under § 98.230(a)(3).

In addition, Subpart W’s definition of source category under § 98.230 lists several types 

of operations, including onshore natural gas processing and onshore petroleum and natural gas 

production, but fails to specify how a reporting entity can determine under which type of 

operation certain types of activities or facilities that can occur in more than one type of operation 

should fall. For example, a facility that removes water could fall under either onshore natural 

gas processing or onshore petroleum and natural gas production. Accordingly, the source 

category definition is a source of considerable confusion and uncertainty for reporting entities. 

GPA requests that EPA reinstate the definitions of gathering lines and booster stations 

from the proposed rule and clarify and align each source category to definitions already provided 

in the CAA (e.g., Natural Gas Processing Facility under NSPS KKK).

4. The current definition of a facility in Subpart W differs from the definition of a 

facility provided in all other applicable regulations under the Clean Air Act 

(“CAA”).

The final rule requires production operations to be aggregated on basin-wide basis for 

purposes of determining the applicability of Subpart W and in meeting subsequent reporting 

obligations. This approach is fundamentally inconsistent with the manner in which the terms 

“stationary source” or “facility” are defined for all other purposes under the CAA. As a result, 

the inconsistent approach adopted in the final Subpart W rule will lead to unnecessary confusion 

and will produce data that are not useful for other CAA purposes. A particular problem is that 

the Subpart W approach will often be incompatible with actual ownership and control of the 

affected operations.

GPA requests that EPA conform the Subpart W definition of “Facility” with other similar 

definitions in other CAA regulatory programs. To avoid creating additional reporting burden, 

EPA should allow companies to “roll up” the GHG emissions from multiple affiliated stationary 

sources when reporting under Subpart W.

* * * * * * *
The Honorable Lisa P. Jackson, Administrator

February 11, 2011

Page 5

Thank you for your consideration of these concerns. If you have any questions, do not 

hesitate to contact me at 918-493-3872.

Sincerely,

Jeff Applekamp

Director, Government Affairs

Gas Processors Association

cc: D. Kruger

P. Gunning

R. Fernandez
BEFORE THE UNITED STATES

ENVIRONMENTAL PROTECTION AGENCY

Mandatory Reporting of Greenhouse Gases: ) Docket No. EPA-HQ-OAR-2009-0923

Petroleum and Natural Gas Systems; ) FRL-9226-3

Final Rule ) RIN 2060-AP99

PETITION FOR RECONSIDERATION

Per section 307(d)(7)(B) of the Clean Air Act, 42 U.S.C. § 7607(d)(7)(B), and for the 

reasons set forth below, the Interstate Natural Gas Association of America (“INGAA”) petitions 

the Administrator of the United States Environmental Protection Agency (“EPA”) to reconsider

provisions of its final rule in “Mandatory Reporting of Greenhouse Gases: Petroleum and 

Natural Gas Systems,” 75 Fed. Reg. 74458 (November 30, 2010)(the “Final Rule”).

This petition voices objections that could not have been raised during the public comment 

period because they concern Final Rule provisions that did not appear in the proposed rule, 74 

Fed. Reg. 16448 (April 10, 2009) (the “Proposed Rule”). Each of INGAA’s first three concerns 

deal with regulations allowing operators to compute greenhouse gas (“GHG”) emissions using 

“best alternative monitoring methods” (“BAMM”) in lieu of the methods prescribed elsewhere in 

Subpart W of EPA’s GHG reporting regulations. The BAMM regulations were not part of 

Proposed Rule, and there was no reasonable basis for INGAA to anticipate their issuance. Also, 

as noted in INGAA’s fourth item for reconsideration, the Final Rule raises implementation issues 

that were not evident in the Proposed Rule because they relate to previously unannounced 

requirements for emissions estimation and reporting.

The issues presented below are of central relevance to the outcome of this rulemaking

and reconsideration should be granted to address them. Because we anticipate these issues will 
- 2 -

require further discussion of a technical nature, INGAA would welcome the opportunity to meet 

with EPA to discuss our concerns further.

INGAA seeks reconsideration of the following four matters:

1. There is a confusing disconnect between the BAMM requests due April 30, 2011, 

and those due September 30, 2011.

Both the legal requirements commonly applicable to interstate natural gas transmission,

and the basic design of compressor station equipment, buildings and grounds, pose significant

and long-term safety, technical and legal barriers to obtaining the data necessary to calculate 

GHG emissions per the procedures prescribed in Subpart W of the GHG reporting rule. See 

generally 40 C.F.R. § 98.233. For many of these compressor stations, reporters will be 

requesting approval to use BAMM during 2011, 2012 and beyond.

For leak detection and measurement (40 C.F.R. § 98.234(f)(4)), the Final Rule specifies

two separate BAMM requests, subject to different filing deadlines, content requirements and 

decision criteria, for approval to use BAMM during two separate periods. Requests to use 

BAMM during calendar 2011 must be filed by April 30, 2011, 40 C.F.R. § 98.234(f)(5)(iii)(A); 

requests to use BAMM in 2012 and beyond must be filed by September 30, 2011, 40 C.F.R. 

§ 98.234(f)(8)(i). For other emissions subject to Subpart W, the Final Rule still specifies two 

separate BAMM requests, due the April 30th and September 30th, but the April 30th request 

covers only the period from July 1, 2011 through December 31, 2011.

The content requirements and approval criteria — and thus the apparent circumstances 

that warrant the use of BAMM — differ widely between the two BAMM requests. The 

April 30th request, governing calendar 2011, focuses on the reporter making “all reasonable 

efforts to obtain the information, services, or equipment necessary to comply with Subpart W.” 

See 40 C.F.R. §§ 98.234(f)(5)(iii)(B)(3)-(4), (C). In contrast, the September 30th request, 
- 3 -

governing 2012 and beyond, asks the reporter to describe why the prescribed data collection 

methodologies do not meet safety requirements, are technically infeasible, or conflict with other 

laws or regulations. 40 C.F.R. § 98.234(f)(8)(iv).

Several aspects of the regulations applicable to the April 30th requests are confusing, 

particularly when compared with the corresponding regulations applicable to the September 30th

requests.

The first point of confusion concerns timing and eligibility assessment. Reporters will 

not have time to assess whether all of their facilities qualify for BAMM by this April 30th, yet the 

Final Rule requires that a request must be filed by April 30th for every facility where BAMM will 

be sought for 2011. In discussions subsequent to its issuance of the Final Rule, EPA suggested 

that for these facilities reporters should submit modified April 30th requests that would serve as 

notice of potential BAMM eligibility — in effect, a placeholder — to be supplemented by the 

September 30th request or other subsequent filing. This approach is consistent with the “potential 

situation” provision in the Final Rule:

If the reporter anticipates the potential need for [BAMM] for sources for which 

they need to petition EPA and the situation is unresolved at the time of the 

deadline, reporters should submit written notice of this potential situation to EPA 

by the specified deadline for requests to be considered.

40 C.F.R. § 98.234(f)(1). INGAA supports the “placeholder” approach and EPA should adopt it 

on reconsideration.

A separate source of confusion confronts reporters who seek to apply BAMM seamlessly 

in 2011, 2012 and beyond (for example, because there is no safe way to obtain the measurements 

otherwise prescribed in Subpart W). In these cases, it is unclear how the content requirements 

and decision criteria for the April 30th filing versus the September 30th should be applied when 

the reporter files a BAMM request.
- 4 -

INGAA urges EPA to reconsider the Final Rule to address this problem. The content 

requirements and approval criteria for the April 30th and September 30th BAMM requests should 

be expanded, or a separate class of these requests should be created, to accommodate cases 

where BAMM will be requested for 2012 and beyond. April 30th requests, which under the 

placeholder approach would serve as written notice that BAMM may be requested in the future, 

should identify the potential sources and generally identify the grounds — safety, technical, 

operational, legal, etc. — the reporter may need to cite when it later proposes using BAMM in 

lieu of a prescribed Subpart W methodology. A reporter filing September 30th requests should 

identify the affected source and should be allowed the option of including the same content 

requirements (thus triggering the same decision criteria) that would be used to employ BAMM 

for 2011. Conversely, a reporter seeking to use BAMM for 2012 and beyond should be allowed 

to submit information on its reasonable efforts to obtain the information, services or equipment 

necessary to comply with subpart W. If such information is submitted, EPA should consider it as 

an independent basis for granting the request.

2. The BAMM sunset provision strands sources that become subject to GHG reporting 

after September 30, 2011, or where unpredictable future events necessitate.

Under current regulations, all requests to use BAMM beyond 2011 must be filed by 

September 30, 2011, 40 C.F.R. § 98.234(f)(8)(i). Other than the ability to notify EPA of a 

“potential situation” that may warrant a future BAMM petition, no binding provision is made for 

sources that are not subject to GHG reporting currently, but that become so after September 30th.

There is no reasonable basis for denying BAMM to a natural gas compressor station that 

experiences an increase in throughput, thus exceeding the reporting threshold for the first time;

or denying BAMM to a facility already subject to reporting, that confronts an unpredictable 

facility or operational issue (e.g., low utilization) that precludes measurement, just because these 
- 5 -

events occur after September 30, 2011. These and other situations should be eligible for 

BAMM, and INGAA seeks reconsideration so EPA can offer BAMM to these otherwise 

stranded facilities and unaddressed future events.

 On reconsideration, EPA should also specify the criteria it will use to evaluate requests 

filed after September 30, 2011. Under the Final Rule, EPA “reserves the right to review 

petitions after the deadline” if notified prior to the 2011 deadlines. 40 C.F.R. §98.234(f)(1). 

However, the Final Rule does not indicate the decision criteria EPA will apply to these requests, 

so future access to BAMM is needlessly uncertain. Requests filed after September 30, 2011, 

should be eligible for BAMM under the same criteria available under the Final Rule (as modified 

in response to the other issues contained in this petition).

3. The criteria for approving BAMM for 2012 and beyond should be modified to 

recognize employee safety more fully.

The Final Rule provides that EPA does not anticipate a need to approve BAMM 

beyond 2011 “except in extreme circumstances, which include safety . . . .” 40 C.F.R. 

§ 98.234(f)(8). INGAA does not consider safeguarding employee safety to be an extreme 

circumstance, and we urge EPA to grant reconsideration so it can articulate a standard that more 

fully recognizes the imperative nature of maintaining employee safety.

4. Numerous technical elements of Subpart W remain unclear, confusing, overly 

complicated or conflicting.

A number of the provisions in the Final Rule — particularly those dealing with reporting 

requirements; segment-specific source inclusion; source-specific emission estimation methods;

and values and assumptions for facility-specific parameters — are unclear, possibly erroneous or 

conflicting. For example, the data elements for reporting reciprocating compressor emissions, 40 

C.F.R. § 98.236(c)(14), cite equations and methods in 40 C.F.R. § 98.233(p). However, there are 
- 6 -

inconsistencies or confusing requirements when reconciling the measurements to be conducted, 

the equations and parameters to be used for estimating emissions, and the data elements to 

report. As another example, there instances where a reporter will be required to use different 

values for a calculation parameter (e.g., gas quality) when estimating emissions for different 

sources within the same facility. It is imperative that EPA address unclear, confusing, overly 

complicated, or conflicting requirements associated with emission sources, emission estimation

methods, and reporting requirements in Subpart W. 

CONCLUSION

In light of the arguments and authorities presented above, and the central relevance of the 

issues presented to the outcome of the rules contemplated in this docket, INGAA urges EPA to 

grant reconsideration of the Final Rule pursuant to CAA section 307(d)(7)(B). 

Respectfully submitted,

/s/

Dan Regan, Regulatory Attorney

 dregan@ingaa.org

Interstate Natural Gas Association of America

20 F St., N.W., Suite 450

Washington, DC 20001

January 31, 2010
Title 40: Protection of Environment 

PART 98—MANDATORY GREENHOUSE GAS REPORTING 

Subpart W—Petroleum and Natural Gas Systems 

(Source: 75 FR 74488, Nov. 30, 2010, unless otherwise noted.) 

§ 98.230 Definition of the source category. 

NO CHANGES 

§ 98.231 Reporting threshold. 

NO CHANGES

§ 98.232 GHGs to report. 

• Add section (m) to clarify that operators can use DEFAULT values or company records for percent 

methane and CO2 for vented and fugitive emissions from transmission and storage segments 

• Revise section (j) based on INGAA-EPA May 26 meeting discussion to clarify : (1) FLARE emissions 

are only reported if flares are listed for the segment in §98.232; (2) flare / vapor recovery efficiency 

should be applied when reporting emissions for ANY source that includes such control; and (3) if flares 

are not listed in §98.232 but flaring applies, the combustion emissions from the flare do NOT need to be 

reported 

(j) All applicable iIndustry segments in §98.232(b) through (d) include flares as a listed source and must report 

the CO2, CH4, and N2O emissions from each flare. 

(i) Other industry segments in §98.232(e) through (i) should not report flare emissions but should consider 

flaring, vapor recovery, or other control when reporting emissions of CH4 and CO2 under §98.236 based on 

calculations in §98.233 that estimate uncontrolled emissions. The emissions reported under §98.236 should 

consider the reduction efficiency (e.g., flare efficiency). Equation W-19 in §98.233(n) can be used to 

calculate CH4 emissions from a controlled emission source. Equation W-19 also applies for CO2 emissions 

for a vapor recovery system. Equation W-20 applies for CO2 emissions for combustion based control 

(flare, thermal oxidizer). The calculation approach should be documented under §98.3(g).

... 

(m) In lieu of the requirements for natural gas composition specified in §98.233, the operator may alternately 

apply a gas composition in (1) or (2) when calculating emissions in §98.233: 

(1) For sources in §98.232(e), (f), (g) and (i), default natural gas composition of 95 percent CH4 and 1 

percent CO2 (by volume).

(2) For sources in §98.232(e) through (i), company gas records consistent with §98.233(u)(2). 

Comment [JMc1]: Approach is to provide this 

“direction” once rather than in each 98.233 section, 

and reporting criteria based on May 26 INGAA 

meeting with EPA. 

With this addition, flare references in §98.233 

sections for transmission are deleted (see below). 

Comment [JMc2]: To simplify, intent is to allow 

operators in transmission, etc to apply either a 

default composition or to use company records / gas 

analysis. 

Alternate would be to add this criteria within 

§98.233(u)(2) and revise equation citations for gas 

composition throughout §98.233 source calculation 

sections. 

Comment [JMc3]: Based on default assumed in 

DOE/EIA national inventory report – e.g., see 

“Documentation for Emissions of Greenhouse Gases 

in the United States 2008”, DOE/EIA-0638 (2008), 

January 2011 

Default would apply for transmission, underground 

storage, LNG storage, and distribution. 
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§ 98.233 Calculating GHG emissions. 

Clarifications in 98.33(a), (e), (i), (k), (o) and (p); minor changes to (q), (r), (t), (u), (v) for consistency 

... 

(a) Natural gas pneumatic device venting. 

Clarify that best available information and engineering judgment can be used to define high vs low 

bleed; also address definition (and provide examples) for intermittent devices [see revision to 98.6 and 

recommended paragraph for preamble with examples]. 

Calculate CH4 and CO2 emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural 

gas pneumatic devices using Equation W–1 of this section. 

Where: 

Masss,i = Annual total mass GHG emissions in metric tons CO2e per year at standard conditions from a natural 

gas pneumatic device vent, for GHG i. 

Count = Total number of continuous high bleed, continuous low bleed, or intermittent bleed natural gas 

pneumatic devices of each type as determined in paragraph (a)(1) of this section. The count shall be 

based on best available information or engineering judgment with the approach described in the 

monitoring plan required under §98.3(g)(5) and does not require bleed rate measurement to 

define device type. 

EF = Population emission factors for natural gas pneumatic device venting listed in Tables W–1A, W–3, and 

W–4 of this subpart for onshore petroleum and natural gas production, onshore natural gas transmission 

compression, and underground natural gas storage facilities, respectively. 

GHGi = For onshore petroleum and natural gas production facilities, concentration of GHG i, CH4or CO2, in 

produced natural gas; for facilities listed in §98.230(a)(3) through (a)(8), GHGi equals 1 or the gas 

composition allowed per §98.232(m). 

Convi = Conversion from standard cubic feet to metric tons CO2e; 0.000410 for CH4, and 0.00005357 for CO2. 

24 * 365 = Conversion to yearly emissions estimate. 

... 

(i) Blowdown vent stacks. 

Clarify “exempt volumes; events to include (i.e., “significant” blowdowns for maintenance or safety), 

and add another calc (operator selects calc to use) where events are calculated and summed.

Calculate CO2 and CH4 blowdown vent stack emissions from depressurizing equipment to the atmosphere to reduce

system pressure for planned or emergency shutdowns or to take equipment out of service for maintenance

(excluding depressurizing to a flare, over-pressure relief, operating pressure control venting and blowdown of nonGHG gases; desiccant dehydrator blowdown venting before reloading is covered in paragraph (e)(5) of this section) as 

follows: 

Comment [JMc4]: Intent is to include 

“significant” blowdown events associated with 

shutdowns and maintenance activity. 

(1) Calculate the total volume (including pipelines, compressor case or cylinders, manifolds, suction bottles, 

discharge bottles, and vessels) between isolation valves determined by engineering estimate based on best 

available data. 

(2) If the total physical volume between isolation valves is greater than or equal to 50 standard cubic feet, retain 

logs of the number of blowdowns for each equipment type (including but not limited to compressors, vessels, 

pipelines, headers, fractionators, and tanks). Blowdown Physical volumes smaller than 50 standard cubic feet are 

exempt from reporting under paragraph (i) of this section. 
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rsion 

(3) The operator can elect to use either Equation W-14a or W-14b. Calculate the total annual venting 

emissions for each equipment type using Equation W–14a of this section: or calculate total annual venting 

emissions using Equation W–14b. The operator can include corrections that address factors such as gas 

compressibility when completing the calculation. 

 [change to (Eq. W-14a)]

Where: 

Es,n = Annual natural gas venting emissions at standard conditions from blowdowns in cubic feet. 

N = Number of repetitive blowdowns for each equipment type of a unique volume in calendar year. 

Comment [JMc5]: Additional description can be 

included in the preamble: Equation W-14a (former 

Equation W-14) applies to an equipment type 

(i.e., group of equipment) where the estimate is 

based on the following physical and operating 

properties: the same unique blowdown chamber 

volume; the same blowdown chamber pressure 

and temperature; and, the same equipment 

purging practices (i.e., C = 0 or 1). Equation W14b is appropriate if the blowdown pressure 

differential (start and end pressures) vary for 

different events and calculations for annual 

emissions are based on summing the calculated 

volume for events that occur throughout the year.

For the latter, each event can be unique, so 

reporting requirements include total annual 

emissions and number of annual events.

Vv = Total volume of blowdown equipment chambers (including pipelines, compressors and vessels) 

between isolation valves in cubic feet. 

C = Purge factor that is 1 if the equipment is not purged or zero if the equipment is purged using non-GHG 

gases. 

Comment [JMc6]: This sentence is needed to 

allow operators to use existing vent records – e.g., 

similar equation used but longstanding calculation 

includes minor adjustments for factors such as 

compressibility. Without this sentence, some 

operators will have “two sets of books” for 

calculating vented emissions. 

Ts = Temperature at standard conditions ( °F). 

Ta = Temperature at actual conditions in the blowdown equipment chamber ( °F). 

Ps = Absolute pressure at standard conditions (psia). 

Pa = Absolute pressure at actual conditions in the blowdown equipment chamber (psia). 

( )( )

( ) ∑= ⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

⎟

⎟

⎠

⎞

⎜

⎜

⎝

⎛

+

−+ =

N

i si a,

i f, a,i 0, a,s

iv, PT

PPT

V

1 67.459

67.459

E ns, (Eq.-W-14b)

Where:

Es,n= Annual natural gas venting emissions at standard conditions from blowdowns in cubic feet.

N = Number of blowdowns in the calendar year.

Vv,i = Total volume of blowdown equipment chambers (including pipelines, compressors and vessels) in 

cubic feet.

Ts = Temperature at standard conditions ( °F).

Ta,i = Temperature at actual conditions (estimated) for event “i” in the blowdown chamber (°F).

Ps = Absolute pressure at standard conditions (psia).

Pa,0,i = Absolute pressure at actual conditions at the start of event “i" in the blowdown chamber (psia).

Pa,f,i = Absolute pressure of natural gas at actual conditions at the end of event “i" in the blowdown 

chamber (psia) ((if the equipment is purged using non-GHG gases then Pa,f,i = 0).

(4) Calculate both CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using 

calculations in paragraph (u) and (v) of this section. This calculation can use the gas composition per 

§98.232(m).

(5) Calculate total annual venting emissions for all blowdown vent stacks by adding all standard volumetric and 

mass emissions determined in from Equations W–14a or W-14b and paragraph (i)(4) of this section. 

... 
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(k) Transmission storage tanks. 

Correct reference to flaring in intro, add monitoring method flexibility, and delete reference to flaring 

calculation (broadly addressed in §98.232(j) and not needed in this section) 

For condensate storage tanks, either water or hydrocarbon, without vapor recovery or thermal control devices in 

onshore natural gas transmission compression facilities calculate CH4, and CO2 and N2O (when flared) annual 

emissions from compressor scrubber dump valve leakage as follows: 

(1) Monitor the tank vapor vent stack annually for emissions using an optical gas imaging instrument according to 

methods set forth in §98.234(a)(1) or by directly measuring the tank vent using a flow meter, calibrated bag, 

or high volume sampler according to methods in §98.234(b) through (d) for a duration of 5 minutes. Or you 

may annually monitor leakage through compressor scrubber dump valve(s) into the tank using an acoustic leak 

detection device according to methods set forth in §98.234(a)(5). 

(2) If the tank vapors are continuous for 5 minutes, or the acoustic leak detection device detects a leak, then use 

one of the following two methods in paragraph (k)(2) of this section to estimate quantify emissions: 

(i) Use a meter, such as a turbine meter, calibrated bag, or high flow sampler to estimate tank vapor 

volumes according to methods set forth in §98.234(b) through (d). If you do not have a continuous flow 

measurement device, you may install a flow measuring device on the tank vapor vent stack. If the vent is 

directly measured for five minutes under section (1) to detect continuous leakage, this serves as the 

measurement. If a leak of 3.1 SCF per hour or greater is measured, a leak is detected and must be 

reported.

(ii) Use an acoustic leak detection device on each scrubber dump valve connected to the tank according to the 

method set forth in §98.234(a)(5). 

(3)(iii) Calculate both CH4 and CO2 volumetric and mass emissions using calculations in (u) and (v) of this 

section, and using Use the appropriate gas composition in paragraph (u)(2)(iii) of this section or the gas 

composition allowed in §98.232(m). 

(4)(3) If the leaking dump valve(s) is repaired following leak detection, the annual emissions shall be calculated 

from the beginning of the calendar year to the time the valve(s) is repaired. 

(4) Calculate emissions from storage tanks to flares as follows:

(i) Use the storage tank emissions volume and gas composition as determined in either paragraph (j)(1)of this 

section or with an acoustic leak detection device in paragraphs (k)(1) through (k)(3) of this section.

(ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine storage tank 

emissions from the flare.

... 
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§98.233(n) PROVIDED HERE FOR REFERENCE ONLY – NO CHANGES... “Efficiency” calcs in 

Equations W-19 and W-20 are shown here because these are referenced in proposed new section 

§98.232(j)(1) [see above] for calculating “reduction efficiency” from §98.233 sources. 

(n) Flare stack emissions. Calculate CO2, CH4, and N2O emissions from a flare stack as follows: 

... 

(4) Calculate GHG volumetric emissions at actual conditions using Equations W–19, W–20, and W–21 of this 

section. 

Where: 

Ea,CH4(un-combusted) = Contribution of annual un-combusted CH4 emissions from flare stack in cubic feet, 

under actual conditions. 

Ea,CO2(un-combusted) = Contribution of annual un-combusted CO2 emissions from flare stack in cubic feet, 

under actual conditions. 

Ea,CO2(combusted) = Contribution of annual combusted CO2 emissions from flare stack in cubic feet, under 

actual conditions. 

Va= Volume of gas sent to flare in cubic feet, during the year. 

η = Fraction of gas combusted by a burning flare (default is 0.98). For gas sent to an unlit flare, η is zero. 

XCH4= Mole fraction of CH4 in gas to the flare. 

XCO2= Mole fraction of CO2 in gas to the flare. 

Yj= Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanesplus). 

Rj= Number of carbon atoms in the gas hydrocarbon constituent j: 1 for methane, 2 for ethane, 3 for propane, 

4 for butane, and 5 for pentanes-plus). 

... 
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Sections (o) and (p) for compressor emissions include significant revisions based on recent discussions 

with EPA on intended requirements for calculating and reporting compressor vent emissions. In 

addition, revisions were completed so that the format / structure of the two sections is analogous. 

(o) Centrifugal compressor venting. Calculate CH4, and CO2 and N2O (when flared) emissions from both wet seal and 

dry seal centrifugal compressor vents as follows: 

(1) Centrifugal compressor package operating status includes two reportable modes: operating and not 

operating de-pressurized. Centrifugal compressor package vent sources are wet seal oil degassing vents, 

unit isolation valve vents, and blowdown valve vents. For each centrifugal compressor package covered by 

§98.232 (d)(2), (e)(2), (f)(2), (g)(2), and (h)(2) you must conduct an annual measurement in the operating mode in 

which it is found during the annual measurement. Measure emissions from each unique mode and vent 

source combination in (i) through (iii) of this section applicable to the as-found mode. all vents (including 

emissions manifolded to common vents) including wet seal oil degassing vents, unit isolation valve vents, and 

blowdown valve vents). Measurement from a single compressor package can (includeing emissions from 

unique vent sources manifolded to common vents). Record emissions from the following vent sourcestypes in 

the specified compressor modes during the annual measurement. 

(i) Operating mode, blowdown valve leakage through the blowdown vent, for both wet seal and dry seal 

compressors. 

(ii) Operating mode, wet seal oil degassing vents. 

(iii) Not operating depressurized mode, unit isolation valve leakage through open blowdown vent, without 

blind flanges, for both wet seal and dry seal compressors. 

(A) For the not operating depressurized mode, each compressor package must be measured at least once in 

any three consecutive calendar years. If a compressor package is not operated and has blind flanges in 

place throughout the 3 year period, measurement is not required in this mode. If the compressor is in 

standby depressurized mode without blind flanges in place and is not operated throughout the 3 year period, 

it must be measured in the standby depressurized mode.

(2) Measure emissions from each vent including emissions manifolded to a common vents from a single 

vent source (For wet seal oil degassing vents, determine vapor volumes sent to an atmospheric vent or flare, unit 

isolation valves, or blowdown valve vents) for a single compressor package using any of the methods in 

(o)(2)(i) though (iv) of this section. Vents may be screened annually using an optical imaging instrument 

according to methods in §98.234(a)(1) and if emissions are not present, then measurement per §98.234(b) is 

not required and emissions are estimated as zero.

(i) Aa temporary meter such as a vane anemometer or permanent flow meter such as an orifice meter

according to 98.234(b) of this section. If you do not have a permanent flow meter, you may install a 

permanent flow meter on the wet seal oil degassing tank vent. 

(3) For blowdown valve leakage and unit isolation valve leakage to open ended vents, you can use one of the 

following methods: 

(ii) Calibrated bagging or high volume sampler according to methods set forth in §98.234(c) and §98.234(d), 

respectively.

(iii) High volume sampler according to methods set forth in §98.234(d),

(iv) For through valve leakage, such as isolation valves on not operating depressurized compressor 

packages and blowdown valves on pressurized compressor packages, you may use an acoustic leak 

detection device according to methods set forth in §98.234(a). If you do not have a flow meter, you may 

install a port for insertion of a temporary meter, or a permanent flow meter, on the vents. 

(43) For each unique mode and vent source combination for which vent gas emission measurements were 

conducted during the reporting year, eEstimate annual emissions for each centrifugal compressor package 

using the flow measurement and Equation W–22 of this section. 

Comment [JMc7]: Sentence is redundant and not 

needed. 

Comment [JMc8]: Sentence is not needed 

because operator clearly has the option to use a 

temporary or permanent meter. 

Comment [JMc9]: NOTE: Calculation and 

reporting requirements would likely be clearer to 

reader if Eqn W-24 (i.e., Section 5) was introduced 

first, which would then provide a more logical flow 

through the estimates. INGAA did not make this 

change to avoid section “restructuring” in these 

edits, but recommends that EPA re-order the sections
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E = MT immmi,s,*T * M (Eq. W-22)

Where: 

Es,i,m = Annual GHGi (either CH4 or CO2) volumetric emissions at standard conditions, in standard cubic feet 

for the unique mode and vent source combination. 

MTm = Measured gas volumetric emissions in standard cubic feet per hour for the unique mode and vent 

source combination. 

Tm = Total time the compressor package is in the mode for which Esi,m is being calculated, in the calendar 

year in hours. 

Mi,m = Mole fraction of GHGi in the vent gas; use the appropriate gas compositions in paragraph (u)(2) of 

this section or according to §98.232(m). 

Bm = Fraction of operating time that the vent gas is sent to vapor recovery or fuel gas as determined by 

keeping logs of the number of operating hours for the vapor recovery system and the time that vent 

gas is directed to the fuel gas system or sales.

(54) For each unique mode and vent source combination for which vent gas emission measurements were 

not conducted during the reporting year, cCalculate annual emissions from each centrifugal compressor 

package using Equation W–23 of this section. 

s, Tmmmi, GHG* i E = F *E (Eq. W-23)

Where: 

Es,i,m = Annual GHGi (either CH4 or CO2) total volumetric GHG emissions at standard conditions from each 

centrifugal compressor package in standard cubic feet for the unique mode and vent source 

combination. 

EFm = For each unique mode and vent source combination, Rreporter emission factor for each mode m, in 

standard cubic feet per hour, from Equation W–24 of this section as calculated in paragraph 56. 

Tm = Total time the compressor package is in the mode for which Esi,m is being calculated, in the 

calendar year in hours per year the compressor was in each mode, as listed in paragraph (o)(1)(i) 

through (o)(1)(iii).

GHGi = For onshore natural gas processing facilities, concentration of GHGi, CH4 or CO2, in produced natural 

gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8),GHGi equals 1 or use 

the gas composition allowed in §98.232(m). 

(5) You shall use all of the volumetric gas flow measurements (MTm) for each unique mode and vent source 

combination (of operating mode wet seal oil degassing vent, operating mode blowdown valve vent, and not 

operating depressurized mode isolation valve vent) to develop for all the reporter's emission factors that are 

mode and vent source-specific. Use Equation W-24 to develop the following emission factors using Equation 

W–24 of this section for each emission source and mode as listed in paragraph (o)(1)(i) through (o)(1)(iii). 

m

m m ountC

MT EF ∑ = (Eq. W-24)

Where: 
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EFm = Reporter emission factors for centrifugal compressor packages in the for a unique three modes m 

and vent source combination as listed in paragraphs (o)(1)(i) through (o)(1)(iii) ) of this section, in 

standard cubic feet of natural gas per hour. 

MTm = All Fflow Mmeasurements from all centrifugal compressor packages for a unique mode and vent 

source combination as listed in paragraphs (o)(1)(i) through (o)(1)(iii) of this section, in standard 

cubic feet of natural gas per hour. 

Countm = Total number of centrifugal compressors packages measured in the respective unique mode and 

vent source combination. 

m = Three unique Compressor mode and vent source combinations as listed in paragraph (o)(1)(i) 

through (o)(1)(iii). 

(i) For each of the unique mode and vent source combinations in §98.233(o)(1)(i) through (iii), The

emission factors must be calculated annually. You must use all measurements from the current calendar year 

and the preceding one (after the second annual measurement) or two calendar years, totaling three 

consecutive calendar years of measurements in paragraph (o)(56) of this section for year three and beyond. 

The emission factor is used for calculating compressor package emissions from the unique mode and 

vent source combinations not measured in a particular year.

(ii) [Reserved] 

(67) Onshore petroleum and natural gas production shall calculate emissions from wet seal centrifugal 

compressor packages wet seal oil degassing vents as follows: 

Where: 

Es,i = Annual total volumetric GHG emissions at standard conditions from wet seal centrifugal compressor 

packages wet seals in standard cubic feet. 

Count = Total number of wet seal centrifugal compressors packages for the reporter. 

EFi = Emission factor for GHGi. Use 12.2 million standard cubic feet per year per compressor package for 

CH4 and 538 thousand standard cubic feet per year per compressor package for CO2 at 68 °F and 14.7 

psia or 12 million standard cubic feet per year per compressor package for CH4 and 530 thousand 

standard cubic feet per year per compressor package for CO2 at 60 °F and 14.7 psia. 

(78) EstimateCalculate both CH4 and CO2 mass emissions from volumetric emissions using the calculations in 

paragraph (v) of this section. 

(9) Calculate emissions from seal oil degassing vent vapors to flares as follows:

(i) Use the seal oil degassing vent vapor volume and gas composition as determined in paragraphs (o)(5) of 

this section.

(ii) Use the calculation methodology of flare stacks in paragraph (n) of this section to determine degassing 

vent vapor emissions from the flare.
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(p) Reciprocating compressor venting. Calculate CH4 and CO2 emissions from all reciprocating compressor vents as 

follows. 

(1) Reciprocating compressor package operating status includes three modes: operating, standby 

pressurized, and not operating de-pressurized. Reciprocating compressor package vent sources are 

reciprocating rod packing vents, unit isolation valve vents, and blowdown valve vents. For each reciprocating 

compressor package covered in §98.232(d)(1), (e)(1), (f)(1), (g)(1), and (h)(1) you must conduct an annual 

measurement for each compressor in the mode in which it is found during the annual measurement, except as 

specified in paragraph (p)(79) of this section. Measure emissions from each unique mode and vent source 

combination in (i) through (iv) of this section applicable to the as-found mode. (including emissions 

manifolded to common vents) reciprocating rod packing vents, unit isolation valve vents, and blowdown valve 

vents). Measurement from a single compressor package can include emissions from unique vent sources

manifolded to common vents. Record emissions from the following vent sourcestypes in the specified 

compressor modes during the annual measurement as follows:

(i)(1) Operating or standby pressurized mode, blowdown vent leakage through the blowdown vent stack. 

(ii) Operating mode, reciprocating rod packing emissions.

(iii) (2) Standby pressurized mode blowdown vent leakage through the blowdown vent stack.

(iv)(3) Not operating depressurized mode, unit isolation valve leakage through the blowdown vent stack, 

without blind flanges. 

(A)(i) For the not operating depressurized mode, each compressor package must be measured at least once 

in any three consecutive calendar years if this mode is not found in the annual measurement. If a 

compressor package is not operated and has blind flanges in place throughout the 3 year period, 

measurement is not required in this mode. If the compressor is in standby depressurized mode without blind 

flanges in place and is not operated throughout the 3 year period, it must be measured in the standby 

depressurized mode.

(B)(ii) [Reserved] 

(2)(4) If reciprocating rod packing and blowdown vent are connected to an open-ended vent line, use one of the 

following two methods to calculate emissions. (i) Mmeasure emissions from eachall vents (including emissions 

manifolded to a common vents from a single vent source (including rod packing, unit isolation valves, andor

blowdown valve vents) for a single compressor package) using either any of the methods in (p)(2)(i) though 

(iv) of this section. Vents may be screened annually using an optical imaging instrument according to 

methods in §98.234(a)(1) and if emissions are not present, then measurement per §98.234(b) is not required 

and emissions are estimated as zero.

calibrated bagging or high volume sampler according to methods set forth in §98.234(c) and §98.234(d), 

respectively. 

(ii) Use a temporary meter such as a vane anemometer or a permanent meter such as an orifice meter to 

measure emissions from all vents (including emissions manifolded to a common vent including rod packing 

vents, unit isolation valve leakage through blowdown vents according to methods set forth in §98.234(b). If 

you do not have a permanent flow meter, you may install a port for insertion of a temporary meter or a 

permanent flow meter on the vents. 

(i) A temporary meter such as a vane anemometer or a permanent meter such as an orifice meter 

according to methods set forth in §98.234(b). 

(ii) Calibrated bagging according to methods set forth in §98.234(c). 

(iii) High volume sampler according to methods set forth in §98.234(d). 

(iv) For through-valve leakage to open ended vents, such as unit isolation valves on not operating 

depressurized compressors packages and blowdown valves on pressurized compressors packages, you may 

use an acoustic detection device according to methods set forth in §98.234(a). 
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(3)(5) If reciprocating rod packing is not equipped with a vent line use the following method to calculate 

emissions: 

(i) You must use the methods described in §98.234(a) to conduct annual leak detection of equipment leaks 

from the packing case into an open distance piece, or from the compressor crank case breather cap or other 

vent with a closed distance piece. 

(ii) Measure emissions found in paragraph (p)(3)(5)(i) of this section using an appropriate meter, or calibrated 

bag, or high volume sampler according to methods set forth in §98.234(b), (c), and (d), respectively. 

(4)(6) For each unique mode and vent source combination for which vent gas emission measurements were 

conducted during the reporting year, Eestimate annual emissions for each reciprocating compressor package 

using the flow measurement and Equation W–26 of this section. 

 

Mimmmi,s, E = MT *T * (Eq. W-26)

Where: 

Es,i,m = Annual GHG i (either CH4or CO2) volumetric emissions at standard conditions, in standard cubic 

feet for the unique mode and vent source combination. 

MTm = Measured gas volumetric emissions in standard cubic feet per hour for the unique mode and vent 

source combination. 

Tm= Total time the compressor package is in the mode for which Es,i,m is being calculated, in the calendar 

year in hours. 

Mi,m = Mole fraction of GHGi in the vent gas; use the appropriate gas compositions in paragraph (u)(2) of 

this section or according to §98.232(m). 

(5)(7) For each unique mode and vent source combination for which vent gas emission measurements were 

not conducted during the reporting year, Ccalculate annual emissions from each reciprocating compressor 

package using Equation W–27 of this section. 

Comment [JMc10]: NOTE: Calculation and 

reporting requirements would likely be clearer to 

reader if Eqn W-28 (i.e., Section 6) was introduced 

first, which would then provide a more logical flow 

through the estimates. INGAA did not make this 

change to avoid section “restructuring” in these 

edits, but recommends that EPA re-order the 

sections. 

s, Tmmmi, GHG* i E = F *E (Eq. W-27)

Where: 

Es,i,m = Annual GHGi (either CH4 or CO2) total volumetric GHG emissions at standard conditions from each 

reciprocating compressor package in standard cubic feet for the unique mode and vent source 

combination. 

EFm = For each unique mode and vent source combination, Rreporter emission factor for each mode, m,

in standard cubic feet per hour, from Equation W–28 of this section as calculated in paragraph 

(p)(76)(i) of this section. 

Tm = Total time the compressor package is in the mode for which Esi,m is being calculated, in the 

calendar year in hours per year the compressor was in mode, m, as listed in paragraph (p)(1) through 

(p)(3).

GHGi = For onshore natural gas processing facilities, concentration of GHG i, CH4or CO2, in produced 

natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8), GHGi equals 

1. or gas composition allowed per §98.232(m). 

m = Compressor mode as listed in paragraph (p)(1) through (p)(3).
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(6i) You shall use all of the volumetric gas flow meter readings from measurements (MTm) for each unique 

mode and vent source combination (of operating mode and standby pressurized blowdown vent, operating 

mode reciprocating rod packing vents, standby pressurized mode blowdown vent, and not operating 

depressurized isolation valve vent) for all the reporter's compressor modes not measured in the calendar year

to develop the following reporter emission factors that are mode and vent source-specific. uUseing

Equation W–28 of this section for to develop the emission factors for each emission source and mode as 

listed in paragraph (p)(1)(i) through (p)(31)(iv). 

Page 11 of 21 

m

m m ountC

MT EF ∑ = (Eq. W-28)

Where: 

EFm= Reporter emission factors for reciprocating compressor packages in the for a unique three modes, 

m, and vent source combination as listed in paragraphs (p)(1)(i) through (p)(1)(iv) of this 

section, in standard cubic feet of natural gas per hour. 

MTm= All flow measurements Meter readings from all reciprocating compressor packages for a unique

vents in each and mode, m, and vent source combination as identified listed in paragraphs

(p)(1)(i) through (p)(1)(iv) of this section, in standard cubic feet of natural gas per hour. 

Countm = Total number of reciprocating compressors packages measured in each mode, m in the 

respective unique mode and vent source combination. 

m = Four unique Compressor mode and vent source combinations as listed in paragraphs (p)(1)(i) 

through (p)(13)(iv). 

(A) You must combine emissions for blowndown vents, measured in the operating and standby pressurized 

modes.

 (iB) For each of the unique mode and vent source combinations in §98.233(p)(1)(i) through (iv), The

emission factors must be calculated annually. You must use all measurements from the current calendar year 

and the preceding one (after the second annual measurement) or two calendar years, totaling three 

consecutive calendar years of measurements in paragraph (p)(6) of this section for year three and beyond. 

The emission factor is used for calculating compressor package emissions from the unique mode and 

vent source combinations not measured in a particular year. 

(ii) [Reserved] 

(8) Determine if the reciprocating compressor vent vapors are sent to a vapor recovery system.

(i) Adjust the emissions estimated in paragraphs (p)(7) of this section downward by the magnitude of emissions 

recovered using a vapor recovery system as determined by engineering estimate based on best available data.

(ii) [Reserved]

(7)(9) Onshore petroleum and natural gas production shall calculate emissions from reciprocating compressors

packages as follows: 

Where: 

Es,i= Annual total volumetric GHG emissions at standard conditions from reciprocating compressors in standard

cubic feet. 
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Count = Total number of reciprocating compressors packages for the reporter. 

EFi= Emission factor for GHG i. Use 9.63 thousand standard cubic feet per year per compressor package for CH4and 

0.535 thousand standard cubic feet per year per compressor package for CO2at 68 °F and 14.7 psia or 9.48 thousand 

standard cubic feet per year per compressor package for CH4and 0.527 thousand standard cubic feet per year per 

compressor package for CO2at 60 °F and 14.7 psia. 

(8)(10) Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using the 

calculations in paragraphs (u) and (v) of this section. 

... 

In (q) and (r), add references to gas composition; minor clarifications and corrections to (t) though (v) 

(q) Leak detection and leaker emission factors. 

... 

GHGi = For onshore natural gas processing facilities, concentration of GHGi, CH4 or CO2, in the total 

hydrocarbon of the feed natural gas; for other facilities listed in § 98.230(a)(4) through (a)(8), GHGi equals 1 for 

CH4 and 1.1 × 10-2 for CO2, or use the gas composition allowed in §98.232(m). 

... 

(r) Population count and emission factors.

... 

GHGi = For onshore petroleum and natural gas production facilities and onshore natural gas processing facilities, 

concentration of GHG i, CH4 or CO2, in produced natural gas or feed natural gas; for other facilities listed in § 

98.230(a)(4) through (a)(8), GHGi equals 1 for CH4 and 1.1 × 10-2 for CO2, or use the gas composition allowed 

in §98.232(m). 

... 

(t) Volumetric emissions. Calculate volumetric emissions at standard conditions as specified in paragraphs (t)(1) or (2) 

of this section, with actual pressure and temperature determined by engineering estimate based on best available 

data unless otherwise specified. 

(1) Calculate natural gas volumetric emissions at standard conditions by converting actual temperature and 

pressure of natural gas emissions to standard temperature and pressure of natural gas using actual natural gas 

emissions temperature and pressure, and Equation W–33 of this section. 

Where: 

Es,n = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet. 

Ea,n = Natural gas volumetric emissions at actual conditions in cubic feet. 

Ts = Temperature at standard conditions ( °F). 

Ta = Temperature at actual emission conditions ( °F). 

Ps = Absolute pressure at standard conditions (psia). 
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rsion 

Pa = Absolute pressure at actual conditions (psia). 

(2) Calculate GHG volumetric emissions at standard conditions by converting actual temperature and pressure of 

GHG emissions to standard temperature and pressure using actual GHG emissions temperature and pressure,

and Equation W–34 of this section. 

Where: 

Es,i= GHG i volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet. 

Ea,i= GHG i volumetric emissions at actual conditions in cubic feet. 

Ts= Temperature at standard conditions ( °F). 

Ta= Temperature at actual emission conditions ( °F). 

Ps= Absolute pressure at standard conditions (psia). 

Pa= Absolute pressure at actual conditions (psia). 

(u) GHG volumetric emissions. Calculate GHG volumetric emissions at standard conditions as specified in paragraphs 

(u)(1) and (2) of this section, with mole fraction of GHGs in the natural gas determined by engineering estimate 

based on best available data unless otherwise specified. 

(1) Estimate CH4and CO2emissions from natural gas emissions using Equation W–35 of this section. 

Where: 

Es,i= GHG i (either CH4or CO2) volumetric emissions at standard conditions in cubic feet. 

Es,n= Natural gas volumetric emissions at standard conditions in cubic feet. 

Mi= Mole fraction of GHGi in the natural gas. 

(2) For Equation W–35 of this section, the mole fraction, Mi, shall be the annual average mole fraction for each 

facility, as specified in paragraphs (u)(2)(i) through (vii) of this section. 

(i) GHG mole fraction in produced natural gas for onshore petroleum and natural gas production facilities. If 

you have a continuous gas composition analyzer for produced natural gas, you must use these values for 

determining the mole fraction. If you do not have a continuous gas composition analyzer, then you must use 

your most recent gas composition based on available sample analysis of the field. 

(ii) GHG mole fraction in feed natural gas for all emissions sources upstream of the de-methanizer or dew 

point control and GHG mole fraction in facility specific residue gas to transmission pipeline systems for all 

emissions sources downstream of the de-methanizer overhead or dew point control for onshore natural gas 

processing facilities. If you have a continuous gas composition analyzer on feed natural gas, you must use 

these values for determining the mole fraction. If you do not have a continuous gas composition analyzer, 

then annual samples must be taken according to methods set forth in §98.234(b). 

(iii) GHG mole fraction in transmission pipeline natural gas that passes through the facility for onshore 

natural gas transmission compression facilities or the composition in §98.232(m)(1). 

(iv) GHG mole fraction in natural gas stored in underground natural gas storage facilities or the composition 

in §98.232(m)(1). 

(v) GHG mole fraction in natural gas stored in LNG storage facilities or the composition in §98.232(m)(1). 
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(vi) GHG mole fraction in natural gas stored in LNG import and export facilities. 

(vii) GHG mole fraction in local distribution pipeline natural gas that passes through the facility for natural 

gas distribution facilities or the composition in §98.232(m)(1). 

(v) GHG mass emissions. Calculate GHG mass emissions in carbon dioxide equivalent at standard conditions by 

converting the GHG volumetric emissions at standard conditions into mass emissions using Equation W–36 of this 

section. 

Where: 

Masss,I = GHG i (either CH4, or CO2 or N2O) mass emissions at standard conditions in metric tons CO2e. 

Es,i = GHG i (either CH4, or CO2 or N2O) volumetric emissions at standard conditions, in cubic feet. 

ρ i = Density of GHG i. Use 0.0538 kg/ft3

 for CO2and N2O, and 0.0196 kg/ft3 for CH4at 68 °F and 14.7 psia 

or 0.0530 kg/ft3

 for CO2and N2O, and 0.0193 kg/ft3 for CH4at 60 °F and 14.7 psia. 

GWP = Global warming potential, 1 for CO2, 21 for CH4, and 310 for N2O. 

... 
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§ 98.234 Monitoring and QA/QC requirements. 

REVISIONS TO ADD METHOD FLEXIBILITY AND TO ALLOW AN ALTERNATIVE TO AWP 

IN 60.18(i) THAT CAPTURES THE RELEVANT PERFORMANCE SPECS FOR DAILY QA/QC 

The GHG emissions data for petroleum and natural gas emissions sources must be quality assured as applicable as 

specified in this section. Offshore petroleum and natural gas production facilities shall adhere to the monitoring and 

QA/QC requirements as set forth in 30 CFR 250. 

(a) You must use any of the methods described as follows in this paragraph to conduct leak detection(s) of equipment 

leaks and through-valve leakage from all source types listed in §98.233(k), (o), (p) and (q) that occur during a 

calendar year, except as provided in paragraph (a)(4) of this section. 

(1) Optical gas imaging instrument. Use an optical gas imaging instrument for equipment leak detection in 

accordance with (i) or (ii). 

(i) 40 CFR part 60, subpart A, §60.18(i)(1)(i) and (2) of the Alternative work practice for monitoring 

equipment leaks with a detection sensitivity of 60 grams per hour. Any emissions detected by the optical 

gas imaging instrument is a leak unless screened with Method 21 (40 CFR part 60, appendix A–7) 

monitoring, in which case 10,000 ppm or greater is designated a leak. Video records per §60.18(i)(1)(ii) are 

not required. In addition, you must operate the optical gas imaging instrument to image the source types 

required by this subpart in accordance with the instrument manufacturer's operating parameters.

(ii) Operate the optical gas imaging instrument consistent with manufacturer operating procedures. 

The instrument must meet the specification in §60.18(i)(1)(i) and manufacturer procedures must 

include daily instrument check procedures similar to those in §60.18(i)(2) based on a detection 

sensitivity level of 60 grams methane per hour (equivalent to 3.1 SCFH) with a purity of no less than 98 

percent by volume. Video records per §60.18(i)(1)(ii) are not required.

(iii) An operator can elect to conduct annual optical gas imaging according to paragraph (i) or (ii) of 

this section to screen vents that require measurement under §98.233(o) and (p). Vent rate 

measurement is not required and the vent rate is recorded as zero if optical gas imaging does not detect 

vented gas. 

(2) Method 21. Use the equipment leak detection methods in 40 CFR part 60, appendix A–7, Method 21. If using 

Method 21 monitoring, if an instrument reading of 10,000 ppm or greater is measured, a leak is detected. 

Inaccessible emissions sources, as defined in 40 CFR part 60, are not exempt from this subpart. Owners or 

operators must use alternative leak detection devices as described in paragraph(a)(1) of this section to monitor 

inaccessible equipment leaks or vented emissions. 

(3) Infrared laser beam illuminated instrument. Use an infrared laser beam illuminated instrument for equipment 

leak detection. Any emissions detected by the infrared laser beam illuminated instrument is a leak unless screened 

with Method 21 monitoring, in which case 10,000 ppm or greater is designated a leak. In addition, you must 

operate the infrared laser beam illuminated instrument to detect the source types required by this subpart in 

accordance with the instrument manufacturer's operating parameters. 

(4) Optical gas imaging instrument. An optical gas imaging instrument must be used for all source types

components requiring a leak survey that are inaccessible and cannot be monitored without elevating the 

monitoring personnel more than 2 meters above a support surface. 

(5) Acoustic leak detection device. Use the acoustic leak detection device to detect through-valve leakage. When 

using the acoustic leak detection device to quantify the through-valve leakage, you must use the instrument 

manufacturer's calculation methods to quantify the through-valve leak. When using the acoustic leak detection 

device, if a leak of 3.1 scf per hour or greater is calculated, a leak is detected. In addition, you must operate the 

acoustic leak detection device to monitor the source valves required by this subpart in accordance with the 

instrument manufacturer's operating parameters. Acoustic devices that provide an audible leak signal but do 

not calculate a leak rate can be used to identify non-leakers with subsequent measurement required to 

calculate the rate if through-valve leakage is identified. Leaks are reported if a leak rate of 3.1 scf per hour 

or greater is measured. 
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(b) You must operate and calibrate all flow meters, composition analyzers and pressure gauges used to measure 

quantities reported in §98.233 according to the procedures in §98.3(i) and the procedures in paragraph (b) of this 

section. You may use an appropriate standard method published by a consensus-based standards organization if such a 

method exists or you may use an industry standard practice. 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). 

(c) Use calibrated bags (also known as vent bags) only where the emissions are at near-atmospheric pressures and 

below the maximum temperature specified by the vent bag manufacturer such that it the bag is safe to handle.

and can capture all the emissions, below the maximum temperature specified by the vent bag manufacturer, and The 

bag must be of sufficient size that the entire emissions volume can be encompassed for measurement. 

(1) Hold the bag in place enclosing the emissions source to capture the entire emissions and record the time 

required for completely filling the bag. If the bag inflates in less than one second, assume one second inflation 

time. 

(2) Perform three measurements of the time required to fill the bag, report the emissions as the average of the 

three readings. 

(3) Estimate natural gas volumetric emissions at standard conditions using calculations in §98.233(t). 

(4) Estimate CH4and CO2volumetric and mass emissions from volumetric natural gas emissions using the 

calculations in §98.233(u) and (v). 

(d) Use a high volume sampler to measure emissions within the capacity of the instrument. 

(1) A technician following manufacturer instructions shall conduct measurements, including equipment 

manufacturer operating procedures and measurement methodologies relevant to using a high volume sampler, 

including positioning the instrument for complete capture of the equipment leak without creating backpressure on 

the source. 

(2) If the high volume sampler, along with all attachments available from the manufacturer, is not able to capture 

all the emissions from the source then use anti-static wraps or other aids to capture all emissions without violating 

operating requirements as provided in the instrument manufacturer's manual. 

(3) Estimate natural gas volumetric emissions at standard conditions using calculations in §98.233(t).

(34) Estimate CH4 and CO2 volumetric and mass emissions from volumetric natural gas emissions using the 

calculations in §98.233(u) and (v). 

(45) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH4 by using calibrated 

gas samples and by following manufacturer's instructions for calibration. 

... 

§ 98.235 Procedures for estimating missing data. 

[ INITIAL SUGGESTION OF TEXT TO BROADEN “ACCESS” TO MISSING DATA PROVISIONS] 

A complete record of all estimated and/or measured parameters used in the GHG emissions calculations is required. If 

data are lost or an error occurs during annual emissions estimation or measurements, or an unanticipated 

circumstance prevents a measurement or leak survey, you must repeat or conduct the estimation or measurement 

activity for those sources as soon as possible, including in the subsequent calendar year if missing data are not 

discovered until after December 31 of the year in which data are collected, until valid data for reporting is obtained. 

Data developed and/or collected in a subsequent calendar year to substitute for missing data cannot be used for that 

subsequent year’s emissions estimation. Where missing data procedures are used for the previous year, at least 30 

days must separate emissions estimation or measurements for the previous year and emissions estimation or 

measurements for the current year of data collection. For missing data which are continuously monitored or measured, 
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(for example flow meters), or for missing temperature or pressure data that are required under § 98.236, the reporter 

may use best available data for use in emissions determinations. The reporter must record and report the basis for the 

best available data in these cases. 

§ 98.236 Data reporting requirements. 

CORRECTIONS ARE ADDED FOR CONSISTENCY WITH §98.233 REVISIONS 

AND UNDERSTANDING OF EPA’S INTENT ON DESIRED INFO FOR REPORTING 

In addition to the information required by §98.3(c), each annual report must contain reported emissions and related 

information as specified in this section. 

(a) Report annual emissions separately for each of the industry segments listed in paragraphs (a)(1) through (8) of this 

section in metric tons CO2e per year at standard conditions. For each segment, report emissions from each source type 

§98.232(a) in the aggregate, unless specified otherwise. For example, an onshore natural gas production operation 

with multiple reciprocating compressors must report emissions from all reciprocating compressors as an aggregate 

number. 

... 

(c) For each aggregated source, unless otherwise specified, report activity data and emissions (in metric tons CO2e per 

year at standard conditions) for each aggregated source type as follows: 

(1) For natural gas pneumatic devices (refer to Equation W–1 of §98.233), report the following: 

(i) Actual cCount and estimated count separately of natural gas pneumatic high bleed devices as applicable. 

(ii) Actual cCount and estimated count separately of natural gas pneumatic low bleed devices as applicable. 

(iii) Actual cCount and estimated count separately of natural gas pneumatic intermittent bleed devices as 

applicable. 

(iv) Report emissions collectively for all pneumatic devices. 

... 

(7) For each blowdown vent stacks (refer to Equation W–14a or W-14b of §98.233), report the following: 

(i) Total number of blowdowns per equipment type in calendar year for Equation W-14a. 

(ii) Total number of blowdowns in calendar year for Equation W-14b.

(iii) Report emissions collectively per equipment type. 

... 

(9) For transmission tank emissions identified using optical gas imaging instrument per §98.234(a) (refer to 

§98.233(k)), or acoustic leak detectionof scrubber dump valves, report the following for each tank: 

(i) Report emissions individually for each tank. 

(ii) [Reserved] 

... 

Comment [JMc11]: Reference to “actual” 

deleted for consistency with language added in 

98.233(a) regarding “best available info” for 

defining device type. In addition, §98.233(a) criteria 

clearly identify differences allowed for device counts 

for different segments. 

Comment [JMc12]: As noted in section 

98.233(i), for facility blowdowns calculated using 

Eq W-14b, most or all events will include a unique 

volume, so tracking counts “per equipment type” is 

not appropriate 
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(13) For each centrifugal compressor packages: 

(i) For each wet seal centrifugal compressors package with wet seals in operatingonal mode (refer to Equations 

W–22 through W–24 of §98.233), report the following for each degassing vent: 

(A) Number of wet seals connected to the degassing vent. 

(B) Fraction of wet seal oil degassing vent gas recovered for fuel or sales or flared. 

(C) Annual throughput in million scf, use an engineering calculation based on best available data.

(D) Type of meters used for making measurements.

(E) Reporter emission factor for wet seal oil degassing vents in cubic feet per hour (refer to Equation W–24 of 

§98.233).

(F) Total time the compressor driver is operating in hours.

(G ) Report Annual wet seal oil degassing vent emissions in metric tons of CH4 and metric tons of CO2

Report seal oil degassing vent emissions for compressors measured (refer to Equation W–22 of §98.233) and 

for compressors not measured (refer to Equation W–23 and Equation W–24 of §98.233). 

(ii) For each wet and or dry seal centrifugal compressors package in operating mode, (refer to Equations W–22 

through W–24 of §98.233), report the following: 

(A) Total time in hours the compressor package is in operating mode. 

(B) Reporter emission factor for blowdown vents in cubic feet per hour (refer to Equation W–24 of §98.233).

(C) Report Bblowdown vent emissions in metric tons of CH4 and metric tons of CO2 when in operating 

mode (refer to Equation W–23 and Equation W–24 of §98.233). 

(C) Annual throughput in million scf, use an engineering calculation based on best available data.

(iii) For each wet and or dry seal centrifugal compressors package in not operating depressurized mode (refer to 

Equations W–22 through W–24 of §98.233), report the following: 

(A) Total time in hours the compressor package is in shutdown, not operating depressurized mode. 

(B) Reporter emission factor for isolation valve emissions in shutdown, depressurized mode in cubic feet per 

hour (refer to Equation W–24 of §98.233).

(C) Report the iIsolation valve leakage emissions in not operating depressurized mode in cubic feet metric

tons of CH4 per hour and metric tons of CO2 (refer to Equation W–23 and Equation W–24 of §98.233).

(iv) For each centrifugal compressor package, Rreport total annual compressor emissions from all modes of 

operation (refer to Equation W–24 of §98.233). 

(v) Report the following:

(A) Reporter emission factor for wet seal oil degassing vents in operating mode in standard cubic feet of 

natural gas per hour (refer to Equation W–24 of §98.233).

(B) Reporter emission factor for blowdown vents in operating mode in standard cubic feet of natural 

gas per hour (refer to Equation W–24 of §98.233). 

(C) Reporter emission factor for isolation valve emissions in not operating depressurized mode in cubic 

feet of natural gas per hour (refer to Equation W–24 of §98.233).

(vi) For centrifugal compressors in onshore petroleum and natural gas production (refer to Equation W–25 of 

§ 98.233), report the following: 

(A) Count of compressors packages. 

(B) Report emissions (refer to Equation W–25 of § 98.233) collectively. 
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(14) For reciprocating compressor packages: 

(i) For each reciprocating compressors package rod packing emissions with or without a vent in operating mode, 

report the following: 

(A) Annual throughput in million scf, use an engineering calculation based on best available data. 

(B) Total time in hours the reciprocating compressor package is in operating mode. 

(C) Report Annual rod packing emissions in metric tons of CH4 and metric tons of CO2 for compressors 

measured (refer to Equation W–26 of §98.233) and for compressors not measured (refer to Equation W–27 

and Equation W–28 of §98.233).

(D) Annual blowdown vent emissions in metric tons of CH4 and metric tons of CO2.

(ii) For each reciprocating compressors package blowdown vents not manifold to rod packing vents, in operating 

and standby pressurized mode (refer to Equations W–26 through W–28 of §98.233), report the following: 

(A) Total time in hours the compressor is in standby, pressurized mode. 

(B) Reporter emission factor for blowdown vents in cubic feet per hour (refer to §98.233, Equation W–28).

(C) Report Annual blowdown vent emissions in metric tons of CH4 and metric tons of CO2 when in 

operating and standby pressurized modes (refer to Equation W–27 and Equation W–28 of §98.233).

(iii) For each reciprocating compressors package in not operating depressurized mode (refer to Equations W–26 

through W–28 of §98.233), report the following: 

(A) Total time the compressor package is in not operating depressurized mode. 

(B) Reporter emission factor for isolation valve emissions in not operating depressurized mode in cubic feet 

per hour (refer to Equation W–28 of §98.233).

(C) Report the Annual isolation valve leakage emissions in metric tons of CH4 and metric tons of CO2 in 

not operating depressurized mode.

(iv) For each reciprocating compressor package, Rreport total annual compressor emissions from all modes of 

operation (refer to Equation W–27 and Equation W–28 of §98.233). 

(vi) Report the following:

(A) Reporter emission factor for rod packing vents in operating mode in standard cubic feet of natural 

gas per hour (refer to Equation W–28 of §98.233).

(B) Reporter emission factor for blowdown vents in operating mode in standard cubic feet of natural 

gas per hour (refer to Equation W–28 of §98.233).

(C) Reporter emission factor for blowdown vents in standby pressurized mode in standard cubic feet of 

natural gas per hour (refer to Equation W–28 of §98.233).

(D) Reporter emission factor for isolation valve emissions in not operating depressurized mode in cubic 

feet of natural gas per hour (refer to Equation W–28 of §98.233).

(vii) For reciprocating compressors in onshore petroleum and natural gas production (refer to Equation W–29 of 

§98.233), report the following: 

(A) Count of compressors packages.

(B) Report emissions collectively. 
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(15) For each equipment leak sources that uses emission factors for estimating emissions (refer to §98.233(q) and (r)). 

(i) For equipment leaks found in each leak survey (refer to §98.233(q)), report the following: 

(A) Total count of leaks found in each complete survey listed by date of survey and each type of leak source 

for which there is a leaker emission factor in Tables W–2, W–3, W–4, W–5, W–6, and W–7 of this subpart. 

(B) Concentration of CH4 and CO2 as described in Equation W–30 of §98.233.

(C) Report Annual CH4 and CO2 emissions (refer to Equation W–30 of §98.233) collectively by equipment 

type. 

(ii) For equipment leaks calculated using population counts and emission factors (refer to §98.233(r)), report the 

following: 

(A) For source categories §98.230(a)(3), (a)(4), (a)(5), (a)(6), and (a)(7), total count for each type of leak 

source in Tables W–2, W–3, W–4, W–5, and W–6 of this subpart for which there is a population emission 

factor, listed by major heading and component type. 

(B) For onshore production (refer to §98.230 paragraph (a)(2)), total count for each type of major equipment 

in Table W–1B and Table W–1C of this subpart, by field. 

(C) Report Annual CH4 and CO2 emissions (refer to Equation W–31 of §98.233) collectively by equipment 

type. 

... 

§ 98.237 Records that must be retained. 

Monitoring Plans, as described in §98.3(g)(5), must be completed by April 1, 2011. In addition to the information 

required by §98.3(g), you must retain the following records: 

(a) Dates on which measurements were conducted. 

(b) Results of all emissions detected and measurements except video records from optical imaging conducted 

according to §98.234(a)(1) or (4) are not required. 

... 

§ 98.238 Definitions. 

Except as provided in this section, all terms used in this subpart have the same meaning given in the Clean Air Act 

and subpart A of this part. 

... 

Compressor means any machine for raising the pressure of a natural gas or CO2 by drawing in low pressure natural 

gas or CO2and discharging significantly higher pressure natural gas or CO2.

Compressor package means one or more compressors with a single drive, including separable, integral, and 

multi-stage compressor designs.

... 

TABLES – APPARENT ERROR IN TABLE W-4 

There appears to be a heading in Table W-4 that is not appropriate. The third bold heading in the table states, 

“Leaker Emission Factors—Storage Station, Gas Service”. It appears that this heading should be deleted and the 

following line that present a component emission factor (“open ended line............ 0.03”) should be merged with the 

previous section under the second heading, “Population Emission Factors—Storage Wellheads, Gas Service”.
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Definitions for Pneumatics in Subpart A 

§ 98.6 Definitions. 

... 

Continuous bleed means a continuous flow of pneumatic supply gas to the process control measurement device (e.g. 

level control, temperature control, pressure control) where the supply gas pressure is modulated by the process 

condition, and then flows to the valve controller where the signal is compared with the process set-point to adjust gas 

pressure in the valve actuator. 

... 

Intermittent bleed pneumatic devices mean automated flow control devices powered by pressurized natural gas and 

used for automatically maintaining a process condition such as liquid level, pressure, delta-pressure and temperature. 

These are snap-acting or throttling devices that discharge a portion or the full volume of the actuator intermittently 

when control action is necessary, but does not bleed continuously. 

IN ADDITION – RECOMMEND EXPLANATORY PARAGRPAH FOR THE PREAMBLE TO 

PROVIDE EXAMPLES (PER DISCUSSION WITH EPA) OF DEVICES INCLUDED AND 

DEVICES EXCLUDED. Example text follows: 

The definition of “intermittent bleed pneumatic device” was revised and examples of devices that are categorized 

as intermittent pneumatics, as well as devices that are excluded, are provided here. Examples of intermittent 

pneumatic or control loop devices include level switches, positioners, pressure switches, thermostats, flow 

integrators, controller-pilots, and volume boosters. Gas actuated isolation valves and recording or control 

measurement devices are not considered pneumatic devices under Subpart W. Manual assist devices and 

pneumatic controller devices that are infrequently actuated, sealed, or do not emit to atmosphere are not 

considered pneumatic devices under Subpart W, including transmitters, transducers, relays (also called a booster, 

transmitter, or amplifier), gauges, control valve operator/actuators, and self contained regulators. Subpart W 

intermittent bleed pneumatic device emissions are only associated with the pneumatic controller, and actuator 

venting is not counted as a device. 

Comment [JMc13]: INGAA considered 

including “examples” in the definition on 

“intermittent” device, but the list may be too large 

and cumbersome. As an alternative, INGAA 

recommends including a paragraph in the preamble 

that lists examples.