BEFORE 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

.

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.