BEFORE THE ADMINISTRATOR 

UNITED STATES ENVIRONMENTAL PROTECTION AGENCY 

WASHINGTON, DC 

PETITION FOR RECONSIDERATION OF FINAL AGENCY ACTION: 

MANDATORY REPORTING OF GREENHOUSE GASES: 

PETROLEUM AND NATURAL GAS SYSTEMS

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

Petitioners 

Chesapeake Energy Corporation 

American Exploration & Production Council 

Counsel for Petitioners 

Sandra Y. Snyder 

Kevin A. Ewing 

Lisa M. Jaeger 

Bracewell & Giuliani LLP 

2000 K Street, NW 

Suite 500 

Washington, DC 20006 

January 31, 2011 
 

1

INTRODUCTION 

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

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

Chesapeake Energy Corporation (Chesapeake) and the American Exploration & 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

effectiveness of the rule. Id.

SUMMARY OF PETITION 

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

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

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

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

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

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

W Rule. 

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

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

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

 – the overall source 

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

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

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

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

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

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

 1

 75 Fed. Reg. 74,460. 
 

2

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

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

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

demonstrated their unworkability for determining what constitutes compliance with the 

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

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

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

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

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

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

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

merit reconsideration so that substantive and procedural flaws may be addressed 

administratively. 

SPECIFIC ISSUES FOR RECONSIDERATION 

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

 JUSTIFY CERTAIN ASPECTS OF THE RULE EITHER THROUGH RECORD 

 DATA OR LEGAL ANALYSIS, WITH THE RESULT THAT THOSE 

 ELEMENTS ARE ARBITRARY AND CAPRICIOUS. 

1. Measurement of emissions. 

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

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

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

Commenters recommended using the API Compendium for that purpose. Commenters 

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

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

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

through an accepted estimation methodology. 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

Mexico Greenhouse Gas Mandatory Emissions Reporting, Emissions Quantification 

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

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

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

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

reporting GHG emissions.3

 It was "designed to strike a balance between flexibility and 

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

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

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

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

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

confidence. 

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

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

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

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

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

same rule. 

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

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

Reform.5

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

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

a highly burdensome measurement requirement on sources with no demonstrable 

 

2

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

1-2 (Aug. 2009). 

3

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

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

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

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

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

4 See n.3, supra. 5

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

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

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

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

2. De minimis emissions from portable equipment. 

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

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

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

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

justify the additional resource strain on covered sources. 

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

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

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

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

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

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

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

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

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

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

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

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

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

(Oct. 30, 2009). 

 

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

* * * 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

impacts. 

* * * 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

EPA finalized an irrational approach. 

3. Designated Representative. 

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

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

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

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

Certifications: 

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

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

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

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

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

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

(Certification 3) 
 

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

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

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

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

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

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

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

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

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

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

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

achieve the desired contractual relationships among the parties. 

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

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

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

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

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

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

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

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

requirement in a timely manner. 

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

operations and directly or indirectly contemplate compliance with applicable laws or 

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

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

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

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

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

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

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

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

uncertainty for companies regarding this new obligation under longstanding existing 

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

legal and administrative burden. 

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

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

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

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

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

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

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

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

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

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

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

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

form JOAs include provisions such as the following: 

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

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

 make them jointly and severally liable) 

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

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

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

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

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

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

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

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

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

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

emission reporting requirement. 

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

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

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

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

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

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

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

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

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

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

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

voluminous ownership lists, and will require administrative process for continually 

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

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

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

process for handling ownership change notifications as ownership can change frequently 

at some wells. 

EPA insists that requiring ownership involvement will ensure accountability for the 

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

requirement to designate a representative will not interfere with contractual relationships 

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

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

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

the agency because EPA responded to petitioners' challenges with conclusory 

statements). 
 

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B. THE FINAL RULE IMPOSES NEW COMPLIANCE REQUIREMENTS AND 

METHODOLOGIES THAT WERE NOT INCLUDED IN THE PROPOSED 

RULE, DEPRIVING COVERED SOURCES OF NOTICE AND AN 

OPPORTUNITY TO COMMENT. 

1. Dump valves. 

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

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

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

unreasonable ongoing monitoring and record keeping burden to impose on industry 

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

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

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

production sites that are mostly unmanned. 

2. Best Available Monitoring Methods (BAMM). 

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

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

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

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

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

certainty in rule procedures and deadlines. 

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

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

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

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

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

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

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

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

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

necessary to conduct the calculations required under the rule. 

3. Emissions manifolded to common vents. 

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

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

centrifugal compressor vents and emissions from all vents (including emissions 

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

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

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

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

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

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

9

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

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

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

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

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

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

seal centrifugal compressors). 

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

 REPORT THAT WOULD REQUIRE MAJOR PIPING MODIFICATIONS AND 

 THAT WOULD UNDULY THREATEN WORKER SAFETY 

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

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

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

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

preferable because the compliance costs associated with the direct measurement 

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

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

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

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

required under this rule” (emphasis added). 

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

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

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

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

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

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

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

on thousands of engines every year. 

D. THE FINAL RULE CONTAINS CONFLICTING AND INCONSISTENT 

 TREATMENT OF REQUIRED ELEMENTS AND DEFINITIONS THAT ARE 

 THE BASIS FOR DETERMINING COMPLIANCE. 

Air emissions inventory regulations must contain requirements with sufficient clarity that 

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

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

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

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

certification statement: 

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

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

10

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

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

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

individuals with primary responsibility for obtaining the information, I 

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

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

are significant penalties for submitting false statements and information or 

omitting required statements and information, including the possibility of 

fine or imprisonment. 

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

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

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

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

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

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

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

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

contrary to law. 

 

1. Excluding boosting stations. 

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

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

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

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

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

inside or outside the processing facility fence." 

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

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

rule. 

Onshore natural gas transmission compression

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

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

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

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

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

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

Onshore natural gas processing

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

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

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

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

11

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

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

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

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

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

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

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

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

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

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

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

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

Gathering lines and boosting stations

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

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

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

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

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

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

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

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

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

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

C.F.R. § 98.230(a)(4). 

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

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

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

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

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

2. Mapping wells to fields. 

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

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

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

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

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

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

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

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

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

requires aggregation of information by field for the following items: 

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

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

each well. 

3. Definition of “facility.” 

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

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

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

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

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

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

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

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

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

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

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

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

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

unintended confusion and inaccuracies in reporting. 

4. Pipeline quality natural gas. 

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

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

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

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

5. Producing horizon/formation. 

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

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

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

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

its meaning could be interpreted differently by the reporting sources. 

6. Well testing venting and flaring. 

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

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

time as well completion. In order to comply with this requirement, covered sources need 

a clear definition of when completion/flowback is finished and when well testing begins. 

Without such clarity, the results reported to EPA will be inconsistent and designated 

representatives will have difficulty certifying that their submissions are complete and 

accurate. 

7. Associated gas venting and flaring. 

40 C.F.R. § 98.233(m) imposes a requirement to report emissions from associated gas 

venting and flaring not in conjunction with well testing. While this regulation references 

40 C.F.R. § 98.233(l), that definition is unclear. Therefore, industry is left without clarity 

regarding what emissions are included in "associated gas venting and flaring not in 

conjunction with well testing." We presume that EPA intended in § 98.233(m) to require 

reporting of emissions from venting/flaring of associated gas from an oil well when there 

is no sales pipeline available, which is the typical setup for well testing. Whether EPA 

meant to impose the requirement to report emissions from all temporary venting events or 

only continuous venting/flaring (as from a stripper well) is unclear. Many individual 

triggers could lead to venting/flaring; therefore, if EPA intended to require reporting of 

temporary venting, such a requirement would impose a large burden on facilities by 

requiring continuous monitoring from all oil wells. 
 

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8. Pneumatic devices. 

The requirement to report emissions from pneumatic devices, 40 C.F.R. § 98.233(a), is 

vague. EPA has imposed a requirement to count each pneumatic device according to its 

bleed rate. High-bleed pneumatic devices are classified as those that vent continuously to 

the atmosphere at a rate in excess of 6 scf/hr, whereas low-bleed pneumatic devices are 

those that bleed at rates equal to or less than 6 scf/hr. EPA has not clarified how industry 

must determine these rates. It is unclear whether it is sufficient to rely on the 

manufacturer's bleed rate data, whether direct measurements are required at each 

individual pneumatic device, or if BAMM can or should be used. Regardless of the 

method used to determine bleed rate, EPA has not given sufficient consideration to the 

burden imposed by requiring that the bleed rate of each device be determined in order to 

count and classify the devices. 

9. Blowdown vent stacks. 

The sources that are required to report emissions from blowdown vent stacks are not 

clear. Table 3 of the preamble lists onshore production as being required to report 

emissions from blowdown vent stacks. 75 Fed. Reg. 74463. In contrast, the statute does 

not require that blowdown vent stack emissions be reported for onshore petroleum and 

natural gas production facilities. See generally 40 C.F.R. § 98.232(c). For compliance 

purposes, sources need resolution of this inconsistency between the language in the 

preamble and the rule. 

CONCLUSION 

For all of the foregoing reasons, Chesapeake and AXPC respectfully request that EPA 

grant the Petition for Reconsideration.