### 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 St ates. 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 br oad range of programs and servic es for member natural gas pipelines, marketers, gatherers, in ternational natural gas companies and industry associates. Today, natural gas m eets 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 effectiv e leak survey options, as we requested, rather than requiring that a ll 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 thes e concerns in the final rule, the Agency has adopted new terms and requirement s with no clear meaning that unless changed will make it impossible for our me mbers to determine with assurance how to comply with the rule, yield conflicti ng and unreliable emissi ons 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 t herefore 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 Ac t). In addition, we request that EPA stay the effectiveness of these provis ions 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 de monstrate to the Admi nistrator that it was impracticable to raise such object ion 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 revi ew) 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 provid ing us no opportunity to comment on them during the period for public comment on t he 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 subjec t 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 duri ng 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 opportuni ty to test this so ftware and the forms to be sure they align with what is required in the Subpart W Rule, once we know what that is.

2As a result of these uncertainties, it will be impossible in present circumstances for Designated Representatives to provide t he required certification of compliance with the related Subpart W reporting requirem ents and emission factor formulas with assurance. In addition, the conflicting in terpretations of key terms and requirements are likely to result in either significant ov er reporting or under reporting or inaccurate reporting of greenhouse gas emissions. Clear ly, 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 applicat ion 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 effe ctive date of action taken by it, pending judicial review.” 5 U.S.C. §705. APA sect ion 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 (irrepar able harm). There is no need to show irreparable harm to support an administrative stay. EPA has applied the APA’s “justice so requires” standard fo r administrative stays in Clean Air Act

cases. 1 EPA can and should find that in th is instance, justice requires staying the Subpart W Rule pending recons ideration. Certainly it is unjust to require compliance from natural gas local distri bution 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 per forming leak surveys and collecting data on emissions this year. The resulting information would be gathered under different interpretations of the rule, as each LDC di d the best it could, and therefore would be of little use to EPA. Accordingly, t here would be no significant damage to EPA’s mission from granting this stay.

AGA accordingly requests a stay of the ef fective date for the Subpart W provisions affecting natural gas distribution, dehydrat ion 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).

3B. AGA’s Objections
AGA requests reconsideration of Subpart W, as applied to Natural Gas Distribution Companies, Natural Gas Distribution Faci lities, dehydration units and internal combustion units at Underground Storage Fa cilities, and LNG facilities, based on the following objections.

1. Key New Terms Are Vague and Confusing

The Subpart W obligations for LDCs are prim arily focused on reporting emission leaks. The manner in which those leaks must be quantified and report ed depends on the regulatory classification of the leaking equip ment. Specifically, physical surveys of the number of leaks are required for “ above ground meters and regulators at custody transfer city gate stations.” Emission fact ors for leaking component are then applied to those numbers to co mpute an end quantity.
On the other hand, the rule requires “devel oped” emission factors to quantify emissions from “above ground mete rs 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 im portantly, the basic distinction that required thes e 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 a lways have a meter. The emission factor equation W-32 for “non-custody-transfer city gat e stations” clearly requires multiplying the emission factor times the num ber 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 i ndustry, but unfortunatel y it means different things to different companies. It can mean the place where an LDC takes custody of

4natural gas from the upstream supplier (eit her 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 lo wer pressure distribution system for a town or city – either directly from the upstream suppl ier (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 si tuation 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 re gulator” 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 ru le. This is essential to ensure that all operators report the same information required by EPA.

It was not possible to comment on this iss ue, because the terms “city gate,” “custody transfer,” " non-custody transfe r," “meter and regulator” and “meter run” were not used in proposed section 98.232(i)(1) until after the fi nal rule went into place Moreover, the whole conceptual framework of the proposed ru le was different, in that the proposed rule did not rely on making distinctions am ong different locations or types of equipment.

b) Custody Transfer Ci ty 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 fi nal 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 specif ied equipment, apply certain default “leaker” emission factors to the componen ts found to be leaking at the time of the survey, total those leaker emission factors for each stat ion, and then total the emissions from all stations and divide by the number of mete r 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 trans fer 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 facilitie s 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 pipe line company). The upstream supplier needs

5to 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 di stribution system, and the LDC has no authority to leak test the equipment owned and operated by another entit y. Since the equipm ent 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 regulat or 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 n on-custody city gate stations contains a math error that results in double counting annual hours of operation, thereby inflating emission estimates for non-cu stody-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 form ula 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 distri bution 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,

6and 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 question s 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 c onfusing provisions in the final rule:
“DISCLAIMER: Any communication on t he GHG Reporting Program (GHGRP) is intended to provide general and administrat ive 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, obligat ions, responsibilities, expectations, or benefits in regard to any person. Fac ility owners or operator s and suppliers are responsible for determining how they woul d be affected by the requirements of the rule.”
Since it is not possible for LDCs to dete rmine what these equations in the final rule require, the remedy must be to revise the final ru le 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 t he proposed changes to the equations before they are adopted in final form.

4. New Electronic Reporting For m 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 tria l runs. Even if EPA fixes problems with the definitions and formulas, this will have no effect if the re porting 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 avail able 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.

75. EPA Should Exclude Small In ternal Combustion Sources, Not Just External Combustion

Under the final rule, LDCs are required to report emissions under Subpart W if they operate a “distribution facilit y” (i.e. distribution system) that is estimated to emit methane from certain listed types of equipm ent equal to or exceeding 25,000 metric tons per year of CO2 equiva lent (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 a nd combustion emissions -- carbon dioxide (CO2), methane (CH4), and nitrous oxi de (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 com bustion emissions from stationary fuel combustion equipment. 3

In the final rule, EPA substantiall y 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 ca se 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, woul d 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 di stribution that have a rated heat capacity less than or equal to 5 mmBtu/hr. AGA suppor ts 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 (r eporting 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).

8to account for such small sources would impose a significant bur den on LDC reporters that is not commensurate with the value of the data that w ould be provided. We note also that given the unusually broad definition of “distributi on facility” – to encompass all distribution pipe and equipment operated by a gas utility acro ss 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 tr aditional CAA concept of a contiguous property or plant si te. AGA requests reconsiderat ion of this new exclusion for small combustion sources and revision to include both small internal and external combustion sources, as well as to clarify t hat reporting of combusti on emissions is only required where the aggregate maximum rated heat input capacity of stationary fuel combustion units totals 30 mmBtu/hr or great er at a discrete station site after the excluded units are deducted from em issions at that station.

In addition, we do not understand why EPA prov ided no similar de minimis exemption for either internal or external small combustion sour ces operated at an underground storage facility. The final rule provides that the operator of an underground storage facility must report combustion emissions purs uant to 40 C.F.R. Pa rt 98, Subpart C. Was it EPA’s intention to require an undergr ound storage facility to report combustion emissions only if the combustion emissions fr om 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 Un its 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 ru le 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 w hether it is possible to determine from the final rule whether or not emissions from dehydration uni ts at natural gas underground storage facilities are requir ed to be reported as underground storage facility emissions. Sections 98.230 and 98.232 contain potentially c onfusing statements in this regard. AGA members belie ve the rule was probably intended to exclude emissions from such dehydrat ion facilities, based on EPA’s explanation in the preamble

9that section 98.232 was intended to define s pecific emission sources that would be subject to reporting for a particular industr y segment. Section 98.230(a) confusingly mentions dehydration units as included wi thin the underground storage segment. But we have understood that se ction 98.232 is intended to limit the equipment sources actually subject to the reporting require ment for each segment. We have also understood that EPA included these listed s ources 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 conf usion, because it implies a different interpretation than the preamble and ot her EPA documents in the rulemaking record. We asked whether or not to include dehydrat ion emissions in reporting emissions for underground storage facilities, ant icipating that the Agency w ould confirm that reporting is not required. Instead, EPA responded as fo llows, 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 dehydr ation, are part of the def inition of the underground storage segment. Therefore, if you have t hese processes at your facility, as defined in 40 CFR 98.6, you would be requi red to report on emissions from these dehydration units.”
This informal Agency response contradicts th e final rule preamble and Response to Comments document. AGA members had been re lying on those documents to interpret sections 98.230 and 98.232. We understood that sinc e dehydration units are not listed as being subject to the reporting require ment for underground storage facilities in section 98.232(f), the rule t herefore does not require r eporting dehydration emissions for this segment. If this is not the inten t, then it is unclear what section 98.232 is supposed to achieve.
The preamble and Response to Comments (R TC) support our interpretation that dehydration emissions are excl uded from the repor ting requirement. For example, the preamble to the final rule explains:
“Reporters of an industry segment as def ined by 40 CFR 98.230 would report emissions under subpart W only from t he corresponding source types listed for that particular industry segment as defi ned in 40 CFR 98.232. For example, an onshore natural gas transmission compression reporter as defined by 40 CFR

1098.230(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 t hat 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 si gnificant sources of emissions under each category source type, taking into consi deration 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 specif ic industrial category for which the reporter’s facility qualifies. Ho wever, for threshold determination the reporter must combine emissions and follow the requirements of Section 98.2, for facilities that contain any source cat egory 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 seem s that even EPA finds these pr ovisions confusing. AGA requests reconsideration and revi sion of the rule to make it clear that operators of underground storage facilities (as well as tr ansmission compression facilities) are not required to report emissions from dehydration units.

III. Additional Requests for Relief Upon Reconsideration

A. EPA Provides No Rational Ex planation for Using Outdated, Inaccurate Emission Factors Rather than Modern, Updated Emission Factors
In our comments on the Subpart W proposed ru le, AGA urged EPA to use updated, modern emission factors as t hey become available. We noted that some updated emission factors are already availabl e and should be adopted as approved default emission factors in the final rule. EPA dec lined 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).

11Instead, the Subpart W Rule requires LDCs to use outdated emission factors to estimate their methane emissions. These ol d 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 near ly 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 natu ral 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 complia nce with continuously more stringent PHMSA regulations, resulting in fewer emi ssions. AGA and its me mbers 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 accu rate GHG emission estimates for plastic distribution pipe, metering and regulator (M&R) stations and other natural gas distribution equipment. GTI’s Operations Technology Deve lopment (OTD) group issued a report in November 2009 providing a new updated emission factor for metering and regulating (M&R) stations that could be us ed 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 cont radictory 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 Na tional Grid provided a link to the OTD web site, where they told EPA the M&R em ission 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 s ubmitted an electronic copy of the OTD emission factor report and asked whether EPA would consider changing the rule to incorporate the new OTD emissi on factor for regulator stat ions. EPA responded that it would take the submission into consideratio n 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 t he use of this new, more a ccurate emission factor for regulator stations upon recons ideration 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

12that EPA revise the rule to facilitate expedi tious adoption of other new emission factors as they are developed, including a new em ission 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 pipel ines, 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 munici pally-owned distribution system.”
40 C.F.R. §78.238, 75 Fed. Reg. at 74,511. There are se veral problems with this definition. First, it is conf using. In discussing the repor ting requirements for LDCs, both the Agency and our members find it difficu lt 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 distri bution systems in multiple st ates - but subject to the regulation of a different public utility commission in each stat e - should count that multistate operation as a single “facility” or should count operations in stat e A as one “facility” and operations in state B as a second “facility. ” Third, most LDCs are served by affiliate or interstate transmi ssion pipelines, and the definition of a distribution facility as an LDC, which is regulated as a separate co mpany 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 distributi on systems. T he 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 natur al gas distribution “facility” – to include virtually ever ything operated by an LDC – the Agency has effectively set a far more stringent applicabi lity 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 “facilit y.”) EPA has not provided satisfactory response to our detailed comments on this i ssue, and we believe there are more workable approaches that could be used. AGA requests reconsideration of the natural gas distribution “facility” definition.

13C. It Was Arbitrary and Caprici ous 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 r egulatory program for a null set. Liquefied natural gas (LNG) satellite and peak shavin g facilities – defined as “LNG Storage Facilities” in the Subpart W Rule – are much smaller than LNG import and export terminals. They have far fewer combus tion sources and components. As AGA demonstrated in its June 11, 2010 comments on the proposed rule, even if every combustion source operated at maximum th roughput for vaporization and liquefaction systems and every component leaked methane (thus requiring the use of leaker emission factors for all com ponents) the collective carbon di oxide 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, becaus e 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 po ssibly 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 concer ned 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 regulator y program for a null set is a classic example of wasteful, unnecessary and arbitrar y 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 Caprici ous for EPA to Create a Subpart W Reporting Regulation for LNG Impor t 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 reas ons, these facilities must be very tight. Almost no

14components leak. If combustion emissions exceed the 25,000 metr ic ton per year threshold, these facilities are already requi red to report CO2 emissions vented from reciprocating compressor (engines) or centri fugal compressors (turbines) under Subpart C. Why then create an additional regulat ory burden on these facilities under Subpart W to conduct extensive on-site leak surve ys 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 rati onal 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 distri bution 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 Coun sel, Environment American Gas Association 400 North Capitol Street N.W. Washington, D.C. 20001 placey@aga.org (202) 824-7340

15BEFORE THE ADMINISTRATOR UNITED STATES ENVIRONMEN TAL PROTECTION AGENCY WASHINGTON, DC

PETITION FOR RECONSIDERATIO N 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, 20111 INTRODUCTION

Pursuant to § 307(d)(7)(B) of the Clean Ai r 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 (Chesapeak e) and the American Exploration & Production Council (AXPC) petition the Ad ministrator of the United States Environmental Protection Agency (EPA) to rec onsider specific provisions its final rule requiring owners and operators of petroleu m 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 N ovember 30, 2010, EPA published the final Subpart W Rule (75 Fed. Reg. 74,458).

Reconsideration of the rule is warranted because the gr ounds 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 impracticab ility. 42 U.S.C. § 7607(d)(7)(B). If this test is met, the Clean Air Act (CAA) r equires 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

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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 larges t independent natural gas and crude oil exploration and production companies in th e U.S. Chesapeake and the members of AXPC will be directly and imme diately affected by the requir ements 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 GH Gs. 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 thousa nds of sources throughout the oil and gas sector. Failure to discern and properly measur e what is a reportable emission as specified in the final rule may result in a source bei ng out of compliance with mandatory federal requirements. Failure to comply with federa l 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 uncer tainty 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 EP A'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 reflect s 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 substantiv e and procedural flaws may be addressed administratively.

SPECIFIC ISSUES FOR RECONSIDERATION

A. IN THE FINAL RULE AND IN RESPO NSE TO COMMENTS, EPA FAILS TO JUSTIFY CERTAIN ASPECTS OF TH E 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 aske d 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 Comp endium for that purpose. Commenters also demonstrated that EPA has concluded th at 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, EP A 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 dem onstrated to underestimate emissions by an order of magnitude or more for sources in cluding gas well liquids unloading, gas well completions and workovers, and centrifugal co mpressor wet seal degassing vents.” EPA, Mandatory Greenhouse Gas Reporting Rule Subpa rt W – Petroleum and Natural Gas: EPA's Response to Public Comments (Nov. 201 0) (hereinafter "RTC") at 1348. EPA is obligated to respond to challenges in a cohe rent 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 conc lusory statements and no di scussion of studies that it relied upon or why its conclusions were reasonable absent such studies).3 The Compendium was initia lly released in April 2001. 2 The 2009 version - the third release of the Compendium - "represents i ndustry best practices for estimating GHG emissions" and the "latest information availa ble" on emission fact ors and methodologies. Id . at ii, 1-2. The Compendium has been regularly modified based upon comments received during "industry confer ences, workshops, and focused outreach to other protocol development organizations, particularly those used by the oil and na tural gas industry in other regions of the world." Id . at 1-2. It has also been subj ect to "broad pe er review" by governmental agencies, non-governmental or ganizations, 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 NM AC (requiring the reporting of GHG emissions in 2010 and allowing the use of the API Compendium).
In fact, numerous protocols throughout the worl d, including those us ed 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 O il & 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 th e accuracy and integrity of their emissions data with great confidence.
EPA’s plan to develop a screening tool, while it will assist in the repo rting process, is not responsive to this comment. A screening tool streamlines the identif ication of emission sources. The Compendium is a highly re spected methodology for estimating emissions. 4 EPA does not even explain its in consistent treatment of these low emissions as compared to other similar levels of emission by ot her sources subject to GHG reporting under the same rule.
The unjustified burdens of emissions measurem ent in this rule should be reconsidered especially in light of the recent Executive Orde r (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 th e least burdensome regulatory approach. Subpart W imposes a highly burdensome measurement requir ement 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/th e-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 lette r and spirit of the EO. 6

2. De minimis emissions from portable equipment.
The final rule likewise fails to adequately support requiring the re porting of de minimis emissions from portable equipment as EPA proposed. 75 Fed. Re g. 18,636 (proposed 40 C.F.R. § 98.230(a)(2)). Commenters explained why the information gained from measuring and reporting portable equipment em issions, which are de minimis, does not justify the additional resource strain on covered sources.

In the final rule, EPA does not resolve th e 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 ra ther 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 th e need to ensure the burden on sources is commensurate with the benefit of obtaini ng the precisely measured data. These emissions are no different in terms of their significance level than other emissions where EPA has concluded that “repor ting of [these] GHG emissions is unreasonable given the cost of monitoring and the rela tive 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 r easoned determination that its benefits justify its costs (recognizing that some benefits and costs ar e 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 pr acticable, the costs of cu mulative 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 c onsider (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 co rrected for flare emissions calculated and reported under other paragraphs of th is section to avoid double counting”).
However, in the case of portable equipmen t, EPA knowingly imposes the requirement on the oil and gas industry to re port these emissions while ig noring the inaccuracy imposed by double-counting these emissions reported else where 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, becau se “[a]lthough refineries will report total fuel supplied under Subpart MM, EPA will not know wh ere the fuels are being combusted to inform any combustion equipment specific policy. . . .” RTC at 1600.
The result is completely arbitrary: in th e same rule, EPA demands exact measurement of very de minimis emissions, while inviting inaccuracy by expr essly requiring doublecounting of emissions from the same sources. This irrational outcome should have and could have been addressed during the rule making process. EPA simply could have applied the reporting requirement to the equipmen t that utilizes field gas and not required reporting from diesel-fired equipment. Rath er 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 indi vidual, must make the following four Certifications:
(i) "I was selected as the designate d representative...by an agreement binding on the owners and operators of the f acility. . . ." (Certification 1)
(ii) "... each such owner and operator shall be fully bound by my representations, actions, inactions, or submi ssions." (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 agr eement by which I was selected to each owner and operator of the facility. . . .” (Certification 4)
The oil and gas industry explores for, and de velops hydrocarbons pursuant to a customary form of agreement, the joint operating agre ement (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 o il and gas in certain de scribed 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 ope rator’s authority is derived from the terms and conditions of the JOA. Although multiple standard forms of JOAs are in use by industry, cont racting parties amend the term s of the standard forms to achieve the desired contractual rela tionships 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 obt aining the consent of other affected parties. The industry operate s thousands of properties, each of which can have multiple interest owners of varying levels of sophistication and willingness to cooperate. Accordingly, obtaining consent coul d prove daunting and unsuccessful. It is possible that recalcitrant owners or thos e 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 contem plate compliance with applicable laws or filing of reports with government authoritie s. Typically, the opera tor certifies to the accuracy of the reports submitted, but is not re quired to additionally make other legally binding certifications that woul d necessitate the operator to ac t as a fiduciary or agent for the owners. The specificity of the Certifica tions EPA requires – and the breadth of their legal implications – will require lawyers to re view 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 therefor e each executed cont ract would need to be individually reviewed. At best, the Cer tification 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 reje cted the suggestion that the operator of a facility be responsible for reporting. See EPA, Mandatory Greenhouse Gas Reporting rule: EPA's Response to Pub lic Comments, Volume No. 11, Designated Representative and Data Collection, Repor ting, 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, EPA7 would have identified multiple provisions th at immediately raise th e question of possible legal impediments to compliance with the Cert ification requirements. For example, some form JOAs include provisions such as the following:

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

• “It is not the intention of the parties t o. . . 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 provisi ons in executed JOAs may prohi bit an operator from being able to make the DR Certifications re quired under Subpart A of the reporting rule.
The rights and duties of JOA parties are th e subject of the JOA—a contract between private parties. If a non-operator were to challenge—by litigat ion or otherwise—an operator’s authority to take action not expres sly authorized by the JOA, EPA’s equivocal thoughts on the contract would not control a dispute between private parties. More fundamentally, EPA lacks the auth ority to reinterpret these cont ractual relationships, or to require that the parties renegotiate the term s 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 re ductions through an emissions trading program on fossil fuel-fir ed power plants. Neither the emission control program of the Acid Rain program, nor the util ity 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 hundr eds 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 th e 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 proce ss. Providing the names of all owners for each individual well will require a certif ication 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 notificat ions as ownership can change frequently at some wells.
EPA insists that requiring ownership invol vement will ensure accountability for the submission of such data, and alleges wit hout 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, whic h 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 pe titioners' challenges with conclusory statements).8 B. THE FINAL RULE IMPOSES NE W 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 onshor e production storage ta nks. 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 opportun ity to comment on the proposal. Onshore production sites could have thousan ds of dump valves per repor ting facility or basin that would require frequent monitoring and mainte nance 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, a nd EPA "may" allow BAMM for "up to the entire 2011 calendar year." This rule creat es uncertainty for sources, which rely on certainty in rule procedures and deadlines.
EPA establishes neither a process nor agen cy deadlines for rendering decisions on whether BAMM will be permitted in a given ca se. 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 propo sal, or seek their input in a supplemental proposal, that BAMM would be permitted, cove red sources could not have sought the inclusion of additional elements in the rule that would pr ovide 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 fi rst reporting year 2011 and for all data necessary to conduct the calcula tions 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 requireme nt 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 covere d 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 calcu lating "CH 4 , CO 2 and N 2 O (when flared) emissions from both wet seal and dry s eal centrifugal compressor vents."9 This modified language not only expands th e rule to cover equipment that was not identified in the proposed rule, but it is al so 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 TH REATEN WORKER SAFETY The final rule requires measuring "emissi ons 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 a ssociated with the direct measurement requirements for 'large' reciprocating compre ssor 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 w ould not represent all the emissions required under this rul e” (emphasis added).

EPA does not explain why the cost of gatheri ng these particular emissions is justified given the expense and small in crease 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 signi ficant 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 regulati ons must contain requirements with sufficient clarity that a knowledgeable person can be confident in knowing they have complied with the regulations. Precision is cri tical here, where designated re presentatives 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 re presentative must sign the following certification statement:

I am authorized to make this subm ission on behalf of the owners and operators of the facility or supplier, as applicable, for which the10 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 a ll 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 fa lse statements and information or omitting required statements and info rmation, including the possibility of fine or imprisonment.

The Subpart W Rule contains numerous re quirements that are vague or subject to different interpretations. These inconsistencie s 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 facia lly unclear. In some instances, EPA was addressing comments, but in doing so cr eated new, not previously proposed, inconsistencies. Through r econsideration 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 fi nal provisions render the rule arbitrary and capricious and contrary to law.

1. Excluding boosting stations.
EPA changed the definition of "onshore natu ral gas processing faci lity" 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 gath ering lines and boosting stations." Yet the definition also now states that the sour ce category does incl ude "all residue gas compression equipment owned or operated by th e natural gas processing facility, whether inside or outside the processing facility fence."
The final rule fails to distinguish betw een a boosting station, which is exempt, and an "onshore natural gas transmission compre ssion 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 natura l gas at elevated pr essure from production fields or natural gas processing facilities in transmission pipelines or into storage. 40 C.F.R. § 98.230(a)(4). A transmission comp ressor station can include equipment to separate liquids or de hydrate natural gas. Id. However, according to the final rule this source category does not include gath ering lines and boosting stations. Id.
Onshore natural gas processing
Onshore natural gas transmission compression st ations are distinct from "onshore natural gas processing," which "separat es 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 pro cesses: oil and condensate removal, water11 removal, separation of natural gas liquids , sulfur and carbon dioxide removal, fractionation of NGLs, or other processes, and also the capture of CO 2 separated from natural gas streams." 40 C.F.R. § 98.230(a)(3 ). Gathering lines and boosting stations are not included in "natural gas proces sing"; however, residue gas compression equipment owned or operated by the natural ga s processing facility is included, whether it is located inside or outside the fence lin e of the processing facility. 40 C.F.R. § 98.230(a)(3). The technical support documen t to Subpart W notes that "processing plants process the gas received from producti on and/or gathering or boosting segments to remove hydrogen sulfide (H 2 S) and/or CO 2 from the natural gas, if any, separate the higher molecular weight hydrocar bons (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, B ackground 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 proc ess 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 natu ral gas transmi ssion facility. . . ." RTC at 938-39. This statement conflic ts 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 cl ear where onshore natural gas compression begins." See Comment EPA-HQ-OAR-2009-0923-1151-7. In response, EPA merely noted that the "final rule doe s not require reporting of emissi ons 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 co mpressor stations are required to report.

2. Mapping wells to fields.

EPA has not clarified how repor ting entities are s upposed 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 Info rmation 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 Mast er List. There is no formal wa y to designate appropriate field names. EPA has also not addr essed how to deal with wells that are not in a recognized field in the EIA Master Li st. Between the 2007 and 2008 ve rsions, 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 w ith fracing (75 Fed. Reg. 74,494)12 3. Completions and workovers w ithout fracing (75 Fed. Reg. 74,495) 4. Storage tank venting (75 Fed. Reg. 74,496) 5. Associated gas venting/fl aring (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 sm allest 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 count y their well is locate d, then they know to which basin they belong. Hence, in this acti on, 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 de marcations are clearly defined and are widely known, and reporting at this level w ould provide the necessary coverage of GHG emissions to inform policy.” 75 Fed. Reg. 74,467.

This lack of clarity cr eates 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 ba sed 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 Fe d. 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 co mposition 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 commun ity use “facility” to mean many different things. See, e.g ., 75 Fed. Reg. 74,468 (discussing ownership structures in relation to booster stati ons); 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 reasone d explanation for why a term other than “facility” cannot be adopted for Subpart W (suc h 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 “pipeline13 quality”, 75 Fed. Reg. 18,615, but nothing in the final rule provides su ch 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 we ll venting for liquids unloadings, the final Subpart W rule utilizes the term "p roducing 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 requi rement 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 vent ing and flaring.

40 C.F.R. § 98.233(m) imposes a requirement to report emissions from associated gas venting and flaring not in conj unction with well testing. While this regulation references 40 C.F.R. § 98.233( l ), that definition is unclear. Theref ore, industry is left without clarity regarding what emissions are included in "associated gas venting and flaring not in conjunction with well testing." We presume th at 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 t hose that vent continuously to the atmosphere at a rate in excess of 6 sc f/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 di rect measurements ar e required at each individual pneumatic device, or if BAMM can or should be used. Regardless of the method used to determine bleed rate, EPA ha s not given sufficient consideration to the burden imposed by requiring that the bleed rate of each device be dete rmined in order to count and classify the devices.

9. Blowdown vent stacks.

The sources that are required to report emissions from bl owdown vent stacks are not clear. Table 3 of the preamble lists ons hore 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 emi ssions 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 inconsistenc y between the language in the preamble and the rule.

CONCLUSION

For all of the foregoing reasons, Chesapeak e 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 Ar iel Rios Building 1200 Pennsylvania Avenue, NW Mail Code: 1101A Washington, D.C. 20460

Re: Request for A dministrative Reconsiderat io n Subpart W o f t he Mandatory Reporting of Greenhouse Gases Rule: Petroleum and Natural Gas Systems

Dear Administrator Jackson:

The Gas Processors Associat io n (“GPA”) hereby requests th at th e U.S. Environmental Protecti on Agency (“EPA” or the “Agency”) reconsi der Subpa rt 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 th e Cl ean Air Act (“CAA”), 42 U.S.C. § 7607(d)(7)(B), where it is impract icable to raise an object io n during the peri od of public co mment or if the g rounds for such an object io n arise af ter the public co mment peri od (but within the time specified for judicial review), and if such object io ns are of central rel evance t o the outcome of the rule, EPA is authorized to reconsider a rul e.

GPA is a non

- profi

t trade organizat io n made up of approximately 120 corporate members, all of who m are engaged in the processing of natural gas into merchantable pipeline gas, or in the ma nufacture, transportation, or further processing of liquid products fro m nat ural 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 internat io nal co mpanies that produce natural gas liquids on a global scale.

As described more fully below, GPA is request ing reconsideration of the fo llo wing key aspects of Subpart W. GPA’s objections to these aspects of the final rule arose after the close of th e public co mment period and are of central relevance to the outcome of the final rule. Thus, reconsideration is authorized and appropriate. GPA’s object io ns are as fo llo ws:

1. Subpart W’s best available mo nit oring method (“ BAMM ”) provi si ons do not provide reporting ent it ies wi

th adequate time to ensure compliance wi th th e final rule.

2. Current compressor vent ing monitoring requirements are overly b urdenso me and present si gnificant safet y a nd operational process concerns to reporting ent it ies

.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 provi ded regarding the definit io n of “g as proces sing facilit y. ” A bsent such definit io ns and clarificat io n s, th ere will be substantial confusio n as to which facilit ies are requi

red to report emissio ns data.

4. The definit io n of a facilit y in Subpart W differs from the definit io n of a facilit y provided in a ll other applicable regulat io ns under th e Cl ean Air Act (“CAA”)

. Thi s inconsistency will create unnecessary confusio n amo ng related programs and is not necessary or just ified.

These object io ns are discussed in detail below.

1. Subpart W’s best available mon itoring method (“BAMM”) provisions do not provide reporting entities with adequate time to ensure compliance with the final

ru le.

GPA member companies are currently assessing the availabilit y o f each individual data source required by the Subpart W to per fo rm required cal culat io ns and com ply wi th th e rule. This process is arduous and time

- consuming and requi res significant personnel from many face ts of GPA’s member companies’ co mp lex organizations. The time period EPA has provided reporting ent it ies to a nalyze their exist ing systems, identify parameters for which BAMM is requi red, and prepare and submit BAMM or BAMM extensio n requests is impract ical and unrealist ic.

Exist ing BAMM provisio ns are difficult to comply with, as BAMM is provided only for speci fic sources and methodologies. Given the significant complexit ies of the rule and the pl ethora of data parameters that must be assessed and co llected for compliance, th e use of BAMM provisio ns fo r one data point of an equat io n but not for others does not provide si gnificant relief for reporting ent it ies . Furtherm ore, because so me of th e data required under Subpart W ma y be BAMM est imates
, but others must be actual data points, th e final rule will resul t in inconsistencies th at m ay impede reporting entit ie s ’ efforts to comply wi th th e rule.

Addit io nally , t he information required to be submitted in BAMM extensio n requests puts

a considerable burden on reporting entit ie s , especially where th ei r time and resources would be better spent preparing and collect in g data for compliance wi th Subpart W . For those data points ident ified for which BAMM is necessary, reporting entit ie s are highly unlikely to be able to di scuss, contract with, and co llect the documentation required to support the BAMM request wi thin the given timeframe.

EPA does not provide any deadlines in t he final rule wi thin which they will respond to BAMM extension requests, which is of considerable concern to reporting entit ie s th at will rely on BAMM to comply wi

th Subpart W in t he fir st year of re porting. Reporti ng ent it ies will face si gnificant uncertainty while wait ing to hear fro m E PA on whethe r the request has been approved and may be left in an untenable posit io n 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 prov ided, without request, for entit ies impacted by Subpart W for the entire first reporting year (2011) and for all data points required fo r cal culat io n methods prescribed by the rule.

2. Current compressor venting monitoring requirements are overly burdensome a nd 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 emissio ns inventory and reporting rule. Widely accepted estimat io n met hods are available to calculate emissions fro m co mpressor s th at can deliver accurate results without requiring direct measurements. Furthermore, such direct measurement requirements are duplicat ive of ongoing EPA research and there fo re not necessary under the reporting rule. In the rule’s Technical Support Document, EPA states that the data fro m th e di

rect measurement porti ons o f t he rule is necessary to support future climate

- rel ated regul atory efforts, though no information is pr ovi ded as to what such efforts are or what they will invo lve. Given the substantial burden Subpart W’s direct measurement requirements place on reporting ent it ies, 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 informat io n.

Addit io nally , t he final rule requires reporting ent it ies to calculate emissions fro m centrifugal co mpressors for both wet seal and dry seal vent ing and fro m blo wdown valve vents. These requirements , which were absent fro m t he proposed rule, will more than double the number of measurements originally ant ic ipated for centrifugal co mpressors and result in a substant ia l addit io nal and unanticipated burden to me asure, collect, and quantif y such data.

The final rule also requires reporting ent it ies to calculate emissio ns fro m r eci procating

com pressor bl owdown valve vents. The proposed rule had only required emissio ns calculat io ns fo r rod pack vent ing and unit isolation valve vent ing systems. This new and, again,
unant ic ipated set of requirements will more than double the number of measurements for reci procating compressors.

Finally , Subpart W requires a nnual measurements on each vent for each compressor, and th e final rul e indicates under § 98.233(o) (1) and § 98.233(p) that if sources are vented through a

commo n manifo ld, each vent source must be measured separately. In practical terms, it is not possible for reporting ent it ies to comply with this requirement under current operating condi ti ons. Com

p liance would require pi

pe s to be cut in o rder to provide adequate access po int s to install meter ports. This would result in ent ir e facilit ies need ing to be shut down, blown down, and purged in order to ensure appropriate safet y co ndit io ns to proceed with such pipe

mo dificati ons

— again represent ing an excessive, overly burdenso me , and avo idable co mp liance burden for reporting ent it ies.

GPA therefore requests that EPA a llo w for the use of accepted estimat io n met hods available to calculate emissio ns from c om pressor vents in lieu o f 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 unde r § 98.230(a)(3) that gathering lines and booster stations are excluded fro m r eporting obligat io ns. However, th e definit io n of a gas processing facilit y a lso includes several processes typical of standard booster stations ( i.e. , water removal). This defi ni ti on therefore seems to imply that booster stations exhibit ing any of these characterist ic s wi th an average annual throughput ≥ 25 MMscfd are subject to Subpart W’s reporting requi rements. Definit io ns o f gathering lines and booster stations appeared in th e proposed rule, but were removed fro m t he final rule. Wit hout such definit io ns, GPA and its member co mpanies are concerned that their reporting liabilit y coul d inappropriately extend to booster stations falling under the definit io n provided under § 98.23 0(a)(3).

In addit io n, Subpart W’s definit io n of source category under § 98.230 lists several t ypes of operati ons, including onshore natural gas processing and onshore petroleum and natural gas producti on, but fails to specify how a reporting entit y c an de termine under which type of operati on certain t ypes of act ivit ies or facilit ies th at can occur in more than one t ype of operation shoul d fall. For example, a facilit y t hat removes water could fall under either onshore natural gas processing or onshore pet rol eum and natural gas production. Accordingly, t he source category definit io n is a source of considerable confusion and uncertaint y fo r reporting entit ie s.
GPA requests that EPA reinstate the definit io n s of gathering lines and booster stations fro m t he proposed rule and clarify and align each source category to definit io ns already provided in t he CAA ( e.g. , Natural Gas Processing Facilit y under NSPS KKK).

4. The current definition of a facility in Subpart W differs from the definition of a facility provide d in all other applicable regulations under the Clean Air Act (“CAA”).
The final rule requires production operations to be aggregated on basin

- wi de basis for purposes of determining the applicabilit y o f Subpart W and in meet ing subsequent reporting obliga ti ons. This approach is fundamentally inconsistent with the manner in which the terms “stati onary source” or “facilit y” are defined for all other purposes under the CAA. As a result, th e 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 th e Subpart W approach will o ft en be inco mpat ible with actual ownership and control of the affected operations.

GPA request s th at EPA co nform th e Subpart W defi nit io n of “Facilit y” with oth er similar definit io ns in other CAA regulatory programs. To avo id creat ing addit io nal reporting burden, EPA should allow companies to “roll up” the GHG emissio ns from mult iple affiliated stationary

s ources when reporting under Subpart W.

* * * * * * *The Honorable Lisa P. Jackson, Administrator

February 11, 2011 Page 5

Thank you for your considerat io n of these concerns. If you have any quest io ns, do not hesi tate to contact m e at 918

- 493

- 3872.

Si ncerely,

Jeff Applekamp Di rector, Government Affairs Gas Processors Associat io n

cc: D. Kruger P. Gunning R. FernandezBEFORE THE U NITED STATES ENVIRONMENTAL PROTECTION AGENCY

Mandatory Reporting of Greenhouse Gases: ) Docket No. EPA

- HQ

- OAR

- 200 9

- 0923 P etr ol e u m and Na t ural G as Systems; ) FRL

- 9 226

- 3 Final Rule ) RIN 2060

- AP99

PETITION FOR RECONSIDERATION

P e r 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 U nited States Environmental Protection Agency (“EPA”) to reconsider

provisions of its f inal r ule in “ Mandatory Reporting of Greenhouse Gases: Petroleum and

Natural Gas Systems ,” 75 Fed. Reg. 74458 ( November 30 , 2010) ( the “ Final Rule ”)

.

T his petition voice s objections that could not have been raised during the public comment

period because the y concern Final Rule provisions that did not appear in the proposed rule, 74

F ed. R eg. 16448 ( April 10, 200 9 ) (the “Proposed Rule”). Each of INGAA’s first t hree concerns

deal with regulations allowing operators to compute greenhouse gas (“GHG”) emissions using

“best alternative m onitoring method s ” (“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 issu ance. Also

,
as noted in INGAA’s fourth item for reconsideration, the Final Rule rais es implemen tation issues

that were not evident in the Proposed Rule because they relate to previously unannounced

requirements for emissions estimation and reporting.

The issu es presented below are of central relevance to the outcome of th is rulemaking

and reconsideration should be granted to address them. Because w e 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.

I NGAA seeks reconsider ation 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 t he basic desig n 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 ru le. 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. § 98.23 4(f)(4)), the Final Rule specif ies

two sepa rate BAMM request s , subject to different filing deadlines, content requirements and

decision criteria, for approval to use BAMM during two separate p e riods. Requests t o 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 t w o
separate BAMM requests, due the April 30 th and September 30 th , but the April 30 th request

covers only the period from July 1, 2011 through December 31, 2011.

T he content requirements and approval criteria

— and thus the apparent circumstances

that warrant the use of BAMM

— differ widely between the two BAMM requests. The

Ap r il 30 th 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 c o ntrast, the September 30 th 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 w ith other

laws or regulations. 40 C.F.R. § 98.234(f)(8)(i v ).

Several aspects of the regulations applicable to the April 30 th requests are confusing,

particularly whe n compar ed with the corresponding regulations applicable to the September 30 th

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 30 th , yet the

Final Rule requires that a request must be filed by April 30 th 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 30 th requests that would serve as

notice of potential BAMM elig ibility

— in effect, a placeholder

— to be supplemented by the

September 30 th 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 [B AMM] 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 30 t h 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 ad dress this problem. The content

requirements and approval criteria for the April 30 th and September 30 th BAMM r equests 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 30 th request s, which under the

placeholder approach would serve as written notice that BAMM may be request ed 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 metho dology. A r eporter filing September 30 th request s 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

. Con versely, 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 . I f 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 regulatio ns, all requests to use BAMM beyond 2011 must be filed by

Septe m ber 30, 2011 , 40 C.F.R. § 98.234(f)(8)(i). Other th a n 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 30 th

. There is no reasonable basis for denying BAMM to a natural gas compressor station that

experiences an increase in throughput, thus exc eed ing 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 an d unaddressed future events

. On reconsideration, EPA should also specify the criteria it will use to evaluate requests

filed after September 30, 2011. U nder 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 cri teria 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 gra nt reconsideration so it can articulate a standard that more

fully recognizes the imperative nature of maintaining employee safety.

4. N umerous technical elements of Subpart W remain unclear, co n fusing, overly complicated or conflicting.

A number of the provisions in the Final Rule

— particularly those dealing with reporting

requirements ; segment

- specific source inclusion ; source

- speci fic emission estimation methods;

and values and assumptions for facility

- specific parameters

— are unclear

, possibly erron eous or
conflicting. For example, the data elements for reporting reci procating 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 reconc iling 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 para meter ( 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 I nterstate N atural G as A ssociation of America 20 F St., N.W., Suite 450 Washington, DC 20001

January 31 , 2010Title 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 us e DEFAULT values or company records for percent methane and CO 2 for vented and fugitive emissions from transmission and storage segments

• Revise section (j) based on INGAA-EPA May 26 meetin g 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 em issions 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 a pplicable i Industry segments in §98.232(b) through (d) include flares as a listed source and must report the CO 2 , CH 4 , and N 2 O 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 CH 4 and CO 2 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 CH 4 emissions from a controlled emission source. Equation W-19 also applies for CO 2 emissions for a vapor recovery system. Equation W-20 applies for CO 2 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 CH 4 and 1 percent CO 2 (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.GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 2 of 21 § 98.233 Calculating GHG emissions. Clarifications in 98.33(a), (e), (i), (k), (o) and (p); mi nor 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 CH 4 and CO 2 emissions from continuous high bleed, continuous low bleed, and intermittent bleed natural gas pneumatic devices using Equation W–1 of this section.

Where:

Mass s,i = Annual total mass GHG emissions in metric tons CO 2 e 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.

GHG i = For onshore petroleum and natural gas production facilities, concentration of GHG i, CH 4 or CO 2 , in produced natural gas; for facilities listed in §98.230(a)(3) through (a)(8), GHG i equals 1 or the gas composition allowed per §98.232(m)

. Conv i = Conversion from standard cubic feet to metric tons CO 2 e; 0.000410 for CH 4 , and 0.00005357 for CO 2 . 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 CO 2 and CH 4 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.GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR ve

Page 3 of 21 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–14 a of this sectio n: or calculate total annual venting emissions using Equation W–14b. The operator can include corrections that address factors such as gas compressibility when comp leting the calculation.

[change to (Eq. W-14a) ]

Where:

E s,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 equipmentpurging 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.

V v = 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.
T s = Temperature at standard conditions ( °F).

T a = Temperature at actual conditions in the blowdown equipment chamber ( °F).

P s = Absolute pressure at standard conditions (psia).

P a = 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

ns, E (Eq.-W-14b)

Where:

E s,n = Annual natural gas venting emissions at standard conditions from blowdowns in cubic feet. N = Number of blowdowns in the calendar year.

V v,i = Total volume of blowdown equipment chambers (including pipelines, compressors and vessels) in cubic feet.

T s = Temperature at standard conditions ( °F).

T a,i = Temperature at actual conditions (estimated ) for event “i” in the blowdown chamber (°F).

P s = Absolute pressure at st andard conditions (psia).

P a , 0,i = Absolute pressure at actual cond itions at the start of event “i" in the blowdown chamber (psia).

P a , 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 P a,f,i = 0).

(4) Calculate both CH 4 and CO 2 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 Equation s W–14 a or W-14b and paragraph (i)(4) of this section.

...GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 4 of 21 (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 CH 4 , and CO 2 and N 2 O (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 CH 4 and CO 2 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 acous tic 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.

...GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 5 of 21 §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 CO 2 , CH 4 , and N 2 O emissions from a flare stack as follows:

... (4) Calculate GHG volumetric emissions at actual cond itions using Equations W–19, W–20, and W–21 of this section.

Where:

E a,CH4 (un-combusted) = Contribution of annual un-combusted CH 4 emissions from flare stack in cubic feet, under actual conditions.

E a,CO2 (un-combusted) = Contribution of annual un-combusted CO 2 emissions from flare stack in cubic feet, under actual conditions.

E a,CO2 (combusted) = Contribution of annual combusted CO 2 emissions from flare stack in cubic feet, under actual conditions.

V a = 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.

X CH4 = Mole fraction of CH 4 in gas to the flare.

X CO2 = Mole fraction of CO 2 in gas to the flare.

Y

j = Mole fraction of gas hydrocarbon constituents j (such as methane, ethane, propane, butane, and pentanesplus).

R

j = 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).

...GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 6 of 21 Sections (o) and (p) for compressor emissions includ e 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 CH 4 , and CO 2 and N 2 O (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 ( includ e ing emissions from unique vent sources manifolded to common vents) . Record emissions from the following vent sources types 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) A a 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 follo wing 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 y ou 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. (4 3 ) For each unique mode and vent source combination for which vent gas emission measurements were conducted during the reporting year, e E stimate 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 sectionsGHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 7 of 21 immmi,s, 

### E = T M * T * M (Eq. W-22)

Where:

E s,i,m = Annual GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions , in standard cubic feet for the unique mode and vent source combination

. MT m = Measured gas volumetric emissions in standard cubic feet per hour for the unique mode and vent source combination

. T m = Total time the compressor package is in the mode for which E si ,m is being calculated, in the calendar year in hours.

M i,m = Mole fraction of GHG i in the vent gas; use the appropriate gas compositions in paragraph (u)(2) of this section or according to §98.232(m)

. B m = 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. (5 4 ) For each unique mode and vent source combination for which vent gas emission measurements were not conducted during the reporting year, c C alculate annual emissions from each centrifugal compressor package using Equation W–23 of this section.

i mmmi, 

### GHG* s, 

### T *E

F E = (Eq. W-23)

Where:

E s,i, m = Annual GHG i (either CH 4 or CO 2 ) total volumetric GHG emissions at standard conditions from each centrifugal compressor package in standard cubic feet for the unique mode and vent source combination

. EF m = For each unique mode and vent source combination, R r eporter emission factor for each mode m , in standard cubic feet per hour, from Equation W–24 of this section as calculated in paragraph 5 6

. T m = Total time the compressor package is in the mode for which E si,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).

GHG i = For onshore natural gas processing facilities, concentration of GHG i , CH 4 or CO 2 , in produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8),GHG i equals 1 or use the gas composition allowed in §98.232(m)

. (5) You shall use all of the volumetric gas flow measurements (MT m ) 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 T M EF ∑

= (Eq. W-24)

Where:GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 8 of 21 EF m = Reporter emission factors for centrifugal compressor packages in the for a unique three modes m and vent source combination as listed in paragraph s (o)(1)(i) through (o)(1)(iii) ) of this section, in standard cubic feet of natural gas per hour.

MT m = All F f low M m easurements 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.

Count m = Total number of centrifugal compressors packages measured in the respective unique mode and vent source combination

.

m = Three unique C ompressor 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)( 5 6 ) of this section for year three and beyond

. The emission factor is used for calculating comp ressor package emissions from the unique mode and vent source combinations not measured in a particular year. (ii) [Reserved] ( 6 7 ) Onshore petroleum and natural gas production shall calculate emissions from wet seal centrifugal
compressor packages wet seal oil degassing vents as follows:

Where:

E s,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.

EF i = Emission factor for GHG i . Use 12.2 million standard cubic feet per year per compressor package for CH 4 and 538 thousand standard cubic feet per year per compressor package for CO 2 at 68 °F and 14.7 psia or 12 million standard cubic feet per year per compressor package for CH 4 and 530 thousand standard cubic feet per year per compressor package for CO 2 at 60 °F and 14.7 psia. ( 7 8 ) Estimate Calcul ate both CH 4 and CO 2 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.GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 9 of 21 (p) Reciprocating compressor venting. Calculate CH 4 and CO 2 emissions from all reciprocating compressor vents as follows. (1) Reciprocating compressor package operating st atus 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)( 7 9 ) 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 sources types 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 plac e 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) M m easure emissions from each all vents ( including emissions manifolded to a common vents from a single vent source ( including rod packing, unit isolation valves, and or 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 annua lly 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).GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 10 of 21 (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, E estimate annual emissions for each reciprocating compressor package using the flow measurement and Equation W–26 of this section.

immmi,s, 

### M * T * T M E = (Eq. W-26)

Where:

E s,i,m = Annual GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions , in standard cubic feet for the unique mode and vent source combination

. MT m = Measured gas volumetric emissions in standard cubic feet per hour for the unique mode and vent source combination

. T m = Total time the compressor package is in the mode for which E s,i,m is being calculated, in the calendar year in hours.

M i,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, C c alculate 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.

i mmmi, 

### GHG* s, 

### T *E

F E = (Eq. W-27)

Where:

E s,i, m = Annual GHG i (either CH 4 or CO 2 ) total volumetric GHG emissions at standard conditions from each reciprocating compressor package in standard cubic feet for the unique mode and vent source combination

. EF m = For each unique mode and vent source combination, R r eporter emission factor for each mode, m, in standard cubic feet per hour, from Equation W–28 of this section as calculated in paragraph (p)(7 6 )(i) of this section.

T m = Total time the compressor package is in the mode for which E si,m is being calculated, in the calendar year in ho urs per year the compressor was in mode, m, as listed in paragraph (p)(1) through (p)(3).

GHG i = For onshore natural gas processing facilities, concentration of GHG i, CH 4 or CO 2 , in produced natural gas or feed natural gas; for other facilities listed in §98.230(a)(4) through (a)(8), GHG i equals 1. or gas composition allowed per §98.232(m)

.

m = Compressor mode as listed in paragraph (p)(1) through (p)(3).GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

( 6 i ) You shall use all of the volumetric gas flow meter readings from measurements (MT m ) 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 repo rter's compressor modes not measured in the calendar year to develop the following reporter emission factors that are mode and vent source-specific . u U s e ing 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)(3 1 ) (iv)

.

Page 11 of 21 m m
m 

### ountC T M EF ∑

= (Eq. W-28)

Where:

EF m = 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.

MT m = 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.

Count m = 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)( 1 3 )(iv). (A) You must combine emissions for blowndown vents, measured in the operating and standby pressurized modes. ( i B ) 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 sect ion for year three and beyond. The emission factor is used for calculating comp ressor package emissions from the unique mode and vent source combinations not measured in a particular year

. (ii) [Reserved] (8) Determine if the reci procating 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 estima te 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:

E s,i = Annual total volumetric GHG emissions at standard conditions from reciprocating compressors in standard cubic feet.GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 12 of 21 Count = Total number of reciprocating compressors packages for the reporter.

EF i = Emission factor for GHG i. Use 9.63 thousand standard cubic feet per year per compressor package for CH 4 and 0.535 thousand standard cubic feet per year per compressor package for CO 2 at 68 °F and 14.7 psia or 9.48 thousand standard cubic feet per year per compressor package for CH 4 and 0.527 thousand standard cubic feet per year per
compressor package for CO 2 at 60 °F and 14.7 psia. (8) (10) Estimate CH 4 and CO 2 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; mi nor clarifications and corrections to (t) though (v)

(q) Leak detection and leaker emission factors.

...
GHGi = For onshore natural gas processing facilities, concentration of GHGi, CH 4 or CO 2 , 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 CH 4 and 1.1 × 10 -2 for CO 2 , 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, CH 4 or CO 2 , in produced natural gas or feed natural gas; for other facilities listed in § 98.230(a)(4) through (a)(8), GHGi equals 1 for CH 4 and 1.1 × 10 -2 for CO 2 , 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 s ection

.

Where:

E s,n = Natural gas volumetric emissions at standard temperature and pressure (STP) conditions in cubic feet.

E a,n = Natural gas volumetric emissions at actual conditions in cubic feet.

T s = Temperature at standard conditions ( °F).

T a = Temperature at actual emission conditions ( °F).

P s = Absolute pressure at st andard conditions (psia).GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR ve

Page 13 of 21 rsion

P a = 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:

E s,i = GHG i volumetric emissions at standard temperat ure and pressure (STP) conditions in cubic feet.

E a,i = GHG i volumetric emissions at actual conditions in cubic feet.

T s = Temperature at standard conditions ( °F).

T a = Temperature at actual emission conditions ( °F).

P s = Absolute pressure at standard conditions (psia).

P a = 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 CH 4 and CO 2 emissions from natural gas emissions using Equation W–35 of this section.

Where:

E s,i = GHG i (either CH 4 or CO 2 ) volumetric emissions at standard conditions in cubic feet.

E s,n = Natural gas volumetric emissions at standard conditions in cubic feet.

M i = Mole fraction of GHGi in the natural gas. (2) For Equation W–35 of this section, the mole fraction, M i , 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)

.GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 14 of 21 (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:

Mass s,I = GHG i (either CH 4 , or CO 2 or N 2 O ) mass emissions at standard conditions in metric tons CO 2 e.
E s,i = GHG i (either CH 4 , or CO 2 or N 2 O ) volumetric emissions at standard conditions, in cubic feet.

ρ i = Density of GHG i. Use 0.0538 kg/ft 3 for CO 2 and N 2 O, and 0.0196 kg/ft 3 for CH 4 at 68 °F and 14.7 psia or 0.0530 kg/ft 3 for CO 2 and N 2 O, and 0.0193 kg/ft 3 for CH 4 at 60 °F and 14.7 psia. GWP = Global warming potential, 1 for CO 2, 21 for CH 4 , and 310 for N 2 O.

...GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 15 of 21 § 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 record ed 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.GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 16 of 21 (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 CH 4 and CO 2 volumetric 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 wrap s 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). (3 4 ) Estimate CH 4 and CO 2 volumetric and mass emissions from volumetric natural gas emissions using the calculations in §98.233(u) and (v). (4 5 ) Calibrate the instrument at 2.5 percent methane with 97.5 percent air and 100 percent CH 4 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 measuremen ts 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,GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 17 of 21 (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 CO 2 e 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 emissi ons from all reciprocating compressors as an aggregate number.

... (c) For each aggregated source, unless otherwise specified, report activity data and emissions (in metric tons CO 2 e 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 c C ount and estimated count separately of natural gas pneumatic high bleed devices as applicable

. (ii) Actual c C ount and estimate d count separately of natural gas pneumatic low bleed devices as applicable

. (iii) Actual c C ount 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 stack s (refer to Equation W–14 a 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 i dentified using optical gas imaging instrument per §98.234(a) (refer to §98.233(k)), or acoustic leak detection of 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 bl owdowns calculated using Eq W-14b, most or all events will include a unique volume, so tracking counts “per equipment type” is not appropriateGHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 18 of 21 (13) For each centrifugal compressor package s: (i) For each wet seal centrifugal compressors package with wet seals in operati ng onal 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) T ype 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 CH 4 and metric tons of CO 2 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 B b lowdown vent emissions in metric tons of CH 4 and metric tons of CO 2 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 i I solation valve leakage emissions in not operating depressurized mode in cubic feet metric tons of CH 4 per hour and metric tons of CO 2 (r efer to Equation W

– 23 and Equation W

– 24 of §98.233). (iv) For each centrifugal compressor package , R r eport 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 stan dard 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). (v i ) 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.GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 19 of 21 (14) For reciprocating compressor package s: (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 CH 4 and metric tons of CO 2 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 CH 4 and metric tons of CO 2 . (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 i n cubic feet per hour (refer to §98.233, Equation W

– 28). (C) Report Annual blowdown vent emissions in metric tons of CH 4 and metric tons of CO 2 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 emissio n 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 CH 4 and metric tons of CO 2 in
not operating depressurized mode. (iv) For each reciprocating compressor package , R r eport 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). (v ii ) 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.GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 20 of 21 (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 CH 4 and CO 2 as described in Equation W

– 30 of §98.233. (C) Report Annual CH 4 and CO 2 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 CH 4 and CO 2 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 CO 2 by drawing in low pressure natural gas or CO 2 and discharging significantly higher pressure natural gas or CO 2. 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—Stor age 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”.GHG MRR Subpart W Final Rule (Nov 2010) – Recommended Revisions. e-CFR version

Page 21 of 21 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 – RECOMME ND 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.